10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

[ X ]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

or

[    ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from        to        

Commission File No. 1-8968

ANADARKO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	76-0146568
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046

(Address of principal executive offices)

Registrant’s telephone number, including area code (832) 636-1000

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

The number of shares outstanding of the Company’s common stock as of July 31, 2012, is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.10 per share	499,678,984

TABLE OF CONTENTS

PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Six Months Ended June 30, 2012 and 2011		2
	Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2012 and 2011		3
	Consolidated Balance Sheets as of June 30, 2012, and December 31, 2011		4
	Consolidated Statement of Equity for the Six Months Ended June 30, 2012		5
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011		6
	Notes to Consolidated Financial Statements		7
Item 2.	Management’s Discussion and Analysis		26
	Financial Results		29
	Operating Results		39
	Liquidity and Capital Resources		41
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		45
Item 4.	Controls and Procedures		46
PART II
Item 1.	Legal Proceedings		47
Item 1A.	Risk Factors		47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		48
Item 6.	Exhibits		49

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended  June 30,						Six Months Ended   June 30,
millions except per-share amounts	2012			2011			2012			2011
Revenues and Other
Natural-gas sales	$	496		$	870		$	1,069		$	1,724
Oil and condensate sales		2,222			2,236			4,466			4,043
Natural-gas liquids sales		282			370			624			703
Gathering, processing, and marketing sales		200			258			453			488
Gains (losses) on divestitures and other, net		22			(58	)		57			(29	)
Total		3,222			3,676			6,669			6,929
Costs and Expenses
Oil and gas operating		249			236			491			468
Oil and gas transportation and other		223			207			463			416
Exploration		1,121			236			1,365			415
Gathering, processing, and marketing		178			205			367			376
General and administrative		262			282			531			491
Depreciation, depletion, and amortization		1,027			985			1,957			1,970
Other taxes		326			413			703			757
Impairments		112			102			162			104
Algeria exceptional profits tax settlement		—			—			(1,804	)		—
Deepwater Horizon settlement and related costs		3			9			11			35
Total		3,501			2,675			4,246			5,032
Operating Income (Loss)		(279	)		1,001			2,423			1,897
Other (Income) Expense
Interest expense		190			216			376			436
(Gains) losses on commodity derivatives, net		(420	)		(343	)		(468	)		(87	)
(Gains) losses on other derivatives, net		376			144			140			85
Other (income) expense, net		(519	)		(18	)		(254	)		(42	)
Total		(373	)		(1	)		(206	)		392
Income (Loss) Before Income Taxes		94			1,002			2,629			1,505
Income Tax Expense (Benefit)		164			440			516			706
Net Income (Loss)		(70	)		562			2,113			799
Net Income Attributable to Noncontrolling Interests		19			18			46			39
Net Income (Loss) Attributable to Common Stockholders	$	(89	)	$	544		$	2,067		$	760
Per Common Share
Net income (loss) attributable to common stockholders—basic	$	(0.18	)	$	1.09		$	4.11		$	1.52
Net income (loss) attributable to common stockholders—diluted	$	(0.18	)	$	1.08		$	4.10		$	1.51
Average Number of Common Shares Outstanding—Basic		500			498			499			497
Average Number of Common Shares Outstanding—Diluted		500			500			501			499
Dividends (per Common Share)	$	0.09		$	0.09		$	0.18		$	0.18

See accompanying Notes to Consolidated Financial Statements.

2

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended  June 30,					Six Months Ended   June 30,
millions	2012			2011		2012		2011
Net Income (Loss)	$	(70	)	$	562	$	2,113	$	799
Other Comprehensive Income (Loss), net of taxes
Reclassification of previously deferred derivative losses to net income (1)		2			3		4		5
Amortization of net actuarial loss and prior service cost to net periodic benefit cost (2)		15			13		30		27
Total		17			16		34		32
Comprehensive Income (Loss)		(53	)		578		2,147		831
Comprehensive Income Attributable to Noncontrolling Interests		19			18		46		39
Comprehensive Income (Loss) Attributable to Common Stockholders	$	(72	)	$	560	$	2,101	$	792

⁽¹⁾  Net of income tax benefit (expense) of $(1) million and $(1) million for the three months ended June 30, 2012 and 2011, respectively, and $(2) million and $(3) million for the six months ended June 30, 2012 and 2011, respectively.

⁽²⁾  Net of income tax benefit (expense) of $(9) million and $(8) million for the three months ended June 30, 2012 and 2011, respectively, and $(17) million and $(16) million for the six months ended June 30, 2012 and 2011, respectively.

See accompanying Notes to Consolidated Financial Statements.

3

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

millions	June 30,     2012			December 31,  2011
ASSETS
Current Assets
Cash and cash equivalents	$	2,794		$	2,697
Accounts receivable, net of allowance:
Customers		1,087			1,269
Others		1,864			1,990
Algeria exceptional profits tax settlement		1,629			—
Other current assets		1,056			975
Total		8,430			6,931
Properties and Equipment
Cost		60,990			60,081
Less accumulated depreciation, depletion, and amortization		23,506			22,580
Net properties and equipment		37,484			37,501
Other Assets		1,661			1,516
Goodwill and Other Intangible Assets		5,757			5,831
Total Assets	$	53,332		$	51,779
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	2,873		$	3,299
Accrued expenses		1,271			1,430
Current portion of long-term debt		1,739			170
Total		5,883			4,899
Long-term Debt		13,093			15,060
Other Long-term Liabilities
Deferred income taxes		8,809			8,479
Asset retirement obligations		1,662			1,737
Other		2,607			2,621
Total		13,078			12,837
Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 517.6 million and 516.0 million shares issued as of June 30, 2012, and December 31, 2011, respectively)		51			51
Paid-in capital		7,995			7,851
Retained earnings		13,595			11,619
Treasury stock (17.9 million and 17.6 million shares as of June 30, 2012, and December 31, 2011, respectively)		(827	)		(804	)
Accumulated other comprehensive income (loss)		(578	)		(612	)
Total Stockholders’ Equity		20,236			18,105
Noncontrolling interests		1,042			878
Total Equity		21,278			18,983
Total Liabilities and Equity	$	53,332		$	51,779

See accompanying Notes to Consolidated Financial Statements.

4

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

	Total Stockholders’ Equity
	Common Stock		Paid-in  Capital		Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests			Total  Equity
millions
Balance at December 31, 2011	$	51	$	7,851	$	11,619		$	(804	)	$	(612	)	$	878		$	18,983
Net income (loss)		—		—		2,067			—			—			46			2,113
Common stock issued		—		110		—			—			—			—			110
Dividends—common		—		—		(91	)		—			—			—			(91	)
Repurchase of common stock		—		—		—			(23	)		—			—			(23	)
Subsidiary equity transactions (1)		—		34		—			—			—			159			193
Distributions to noncontrolling interest owners		—		—		—			—			—			(52	)		(52	)
Contributions from noncontrolling interest owners		—		—		—			—			—			11			11
Reclassification of previously deferred derivative losses to net income		—		—		—			—			4			—			4
Adjustments for pension and other postretirement plans		—		—		—			—			30			—			30
Balance at June 30, 2012	$	51	$	7,995	$	13,595		$	(827	)	$	(578	)	$	1,042		$	21,278

⁽¹⁾  The $34 million increase to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders, totaled $2,101 million for the six months ended June 30, 2012.

See accompanying Notes to Consolidated Financial Statements.

5

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
millions	2012			2011
Cash Flows from Operating Activities
Net income (loss)	$	2,113		$	799
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		1,957			1,970
Deferred income taxes		143			258
Dry hole expense and impairments of unproved properties		1,187			227
Impairments		162			104
(Gains) losses on divestitures, net		29			18
Unrealized (gains) losses on derivatives, net		83			75
Other		120			61
Changes in assets and liabilities:
Deepwater Horizon settlement and related costs		24			—
Algeria exceptional profits tax settlement		(1,691	)		—
Tronox-related contingent loss		(250	)		—
(Increase) decrease in accounts receivable		351			(535	)
Increase (decrease) in accounts payable and accrued expenses		(486	)		241
Other items—net		148			(92	)
Net cash provided by (used in) operating activities		3,890			3,126
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs		(3,553	)		(2,799	)
Acquisition of midstream businesses		—			(804	)
Divestitures of properties and equipment and other assets		258			55
Other—net		(112	)		(41	)
Net cash provided by (used in) investing activities		(3,407	)		(3,589	)
Cash Flows from Financing Activities
Borrowings, net of issuance costs		886			1,046
Repayments of debt		(1,305	)		(859	)
Increase (decrease) in accounts payable, banks		(39	)		(38	)
Dividends paid		(91	)		(90	)
Repurchase of common stock		(23	)		(30	)
Issuance of common stock, including tax benefit on stock option exercises		38			49
Sale of subsidiary units		212			130
Distributions to noncontrolling interest owners		(52	)		(37	)
Contributions from noncontrolling interest owners		11			4
Net cash provided by (used in) financing activities		(363	)		175
Effect of Exchange Rate Changes on Cash		(23	)		14
Net Increase (Decrease) in Cash and Cash Equivalents		97			(274	)
Cash and Cash Equivalents at Beginning of Period		2,697			3,680
Cash and Cash Equivalents at End of Period	$	2,794		$	3,406

See accompanying Notes to Consolidated Financial Statements.

6

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.  Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of natural gas, crude oil, condensate, and natural gas liquids (NGLs). In addition, the Company engages in the gathering, processing, and treating of natural gas, and the transporting of natural gas, crude oil, and NGLs. The Company also participates in the hard minerals business through its ownership of non-operated joint ventures and royalty arrangements. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

Basis of Presentation  The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s Consolidated Balance Sheets as of June 30, 2012, and December 31, 2011, the Consolidated Statements of Income and Comprehensive Income for the three and six months ended June 30, 2012 and 2011, the Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011, and the Consolidated Statement of Equity for the six months ended June 30, 2012. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

Use of Estimates  In preparing financial statements in accordance with accounting principles generally accepted in the United States, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to the value of properties and equipment; proved reserves; goodwill; intangible assets; asset retirement obligations; litigation reserves; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

2.  Acquisitions

The acquisitions of the Platte Valley assets in February 2011 and the Wattenberg Plant in May 2011 constitute business combinations and were accounted for using the acquisition method. Preliminary fair-value measurements made at the acquisition dates were finalized in the first quarter of 2012. There were no changes to the fair value of assets acquired and liabilities assumed from the amounts included on the Company’s Consolidated Balance Sheet as of December 31, 2011.

3.  Inventories

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

millions	June 30,              2012		December 31,     2011
Crude oil	$	69	$	103
Natural gas		31		49
NGLs		41		59
Total	$	141	$	211

7

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4.  Properties and Equipment

Suspended Exploratory Well Costs  The Company’s suspended exploratory well costs at June 30, 2012, and December 31, 2011, were $1.9 billion and $1.4 billion, respectively. The increase in suspended exploratory well costs during 2012 primarily relates to the capitalization of costs associated with successful exploration drilling in Mozambique, the Gulf of Mexico, the Utica and Marcellus shales in the Southern and Appalachia Region, Ghana, and Côte d’Ivoire. For the six months ended June 30, 2012, $39 million of exploratory well costs previously capitalized as suspended well costs for greater than one year were charged to dry hole expense and $82 million of capitalized suspended well costs were reclassified to proved properties.

Management believes projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development and is actively pursuing efforts to assess whether reserves can be attributed to these projects. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time.

Impairments of Unproved Properties  In the second quarter of 2012, the Company recognized a $720 million impairment of unproved Powder River coalbed methane properties primarily due to lower natural-gas prices. The Company also recognized a $124 million impairment of an unproved Gulf of Mexico natural-gas property due to a reduction of estimated recoverable reserves as a result of the forecasted natural-gas price environment. This Gulf of Mexico property is located on a lease that is close to expiration and the Company does not plan to pursue the exploitation of this property under the forecasted natural-gas price environment. These impairments are included in exploration expense in the Company’s Consolidated Statements of Income for the three and six months ended June 30, 2012, and the impacted assets were impaired to fair value, estimated using Level 3 fair-value inputs.

Impairments  Impairment expense for the three and six months ended June 30, 2012, was $112 million and $162 million, respectively. In the second quarter of 2012, due to lower natural-gas prices, the Company recognized impairments of $79 million related to certain onshore domestic oil and gas exploration and production reporting segment properties and $4 million related to midstream reporting segment properties. The Company also recognized impairments of $50 million and $17 million in the first and second quarter of 2012, respectively, related to downward reserves revisions for a Gulf of Mexico property included in the oil and gas exploration and production reporting segment that is near the end of its economic life. These properties were impaired to an aggregate fair value of $41 million based on an income approach, estimated using Level 3 fair-value inputs.

Also in the second quarter of 2012, the Company recognized impairment expense of $11 million ($4 million net of tax) related to the Company’s investment in Venezuelan assets due to declines in estimated recoverable reserves and lower crude-oil prices. These assets are included in the oil and gas exploration and production reporting segment and were impaired to fair value based on an income approach, estimated using Level 3 fair-value inputs. At June 30, 2012, the Company’s after-tax net investment in these assets was $34 million.

Impairment expense for the three and six months ended June 30, 2011, was $102 million and $104 million, respectively, including $100 million recognized in the second quarter of 2011 related to onshore domestic properties due to a change in projected cash flows resulting from the Company’s intent to divest of the properties. These properties were included in the oil and gas exploration and production reporting segment and were impaired to a fair value of $491 million based on an income approach, estimated using Level 3 fair-value inputs.

Assets Held for Sale  In 2011, the Company began marketing domestic properties from the oil and gas exploration and production reporting segment and the midstream reporting segment in order to redirect its operating activities and capital investment to other areas. During the first quarter of 2012, the Company decided not to proceed with the sale of properties from the midstream reporting segment. In 2012, the Company sold certain domestic oil and gas exploration and production reporting segment properties and recognized losses of $13 million and $30 million included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income for the three and six months ended June 30, 2012, respectively. At June 30, 2012, the remaining balances of assets and liabilities associated with assets held for sale were not material.

8

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5.  Noncontrolling Interests

Western Gas Partners, LP (WES), a consolidated subsidiary, is a limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. In June 2012, WES issued five million common units to the public, raising net proceeds of $212 million, which increased the noncontrolling interest component of total equity. At June 30, 2012, Anadarko’s ownership interest in WES consisted of a 41.4% limited partner interest, the entire 2.0% general partner interest, and incentive distribution rights.

6.  Derivative Instruments

Objective and Strategy  The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as Henry Hub for natural gas and Cushing for oil. Basis swaps are used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).

Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest-rate changes. The fair value of the Company’s interest-rate swap portfolio increases (decreases) when interest rates increase (decrease).

The Company does not apply hedge accounting to any of its derivative instruments. As a result, both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings. Accumulated other comprehensive loss balances of $103 million ($66 million after tax) and $109 million ($70 million after tax) at June 30, 2012, and December 31, 2011, respectively, relate to interest-rate derivatives that were previously subject to hedge accounting.

9

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6.  Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities  Below is a summary of the Company’s derivative instruments related to its Oil and Natural-Gas Production/Processing Activities at June 30, 2012. The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are a combination of NYMEX Cushing and London Brent Dated prices.

	2012			2013
Natural Gas
Three-Way Collars (thousand MMBtu/d)		—	(1)		450
Average price per MMBtu
Ceiling sold price (call)	$	—		$	6.57
Floor purchased price (put)	$	—		$	5.00
Floor sold price (put)	$	—		$	4.00
Fixed-Price Contracts (thousand MMBtu/d)		1,000			—
Average price per MMBtu	$	4.69		$	—
Crude Oil
Three-Way Collars (MBbls/d)		62			—
Average price per barrel
Ceiling sold price (call)	$	122.30		$	—
Floor purchased price (put)	$	101.22		$	—
Floor sold price (put)	$	81.34		$	—
Fixed-Price Contracts (MBbls/d)		60			—
Average price per barrel	$	107.19		$	—

⁽¹⁾  Includes the effects of offsetting purchased and sold natural-gas three-way collars of 500,000 MMBtu/d.

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

Marketing and Trading Derivative Activities  In addition to the positions in the above tables, the Company also engages in marketing and trading activities, which include physical product sales and related derivative transactions used to manage commodity-price risk. At June 30, 2012, the Company had fixed-price physical transactions related to natural gas totaling 12 billion cubic feet (Bcf), offset by derivative transactions for 12 Bcf. At December 31, 2011, the Company had fixed-price physical transactions related to natural gas totaling 22 Bcf, offset by derivative transactions for 21 Bcf, for a net position of 1 Bcf.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6.  Derivative Instruments (Continued)

Interest-Rate Derivatives  Anadarko has outstanding interest-rate swap contracts as a fixed-rate payor to mitigate the interest-rate risk associated with anticipated debt issuances. The Company locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR. The swap instruments include a provision that requires both the termination of the swaps and cash settlement in full at the start of the reference period.

The Company had the following outstanding interest-rate swaps at June 30, 2012:

millions except percentages	Reference Period		Weighted-Average
Notional Principal Amount	Start	End	Interest Rate
$                     250	October 2012	October 2022	4.91%
$                     750	October 2012	October 2042	4.80%
$                     750	June 2014	June 2024	6.00%
$                  1,100	June 2014	June 2044	5.57%

Effect of Derivative Instruments—Balance Sheet  The fair value of the Company’s derivative instruments is presented below.

	Gross				Gross
	Derivative Assets				Derivative Liabilities
millions	June 30,		December 31,		June 30,			December 31,
Balance Sheet Classification	2012		2011		2012			2011
Commodity derivatives
Other current assets	$	860	$	924	$	(212	)	$	(353	)
Other assets		111		150		(25	)		(15	)
Accrued expenses		8		5		(18	)		(33	)
Other liabilities		7		1		(14	)		(17	)
		986		1,080		(269	)		(418	)
Interest-rate and other derivatives
Accrued expenses		—		—		(439	)		(391	)
Other liabilities		—		—		(898	)		(808	)
		—		—		(1,337	)		(1,199	)
Total Derivatives	$	986	$	1,080	$	(1,606	)	$	(1,617	)

11

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6.  Derivative Instruments (Continued)

Effect of Derivative Instruments—Statement of Income  The realized and unrealized gain or loss amounts related to derivative instruments are presented below.

	Three Months Ended									Six Months Ended
millions	June 30, 2012									June 30, 2012
Classification of (Gain) Loss Recognized	Realized			Unrealized			Total			Realized			Unrealized			Total
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	(1	)	$	8		$	7		$	(3	)	$	13		$	10
(Gains) losses on commodity derivatives, net		(263	)		(157	)		(420	)		(400	)		(68	)		(468	)
Interest-rate and other derivatives
(Gains) losses on other derivatives, net		2			374			376			2			138			140
Derivative (gain) loss, net	$	(262	)	$	225		$	(37	)	$	(401	)	$	83		$	(318	)
	Three Months Ended									Six Months Ended
millions	June 30, 2011									June 30, 2011
Classification of (Gain) Loss Recognized	Realized			Unrealized			Total			Realized			Unrealized			Total
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	4		$	(4	)	$	—		$	16		$	(5	)	$	11
(Gains) losses on commodity derivatives, net		(27	)		(316	)		(343	)		(84	)		(3	)		(87	)
Interest-rate and other derivatives
(Gains) losses on other derivatives, net		2			142			144			2			83			85
Derivative (gain) loss, net	$	(21	)	$	(178	)	$	(199	)	$	(66	)	$	75		$	9

⁽¹⁾  Represents the effect of marketing and trading derivative activities.

Credit-Risk Considerations  The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or the Intercontinental Exchange through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact of a counterparty’s creditworthiness on fair value. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure. The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and routinely exercises its contractual right to offset realized gains against realized losses when settling with derivative counterparties.

In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across all derivative types. At June 30, 2012, $470 million of the Company’s $1.6 billion gross derivative liability balance, and at December 31, 2011, $749 million of the Company’s $1.6 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types, as settlement timing differs.

Some of the Company’s derivative instruments are subject to provisions that can require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered. However, most of the Company’s derivative counterparties maintain secured positions with respect to the Company’s derivative liabilities under the Company’s $5.0 billion senior secured revolving credit facility ($5.0 billion Facility), the available capacity of which is sufficient to secure potential obligations to such counterparties.

At June 30, 2012, and December 31, 2011, the aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed was $156 million and $2 million (net of collateral), respectively, included in accrued expenses on the Company’s Consolidated Balance Sheets.

12

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6.  Derivative Instruments (Continued)

Fair Value  Fair value of futures contracts is based on quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, implied market volatility and discount factors. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments.

The fair value of the Company’s derivative financial assets and liabilities, by input level within the fair-value hierarchy, is presented below.

millions June 30, 2012	Level 1			Level 2			Level 3		Netting (1)			Collateral			Total
Assets
Commodity derivatives
Financial institutions	$	2		$	883		$	—	$	(219	)	$	(41	)	$	625
Other counterparties		—			101			—		(33	)		—			68
Total derivative assets	$	2		$	984		$	—	$	(252	)	$	(41	)	$	693
Liabilities
Commodity derivatives
Financial institutions	$	(3	)	$	(217	)	$	—	$	219		$	1		$	—
Other counterparties		—			(49	)		—		33			—			(16	)
Interest-rate and other derivatives		—			(1,337	)		—		—			—			(1,337	)
Total derivative liabilities	$	(3	)	$	(1,603	)	$	—	$	252		$	1		$	(1,353	)
December 31, 2011
Assets
Commodity derivatives
Financial institutions	$	3		$	909		$	—	$	(323	)	$	(52	)	$	537
Other counterparties		—			168			—		(51	)		—			117
Total derivative assets	$	3		$	1,077		$	—	$	(374	)	$	(52	)	$	654
Liabilities
Commodity derivatives
Financial institutions	$	(4	)	$	(375	)	$	—	$	361		$	7		$	(11	)
Other counterparties		—			(39	)		—		13			—			(26	)
Interest-rate and other derivatives		—			(1,199	)		—		—			130			(1,069	)
Total derivative liabilities	$	(4	)	$	(1,613	)	$	—	$	374		$	137		$	(1,106	)

⁽¹⁾  Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

13

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7.  Debt and Interest Expense

Debt  All of the Company’s outstanding debt is senior unsecured, except for borrowings under the $5.0 billion Facility. The following presents the Company’s outstanding debt:

millions	June 30,         2012			December 31,   2011
Long-term notes and debentures	$	15,521		$	16,452
WES borrowings		1,020			500
Total debt at face value	$	16,541		$	16,952
Net unamortized discounts and premiums (1)		(1,709	)		(1,722	)
Total borrowings	$	14,832		$	15,230
Less: Current portion of long-term debt		1,739			170
Total long-term debt	$	13,093		$	15,060

⁽¹⁾ Unamortized discounts and premiums are amortized over the term of the related debt.

Fair Value  The Company uses a market approach to determine fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. At June 30, 2012, and December 31, 2011, the estimated fair value of the Company’s total borrowings was $17.1 billion and $17.3 billion, respectively.

Debt Activity  The following presents the Company’s debt activity during the six months ended June 30, 2012.

millions	Carrying         Value			Description
Balance at December 31, 2011	$	15,230
Borrowings		319		WES revolving credit facility
Repayments		(131	)	6.125% Senior Notes due 2012
		(40	)	WES revolving credit facility
Other, net		8		Changes in debt premium or discount
Balance at March 31, 2012	$	15,386
Issuance		516		WES 4.00% Senior Notes due 2022
Borrowings		55		WES revolving credit facility
Repayments		(800	)	$5.0 billion Facility
		(334	)	WES revolving credit facility
Other, net		9		Changes in debt premium or discount
Balance at June 30, 2012	$	14,832

Anadarko Revolving Credit Facility and Letter of Credit Facility  At June 30, 2012, the Company was in compliance with all applicable covenants contained in the $5.0 billion Facility, had outstanding borrowings of $1.7 billion at an interest rate of 1.75%, and had available borrowing capacity of $3.2 billion ($5.0 billion maximum capacity, less $1.7 billion of outstanding borrowings and $150 million of letter-of-credit capacity required to be maintained pursuant to the terms of the LOC Facility discussed below). The Company intends to repay the outstanding borrowings under the $5.0 billion Facility with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute within the next year and has classified these borrowings as current portion of long-term debt on the Company’s Consolidated Balance Sheet at June 30, 2012.

14

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7.  Debt and Interest Expense (Continued)

In 2011, the Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit. In June 2012, the agreement was amended to reduce the amount of letters of credit to a maximum of $150 million (LOC Facility). Compensating balances deposited with the financial institution provide for reduced fees under the LOC Facility. These compensating balances may be withdrawn at any time, resulting in higher fees. At June 30, 2012, cash and cash equivalents includes $23 million of demand deposits serving as compensating balances for outstanding letters of credit.

WES Revolving Credit Facility  In the second quarter of 2012, WES repaid all outstanding borrowings under its five-year $800 million senior unsecured revolving credit facility (RCF) with net proceeds from its public offering of $520 million aggregate principal amount of 4.00% Senior Notes due 2022. At June 30, 2012, WES was in compliance with all covenants contained in the RCF.

Interest Expense  The following summarizes the amounts included in interest expense.

	Three Months Ended     June 30,						Six Months Ended          June 30,
millions	2012			2011			2012			2011
Current debt, long-term debt, and other	$	236		$	250		$	486		$	498
Capitalized interest		(46	)		(34	)		(110	)		(62	)
Total interest expense	$	190		$	216		$	376		$	436

8.  Stockholders’ Equity

The reconciliation between basic and diluted earnings per share attributable to common stockholders is as follows:

	Three Months Ended     June 30,					Six Months Ended          June 30,
millions except per-share amounts	2012			2011		2012		2011
Net income (loss)
Net income (loss) attributable to common stockholders	$	(89	)	$	544	$	2,067	$	760
Less: Distributions on participating securities		—			1		1		1
Less: Undistributed income allocated to participating securities		—			3		12		4
Basic	$	(89	)	$	540	$	2,054	$	755
Diluted	$	(89	)	$	540	$	2,054	$	755
Shares
Average number of common shares outstanding—basic		500			498		499		497
Dilutive effect of stock options and performance-based stock awards		—			2		2		2
Average number of common shares outstanding—diluted		500			500		501		499
Excluded (1)		12			6		5		6
Net income (loss) per common share
Basic	$	(0.18	)	$	1.09	$	4.11	$	1.52
Diluted	$	(0.18	)	$	1.08	$	4.10	$	1.51
Dividends per common share	$	0.09		$	0.09	$	0.18	$	0.18

⁽¹⁾ Inclusion of certain shares would have had an anti-dilutive effect.

15

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9.  Commitments

In January 2012, the Company entered into a two-and-a-half-year lease agreement for a deepwater drilling rig expected to be delivered in late 2012. In July 2012, the Company entered into a three-year lease agreement for a deepwater drilling rig expected to be delivered in late 2013. These lease obligations total approximately $875 million, with aggregate future annual minimum lease payments of $13 million in 2012, $192 million in 2013, $317 million in 2014, $228 million in 2015, and $125 million in 2016.

10.   Contingencies

General  The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims, title disputes, tax disputes, royalty claims, contract claims, oil-field contamination claims, and environmental claims, including claims involving assets owned by acquired companies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

The following discussion of the Company’s contingencies includes material developments with respect to matters previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011. There have been no new significant matters since the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

Deepwater Horizon Events  In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% non-operated interest. In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify, relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against claims and damages arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and other potential damages. This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-upon amount, BP p.l.c. has agreed to become the sole guarantor. The Settlement Agreement does not indemnify Anadarko against potential fines, penalties, or punitive damages. The Company has not recorded a liability for any costs that are subject to indemnification by BP. For additional disclosure of the Deepwater Horizon events, the Company’s Settlement Agreement with BP, environmental claims under OPA, NRD claims, potential penalties and fines, and civil litigation, see Note 2—Deepwater Horizon Events in the Notes to the Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

Penalties and Fines  In December 2010, the U.S. Department of Justice, on behalf of the United States, filed a civil lawsuit in the U.S. District Court in New Orleans, Louisiana (Louisiana District Court) against several parties, including Anadarko Petroleum Corporation and Anadarko E&P Company LP (AE&P), a subsidiary of Anadarko, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. In February 2012, the Louisiana District Court entered a declaratory judgment that, as a partial owner of the Macondo well, Anadarko is liable for civil penalties under Section 311 of the CWA and denied both the Company’s and the United States’ motions for summary judgment with respect to the liability of AE&P. The declaratory judgment addresses liability only, and does not address the amount of any civil penalty. In February 2012, the Louisiana District Court entered a stipulated order (Stipulated Order), agreed to by the Company and the United States, that the United States will not assert any claim for a CWA penalty against AE&P, and that the United States will not assert any other theories of liability under the CWA (e.g., operator or person-in-charge liability) against either Anadarko or AE&P. Further, the Stipulated Order reserved the issue of an assessment of a civil penalty against Anadarko until a later proceeding to be scheduled by the Louisiana District Court. The Company believes that the Stipulated Order does not have a material impact on Anadarko’s potential liability.

16

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10.   Contingencies (Continued)

As discussed below, numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. Certain state and local governments have appealed, or have provided indication of a likely appeal of the Louisiana District Court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. If such an appeal is successful, state and/or local laws and regulations could become sources of penalties or fines against the Company.

Applicable accounting guidance requires the Company to accrue a liability if it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. The Louisiana District Court’s declaratory judgment in February 2012, satisfies the requirement that a loss, arising from the future assessment of a civil penalty against Anadarko, is probable. Notwithstanding, the Company currently cannot estimate the amount of any potential civil penalty. The CWA sets forth subjective criteria, including degree of fault and history of prior violations, which significantly influence the magnitude of CWA penalty assessments. As a result of the subjective nature of CWA penalty assessments, the Company currently cannot estimate the amount of any such penalty. Furthermore, the February 2012 settlement of Deepwater Horizon-related civil penalties (including those under the CWA) by the other non-operating partner with the United States and five affected Gulf states (Texas, Louisiana, Mississippi, Alabama, and Florida) does not affect the Company’s current conclusion regarding its ability to estimate potential fines and penalties. The Company lacks insight into those settlement discussions, retains legal counsel separate from the other non-operating party, and was not involved in any manner with respect to that settlement.

Given the Company’s lack of direct operational involvement in the event, as confirmed by the Louisiana District Court, and the subjective criteria of the CWA, the Company believes that its exposure to CWA penalties will not materially impact the Company’s consolidated financial position, results of operations, or cash flows.

Civil Litigation Damage Claims  Numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court. Only OPA claims seeking economic loss damages against the Company remain. In addition, certain state and local governments have appealed, or have provided indication of a likely appeal of, the MDL court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages, irrespective of whether such claims are based on federal (including OPA) or state law.

The Louisiana District Court plans to hold a trial in Transocean’s Limitation of Liability case in the MDL. The first phase of the trial is to determine certain liability issues and the liability allocation among the parties alleged to be involved in or liable for the Deepwater Horizon events. In March 2012, BP and the Plaintiffs’ Steering Committee (PSC) entered into a tentative settlement agreement to resolve the substantial majority of economic loss and medical claims stemming from the Deepwater Horizon events. In light of this settlement agreement, the Louisiana District Court postponed the start of the trial until a future date and requested that the parties submit separate briefs that explain the parties’ opinions as to the impact of the tentative settlement on the Louisiana District Court’s previously issued trial plan. BP and the PSC jointly filed the proposed settlement agreement with the Louisiana District Court in April 2012. In May 2012, the Louisiana District Court issued its revised case management order (CMO) ruling that the first phase of the trial will commence in January 2013, and will address issues arising out of the conduct of various parties involved with the Deepwater Horizon events. The CMO provides that the Stipulated Order excusing Anadarko from participation in the first phase of the trial remains in effect. The CMO also provides that the second phase of trial will follow the first phase after a two-to-three week recess and will address source-control and qualification issues.

Two separate class action complaints were filed in June and August 2010, in the U.S. District Court for the Southern District of New York (New York District Court) on behalf of purported purchasers of the Company’s stock between June 9, 2009, and June 12, 2010, against Anadarko and certain of its officers. The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 (Exchange Act) for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. In March 2012, the New York District Court granted the Lead Plaintiff’s motion to transfer venue to the U.S. District Court for the Southern District of Texas – Houston Division (Texas District Court). In May 2012, the Texas District Court granted the defendants’ motion to transfer the consolidated action within the district to Judge Keith P. Ellis.

17

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10.   Contingencies (Continued)

In November 2011, the Company’s Board of Directors (Board) received a letter from a purported shareholder demanding that the Board investigate, address, remedy, and commence derivative proceedings against certain officers and directors for their alleged breach of fiduciary duty related to the Deepwater Horizon events. The Board has considered this demand and in February 2012 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter. In March 2012, the Company’s Board received a similar demand letter from a purported shareholder supplementing an original demand that had been made by the shareholder in September 2010 related to the Deepwater Horizon events. The Board has considered this demand and in April 2012 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter.

Given the various stages of these proceedings, the Company currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses, related to ongoing proceedings. The Company intends to vigorously defend itself, its officers, and its directors in each of these proceedings, and will avail itself of any and all indemnities provided by BP against civil damages.

Remaining Liability Outlook  It is reasonably possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential fines and penalties, shareholder claims, and certain other claims not covered by the indemnification provisions of the Settlement Agreement; however, the Company does not believe that any potential liability attributable to the foregoing items, individually or in the aggregate, will have a material impact on the Company’s consolidated financial position, results of operations, or cash flows. This assessment takes into account certain qualitative factors, including the subjective and fault-based nature of CWA penalties, the Company’s indemnification by BP against certain damage claims as discussed above, BP’s creditworthiness, the merits of the shareholder claims, and directors and officers insurance coverage related to outstanding shareholder claims.

The Company will continue to monitor the MDL and other legal proceedings discussed above as well as federal investigations related to the Deepwater Horizon events, including review of the preliminary investigatory findings recently announced by the U.S. Chemical Safety Board. The Company cannot predict the nature of evidence that may be discovered during the course of legal proceedings and investigations, the timing of discovery, or the timing of completion of any legal proceedings or investigations.

Although the Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and certain other potential liabilities, the Company may be required to recognize a liability for these amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c.

Tronox Litigation  In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee and seeks, among other things, to recover damages, including interest, in excess of $18.9 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. In accordance with Tronox’s Plan of Reorganization, the Adversary Proceeding is being prosecuted by the Anadarko Litigation Trust. Pursuant to the Anadarko Litigation Trust Agreement, the Anadarko Litigation Trust was “deemed substituted” for Tronox in the Adversary Proceeding as the party in such litigation. For purposes of this Form 10-Q, references to “Tronox” after February 2011 refer to the Anadarko Litigation Trust. For additional disclosure related to the Tronox Litigation, see Note 16—Contingencies—Tronox Litigation in the Notes to the Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

The U.S. government was granted authority to intervene in the Adversary Proceeding, and in May 2009 asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act (FDCPA Complaint). In April 2012, Anadarko and Kerr-McGee filed an answer to the FDCPA Complaint.

18

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10.   Contingencies (Continued)

In February 2012, the Company filed a motion for partial summary judgment seeking dismissal of several claims, including all actual and constructive fraudulent transfer claims protected by Section 546(e) of the U.S. Bankruptcy Code. The court has not yet ruled on that issue. Trial began in May 2012 and is expected to last through September 2012.

The Company’s recent attempts to resolve the Adversary Proceeding through mediation and settlement discussions have reached an impasse and at this time the Company believes the likelihood of settlement is remote. The Company now considers litigation the probable form of final resolution of the Adversary Proceeding. Previously, the Company believed it probable that the parties would reach a settlement on reasonable terms and thus the Company considered a loss, via settlement, related to the Adversary Proceeding probable. Based on this assumption, a $275 million loss contingency was accrued in the first quarter of 2012, which increased the Company’s total estimated contingent loss accrual related to the Adversary Proceeding to $525 million as of March 31, 2012. Due to the change in the Company’s opinion as to the probable form of resolution of this matter, the Company reversed the settlement-based $525 million contingent loss accrual related to this matter in the second quarter of 2012.

The Company remains confident in the merits of its position, and continues to vigorously defend the claims asserted in the Adversary Proceeding. The Company does not believe a loss resulting from litigating the Adversary Proceeding is probable. Accounting guidance requires that contingent losses be probable in nature for loss recognition to be appropriate. Accordingly, the Company’s Consolidated Balance Sheet as of June 30, 2012, does not include a loss-contingency liability related to the litigation of the Adversary Proceeding.

Although the Company does not consider a loss related to the litigation of the Adversary Proceeding probable, it is reasonably possible that the Company could incur a loss as a result of litigating this matter. Despite the plaintiffs’ damage claims in excess of $18.9 billion, the Company currently believes a reasonable range of potential loss is zero to $1.4 billion. The low end of the Company’s estimated range of potential loss is based on the Company’s current belief that it will more likely than not prevail in defending against the claims asserted in the Adversary Proceeding. The high end of the Company’s estimated range of potential loss represents the amount of consideration received by Kerr-McGee at the time of the Tronox spin-off, approximately $985 million, plus interest thereon.

The Company’s estimated range of potential loss is based on the Company’s opinion regarding the current status of and likelihood of final resolution through litigation and could change as a result of developments in the Adversary Proceeding, or if the likelihood of settlement ceases to be remote. The Company’s ultimate financial obligation resulting from resolution of the Adversary Proceeding could vary, perhaps materially, from the Company’s above-stated estimated range of potential loss.

Separately, in July 2009, a consolidated class action complaint was filed in the New York District Court on behalf of purported purchasers of Tronox’s equity and debt securities between November 21, 2005, and January 12, 2009, against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors, and Ernst & Young LLP (Securities Case). The complaint alleges causes of action arising under Sections 10(b) and 20(a) of the Exchange Act for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort-claim liabilities. The plaintiffs allege, among other things, that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including filings made in connection with Tronox’s initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. Certain parties, including Anadarko, Kerr-McGee, and the former Kerr-McGee officers and directors, reached a tentative settlement in this matter in April 2012, subject to approval by the court. The tentative settlement amount will be directly funded by the insurers for Tronox, Anadarko, and Kerr-McGee. As a result, offsetting gains and losses have been recorded to reflect the impact of the tentative settlement of the Securities Case.

19

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10.   Contingencies (Continued)

Other Litigation  In December 2008, Anadarko sold its interest in the Peregrino heavy-oil field offshore Brazil. The Company is currently litigating a dispute with the Brazilian tax authorities regarding the tax rate applicable to the transaction. Currently, $169 million, the amount of tax in dispute, resides in a judicially controlled Brazilian bank account, pending final resolution of the matter and is included in other assets on the Company’s Consolidated Balance Sheet as of June 30, 2012.

In July 2009, the lower judicial court ruled in favor of the Brazilian tax authorities. The Company appealed this decision to the Brazilian Regional courts, which upheld the lower court’s ruling in favor of the Brazilian tax authorities in December 2011. In April 2012, the Company filed simultaneous appeals to the Brazilian Superior court and the Brazilian Supreme court. The Brazilian Supreme court is not required to hear the case.

The Company believes that it will, more likely than not, prevail in Brazilian courts. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation as of June 30, 2012. The Company continues to vigorously defend itself in Brazilian courts.

Deepwater Drilling Moratorium and Other Related Matters  In June 2010, as a result of the moratorium on drilling in the Gulf of Mexico between mid-May 2010 and mid-October 2010 (Moratorium), the Company gave written notice of termination to a drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit in the Texas District Court against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on June 19, 2010. The drilling contractor filed an Original Answer in July 2010 denying the Moratorium constituted a force majeure event and asserting that Anadarko had breached the drilling contract. In the second quarter of 2012, the Company and the drilling contractor mutually agreed to dismiss all claims related to this dispute. The resolution of this dispute did not have a material impact on Anadarko’s consolidated financial position, results of operations, or cash flows.

Algeria Exceptional Profits Tax Settlement  In 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production and issued regulations implementing this legislation. The Company notified Sonatrach of the Company’s disagreement with Sonatrach’s collection of the exceptional profits tax and initiated arbitration against Sonatrach in February 2009. The arbitration hearing was held in June 2011.

In March 2012, Anadarko reached an agreement with Sonatrach to resolve the exceptional profits tax dispute. The agreement was approved by the Algerian government and provides for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period which began in June 2012. At June 30, 2012, a receivable of $1.6 billion on the Company’s Consolidated Balance Sheet was included in the oil and gas exploration and production reporting segment. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for the six months ended June 30, 2012, to reflect the effect of this agreement on previously recorded expenses. Additionally, the parties agreed to an amendment to the existing Production Sharing Agreement (PSA) that provides the Company increased sales volumes in future periods. The amendment also confirms the duration for each exploitation license granted under the PSA will be 25 years from the date the license was awarded.

20

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11.   Income Taxes

The following is a summary of income tax expense (benefit) and effective tax rates.

	Three Months Ended June 30,				Six Months Ended June 30,
millions except percentages	2012		2011		2012		2011
Income tax expense (benefit)	$	164	$	440	$	516	$	706
Effective tax rate		174%		44%		20%		47%

The increase from the 35% U.S. federal statutory rate for the three months ended June 30, 2012, was primarily attributable to the foreign tax rate differential and valuation allowances, recurring accrual of the Algerian exceptional profits tax, and U.S. tax impact from losses and restructuring of foreign operations. The decrease from the 35% U.S. federal statutory rate for the six months ended June 30, 2012, was primarily attributable to the resolution of the Algeria exceptional profits tax dispute. This amount was partially offset by the foreign tax rate differential and valuation allowances, recurring accrual of the Algerian exceptional profits tax, and U.S. tax impact from losses and restructuring of foreign operations.

The increase from the 35% U.S. federal statutory rate for the three and six months ended June 30, 2011, was primarily attributable to the recurring accrual of the Algerian exceptional profits tax, foreign tax rate differential and valuation allowances, U.S. tax on foreign income inclusions and distributions, state income taxes, and items resulting from business acquisitions. These items were partially offset by the U.S. income tax benefits associated with foreign losses and restructuring of foreign operations.

12.   Supplemental Cash Flow Information

The following presents cash paid (received) for interest (net of amounts capitalized) and income taxes, as well as non-cash investing transactions.

	Six Months Ended       June 30,
millions	2012			2011
Cash paid (received)
Interest	$	354		$	415
Income taxes	$	(40	)	$	82
Non-cash investing activities
Fair value of properties and equipment received in non-cash exchange transactions	$	31		$	4
Gain related to the fair-value remeasurement of Anadarko’s pre-acquisition 7% equity interest in the Wattenberg Plant	$	—		$	21

13.   Segment Information

Anadarko’s business segments are separately managed due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company’s three reporting segments are oil and gas exploration and production, midstream, and marketing. The oil and gas exploration and production segment explores for and produces natural gas, crude oil, condensate, and NGLs. The midstream segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production. The midstream reporting segment consists of two operating segments, WES and other midstream activities, which are aggregated into one reporting segment due to similar financial and operating characteristics. The marketing segment sells most of Anadarko’s production, as well as third-party purchased volumes.

21

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

13.   Segment Information (Continued)

To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes income (loss) before income taxes; interest expense; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; Deepwater Horizon settlement and related costs; Algeria exceptional profits tax settlement; Tronox-related contingent loss; unrealized (gains) losses on derivatives, net; and realized (gains) losses on other derivatives, net, less net income attributable to noncontrolling interests (Adjusted EBITDAX). The Company’s definition of Adjusted EBITDAX excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Adjusted EBITDAX also excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Anadarko’s definition of Adjusted EBITDAX excludes Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, and Tronox-related contingent loss, as these costs are outside the normal operations of the Company. See Note 10—Contingencies. Finally, unrealized (gains) losses on derivatives, net and realized (gains) losses on other derivatives, net are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders.

Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income or cash flows from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes.

	Three Months Ended       June 30,						Six Months Ended       June 30,
millions	2012			2011			2012			2011
Income (loss) before income taxes	$	94		$	1,002		$	2,629		$	1,505
Exploration expense		1,121			236			1,365			415
DD&A		1,027			985			1,957			1,970
Impairments		112			102			162			104
Deepwater Horizon settlement and related costs (1)		3			9			11			35
Algeria exceptional profits tax settlement (2)		—			—			(1,804	)		—
Tronox-related contingent loss (2)		(525	)		—			(250	)		—
Interest expense		190			216			376			436
Unrealized (gains) losses on derivatives, net		225			(178	)		83			75
Realized (gains) losses on other derivatives, net (2)		2			2			2			2
Less: Net income attributable to noncontrolling interests		19			18			46			39
Consolidated Adjusted EBITDAX	$	2,230		$	2,356		$	4,485		$	4,503

⁽¹⁾  In the third quarter of 2011, the Company revised the definition of Adjusted EBITDAX to exclude Deepwater Horizon settlement and related costs. Prior periods have been adjusted to reflect this change.

⁽²⁾  In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. Prior periods have been adjusted to reflect this change.

22

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

13.   Segment Information (Continued)

The following presents selected financial information for Anadarko’s reporting segments. Information presented below as “Other and Intersegment Eliminations” includes results from hard-minerals non-operated joint ventures and royalty arrangements, and corporate, financing, and certain hedging activities.

millions	Oil and Gas Exploration & Production			Midstream			Marketing			Other and  Intersegment  Eliminations			Total
Three Months Ended June 30, 2012
Sales revenues	$	1,888		$	81		$	1,231		$	—		$	3,200
Intersegment revenues		1,035			220			(1,124	)		(131	)		—
Gains (losses) on divestitures and other, net		(12	)		(1	)		—			35			22
Total revenues and other		2,911			300			107			(96	)		3,222
Operating costs and expenses (1)		873			174			158			33			1,238
Realized (gains) losses on commodity derivatives, net		—			—			—			(263	)		(263	)
Other (income) expense, net (2)		—			—			—			6			6
Net income attributable to noncontrolling interests		—			19			—			—			19
Total expenses and other		873			193			158			(224	)		1,000
Unrealized (gains) losses on derivatives, net included in marketing revenue		—			—			8			—			8
Adjusted EBITDAX	$	2,038		$	107		$	(43	)	$	128		$	2,230
Three Months Ended June 30, 2011
Sales revenues	$	2,071		$	98		$	1,565		$	—		$	3,734
Intersegment revenues		1,330			223			(1,448	)		(105	)		—
Gains (losses) on divestitures and other, net		(114	)		20			—			36			(58	)
Total revenues and other		3,287			341			117			(69	)		3,676
Operating costs and expenses (1)		921			199			135			88			1,343
Realized (gains) losses on commodity derivatives, net		—			—			—			(27	)		(27	)
Other (income) expense, net (2)		—			—			—			(18	)		(18	)
Net income attributable to noncontrolling interests		—			18			—			—			18
Total expenses and other		921			217			135			43			1,316
Unrealized (gains) losses on derivatives, net included in marketing revenue		—			—			(4	)		—			(4	)
Adjusted EBITDAX	$	2,366		$	124		$	(22	)	$	(112	)	$	2,356

⁽¹⁾ Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.

⁽²⁾ Other (income) expense, net excludes Tronox-related contingent loss since this expense is excluded from Adjusted EBITDAX.

23

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

13.   Segment Information (Continued)

millions	Oil and Gas Exploration & Production			Midstream			Marketing			Other and  Intersegment  Eliminations			Total
Six Months Ended June 30, 2012
Sales revenues	$	3,787		$	168		$	2,657		$	—		$	6,612
Intersegment revenues		2,209			469			(2,419	)		(259	)		—
Gains (losses) on divestitures and other, net		(29	)		(2	)		—			88			57
Total revenues and other		5,967			635			238			(171	)		6,669
Operating costs and expenses (1)		1,799			363			312			81			2,555
Realized (gains) losses on commodity derivatives, net		—			—			—			(400	)		(400	)
Other (income) expense, net (2)		—			—			—			(4	)		(4	)
Net income attributable to noncontrolling interests		—			46			—			—			46
Total expenses and other		1,799			409			312			(323	)		2,197
Unrealized (gains) losses on derivatives, net included in marketing revenue		—			—			13			—			13
Adjusted EBITDAX	$	4,168		$	226		$	(61	)	$	152		$	4,485
Six Months Ended June 30, 2011
Sales revenues	$	3,867		$	162		$	2,929		$	—		$	6,958
Intersegment revenues		2,455			433			(2,680	)		(208	)		—
Gains (losses) on divestitures and other, net		(114	)		20			—			65			(29	)
Total revenues and other		6,208			615			249			(143	)		6,929
Operating costs and expenses (1)		1,762			365			271			110			2,508
Realized (gains) losses on commodity derivatives, net		—			—			—			(84	)		(84	)
Other (income) expense, net (2)		—			—			—			(42	)		(42	)
Net income attributable to noncontrolling interests		—			39			—			—			39
Total expenses and other		1,762			404			271			(16	)		2,421
Unrealized (gains) losses on derivatives, net included in marketing revenue		—			—			(5	)		—			(5	)
Adjusted EBITDAX	$	4,446		$	211		$	(27	)	$	(127	)	$	4,503

⁽¹⁾ Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.

⁽²⁾ Other (income) expense, net excludes Tronox-related contingent loss since this expense is excluded from Adjusted EBITDAX.

24

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14.   Pension Plans and Other Postretirement Benefits

The Company has non-contributory U.S. defined-benefit pension plans, including both qualified and supplemental plans, and a foreign contributory defined-benefit pension plan. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree, and in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is noncontributory.

During the six months ended June 30, 2012, the Company made contributions of $32 million to its funded pension plans, $2 million to its unfunded pension plans, and $9 million to its unfunded other postretirement benefit plans. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. During the remainder of 2012, the Company expects to contribute approximately $88 million to its funded pension plans, approximately $32 million to its unfunded pension plans, and approximately $10 million to its unfunded other postretirement benefit plans.

The following sets forth the components of net periodic benefit cost for the Company’s pension and other postretirement benefit plans.

	Pension Benefits						Other Benefits
millions	2012			2011			2012		2011
Three Months Ended June 30
Service cost	$	19		$	19		$	3	$	2
Interest cost		22			22			4		4
Expected return on plan assets		(22	)		(22	)		—		—
Amortization of net actuarial loss (gain)		23			21			—		—
Amortization of net prior service cost (credit)		—			—			1		—
Net periodic benefit cost	$	42		$	40		$	8	$	6
Six Months Ended June 30
Service cost	$	38		$	39		$	5	$	4
Interest cost		43			43			8		8
Expected return on plan assets		(45	)		(43	)		—		—
Amortization of net actuarial loss (gain)		46			42			—		—
Amortization of net prior service cost (credit)		—			1			1		—
Net periodic benefit cost	$	82		$	82		$	14	$	12

25

Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases, and management discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by, or that otherwise include the words “may,” “could,” “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 be correct. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events, or otherwise.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:

• the Company’s assumptions about the energy market;

• production levels;

• reserve levels;

• operating results;

• competitive conditions;

• technology;

• the availability of capital resources, capital expenditures, and other contractual obligations;

• the supply and demand for, the price of, and the commercializing and transporting of natural gas, crude oil, natural gas liquids (NGLs), and other products or services;

• volatility in the commodity-futures market;

• the weather;

• inflation;

• the availability of goods and services;

• drilling risks;

• future processing volumes and pipeline throughput;

• general economic conditions, either internationally or nationally or in the jurisdictions in which the Company or its subsidiaries are doing business;

• legislative or regulatory changes, including retroactive royalty or production tax regimes; hydraulic-fracturing regulation; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation; environmental risks; and liability under federal, state, foreign, and local environmental laws and regulations;

• the ability of BP Exploration & Production Inc. (BP) to meet its indemnification obligations to the Company for, among other things, damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and associated damage-assessment costs, and any claims arising under the Operating Agreement (OA) for the Macondo well, as well as the ability of BP Corporation North America Inc. (BPCNA) and BP p.l.c. to satisfy their guarantees of such indemnification obligations;

26

• the impact of remaining claims related to the Deepwater Horizon events, including, but not limited to, fines, penalties, and punitive damages against which the Company is not indemnified by BP;

• the legislative and regulatory changes that may impact the Company’s Gulf of Mexico and international offshore operations, including those resulting from the Deepwater Horizon events;

• current and potential legal proceedings, or environmental or other obligations related to or arising from Tronox Incorporated (Tronox);

• civil or political unrest in a region or country;

• the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties;

• volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity and interest-rate risk;

• the Company’s ability to successfully monetize select assets, repay its debt, and the impact of changes in the Company’s credit ratings;

• disruptions in international crude oil cargo shipping activities;

• electronic, cyber, and physical security breaches;

• the supply and demand, technological, political, and commercial conditions associated with long-term development and production projects in domestic and international locations; and

• other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in the Company’s 2011 Annual Report on Form 10-K, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management.

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this report in Part I, Item 1, the information set forth in Risk Factors under Part II, Item 1A as well as the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the 2011 Annual Report on Form 10-K, and the information set forth in the Risk Factors under Part I, Item 1A of the 2011 Annual Report on Form 10-K. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

OVERVIEW

Anadarko is among the world’s largest independent exploration and production companies. Anadarko is engaged in the exploration, development, production, and marketing of natural gas, crude oil, condensate, and NGLs. The Company also engages in the gathering, processing, and treating of natural gas, and the transporting of natural gas, crude oil, and NGLs. The Company has production and exploration activities worldwide, including activities in the United States, Algeria, Mozambique, West Africa, China, Brazil, Indonesia, South Africa, and New Zealand.

27

Significant operating and financial activities during the second quarter of 2012 include the following:

Overall

• Anadarko achieved second-quarter sales volumes of 742 thousand barrels of oil equivalent per day (MBOE/d), representing an 8% increase over the second quarter of 2011.

• The Company achieved second-quarter liquids sales volumes of 318 thousand barrels per day (MBbls/d), representing a 7% increase over the second quarter of 2011.

United States Onshore

• The Company’s Rocky Mountains Region (Rockies) achieved second-quarter sales volumes of 317 MBOE/d, representing a 6% increase over the second quarter of 2011, primarily due to increased sales volumes from the Wattenberg field and the Greater Natural Buttes area.

• The Southern and Appalachia Region achieved second-quarter sales volumes of 192 MBOE/d, representing a 37% increase over the second quarter of 2011, primarily due to increased sales volumes from the Eagleford and Marcellus shales.

Gulf of Mexico

• The Company’s Gulf of Mexico second-quarter sales volumes were 133 MBOE/d, representing a 5% decrease from the second quarter of 2011, primarily due to natural production declines, partially offset by the impact of a full quarter of production from Caesar/Tonga.

• The Company successfully drilled the Heidelberg sidetrack appraisal well (44.25% working interest) in Green Canyon Block 903, which defined the down-dip limits of the Heidelberg field.

• The Company participated in the successful drilling of a third Vito appraisal well (18.67% working interest) in the Mississippi Canyon area, encountering approximately 620 net feet of oil pay.

International

• The Company’s International second-quarter sales volumes were 85 MBOE/d, representing a 7% decrease from the second quarter of 2011, primarily due to the timing of cargo liftings in Ghana.

• Offshore Mozambique, the Company successfully drilled the Barquentine-4 appraisal well, as well as the Golfinho and Atum discovery wells (all at 36.5% working interest).

• Offshore Mozambique, the Company successfully tested the Barquentine-1 well (36.5% working interest), achieving an equipment-constrained flow rate of 100 million cubic feet per day (MMcf/d).

• Offshore Côte d’Ivoire, the Company successfully drilled the Paon exploration well (40% working interest), encountering more than 100 net feet of light-oil pay.

Financial

• The Company generated approximately $2.0 billion of cash flows from operations and ended the quarter with $2.8 billion of cash on hand.

• Anadarko’s net loss attributable to common stockholders for the second quarter of 2012 totaled $89 million, which included $844 million for impairments of certain unproved properties.

• The Company repaid $800 million of borrowings under the senior secured revolving credit facility, which matures in September 2015 ($5.0 billion Facility).

• The Company received the first crude-oil delivery related to the resolution of the Algeria exceptional profits tax dispute.

28

The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the three months ended June 30, 2012,” refer to the comparison of the three months ended June 30, 2012, to the three months ended June 30, 2011, and any increases or decreases “for the six months ended June 30, 2012,” refer to the comparison of the six months ended June 30, 2012, to the six months ended June 30, 2011. The primary factors that affect the Company’s results of operations include commodity prices for natural gas, crude oil, and NGLs; sales volumes; the Company’s ability to discover additional oil and natural-gas reserves; the cost of finding such reserves; and operating costs.

RESULTS OF OPERATIONS

Selected Data

	Three Months Ended June 30,						Six Months Ended June 30,
millions except per-share amounts	2012			2011			2012			2011
Financial Results
Revenues and other	$	3,222		$	3,676		$	6,669		$	6,929
Costs and expenses		3,501			2,675			4,246			5,032
Other (income) expense		(373	)		(1	)		(206	)		392
Income tax expense (benefit)		164			440			516			706
Net income (loss) attributable to common stockholders	$	(89	)	$	544		$	2,067		$	760
Net income (loss) per common share attributable to common stockholders—diluted	$	(0.18	)	$	1.08		$	4.10		$	1.51
Average number of common shares outstanding—diluted		500			500			501			499
Operating Results
Adjusted EBITDAX (1)	$	2,230		$	2,356		$	4,485		$	4,503
Sales volumes (MMBOE)		68			62			132			124

MMBOE—millions of barrels of oil equivalent

⁽¹⁾  See Operating Results—Segment Analysis—Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a U.S. Generally Accepted Accounting Principles (GAAP) measure, and a reconciliation of Adjusted EBITDAX to income (loss) before income taxes, which is presented in accordance with GAAP.

FINANCIAL RESULTS

Net Income (Loss) Attributable to Common Stockholders    For the second quarter of 2012, Anadarko’s net loss attributable to common stockholders totaled $89 million, or $0.18 per share (diluted), compared to net income attributable to common stockholders of $544 million, or $1.08 per share (diluted), for the second quarter of 2011. Anadarko’s net loss for the three months ended June 30, 2012, included $844 million for impairments of certain unproved properties. For the six months ended June 30, 2012, Anadarko’s net income attributable to common stockholders totaled $2.1 billion, or $4.10 per share (diluted), compared to net income attributable to common stockholders of $760 million, or $1.51 per share (diluted), for the same period of 2011. As discussed more fully below, Anadarko’s net income for the six months ended June 30, 2012, included $1.8 billion related to the favorable resolution of the exceptional profits tax dispute with Sonatrach and $844 million for impairments of certain unproved properties.

29

Sales Revenues and Volumes

	Three Months Ended June  30,						Six Months Ended June  30,
millions except percentages	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
Sales Revenues
Natural-gas sales	$	496		(43)%	$	870	$	1,069		(38)%	$	1,724
Oil and condensate sales		2,222		(1)		2,236		4,466		10		4,043
Natural-gas liquids sales		282		(24)		370		624		(11)		703
Total	$	3,000		(14)	$	3,476	$	6,159		(5)	$	6,470

Anadarko’s total sales revenues for the three months ended June 30, 2012, decreased primarily due to lower average commodity prices, partially offset by higher sales volumes for all products. Anadarko’s total sales revenues for the six months ended June 30, 2012, decreased primarily due to lower average natural-gas and NGLs prices, partially offset by higher sales volumes for all products and higher average prices for crude oil.

	Three Months Ended June 30,
millions	Natural   Gas			Oil and Condensate			NGLs			Total
2011 sales revenues	$	870		$	2,236		$	370		$	3,476
Changes associated with sales volumes		81			156			22			259
Changes associated with prices		(455	)		(170	)		(110	)		(735	)
2012 sales revenues	$	496		$	2,222		$	282		$	3,000
	Six Months Ended June 30,
	Natural   Gas			Oil and Condensate			NGLs			Total
2011 sales revenues	$	1,724		$	4,043		$	703		$	6,470
Changes associated with sales volumes		91			258			44			393
Changes associated with prices		(746	)		165			(123	)		(704	)
2012 sales revenues	$	1,069		$	4,466		$	624		$	6,159

30

	Three Months Ended June  30,						Six Months Ended June  30,
Sales Volumes	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
Barrels of Oil Equivalent
(MMBOE except percentages)
United States		60		11%		54		116		6%		109
International		8		(7)		8		16		—		15
Total		68		8		62		132		6		124
Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States		657		11%		594		639		6%		602
International		85		(7)		91		84		(2)		86
Total		742		8		685		723		6		688

Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q and Other (Income) Expense—(Gains) Losses on Commodity Derivatives, net. Production of natural gas, crude oil, and NGLs usually is not affected by seasonal swings in demand.

Natural-Gas Sales Volumes, Average Prices, and Revenues

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		Inc/(Dec) vs. 2011	2011		2012		Inc/(Dec) vs. 2011	2011
United States
Sales volumes—Bcf		230	9%		212		450	5%		429
MMcf/d		2,544	9		2,326		2,480	5		2,369
Price per Mcf	$	2.15	(48)	$	4.11	$	2.37	(41)	$	4.02
Natural-gas sales revenues (millions)	$	496	(43)	$	870	$	1,069	(38)	$	1,724

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

The Company’s natural-gas sales volumes increased 218 MMcf/d and 111 MMcf/d for the three and six months ended June 30, 2012, respectively. These increases were due to higher sales volumes in the Southern and Appalachia Region of 229 MMcf/d and 173 MMcf/d, respectively, primarily as a result of drilling in the Marcellus and Eagleford shales, and higher sales volumes in the Rockies of 81 MMcf/d and 65 MMcf/d, respectively, associated with continued drilling in the Greater Natural Buttes area and the Wattenberg field. These increases were largely offset by reduced sales volumes for the three and six months ended June 30, 2012, in the Gulf of Mexico of 92 MMcf/d and 127 MMcf/d, respectively, primarily due to natural production declines.

The average natural-gas price Anadarko received decreased for the three and six months ended June 30, 2012, due to increased domestic production resulting in above-average U.S. natural-gas storage levels.

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Crude-Oil and Condensate Sales Volumes, Average Prices, and Revenues

	Three Months Ended June  30,						Six Months Ended June  30,
	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
United States
Sales volumes—MMBbls		15		16%		12		27		12%		24
MBbls/d		156		16		134		148		12		133
Price per barrel	$	98.20		(6)	$	104.68	$	101.76		4	$	98.23
International
Sales volumes—MMBbls		8		(7)%		8		16		—%		15
MBbls/d		85		(7)		91		84		(2)		86
Price per barrel	$	106.77		(7)	$	115.33	$	113.30		5	$	107.91
Total
Sales volumes—MMBbls		23		7%		20		43		6%		39
MBbls/d		241		7		225		232		6		219
Price per barrel	$	101.22		(7)	$	108.99	$	105.94		4	$	102.04
Oil and condensate sales revenues (millions)	$	2,222		(1)	$	2,236	$	4,466		10	$	4,043

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s crude-oil and condensate sales volumes increased 16 MBbls/d and 13 MBbls/d for the three and six months ended June 30, 2012, respectively. Increased drilling in the Wattenberg field led to sales-volume improvements in the Rockies of 6 MBbls/d for both the three and six months ended June 30, 2012. In addition, for the three and six months ended June 30, 2012, sales volumes in the Gulf of Mexico increased 8 MBbls/d and 2 MBbls/d, respectively, attributable to the start of oil production at Caesar/Tonga in March 2012. Increased activity in the Eagleford shale and Bone Spring/Avalon formations also contributed to increased sales volumes in the Southern and Appalachia Region of 9 MBbls/d and 7 MBbls/d, for the three and six months ended June 30, 2012, respectively. The increase for the three months ended June 30, 2012, was partially offset by lower sales volumes in Ghana of 9 MBbls/d due to the timing of cargo liftings.

Anadarko’s average crude-oil price received decreased for the three months ended June 30, 2012, primarily due to increasing macroeconomic concerns in Europe and China. Anadarko’s average crude-oil price received increased for the six months ended June 30, 2012, due to concerns about potential supply disruptions from political unrest in the Middle East, which more than offset macroeconomic concerns.

32

Natural-Gas Liquids Sales Volumes, Average Prices, and Revenues

	Three Months Ended June 30,						Six Months Ended June 30,
	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
United States
Sales volumes—MMBbls		7		6%		6		14		6%		13
MBbls/d		77		6		72		78		6		74
Price per barrel	$	40.41		(28)	$	56.21	$	43.82		(16)	$	52.47
Natural-gas liquids sales revenues (millions)	$	282		(24)	$	370	$	624		(11)	$	703

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. For the three and six months ended June 30, 2012, the Company’s NGLs sales volumes increased by 5 MBbls/d and 4 MBbls/d, respectively, as a result of drilling in liquids-rich areas, primarily at Wattenberg and Greater Natural Buttes in the Rockies and the Eagleford shale in the Southern and Appalachia Region.

The average NGLs price decreased for the three and six months ended June 30, 2012, primarily due to lower market prices for ethane and propane. The demand for ethane decreased due to several petrochemical plants, the primary feedstock for which is ethane, being offline a portion of the first and second quarter for maintenance and conversion upgrades. Also, mild winter temperatures across much of the United States reduced demand for propane and contributed to above-average levels of propane stockpiles.

Gathering, Processing, and Marketing Margin

	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
Gathering, processing, and marketing sales	$	200		(22)%	$	258	$	453		(7)%	$	488
Gathering, processing, and marketing expenses		178		(13)		205		367		(2)		376
Margin	$	22		(58)	$	53	$	86		(23)	$	112

For the three and six months ended June 30, 2012, the gathering, processing, and marketing margin decreased primarily due to lower commodity prices, which led to reduced natural-gas processing margins. Also, for the six months ended June 30, 2012, marketing margins decreased due to lower margins on sales from inventory caused by lower prices and volumes, as well as a write-down of natural-gas inventory to market value. These decreases for the three and six months ended June 30, 2012, were partially offset by an increase in gathering and processing revenues associated with increased throughput volumes across several of Anadarko’s fee-based systems, and additional margin provided by midstream assets acquired in February 2011 and May 2011.

Gains (Losses) on Divestitures and Other, net

Losses on divestitures during the three and six months ended June 30, 2012, were $12 million and $29 million, respectively, primarily related to oil and gas exploration and production reporting segment domestic properties. Gains (losses) on divestitures for the three and six months ended June 30, 2011, included a loss of $76 million related to the effective termination of natural-gas processing contracts between the Company and the previous owner of the Wattenberg Plant, which occurred in connection with the Company’s purchase of the plant. The loss represents the aggregate amount by which the Company’s contracts with the previous owner of the Wattenberg Plant were unfavorable as compared to current market transactions for the same or similar services at the date of the Company’s acquisition of the plant. This loss was partially offset by the recognition of a $21 million gain from the acquisition-date fair-value remeasurement of the Company’s pre-acquisition equity interest in the Wattenberg Plant.

33

Costs and Expenses

	Three Months Ended June 30,						Six Months Ended June 30,
	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
Oil and gas operating (millions)	$	249		6%	$	236	$	491		5%	$	468
Oil and gas operating—per BOE		3.68		(3)		3.79		3.73		(1)		3.76
Oil and gas transportation and other (millions)		223		8		207		463		11		416
Oil and gas transportation and other—per BOE		3.30		(1)		3.32		3.51		5		3.35

For the three and six months ended June 30, 2012, oil and gas operating expenses increased by $13 million and $23 million, respectively. For the three and six months ended June 30, 2012, operating expenses increased $21 million and $33 million, respectively, due to increased activity in Ghana and the Bone Spring/Avalon formations. Also, for the three and six months ended June 30, 2012, water-handling costs increased $5 million and $8 million, respectively, primarily due to increased activity in the Rockies, and surface maintenance costs increased $7 million for the six months ended June 30, 2012, primarily due to increased activity in the Gulf of Mexico. Partially offsetting these increases were lower costs for workovers of $16 million and $24 million for the three and six months ended June 30, 2012, respectively, primarily in the Rockies and the Gulf of Mexico. For the three and six months ended June 30, 2012, oil and gas operating expenses per barrel of oil equivalent (BOE) decreased by $0.11 and $0.03, respectively, primarily due to increased operating efficiencies and increased sales volumes.

For the three and six months ended June 30, 2012, oil and gas transportation and other expenses increased by $16 million and $47 million, respectively, primarily due to higher gas gathering and transportation costs attributable to higher volumes and increased costs attributable to growth in the Company’s U.S. onshore asset base. This increase was partially offset by a reversal of $25 million of previously accrued rig termination fees for a deepwater drilling rig in the Gulf of Mexico. This expense reversal resulted from a dispute settlement with the drilling contractor. See Note 10—Contingencies—Deepwater Drilling Moratorium and Other Related Matters in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information. Oil and gas transportation and other expenses per BOE decreased by $0.02 for the three months ended June 30, 2012, primarily due to increased sales volumes and the reversal of rig termination fees. Oil and gas transportation and other expenses per BOE increased by $0.16 for the six months ended June 30, 2012, primarily due to the higher costs discussed above.

34

	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
Exploration Expense
Dry hole expense	$	115		174%	$	42	$	204		NM	$	58
Impairments of unproved properties		923		NM		95		983		NM		169
Geological and geophysical expenses		14		(73)		52		49		(51)%		100
Exploration overhead and other		69		47		47		129		47		88
Total exploration expense	$	1,121		NM	$	236	$	1,365		NM	$	415

NM—percentage change does not provide

meaningful information

Exploration expense increased by $885 million and $950 million for the three and six months ended June 30, 2012, respectively. During the second quarter of 2012, the Company recognized $844 million for impairments of certain unproved properties in the Rockies and the Gulf of Mexico. Approximately $720 million was associated with the impairment of unproved Powder River coalbed methane properties in the Rockies primarily due to lower natural-gas prices. The Company also recognized $124 million associated with an unproved Gulf of Mexico natural-gas property due to a reduction of estimated recoverable reserves as a result of the forecasted natural-gas price environment. This Gulf of Mexico property is located on a lease that is close to expiration and the Company does not plan to pursue the exploitation of this property under the forecasted natural-gas price environment. The remaining increases of $41 million and $106 million for the three and six months ended June 30, 2012, respectively, were primarily due to higher dry hole expense of $73 million and $146 million, respectively, primarily in Sierra Leone, Côte d’Ivoire, and the Gulf of Mexico, which were partially offset by lower geological and geophysical expense of $38 million and $51 million, respectively, primarily due to fewer seismic purchases in the Gulf of Mexico, Mozambique, Kenya, and Liberia.

	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
General and administrative	$	262		(7)%	$	282	$	531		8%	$	491
Depreciation, depletion, and amortization		1,027		4		985		1,957		(1)		1,970
Other taxes		326		(21)		413		703		(7)		757
Impairments		112		10		102		162		56		104

For the three months ended June 30, 2012, general and administrative (G&A) expense decreased by $20 million primarily due to consulting fees of $16 million incurred during the second quarter of 2011 related to the Maverick basin joint venture. For the six months ended June 30, 2012, G&A expense increased $40 million primarily due to legal-related expenses. The increase was partially offset by lower consulting fees of $16 million as discussed above and decreased insurance costs of $11 million due to lower premiums for directors and officers insurance in 2012.

For the three months ended June 30, 2012, depreciation, depletion, and amortization (DD&A) expense increased by $42 million due to higher sales volumes, the start of production at Caesar/Tonga in March 2012, and the accelerated depletion of a natural-gas field in the Gulf of Mexico, partially offset by lower per-barrel DD&A rates resulting from asset impairments recorded in the fourth quarter of 2011 and reserve additions at the Eagleford shale. For the six months ended June 30, 2012, DD&A expense decreased by $13 million due to lower per-barrel DD&A rates related to the 2011 asset impairments and reserve additions at the Eagleford shale, partially offset by higher sales volumes.

35

For the three and six months ended June 30, 2012, other taxes decreased by $87 million and $54 million, respectively, primarily related to lower Algeria exceptional profits taxes of $60 million and $45 million, respectively, due to a lower Algeria effective tax rate resulting from the resolution of the exceptional profits tax dispute with Sonatrach. Other taxes were also lower for the three and six months ended June 30, 2012, due to decreased U.S. production and severance taxes of $24 million and $10 million, respectively, primarily due to lower natural-gas prices.

Impairment expense for the three and six months ended June 30, 2012, was $112 million and $162 million, respectively. In the second quarter of 2012, due to lower natural-gas prices, the Company recognized impairments of $79 million related to certain onshore domestic oil and gas exploration and production reporting segment properties and $4 million related to midstream reporting segment properties. The Company also recognized impairments of $50 million and $17 million during the first and second quarter of 2012, respectively, related to downward reserves revisions for a Gulf of Mexico property that is near the end of its economic life. Also in the second quarter of 2012, the Company recognized impairment expense of $11 million related to the Company’s investment in Venezuelan assets due to declines in estimated recoverable reserves and lower crude-oil prices. Impairment expense for the three and six months ended June 30, 2011, was $102 million and $104 million, respectively, including $100 million recognized in the second quarter of 2011 related to onshore domestic oil and gas exploration and production reporting segment properties due to a change in projected cash flows resulting from the Company’s intent to divest of the properties.

	Three Months Ended June  30,						Six Months Ended June 30,
millions except percentages	2012		Inc/(Dec) vs. 2011		2011		2012			Inc/(Dec) vs. 2011		2011
Algeria exceptional profits tax settlement	$	—		NM	$	—		$  (1,804	)		NM	$	—
Deepwater Horizon settlement and related costs		3		(67)%		9		11			(69)%		35

In March 2012, Anadarko reached an agreement with Sonatrach to resolve the exceptional profits tax dispute. The agreement was approved by the Algerian government and provides for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period that began in June 2012. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income in the first quarter of 2012 to reflect the effect of this agreement on previously recorded expenses. The Company expects to receive approximately $1.0 billion from the sale of the crude oil during 2012 and the balance in the first half of 2013. Additionally, the parties agreed to an amendment to the existing Production Sharing Agreement (PSA) that provides the Company increased sales volumes and a lower effective exceptional profits tax rate in future periods. The amendment also confirms the duration for each exploitation license granted under the PSA will be 25 years from the date the license was awarded.

For the three and six months ended June 30, 2012, Deepwater Horizon settlement and related costs decreased by $6 million and $24 million, respectively, due to lower legal expenses and related costs associated with the Deepwater Horizon events. See Note 10—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.

36

Other (Income) Expense

	Three Months Ended                  June 30,								Six Months Ended                      June 30,
millions except percentages	2012			Inc/(Dec) vs. 2011		2011			2012			Inc/(Dec) vs. 2011		2011
Interest Expense
Current debt, long-term debt, and other	$	236			(6)%	$	250		$	486			(2)%	$	498
Capitalized interest		(46	)		(35)		(34	)		(110	)		(77)		(62	)
Total interest expense	$	190			(12)	$	216		$	376			(14)	$	436

For the three and six months ended June 30, 2012, interest expense decreased by $26 million and $60 million, respectively, primarily due to an increase in capitalized interest of $13 million and $49 million, respectively, related to higher construction-in-progress balances for long-term capital projects. Additionally, interest expense for the three and six months ended June 30, 2012, decreased $9 million and $17 million, respectively, as a result of interest incurred during 2011 related to the Company’s capital lease obligation for a floating production, storage, and offloading vessel for the Company’s Jubilee field operations in Ghana. In December 2011, the Company and its partners in the Jubilee project purchased the vessel, resulting in cancellation of the capital lease obligation. Also, for the three and six months ended June 30, 2012, interest expense decreased $5 million and $15 million, respectively, due to lower fees on issued letters of credit and unused credit-facility commitment fees, as well as other items. These items were partially offset by interest expense of $9 million and $21 million related to borrowings under the $5.0 billion Facility for the three and six months ended June 30, 2012, respectively. For additional information regarding the Company’s financing activities, see Liquidity and Capital Resources.

	Three Months Ended                  June 30,								Six Months Ended                      June 30,
millions except percentages	2012			Inc/(Dec) vs. 2011		2011			2012			Inc/(Dec) vs. 2011		2011
(Gains) Losses on Commodity Derivatives, net
Realized (gains) losses
Natural gas	$	(224	)		NM	$	(71	)	$	(394	)		176%	$	(143	)
Oil and condensate		(36	)		182%		44			(3	)		105		59
Natural gas liquids		(3	)		NM		—			(3	)		NM		—
Total realized (gains) losses		(263	)		NM		(27	)		(400	)		NM		(84	)
Unrealized (gains) losses
Natural gas		288			NM		14			202			NM		61
Oil and condensate		(414	)		25		(330	)		(241	)		NM		(64	)
Natural gas liquids		(31	)		NM		—			(29	)		NM		—
Total unrealized (gains) losses		(157	)		(50)		(316	)		(68	)		NM		(3	)
Total (gains) losses on commodity derivatives, net	$	(420	)		22	$	(343	)	$	(468	)		NM	$	(87	)

The Company enters into commodity derivatives to manage the risk of a decrease in the market prices for its anticipated sales of production. The change in (gains) losses on commodity derivatives, net includes the impact of changes in fair value of open positions at June 30 of each year and changes in fair value of derivatives entered into or settled within each period. For additional information on (gains) losses on commodity derivatives, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

37

	Three Months Ended                  June 30,						Six Months Ended                      June 30,
millions except percentages	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
(Gains) Losses on Other Derivatives, net
Realized (gains) losses—interest-rate derivatives and other	$	2		—%	$	2	$	2		—%	$	2
Unrealized (gains) losses—interest-rate derivatives and other		374		(163)		142		138		(66)		83
Total (gains) losses on other derivatives, net	$	376		(161)	$	144	$	140		(65)	$	85

Anadarko enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to interest-rate changes. The fair value of the Company’s interest-rate swap portfolio increases (decreases) when interest rates increase (decrease). Interest rate derivatives with a notional principal amount of $1.0 billion are scheduled to settle in October 2012.

	Three Months Ended                  June 30,								Six Months Ended                      June 30,
millions except percentages	2012			Inc/(Dec)  vs. 2011		2011			2012			Inc/(Dec)  vs. 2011		2011
Other (Income) Expense, net
Interest income	$	(2	)		(75)%	$	(8	)	$	(4	)		(67)%	$	(12	)
Other		(517	)		NM		(10	)		(250	)		NM		(30	)
Total other (income) expense, net	$	(519	)		NM	$	(18	)	$	(254	)		NM	$	(42	)

For the three months ended June 30, 2012, total other income increased by $501 million, primarily due to the reversal of a $525 million Tronox-related contingent loss (see Note 10—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q), partially offset by $27 million related to changes in foreign currency gains/losses. These gains/losses reflect the impact of exchange-rate changes primarily applicable to foreign currency purchased in anticipation of funding future capital expenditures on major international development projects, as well as foreign currency held in escrow pending final determination of the Company’s Brazilian tax liability attributable to the 2008 divestiture of the Peregrino field offshore Brazil. For the six months ended June 30, 2012, total other income increased by $212 million, primarily due to the reversal of the Tronox-related contingent loss, partially offset by $39 million related to changes in foreign currency gains/losses.

Income Tax Expense

	Three Months Ended     June 30,				Six Months Ended          June 30,
millions except percentages	2012		2011		2012		2011
Income tax expense (benefit)	$	164	$	440	$	516	$	706
Effective tax rate		174%		44%		20%		47%

The increase from the 35% U.S. federal statutory rate for the three months ended June 30, 2012, was primarily attributable to the following:

• foreign tax rate differential and valuation allowances;

• the recurring accrual of the Algerian exceptional profits tax; and

• U.S. tax impact from losses and restructuring of foreign operations.

38

The decrease from the 35% U.S. federal statutory rate for the six months ended June 30, 2012, was primarily attributable to the resolution of the Algerian exceptional profits tax dispute. This amount was partially offset by the following:

• foreign tax rate differential and valuation allowances;

• the recurring accrual of the Algerian exceptional profits tax; and

• U.S. tax impact from losses and restructuring of foreign operations.

The increase from the 35% U.S. federal statutory rate for the three and six months ended June 30, 2011, was primarily attributable to the following:

• the recurring accrual of the Algerian exceptional profits tax;

• foreign tax rate differential and valuation allowances;

• U.S. tax on foreign income inclusions and distributions;

• state income taxes; and

• items resulting from business acquisitions.

These items were partially offset by the U.S. income tax benefits associated with foreign losses and restructuring of foreign operations.

Net Income Attributable to Noncontrolling Interests

For the three and six months ended June 30, 2012, the Company’s net income attributable to noncontrolling interests of $19 million and $46 million, respectively, primarily related to a 56.6% public ownership interest in Western Gas Partners, LP (WES) at June 30, 2012. For the three and six months ended June 30, 2011, the Company’s net income attributable to noncontrolling interests of $18 million and $39 million, respectively, primarily related to a 53.7% public ownership in WES at June 30, 2011.

OPERATING RESULTS

Segment Analysis—Adjusted EBITDAX  To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes income (loss) before income taxes, interest expense, exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, Tronox-related contingent loss, unrealized (gains) losses on derivatives, net, and realized (gains) losses on other derivatives, net, less net income attributable to noncontrolling interests (Adjusted EBITDAX). The Company’s definition of Adjusted EBITDAX, which is not a GAAP measure, excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Adjusted EBITDAX also excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Anadarko’s definition of Adjusted EBITDAX also excludes Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, and Tronox-related contingent loss, as these costs are outside the normal operations of the Company. See Note 10—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for discussion of these events. Finally, unrealized (gains) losses on derivatives, net and realized (gains) losses on other derivatives, net are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders.

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Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies. Therefore, Anadarko’s consolidated Adjusted EBITDAX should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures prepared in accordance with GAAP, such as operating income or cash flows from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect net income (loss) attributable to common stockholders and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Anadarko’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes, and consolidated Adjusted EBITDAX by reporting segment.

Adjusted EBITDAX

	Three Months Ended June 30,								Six Months Ended June 30,
millions except percentages	2012			Inc/(Dec) vs. 2011		2011			2012			Inc/(Dec) vs. 2011		2011
Income (loss) before income taxes	$	94			(91)%	$	1,002		$	2,629			75%	$	1,505
Exploration expense		1,121			NM		236			1,365			NM		415
DD&A		1,027			4		985			1,957			(1)		1,970
Impairments		112			10		102			162			56		104
Deepwater Horizon settlement and related costs (1)		3			(67)		9			11			(69)		35
Algeria exceptional profits tax settlement (2)		—			NM		—			(1,804	)		NM		—
Tronox-related contingent loss (2)		(525	)		NM		—			(250	)		NM		—
Interest expense		190			(12)		216			376			(14)		436
Unrealized (gains) losses on derivatives, net		225			NM		(178	)		83			11		75
Realized (gains) losses on other derivatives, net (2)		2			—		2			2			—		2
Less: Net income attributable to noncontrolling interests		19			6		18			46			18		39
Consolidated Adjusted EBITDAX	$	2,230			(5)	$	2,356		$	4,485			—	$	4,503
Adjusted EBITDAX by reporting segment
Oil and gas exploration and production	$	2,038			(14)%	$	2,366		$	4,168			(6)%	$	4,446
Midstream		107			(14)		124			226			7		211
Marketing		(43	)		(95)		(22	)		(61	)		(126)		(27	)
Other and intersegment eliminations		128			NM		(112	)		152			NM		(127	)

⁽¹⁾  In the third quarter of 2011, the Company revised the definition of Adjusted EBITDAX to exclude Deepwater Horizon settlement and related costs. Prior periods have been adjusted to reflect this change.

⁽²⁾  In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. Prior periods have been adjusted to reflect this change.

Oil and Gas Exploration and Production  Adjusted EBITDAX for the three and six months ended June 30, 2012, decreased primarily due to lower NGLs and natural-gas prices, partially offset by higher sales volumes and a $76 million loss recorded in the second quarter of 2011 related to the termination of natural-gas processing contracts between the Company and the previous owner of the Wattenberg Plant. The decrease for the three months ended June 30, 2012, was also attributable to lower crude-oil prices, while the decrease for the six months ended June 30, 2012, was partially offset by higher crude-oil prices.

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Midstream  The decrease in Adjusted EBITDAX for the three months ended June 30, 2012, is primarily due to lower commodity prices, which led to reduced natural-gas processing margins. This decrease was partially offset by increased throughput across several of Anadarko’s fee-based systems, which provided an increase to gathering and processing revenue, and additional margin provided by assets acquired in February 2011 and May 2011. The increase in Adjusted EBITDAX for the six months ended June 30, 2012, is primarily due to increased throughput across several of Anadarko’s fee-based systems and additional margin provided by assets acquired in February 2011 and May 2011. This increase was partially offset by lower commodity prices, which led to reduced natural-gas processing margins.

Marketing  Marketing earnings primarily represent the margin earned on sales of natural gas, oil, and NGLs purchased from third parties. For the three and six months ended June 30, 2012, Adjusted EBITDAX decreased primarily due to lower marketing margins on sales from inventory as a result of lower prices and volumes. Also, for the six months ended June 30, 2012, Adjusted EBITDAX decreased due to a write-down of natural-gas inventory to market value.

Other and Intersegment Eliminations  Other and intersegment eliminations consist primarily of corporate costs, realized gains and losses on commodity derivatives, and income from hard minerals investments and royalties. The increase in Adjusted EBITDAX for the three and six months ended June 30, 2012, was primarily due to higher realized gains on commodity derivatives in 2012. See Other (Income) Expense.

LIQUIDITY AND CAPITAL RESOURCES

Overview  Anadarko generates cash needed to fund capital expenditures, debt-service obligations, and dividend payments primarily from operating activities, and enters into debt and equity transactions to maintain the desired capital structure and to finance acquisition opportunities. Liquidity may also be enhanced through asset divestitures and joint ventures that reduce future capital expenditures.

Consistent with this approach, during the six months ended June 30, 2012, cash flows from operating activities were the primary source of capital investment funding. The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule, and evaluates available funding alternatives in light of current and expected conditions.

In March 2012, Moody’s Investors Service returned the Company’s senior unsecured rating to investment grade. As a result, the Company was able to terminate $269 million of letters of credit in the second quarter of 2012 that were outstanding under the LOC Facility (discussed below) at March 31, 2012. In addition, all cash that secured financial trades, previously posted due to credit-related provisions, had been returned to the Company at June 30, 2012.

During the second quarter of 2012, the Company repaid $800 million of borrowings under the Company’s $5.0 billion Facility with cash on hand. At June 30, 2012, the Company had outstanding borrowings of $1.7 billion at an interest rate of 1.75% under the $5.0 billion Facility. These borrowings were used to fund a portion of the Company’s 2011 settlement agreement with BP. The Company intends to repay these borrowings with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute.

At June 30, 2012, Anadarko’s remaining 2012 debt maturities were $39 million, with no scheduled debt maturities for 2013. The Company intends to repay $1.7 billion of outstanding borrowings under the $5.0 billion Facility within the next year, and has classified these borrowings, along with the scheduled debt maturities, as current portion of long-term debt on the Company’s Consolidated Balance Sheet at June 30, 2012. In addition, up to $682 million (the accreted amount through October 2012) of the Zero-Coupon Senior Notes due 2036 can be put to the Company in October 2012. The Company has classified the Zero-Coupons as long-term debt on the Company’s Consolidated Balance Sheet at June 30, 2012, because the Company has the ability and the intent to refinance these obligations using long-term debt if put to the Company in October 2012.

The Company has a variety of funding sources available to satisfy its debt service obligations and to fund capital expenditures and dividend payments, including cash on hand, an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through the monetization of certain assets or joint-venture arrangements, and available capacity under the $5.0 billion Facility. Management believes that the Company’s liquidity position, asset portfolio, and continued strong operating and financial performance provide the necessary financial flexibility to fund current operations.

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Revolving Credit Facility and Letter of Credit Facility  Obligations incurred under the $5.0 billion Facility, as well as obligations Anadarko has to lenders or their affiliates pursuant to certain derivative instruments that are supported by the $5.0 billion Facility, as discussed in Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, are guaranteed by certain of the Company’s wholly owned domestic subsidiaries, and are secured by a perfected first-priority security interest in certain exploration and production assets located in the United States and 65% of the capital stock of certain wholly owned foreign subsidiaries. The Company was in compliance with all applicable covenants contained in the $5.0 billion Facility and had available borrowing capacity of $3.2 billion at June 30, 2012 ($5.0 billion maximum capacity, less $1.7 billion of outstanding borrowings and $150 million of letter-of-credit capacity required to be maintained pursuant to the terms of the LOC Facility discussed below).

In 2011, the Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit. In June 2012, the agreement was amended to reduce the amount of letters of credit to a maximum of $150 million (LOC Facility). Compensating balances deposited with the financial institution provide for reduced fees under the LOC Facility. These compensating balances may be withdrawn at any time, resulting in higher fees. Cash and cash equivalents includes $23 million of demand deposits serving as compensating balances for outstanding letters of credit at June 30, 2012.

WES Funding Sources  Anadarko’s consolidated subsidiary, WES, uses cash flow from operations to fund its ongoing operations (including capital investments in the ordinary course of business), service its debt, and make distributions to its equity holders. As needed, WES supplements cash generated from its operating activities with proceeds from debt or equity issuances or borrowings under its five-year $800 million senior unsecured revolving credit facility maturing in March 2016 (RCF).

WES was in compliance with all covenants contained in its RCF, had no outstanding borrowings under the RCF, and had the full $800 million of RCF borrowing capacity available at June 30, 2012. See Financing Activities below.

Sources of Cash

Operating Activities  Anadarko’s cash flows from operating activities during the six months ended June 30, 2012, was $3.9 billion, compared to $3.1 billion for the same period of 2011. Cash flows for 2012 increased primarily due to higher average crude-oil prices, higher sales volumes, and the impact of changes in working capital items, but were partially offset by lower average NGLs and natural-gas prices.

One of the primary sources of variability in the Company’s cash flows from operating activities is fluctuations in commodity prices, which Anadarko partially mitigates by entering into commodity derivatives. Sales-volume changes also impact cash flow, but have not been as volatile as commodity prices. Anadarko’s cash flows from operating activities are dependent on commodity prices, sales volumes, costs required for continued operations, and debt service.

Investing Activities  During the six months ended June 30, 2012, Anadarko received pretax proceeds of $258 million related to several property divestiture transactions.

Financing Activities  During the six months ended June 30, 2012, Anadarko’s consolidated subsidiary, WES, borrowed $374 million under its RCF primarily to fund the acquisition of certain midstream assets from Anadarko. In June 2012, WES completed a public offering of $520 million aggregate principal amount of 4.00% Senior Notes due 2022. Also in June 2012, WES issued five million common units to the public, raising net proceeds of $212 million. Proceeds from these public offerings were used to repay outstanding RCF borrowings and for other general partnership purposes, including the funding of capital expenditures.

Uses of Cash

Anadarko invests significant capital to acquire, explore, and develop oil and natural-gas resources and to expand its midstream infrastructure, and also utilizes cash to fund ongoing operating costs, capital contributions to equity subsidiaries, debt repayments, and distributions to its shareholders.

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Capital Expenditures  The following table presents the Company’s capital expenditures by category.

	Six Months Ended June 30,
millions	2012		2011
Property acquisition—exploration	$	96	$	274
Exploration		809		341
Development		1,938		1,548
Capitalized interest		110		62
Total oil and gas capital expenditures		2,953		2,225
Gathering, processing, and marketing and other (1)		646		1,083
Total capital expenditures (2)	$	3,599	$	3,308

⁽¹⁾  Includes WES capital expenditures of $221 million and $338 million for the six months ended June 30, 2012 and 2011, respectively.

⁽²⁾  Capital expenditures in the table above are presented on an accrual basis. Additions to properties and equipment on the Company’s Consolidated Statements of Cash Flows only include capital expenditures funded with cash payments during the period.

The Company’s capital spending increased 9% for the six months ended June 30, 2012, primarily due to increased exploration drilling onshore and offshore United States, and in East and West Africa; increased development drilling onshore United States; construction costs related to the development of the Lucius project located in the Gulf of Mexico; and higher expenditures for domestic onshore plants and gathering systems. These increases were partially offset by lower property acquisition costs, primarily onshore United States, and midstream asset acquisitions in 2011. In May 2011, Anadarko increased its ownership interest in the Wattenberg Plant to 100% by acquiring an additional 93% interest for $576 million. Also, during the first quarter of 2011, WES acquired a third-party processing plant and related gathering systems located in the Rocky Mountains area for $302 million.

Pension Contributions  During the six months ended June 30, 2012, the Company made contributions of $32 million to its funded pension plans, $2 million to its unfunded pension plans, and $9 million to its unfunded other postretirement benefit plans. During the remainder of 2012, the Company expects to contribute approximately $88 million to its funded pension plans, approximately $32 million to its unfunded pension plans, and approximately $10 million to its unfunded other postretirement benefit plans.

Debt Retirements and Repayments  During the six months ended June 30, 2012, the Company used cash on hand to repay $800 million of borrowings under its $5.0 billion Facility and retire $131 million of 6.125% Senior Notes that matured in March 2012. In addition, WES repaid $374 million of borrowings under its RCF.

Common Stock Dividends and Distributions to WES Noncontrolling Interest Owners  During the six months ended June 30, 2012 and 2011, Anadarko paid $91 million in dividends to its common stockholders (nine cents per share in each quarterly period). Anadarko has paid a dividend to its common stockholders on a quarterly basis since becoming an independent public company in 1986. The amount of future dividends paid to Anadarko common stockholders will be determined by the Board of Directors on a quarterly basis and will depend on the Company’s earnings, financial condition, capital requirements, the effect a dividend payment would have on its compliance with its financial covenants, and other factors.

WES distributed to its unitholders, other than Anadarko, an aggregate of $45 million and $33 million during the six months ended June 30, 2012 and 2011, respectively. WES has made quarterly distributions to its unitholders since its initial public offering in the second quarter of 2008, and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.48 per common unit for the second quarter of 2012 (to be paid in August 2012).

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Outlook

The Company is committed to the execution of its worldwide exploration, appraisal, and development programs. The Company estimates a 2012 capital spending range of $7.0 billion to $7.4 billion, including $410 million to $460 million for WES capital expenditures.

Anadarko believes that its cash on hand and expected level of operating cash flows will be sufficient to fund the Company’s projected operational and capital programs for 2012, while continuing to meet its other obligations. The Company’s cash on hand is available for use and could be supplemented, as needed, with available borrowing capacity under the $5.0 billion Facility. The Company currently does not consider European sovereign debt events to pose significant risk to the Company’s ability to access available borrowing capacity under the $5.0 billion Facility. The Company may also enter into carried-interest arrangements and asset divestitures to supplement cash flow. In order to redirect its operating activities and capital investment to other areas, the Company is marketing certain of its properties.

The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule, and evaluates available funding alternatives in light of current and expected conditions. In order to reduce commodity-price risk and increase the predictability of 2012 cash flows, Anadarko entered into strategic derivative positions, which cover approximately 42% and 52% of its remaining 2012 anticipated natural-gas and crude-oil sales volumes, respectively. In addition, the Company has derivative positions in place for 2013. In July 2012, the Company entered into fixed-price swaps for 900,000 million British thermal units per day (MMBtu/d), at an average price of $4.00 per MMBtu, in exchange for instruments that will effectively offset its outstanding 2013 natural-gas three-way collars of 450,000 MMBtu/d. See Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

In July 2012, the Company signed a definitive agreement to enter into a carried-interest arrangement that requires a third-party partner to fund approximately $556 million of Anadarko’s capital costs in the Lucius development, located in the Gulf of Mexico, in exchange for a 7.2% working interest in the Lucius assets. The third party will fund 100% of Anadarko’s future capital costs in the development until the carry is fully funded, which is expected to occur by year-end 2014. The agreement is expected to close during the third quarter of 2012, with an effective date of January 1, 2012, and is subject to customary closing conditions.

In the first quarter of 2011, the Company entered into a carried-interest arrangement that requires a third-party partner to fund approximately $1.6 billion of Anadarko’s future capital costs in the Eagleford shale, located in southwest Texas, in exchange for a one-third interest in Anadarko’s Eagleford shale assets. The third party will fund 90% of Anadarko’s future capital costs in the basin until the carry is fully funded, which is expected to occur by year-end 2013. At June 30, 2012, $839 million of the total $1.6 billion obligation had been funded.

In the first quarter of 2010, the Company entered into a carried-interest arrangement whereby a third-party partner agreed to fund up to $1.5 billion of Anadarko’s share of future capital costs in the area to earn a 32.5% interest in Anadarko’s Marcellus shale assets, primarily located in north-central Pennsylvania. At June 30, 2012, $1.4 billion of the total $1.5 billion obligation had been funded. The carry was fully funded in July 2012.

Obligations and Commitments

In January 2012, the Company entered into a two-and-a-half-year lease agreement for a deepwater drilling rig expected to be delivered in late 2012. In July 2012, the Company entered into a three-year lease agreement for a deepwater drilling rig expected to be delivered in late 2013. These lease obligations total approximately $875 million, with aggregate future annual minimum lease payments of $13 million in 2012, $192 million in 2013, $317 million in 2014, $228 million in 2015, and $125 million in 2016.

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. In addition, foreign-currency exchange-rate risk exists due to anticipated foreign-currency denominated payments and receipts. These risks can affect revenues and cash flow from operating, investing, and financing activities. The Company’s risk-management policies provide for the use of derivative instruments to manage these risks. The types of commodity derivative instruments utilized by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. Both exchange and over-the-counter traded commodity derivative instruments may be subject to margin deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties in order to satisfy these margin requirements. For additional information related to the Company’s derivative and financial instruments, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

COMMODITY-PRICE RISK  The Company’s most significant market risk relates to prices for natural gas, crude oil, and NGLs. Management expects energy prices to remain volatile and unpredictable. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of the Company’s oil and gas properties or goodwill may be required if commodity prices experience a significant decline. Below is a sensitivity analysis for 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 production of 348 Bcf of natural gas and 22 MMBbls of crude oil at June 30, 2012, with a net derivative asset position of $694 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $236 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $235 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of crude-oil and natural-gas production volumes.

Derivative Instruments Held for Trading Purposes  The Company had a net derivative asset position of $23 million (gains of $41 million and losses of $18 million) on derivative instruments entered into for trading purposes at June 30, 2012. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would not materially impact the Company’s gains or losses on these derivative instruments.

Algerian Settlement Volumes  Volumes received by Anadarko in connection with the resolution of the Algeria exceptional profits tax dispute will be valued at month-average dated Brent price plus a Saharan Blend quality differential. See Note 10—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information. Generally, the market in this region is priced over a five-day period related to the bill of lading date. To the extent the Company’s realized sales price is greater than or less than the settlement value, the Company will record a gain or a loss in the period of sale.

INTEREST-RATE RISK  The Company’s $1.7 billion of borrowings under its $5.0 billion Facility are subject to variable interest rates. The balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheet is subject to fixed interest rates. The Company’s $2.9 billion of LIBOR-based obligations, which are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two non-controlled entities, give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. A 10% increase in LIBOR would not materially impact the Company’s interest cost on outstanding debt, but would affect fair value of outstanding debt.

At June 30, 2012, the Company had a net derivative liability position of $1.3 billion related to interest-rate swaps. A 10% increase or decrease in interest rates would increase or decrease, respectively, the aggregate fair value of outstanding interest-rate swap agreements by approximately $113 million. However, any change in the interest-rate derivative gain or loss would be substantially offset by an increase or decrease, respectively, in borrowing costs associated with future debt issuances. For a summary of the Company’s open interest-rate derivative positions, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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FOREIGN-CURRENCY EXCHANGE-RATE RISK  Anadarko’s operating revenues are realized in U.S. dollars, and the predominant portion of Anadarko’s capital and operating expenditures are U.S.-dollar-denominated. Exposure to foreign-currency risk generally arises in connection with project-specific contractual arrangements and other commitments. Near-term foreign-currency-denominated expenditures are primarily in euros, Brazilian reais, and British pounds sterling. Management periodically enters into transactions to mitigate a portion of its exposure to foreign-currency exchange-rate risk.

With respect to international oil and gas development projects, Anadarko is a party to contracts with commitments extending through November 2012 that are impacted by euro-to-U.S. dollar exchange rates. The Company also has exposure related to exchange-rate changes applicable to cash held in escrow of $169 million as of June 30, 2012, pending final determination of the Company’s Brazilian tax liability attributable to its 2008 divestiture of the Peregrino field offshore Brazil.

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934. The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that the information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of June 30, 2012.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the second quarter of 2012 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II.    OTHER INFORMATION

Item 1.  Legal Proceedings

GENERAL  The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims, title disputes, tax disputes, royalty claims, contract claims, oil-field contamination claims, and environmental claims, including claims involving assets owned by acquired companies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

See Note 10—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference, for material developments with respect to matters previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

Item 1A.  Risk Factors

Consider carefully the risk factor included below, as well as those under the caption “Risk Factors” under Part I, Item 1A in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, together with all of the other information included in this Form 10-Q; in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011; and in the Company’s other public filings, press releases, and public discussions with Company management.

We are, and in the future may become, involved in legal proceedings related to Tronox and, as a result, may incur substantial costs in connection with those proceedings.

In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance. Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee and seeks, among other things, to recover damages, including interest, in excess of $18.9 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. For a description of the updates to this litigation since the description thereof included in Note 16—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements included in Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, see Note 10—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. An adverse resolution of any proceedings related to Tronox could subject us to significant monetary damages and other penalties, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

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Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

The following sets forth information with respect to repurchases by the Company of its shares of common stock during the second quarter of 2012.

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
April 1-30		9,659	$	78.34		—
May 1-31		942	$	70.42		—
June 1-30		630	$	58.13		—
Second-Quarter 2012		11,231	$	76.54		—	$	—

⁽¹⁾  During the second quarter of 2012, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee stock plan share issuances.

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Item 6.  Exhibits

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Exhibit         Number	Description	Original Filed         Exhibit	File   Number
3 (i)	Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 22, 2009	3.3 to Form 8-K filed on May 22, 2009	1-8968
(ii)	By-Laws of Anadarko Petroleum Corporation, amended and restated as of May 15, 2012	3.1 to Form 8-K filed on May 15, 2012	1-8968
*  10 (i)	Time Sharing Agreement between James T. Hackett and Anadarko Petroleum Corporation, dated May 15, 2012
*(ii)	Time Sharing Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated May 15, 2012
(iii)	Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, effective as of May 15, 2012	10.1 to Form 8-K filed on May 15, 2012	1-8968
(iv)	Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Stock Option Award Agreement	10.2 to Form 8-K filed on May 15, 2012	1-8968
(v)	Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement	10.3 to Form 8-K filed on May 15, 2012	1-8968
(vi)	Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement	10.4 to Form 8-K filed on May 15, 2012	1-8968
(vii)	Form of U.K. Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan	10.5 to Form 8-K filed on May 15, 2012	1-8968
*   31 (i)	Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer
*   31 (ii)	Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer
*   32	Section 1350 Certifications
* 101 .INS	XBRL Instance Document
* 101 .SCH	XBRL Schema Document
* 101 .CAL	XBRL Calculation Linkbase Document
* 101 .LAB	XBRL Label Linkbase Document
* 101 .PRE	XBRL Presentation Linkbase Document
* 101 .DEF	XBRL Definition Linkbase Document

49

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned duly authorized officer and principal financial officer.

		ANADARKO PETROLEUM CORPORATION
August 8, 2012	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin
		Senior Vice President, Finance and Chief Financial Officer

50

EX-10.(I)

EXHIBIT 10(i)

TIME SHARING AGREEMENT

THIS TIME SHARING AGREEMENT (the “Agreement”), is made and entered into effective May 15, 2012, by and between Anadarko Petroleum Corporation, a Delaware corporation (the “Operator” or the “Company”), and James T. Hackett (the “Passenger”).

RECITALS

WHEREAS, Operator owns and/or operates the aircraft (individually and/or collectively, as the case may be, the “Aircraft”) listed on Schedule A hereto for business use by employees and non-employee directors of the Company in accordance with 14 C.F.R. Part 91of the Federal Aviation Regulations (as found at 14 C.F.R. Parts 1-199 generally, the “FAR”) and the Company’s Corporate Aircraft Policy regarding the use of corporate aircraft (the “Aircraft Policy”); and

WHEREAS, Operator has the right and lawful authority to enter into time sharing agreements, as provided in §91.501 of the FAR to provide its senior executives with personal travel consistent with the Company’s Aircraft Policy; and

WHEREAS, Operator has agreed to make the Aircraft, with flight crew, when the Aircraft and flight crew are not otherwise needed for business purposes, available to Passenger for Passenger’s personal travel in accordance with the Aircraft Policy on a non-exclusive time-sharing basis in accordance with §91.501 of the FAR; and

WHEREAS, the Passenger agrees to reimburse the Operator for the personal use of the Aircraft for certain flights as permitted under the FAR and as pursuant to the terms of this Agreement, which sets forth the understanding of the parties.

NOW THEREFORE, Operator and Passenger declaring their intention to enter into and be bound by this Agreement, and for the good and valuable consideration set forth below, hereby covenant and agree as follows:

NOW, THEREFORE, the parties hereto agree as follows:

1.        Provision of Aircraft and Crew.  Subject to Aircraft availability, Operator agrees to provide to Passenger the Aircraft and flight crew on a time sharing basis in accordance with the provisions of FAR Part 91, including §§ 91.501(b)(6), 91.501(c)(1) and 91.501(d) of the FAR. Operator shall provide, at its sole expense, qualified flight crew for all flight operations under this Agreement. If Operator is no longer the operator of any of the Aircraft, Schedule A shall be deemed amended to delete any reference to such Aircraft and this Agreement shall be terminated as to such Aircraft but shall remain in full force and effect with respect to each of the other Aircraft identified thereon, if any. No such termination shall affect any of the rights and obligations of the parties accrued or incurred prior to such termination. If Operator becomes the operator of any aircraft not listed on Schedule A hereto, Schedule A shall be modified to include such aircraft as an Aircraft covered by this Agreement, and thereafter this Agreement shall

Anadarko Aircraft Time Sharing Agreement — James T. Hackett Page 1

remain in full force and effect with respect to such Aircraft and each of the other Aircraft identified thereon, if any.

2.        Term.  The term of this Agreement (the “Term”) shall commence on the date hereof and shall continue until terminated by either party on written notice to the other party, such termination to become effective 30 days from the date of the notice; provided, however, that this Agreement may be terminated by Operator on such shorter notice as may be required for Operator to comply with applicable law, regulations, the requirements of any financial institution with a security or other interest in the Aircraft, insurance requirements, or in the event the insurance required hereunder is not in full force and effect. This Agreement shall be terminated immediately upon the termination of Passenger’s employment with Operator. Notwithstanding the foregoing, any provisions directly or indirectly related to Passenger’s payment obligations for flights completed prior to the date of termination and the limitation of liability provisions in Section 10 shall survive the termination of this Agreement.

Reimbursement of Expenses. For each Trip or Round Trip (as such terms are defined below) conducted under this Agreement, Passenger shall pay Operator an amount (as determined by Operator) equal to the actual expenses of operating such Trip, not to exceed the sum of the following expenses as permitted pursuant to FAR § 91.501(d):

a. Fuel, oil, lubricants, and other additives;

b. Travel expenses of the crew, including food, lodging, and ground transportation;

c. Hangar and tie-down costs away from the Aircraft’s base of operation;

d. Insurance obtained for the specific flight as per Section 8(b);

e. Landing fees, airport taxes, and similar assessments;

f.          Customs, foreign permit, and similar fees directly related to the flight;

g. In-flight food and beverages;

h. Passenger ground transportation;

i. Flight planning and weather contract services; and

j.          An additional charge equal to one hundred percent (100%) of the expenses listed in  subsection (a) above.

The term “Trip” shall mean a flight from a departure point to a single destination. A “Round Trip” shall mean a flight from a departure point to one destination and back to the same departure point. In the event that Passenger travels from a departure point to multiple destinations, the Operator will provide a separate invoice for each Trip.

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3.        Invoicing and Payment.  All payments to be made to Operator by Passenger hereunder shall be paid in the manner set forth in this Section 3. Operator will pay, or cause to be paid, all expenses related to the operation of the Aircraft hereunder in the ordinary course. Within 30 days of the end of each Trip or Round Trip, Operator shall provide or cause to be provided to Passenger an invoice showing all personal use of the Aircraft by Passenger pursuant to this Agreement during that Trip or Round Trip and a complete accounting detailing all amounts that are payable by Passenger pursuant to Section 2 for that Trip or Round Trip (plus applicable domestic or international air transportation excise taxes, and any other fees, taxes or charges assessed on passengers by and remitted to a government agency or airport authority). Passenger shall pay all amounts due under the invoice in a manner reasonably acceptable to Operator not later than 30 days after receipt thereof. In the event Operator has not received all supplier invoices for reimbursable charges relating to such Trip or Round Trip prior to such invoicing, Operator shall issue a supplemental invoice(s) for such charge(s) to Passenger, and Passenger shall pay each supplemental invoice within 30 days after receipt thereof.

4.        Flight Requests.  Passenger shall provide the Operator’s aviation department or designated point of contact with Trip requests for Passenger’s personal travel to be undertaken pursuant to this Agreement and proposed flight schedules as far in advance of Passenger’s desired departure as possible, and at least 24 hours prior to Passenger’s planned departure or as may be required by law. The advance notice requirement in this Section 4 may be waived by Operator in its discretion. All flight requests for travel under this Agreement shall be in accordance with all reasonable policies established by Operator. Flight requests shall be made by Passenger in a form that is acceptable to Operator. Operator shall have sole and exclusive authority over the scheduling of the Aircraft. Operator shall not be liable to Passenger or any other person for loss, injury, or damage occasioned by the delay or failure to furnish the Aircraft and crew pursuant to this Agreement for any reason. In addition to requested schedules and departure times, Passenger shall provide at least the following information for each proposed flight reasonably in advance of the desired departure time as required by Operator or its flight crew:

a. Departure point;

b. Destination;

c. Date and time of flight;

d. Number and identity of anticipated passengers;

e. Nature and extent of luggage and/or cargo expected to be carried;

f.          Date and time of return flight, if any; and

g. Any other information concerning the proposed flight that may be pertinent to or required by Operator, its flight crew, or governmental entities.

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5.        Operational Authority and Control.

a. Operator shall be responsible for the physical and technical operation of the Aircraft and the safe performance of all flights under this Agreement, and shall retain full authority and control, including exclusive operational control and exclusive possession, command and control of the Aircraft for all flights under this Agreement.

b. Operator shall furnish at its expense a fully qualified flight crew with appropriate credentials to conduct each flight undertaken under this Agreement and included on the insurance policies that Operator is required to maintain hereunder. In accordance with applicable FAR, the qualified flight crew provided by Operator will exercise all required and/or appropriate duties and responsibilities in regard to the safety of each flight conducted hereunder. The pilot-in-command shall have absolute discretion in all matters concerning the preparation of the Aircraft for flight and the flight itself, the load carried and its distribution, the decision whether or not a flight shall be undertaken, the route to be flown, the place where landings shall be made, and all other matters relating to operation of the Aircraft. Passenger specifically agrees that the flight crew shall have final and complete authority to delay or cancel any flight for any reason or condition that in the sole judgment of the pilot-in-command could compromise the safety of the flight, and to take any other action that in the sole judgment of the pilot-in-command is necessitated by considerations of safety. No such action of the pilot-in-command shall create or support any liability to Passenger or any other person for loss, injury, damage or delay. Operator’s operation of the Aircraft hereunder shall be strictly within the guidelines and policies established by Operator and FAR Part 91.

c. Subject to Aircraft and crew availability, Operator shall use its good faith efforts, consistent with its approved policies, to accommodate Passenger’s needs and avoid conflicts in scheduling. Although every good faith effort shall be made to avoid its occurrence, any flights scheduled under this Agreement are subject to cancellation by either party without incurring liability to the other party. In the event of a cancellation, the canceling party shall provide the maximum notice reasonably practicable.

d. In the absence of another flight scheduled on the aircraft by Passenger or another scheduled business trip, the Aircraft may remain at the destination until its next required use. If the next use of the Aircraft is a business use, Operator shall not charge the Passenger for expenses associated with hangar and tie-down costs away from the Aircraft’s base of operation; if, however, the next use of the Aircraft is by Passenger, Operator shall have the option of returning the Aircraft to its base of operations or permitting it

Anadarko Aircraft Time Sharing Agreement — James T. Hackett Page 4

to remain at the destination. In either event, Passenger shall pay for the associated costs.

6.        Aircraft Maintenance. Operator shall, at its own expense, cause the Aircraft to be inspected, maintained, serviced, repaired, overhauled, and tested in accordance with FAR Part 91 so that the Aircraft will remain in good operating condition and in a condition consistent with its airworthiness certification and shall take such requirements into account in scheduling the Aircraft hereunder, including but not limited compliance with applicable airworthiness directives and service bulletins. Performance of maintenance, preventive maintenance or inspection shall not be delayed or postponed for the purpose of scheduling the Aircraft unless such maintenance or inspection can safely be conducted at a later time in compliance with applicable laws, regulations and requirements, and such delay or postponement is consistent with the sound discretion of the pilot-in-command. In the event that any non-standard maintenance is required during the term and will interfere with Passenger’s requested or scheduled flights, Operator, or Operator’s pilot-in-command, shall notify Passenger of the maintenance required, the effect on the ability to comply with Passenger’s requested or scheduled flights and the manner in which the parties will proceed with the performance of such maintenance and conduct of such flight(s). In no event shall Operator be liable to Passenger or any other person for loss, injury or damage occasioned by the delay or failure to furnish the Aircraft under this Agreement, whether or not maintenance-related.

7.        Insurance.

a. Operator, at its expense, will maintain or cause to be maintained in full force and effect throughout the Term of this Agreement an aviation liability and hull insurance policy including: aviation liability insurance against bodily injury and property damage claims arising out of the use of the Aircraft in an amount not less than $250 Million for each occurrence; and hull insurance for the Aircraft in amounts determined by Operator at its sole discretion. The aviation liability coverage shall include Passenger as an insured, and include a severability of interest provision providing that the insurance shall apply separately to each insured against whom a claim is made, except as respects the limits of liability. The aviation liability and hull insurance coverage shall include provisions whereby the insurer(s) waive all rights of subrogation they may have or acquire against Passenger and shall permit the use of the Aircraft by Operator for compensation or hire as provided in §91.501 of the FAR.

b. Operator shall use reasonable commercial efforts to provide such additional insurance for specific flights under this Agreement as Passenger may reasonably request. Passenger acknowledges that any trips scheduled to areas not currently covered by existing policies may require Operator to purchase additional insurance to comply with applicable regulations, and Operator shall be required to maintain or cause to be maintained such additional insurance. The cost of all flight-specific insurance shall be borne by Passenger as provided in Section 2(d) above.

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8.        Use of Aircraft.  Passenger warrants that:

a. Passenger has all necessary powers to enter into the transactions contemplated in this Agreement and has taken actions required to authorize and approve this Agreement;

b. Passenger will use the Aircraft under this Agreement for and only for its own account, including the carriage of its guests, and will not use the Aircraft for the purpose of providing transportation of passengers or cargo for compensation or hire or for common carriage;

c. Passenger will not permit any lien, security interest or other charge or encumbrance to attach against the Aircraft as a result of his actions or inactions, and shall not attempt to convey, mortgage, assign, lease or in any way alienate the Aircraft or Operator’s rights hereunder or create any kind of lien or security interest involving the Aircraft or do anything or take any action that might mature into such a lien;

d. During the Term of this Agreement, Passenger will abide by and conform to all such laws, governmental and airport orders, rules, and regulations as shall from time to time be in effect relating in any way to the operation or use of the Aircraft by a lessee under a time sharing arrangement and all applicable policies of Operator; and

e. Passenger acknowledges that its discretion in determining the origin and destination of flights under this Agreement shall be subject to the following: such origin and destination, and the routes to reach such origin and destination, are not within or over (i) an area of hostilities, (ii) an area excluded from coverage under the insurance policies maintained by Operator with respect to the Aircraft, or (iii) a country or jurisdiction for which exports or transactions are subject to specific restrictions under any United States export or other law or United Nations Security Council Directive, including without limitation, the Trading with the Enemy Act, 50 U.S.C. App. Section 1 et seq., the International Emergency Economic Powers Act, 50 U.S.C. App. Section 1700 et seq., and the Export Administration Act, 50 U.S.C. App. Sections 2401 et seq.

9.        Limitation of Liability.  NEITHER OPERATOR (NOR ITS AFFILIATES) MAKES, HAS MADE OR SHALL BE DEEMED TO MAKE OR HAVE MADE ANY WARRANTY OR REPRESENTATION, EITHER EXPRESS OR IMPLIED, WRITTEN OR ORAL, WITH RESPECT TO ANY AIRCRAFT TO BE USED HEREUNDER OR ANY ENGINE OR COMPONENT THEREOF INCLUDING, WITHOUT LIMITATION, ANY WARRANTY AS TO DESIGN, COMPLIANCE WITH SPECIFICATIONS, QUALITY OF MATERIALS OR WORKMANSHIP, MERCHANTABILITY, FITNESS FOR ANY PURPOSE, USE OR OPERATION, AIRWORTHINESS, SAFETY, PATENT,

Anadarko Aircraft Time Sharing Agreement — James T. Hackett Page 6

TRADEMARK OR COPYRIGHT INFRINGEMENT OR TITLE. IN NO EVENT SHALL OPERATOR OR ITS AFFILIATES BE LIABLE FOR OR HAVE ANY DUTY FOR INDEMNIFICATION OR CONTRIBUTION TO PASSENGER OR ITS EMPLOYEES, AGENTS OR GUESTS FOR ANY CLAIMED INDIRECT, SPECIAL, CONSEQUENTIAL, OR PUNITIVE DAMAGES, REGARDLESS OF WHETHER IT KNEW OR SHOULD HAVE KNOWN OF THE POSSIBILITY OF SUCH DAMAGE, LOSS OR EXPENSE. The provisions of this Section 9 shall survive the termination or expiration of this Agreement.

10.      Base of Operations. For purposes of this Agreement, the base of operation of the Aircraft is Houston, Texas, provided that such base may be changed at Operator’s sole discretion upon notice from Operator to Passenger.

11.      Notices and Communications. All notices and other communications under this Agreement shall be in writing (except as permitted in Section 4) and shall be given (and shall be deemed to have been duly given upon receipt or refusal to accept receipt) by personal delivery, by facsimile or electronic mail (with a simultaneous confirmation copy sent by first class mail properly addressed and postage prepaid), or by a reputable overnight courier service, addressed as follows:

If to Operator:	Anadarko Petroleum Corporation
	c/o Director of Aviation
	17320 Chanute Road
	Houston, TX 77032
If to Passenger:	James T. Hackett
	1201 Lake Robbins Dr.
	The Woodlands, TX 77380

Or, to such other person or address as either party may from time to time designate in writing to the other party.

12.      Entire Agreement.  This Agreement constitutes the entire understanding between the parties with respect to its subject matter, and there are no representations, warranties, rights, obligations, liabilities, conditions, covenants, or agreements relating to such subject matter that are not expressly set forth herein. There are no third-party beneficiaries of this Agreement.

13.      Further Acts.  Operator and Passenger shall from time to time perform such other and further acts and execute such other and further instruments as may be required by law or may be reasonably necessary (i) to carry out the intent and purpose of this Agreement, and (ii) to establish, maintain and protect the respective rights and remedies of the other party.

14.      Successors and Assigns.  Passenger shall not have the right to assign, transfer or pledge this Agreement. This Agreement shall be binding on the parties hereto and their

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respective heirs, executors, administrators, successors and assigns, and shall inure to the benefit of the parties hereto, and, except as otherwise provided herein, their respective heirs, executors, administrators, other legal representatives, successors and permitted assigns.

15.      Taxes.     Passenger shall be responsible for paying, and Operator shall be responsible for collecting from Passenger and paying over to the appropriate authorities, all applicable Federal excise taxes imposed under IRC §4261 and all sales, use and other excise taxes imposed by any authority in connection with the use of the Aircraft by Passenger hereunder.

16.      Governing Law and Consent to Jurisdiction.  This Agreement shall be governed by the laws of the State of Texas, without regard to its choice of law principles. The parties hereby consent and agree to submit to the exclusive jurisdiction and venue of any state or federal court in Texas in any proceedings hereunder, and each hereby waives any objection to any such proceedings based on improper venue or forum non-conveniens or similar principles. The parties hereto hereby further consent and agree to the exercise of such personal jurisdiction over them by such courts with respect to any such proceedings, waive any objection to the assertion or exercise of such jurisdiction and consent to process being served in any such proceedings in the manner provided for the giving of notices hereunder.

17.      Severability.  If any provision of this Agreement is held to be illegal, invalid or unenforceable, the legality, validity and enforceability of the remaining provisions shall not be affected or impaired.

18.      Amendment or Modification.  This Agreement may be amended, modified or terminated only in writing duly executed by the parties hereto.

19.      Counterparts.  This Agreement may be executed in any number of counterparts, each of which shall be deemed an original, and all of which shall constitute one and the same Agreement, binding on all the parties notwithstanding that all the parties are not signatories to the same counterpart. Each party may transmit its signature by facsimile, and any faxed counterpart of this Agreement shall have the same force and effect as a manually-executed original.

20.      Truth-in-Leasing Compliance.  Operator, on behalf of Passenger, shall (i) deliver a copy of this Agreement to the Federal Aviation Administration, Aircraft Registration Branch, Attn: Technical Section, P.O. Box 25724, Oklahoma City, Oklahoma 73125 within 24 hours of its execution, (ii) notify the appropriate Flight Standards District Office at least 48 hours prior to the first flight under this Agreement of the registration number of the Aircraft, and the location of the airport of departure and departure time for such flight, and (iii) carry a copy of this Agreement onboard the Aircraft at all times when the Aircraft is being operated under this Agreement.

20A.    Subordination; Consent to Assignment.

I. 5169 Aircraft/680-0024 Aircraft

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This Agreement, to the extent it relates to the 5169 Aircraft (as such term is defined below) and/or the 680-0024 Aircraft (as such term is defined below), as the case may be, is subject to the terms and provisions of:

(i)  that certain Aircraft Lease (S/N 5169) dated as of September 26, 2007 (as amended, collectively, the “5169 Aircraft Lease”) between APC Aviation, Inc. (“APC”) and Bank of America, N.A. (“Bank of America”) regarding that certain Gulfstream Aerospace GV-SP (G550) (shown on the International Registry as Gulfstream GV-SP (G550)) aircraft, bearing U.S. Registration Mark N203A (formerly N569GA) and manufacturer’s serial number 5169 (the “5169 Aircraft”);

(ii)  that certain Aircraft Lease (S/N 680-0024) dated as of April 27, 2005 (as amended, collectively, the “680-0024 Aircraft Lease”) between APC and Banc of America Leasing & Capital, LLC (“Banc of America Leasing”) regarding that certain Cessna 680 (a/k/a Citation Sovereign) aircraft bearing U.S. Registration Mark N565A and manufacturer’s serial no. 680-0024 (the “680-0024 Aircraft”);

(iii)  that certain Aircraft Sublease dated as of February 14, 2008 (as amended, collectively, the “5169 Aircraft Sublease”) between APC and Operator regarding the 5169 Aircraft;

(iv) that certain Consent to Sublease and Assignment dated as of February 14, 2008 (the “5169 Consent to Sublease”) between Bank of America, APC and Operator regarding the 5169 Aircraft;

(v) that certain Aircraft Sublease dated as of April 29, 2005 (as amended, collectively, the “680-0024 Aircraft Sublease”) between APC and Operator;

(vi) that certain Consent to Sublease and Assignment dated as of April 29, 2005 (the “680-0024 Consent to Sublease”) between Banc of America Leasing, APC and Operator regarding the 680-0024 Aircraft; and

(vii) any related documents, agreements or instruments of any kind whatsoever relating to any of the 5169 Aircraft Lease, the 680-0024 Aircraft Lease, the 5169 Aircraft Sublease, the 680-0024 Aircraft Sublease, the 5169 Consent to Sublease and/or the 680-0024 Consent to Sublease.

Without limiting the generality of the foregoing, the rights of APC, Operator, Passenger and any other party, person or entity of any kind whatsoever claiming through any of APC, Operator or Passenger with respect to the 5169 Aircraft and/or the 680-0024 Aircraft (and any and all proceeds thereof, including, any insurance proceeds) shall be subject and subordinate in all respects to any and all of the rights, privileges, powers, entitlements, benefits, remedies, title or interests of Bank of America in or to the 5169 Aircraft (and any and all proceeds thereof, including, any insurance proceeds) and of Banc of America Leasing in or to the 680-0024 Aircraft (and any and all proceeds thereof, including, any insurance proceeds), including, all of their respective rights and remedies under or in connection with any of the 5169 Aircraft Lease, the 680-0024 Aircraft Lease, the 5169 Aircraft Sublease, the 680-0024 Aircraft Sublease, the 5169 Consent to Sublease, the 680-0024 Consent to Sublease and any related documents, agreements or instruments of any kind whatsoever (including, without limitation, Bank of America’s and Banc of America

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Leasing’s respective right to repossess the 5169 Aircraft and/or 680-0024 Aircraft, as the case may be, and to terminate this Agreement with respect to the 5169 Aircraft and/or 680-0024 Aircraft, as the case may be, pursuant to the 5169 Aircraft Lease, the 680-0024 Aircraft Lease and this Section). In addition, and notwithstanding anything to the contrary set forth in this Agreement or otherwise, upon the occurrence of any Event of Default (as such term is defined in each of the 5169 Aircraft Lease and the 680-0024 Aircraft Lease) under or in connection with 5169 Aircraft Lease and/or the 680-0024 Aircraft Lease, this Agreement shall automatically and immediately terminate with respect to the 5169 Aircraft and/or 680-0024 Aircraft, as the case may be.

II. 5307 Aircraft

This Agreement, to the extent it relates to the 5307 Aircraft (as such term is defined below), is subject to the terms and provisions of:

(i)  that certain Aircraft Lease (S/N 5307) dated as of November 15, 2010 (as amended, the “5307 Aircraft Lease”) between APC Aviation, Inc. (“APC”) and Wells Fargo Equipment Finance, Inc. (“WFEFI”) regarding that certain Gulfstream Aerospace GV-SP (G550) (shown on the International Registry as Gulfstream GV-SP (G550)) aircraft, bearing U.S. Registration Mark N288A (formerly N507GA) and manufacturer’s serial number 5307 (the “5307 Aircraft”);

(ii)    that certain Aircraft Sublease dated as of March 3, 2011 (as amended, collectively, the “5307 Aircraft Sublease”) between APC and Operator regarding the 5307 Aircraft;

(iii) that certain Collateral Assignment of Agreement dated March 3, 2011 between APC and WFEFI and

(iv)  any related documents, agreements or instruments of any kind whatsoever relating to any of the 5307 Aircraft Lease and the 5307 Aircraft Sublease

(collectively, the “5307 Documents”).

Without limiting the generality of the foregoing, the rights of APC, Operator, Passenger and any other party, person or entity of any kind whatsoever claiming through any of APC, Operator or Passenger with respect to the 5307 Aircraft (and any and all proceeds thereof, including, any insurance proceeds) shall be subject and subordinate in all respects to any and all of the rights, privileges, powers, entitlements, benefits, remedies, title or interests of WFEFI in or to the 5307 Aircraft (and any and all proceeds thereof, including, any insurance proceeds), including, all of WFEFI’s rights and remedies under or in connection with any of the 5307 Documents (including, without limitation, WFEFI’s right to repossess the 5307 Aircraft and to terminate this Agreement with respect to the 5307 Aircraft. In addition, and notwithstanding anything to the contrary set forth in this Agreement or otherwise, upon the occurrence of any Event of Default (as such term is defined in the 5307 Aircraft Lease and the 5307 Aircraft Sublease), this Agreement shall automatically and immediately terminate with respect to the 5307 Aircraft.

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Without limiting the generality of any terms or provisions of this Agreement or otherwise, Passenger hereby acknowledges and consents to the assignment by Operator of Operator’s right, title and interest in and to this Agreement (i) as it relates to the 5169 Aircraft to Bank of America and its successors and assigns, (ii) as it relates to the 680-0024 Aircraft to Banc of America Leasing and its successors and assigns and (iii) as it relates to the 5307 Aircraft to WFEFI and its successors and assigns.

[Truth-in-Leasing and Signature Page Follows]

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21.      TRUTH-IN-LEASING STATEMENT PURSUANT TO SECTION 91.23 OF THE FEDERAL AVIATION REGULATIONS.

OPERATOR CERTIFIES THAT EACH OF THE AIRCRAFT HAS BEEN INSPECTED AND MAINTAINED DURING THE 12-MONTH PERIOD PRECEDING THE DATE OF THIS AGREEMENT (OR SUCH SHORTER PERIOD AS OPERATOR SHALL HAVE POSSESSED THE AIRCRAFT) IN ACCORDANCE WITH THE PROVISIONS OF PART 91 OF THE FEDERAL AVIATION REGULATIONS. EACH OF THE AIRCRAFT WILL BE MAINTAINED AND INSPECTED IN COMPLIANCE WITH THE MAINTENANCE AND INSPECTION REQUIREMENTS FOR ALL OPERATIONS TO BE CONDUCTED UNDER THIS AGREEMENT.

OPERATOR AGREES, CERTIFIES AND ACKNOWLEDGES, AS EVIDENCED BY ITS SIGNATURE BELOW, THAT WHENEVER ANY OF THE AIRCRAFT IS OPERATED UNDER THIS AGREEMENT, OPERATOR SHALL BE KNOWN AS, CONSIDERED, AND SHALL IN FACT BE THE OPERATOR OF THE AIRCRAFT, AND THAT OPERATOR UNDERSTANDS ITS RESPONSIBILITIES FOR COMPLIANCE WITH APPLICABLE FEDERAL AVIATION REGULATIONS.

THE PARTIES UNDERSTAND THAT AN EXPLANATION OF FACTORS AND PERTINENT FEDERAL AVIATION REGULATIONS BEARING ON OPERATIONAL CONTROL CAN BE OBTAINED FROM THE NEAREST FAA FLIGHT STANDARDS DISTRICT OFFICE.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed on the day and year first above written. The persons signing below warrant their authority to sign.

Anadarko Petroleum Corporation		JAMES T. HACKETT
By:	/s/ Robert K. Reeves	/s/ James T. Hackett
	Robert K. Reeves
	Senior Vice President, General Counsel
	and Chief Administrative Officer

A legible copy of this Agreement shall be kept in the Aircraft

for all operations conducted hereunder.

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SCHEDULE A

Type of Aircraft	U.S. Registration Number	Manufacturer Serial Number
Cessna Sovereign	N565A	024
Gulfstream G550	N288A	5307
Gulfstream G550	N273A	5273
Gulfstream G550	N203A	5169

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EX-10.(II)

EXHIBIT 10(ii)

TIME SHARING AGREEMENT

THIS TIME SHARING AGREEMENT (the “Agreement”), is made and entered into effective May 15, 2012, by and between Anadarko Petroleum Corporation, a Delaware corporation (the “Operator” or the “Company”), and R. A. Walker (the “Passenger”).

RECITALS

WHEREAS, Operator owns and/or operates the aircraft (individually and/or collectively, as the case may be, the “Aircraft”) listed on Schedule A hereto for business use by employees and non-employee directors of the Company in accordance with 14 C.F.R. Part 91of the Federal Aviation Regulations (as found at 14 C.F.R. Parts 1-199 generally, the “FAR”) and the Company’s Corporate Aircraft Policy regarding the use of corporate aircraft (the “Aircraft Policy”); and

WHEREAS, Operator has the right and lawful authority to enter into time sharing agreements, as provided in §91.501 of the FAR to provide its senior executives with personal travel consistent with the Company’s Aircraft Policy; and

WHEREAS, Operator has agreed to make the Aircraft, with flight crew, when the Aircraft and flight crew are not otherwise needed for business purposes, available to Passenger for Passenger’s personal travel in accordance with the Aircraft Policy on a non-exclusive time-sharing basis in accordance with §91.501 of the FAR; and

WHEREAS, the Passenger agrees to reimburse the Operator for the personal use of the Aircraft for certain flights as permitted under the FAR and as pursuant to the terms of this Agreement, which sets forth the understanding of the parties.

NOW THEREFORE, Operator and Passenger declaring their intention to enter into and be bound by this Agreement, and for the good and valuable consideration set forth below, hereby covenant and agree as follows:

NOW, THEREFORE, the parties hereto agree as follows:

1.        Provision of Aircraft and Crew.  Subject to Aircraft availability, Operator agrees to provide to Passenger the Aircraft and flight crew on a time sharing basis in accordance with the provisions of FAR Part 91, including §§ 91.501(b)(6), 91.501(c)(1) and 91.501(d) of the FAR. Operator shall provide, at its sole expense, qualified flight crew for all flight operations under this Agreement. If Operator is no longer the operator of any of the Aircraft, Schedule A shall be deemed amended to delete any reference to such Aircraft and this Agreement shall be terminated as to such Aircraft but shall remain in full force and effect with respect to each of the other Aircraft identified thereon, if any. No such termination shall affect any of the rights and obligations of the parties accrued or incurred prior to such termination. If Operator becomes the operator of any aircraft not listed on Schedule A hereto, Schedule A shall be modified to include such aircraft as an Aircraft covered by this Agreement, and thereafter this Agreement shall

Anadarko Aircraft Time Sharing Agreement — R. A. Walker Page 1

remain in full force and effect with respect to such Aircraft and each of the other Aircraft identified thereon, if any.

2.        Term.  The term of this Agreement (the “Term”) shall commence on the date hereof and shall continue until terminated by either party on written notice to the other party, such termination to become effective 30 days from the date of the notice; provided, however, that this Agreement may be terminated by Operator on such shorter notice as may be required for Operator to comply with applicable law, regulations, the requirements of any financial institution with a security or other interest in the Aircraft, insurance requirements, or in the event the insurance required hereunder is not in full force and effect. This Agreement shall be terminated immediately upon the termination of Passenger’s employment with Operator. Notwithstanding the foregoing, any provisions directly or indirectly related to Passenger’s payment obligations for flights completed prior to the date of termination and the limitation of liability provisions in Section 10 shall survive the termination of this Agreement.

Reimbursement of Expenses.  For each Trip or Round Trip (as such terms are defined below) conducted under this Agreement, Passenger shall pay Operator an amount (as determined by Operator) equal to the actual expenses of operating such Trip, not to exceed the sum of the following expenses as permitted pursuant to FAR § 91.501(d):

a.	Fuel, oil, lubricants, and other additives;
b.	Travel expenses of the crew, including food, lodging, and ground transportation;
c.	Hangar and tie-down costs away from the Aircraft’s base of operation;
d.	Insurance obtained for the specific flight as per Section 8(b);
e.	Landing fees, airport taxes, and similar assessments;
f.	Customs, foreign permit, and similar fees directly related to the flight;
g.	In-flight food and beverages;
h.	Passenger ground transportation;
i.	Flight planning and weather contract services; and
j.	An additional charge equal to one hundred percent (100%) of the expenses listed in subsection (a) above.

The term “Trip” shall mean a flight from a departure point to a single destination. A “Round Trip” shall mean a flight from a departure point to one destination and back to the same departure point. In the event that Passenger travels from a departure point to multiple destinations, the Operator will provide a separate invoice for each Trip.

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3.        Invoicing and Payment.  All payments to be made to Operator by Passenger hereunder shall be paid in the manner set forth in this Section 3. Operator will pay, or cause to be paid, all expenses related to the operation of the Aircraft hereunder in the ordinary course. Within 30 days of the end of each Trip or Round Trip, Operator shall provide or cause to be provided to Passenger an invoice showing all personal use of the Aircraft by Passenger pursuant to this Agreement during that Trip or Round Trip and a complete accounting detailing all amounts that are payable by Passenger pursuant to Section 2 for that Trip or Round Trip (plus applicable domestic or international air transportation excise taxes, and any other fees, taxes or charges assessed on passengers by and remitted to a government agency or airport authority). Passenger shall pay all amounts due under the invoice in a manner reasonably acceptable to Operator not later than 30 days after receipt thereof. In the event Operator has not received all supplier invoices for reimbursable charges relating to such Trip or Round Trip prior to such invoicing, Operator shall issue a supplemental invoice(s) for such charge(s) to Passenger, and Passenger shall pay each supplemental invoice within 30 days after receipt thereof.

4.        Flight Requests.  Passenger shall provide the Operator’s aviation department or designated point of contact with Trip requests for Passenger’s personal travel to be undertaken pursuant to this Agreement and proposed flight schedules as far in advance of Passenger’s desired departure as possible, and at least 24 hours prior to Passenger’s planned departure or as may be required by law. The advance notice requirement in this Section 4 may be waived by Operator in its discretion. All flight requests for travel under this Agreement shall be in accordance with all reasonable policies established by Operator. Flight requests shall be made by Passenger in a form that is acceptable to Operator. Operator shall have sole and exclusive authority over the scheduling of the Aircraft. Operator shall not be liable to Passenger or any other person for loss, injury, or damage occasioned by the delay or failure to furnish the Aircraft and crew pursuant to this Agreement for any reason. In addition to requested schedules and departure times, Passenger shall provide at least the following information for each proposed flight reasonably in advance of the desired departure time as required by Operator or its flight crew:

a.	Departure point;
b.	Destination;
c.	Date and time of flight;
d.	Number and identity of anticipated passengers;
e.	Nature and extent of luggage and/or cargo expected to be carried;
f.	Date and time of return flight, if any; and
g.	Any other information concerning the proposed flight that may be pertinent to or required by Operator, its flight crew, or governmental entities.

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5.        Operational Authority and Control.

a. Operator shall be responsible for the physical and technical operation of the Aircraft and the safe performance of all flights under this Agreement, and shall retain full authority and control, including exclusive operational control and exclusive possession, command and control of the Aircraft for all flights under this Agreement.

b. Operator shall furnish at its expense a fully qualified flight crew with appropriate credentials to conduct each flight undertaken under this Agreement and included on the insurance policies that Operator is required to maintain hereunder. In accordance with applicable FAR, the qualified flight crew provided by Operator will exercise all required and/or appropriate duties and responsibilities in regard to the safety of each flight conducted hereunder. The pilot-in-command shall have absolute discretion in all matters concerning the preparation of the Aircraft for flight and the flight itself, the load carried and its distribution, the decision whether or not a flight shall be undertaken, the route to be flown, the place where landings shall be made, and all other matters relating to operation of the Aircraft. Passenger specifically agrees that the flight crew shall have final and complete authority to delay or cancel any flight for any reason or condition that in the sole judgment of the pilot-in-command could compromise the safety of the flight, and to take any other action that in the sole judgment of the pilot-in-command is necessitated by considerations of safety. No such action of the pilot-in-command shall create or support any liability to Passenger or any other person for loss, injury, damage or delay. Operator’s operation of the Aircraft hereunder shall be strictly within the guidelines and policies established by Operator and FAR Part 91.

c. Subject to Aircraft and crew availability, Operator shall use its good faith efforts, consistent with its approved policies, to accommodate Passenger’s needs and avoid conflicts in scheduling. Although every good faith effort shall be made to avoid its occurrence, any flights scheduled under this Agreement are subject to cancellation by either party without incurring liability to the other party. In the event of a cancellation, the canceling party shall provide the maximum notice reasonably practicable.

d. In the absence of another flight scheduled on the aircraft by Passenger or another scheduled business trip, the Aircraft may remain at the destination until its next required use. If the next use of the Aircraft is a business use, Operator shall not charge the Passenger for expenses associated with hangar and tie-down costs away from the Aircraft’s base of operation; if, however, the next use of the Aircraft is by Passenger, Operator shall have the option of returning the Aircraft to its base of operations or permitting it

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to remain at the destination. In either event, Passenger shall pay for the associated costs.

6.        Aircraft Maintenance. Operator shall, at its own expense, cause the Aircraft to be inspected, maintained, serviced, repaired, overhauled, and tested in accordance with FAR Part 91 so that the Aircraft will remain in good operating condition and in a condition consistent with its airworthiness certification and shall take such requirements into account in scheduling the Aircraft hereunder, including but not limited compliance with applicable airworthiness directives and service bulletins. Performance of maintenance, preventive maintenance or inspection shall not be delayed or postponed for the purpose of scheduling the Aircraft unless such maintenance or inspection can safely be conducted at a later time in compliance with applicable laws, regulations and requirements, and such delay or postponement is consistent with the sound discretion of the pilot-in-command. In the event that any non-standard maintenance is required during the term and will interfere with Passenger’s requested or scheduled flights, Operator, or Operator’s pilot-in-command, shall notify Passenger of the maintenance required, the effect on the ability to comply with Passenger’s requested or scheduled flights and the manner in which the parties will proceed with the performance of such maintenance and conduct of such flight(s). In no event shall Operator be liable to Passenger or any other person for loss, injury or damage occasioned by the delay or failure to furnish the Aircraft under this Agreement, whether or not maintenance-related.

7.        Insurance.

a. Operator, at its expense, will maintain or cause to be maintained in full force and effect throughout the Term of this Agreement an aviation liability and hull insurance policy including: aviation liability insurance against bodily injury and property damage claims arising out of the use of the Aircraft in an amount not less than $250 Million for each occurrence; and hull insurance for the Aircraft in amounts determined by Operator at its sole discretion. The aviation liability coverage shall include Passenger as an insured, and include a severability of interest provision providing that the insurance shall apply separately to each insured against whom a claim is made, except as respects the limits of liability. The aviation liability and hull insurance coverage shall include provisions whereby the insurer(s) waive all rights of subrogation they may have or acquire against Passenger and shall permit the use of the Aircraft by Operator for compensation or hire as provided in §91.501 of the FAR.

b. Operator shall use reasonable commercial efforts to provide such additional insurance for specific flights under this Agreement as Passenger may reasonably request. Passenger acknowledges that any trips scheduled to areas not currently covered by existing policies may require Operator to purchase additional insurance to comply with applicable regulations, and Operator shall be required to maintain or cause to be maintained such additional insurance. The cost of all flight-specific insurance shall be borne by Passenger as provided in Section 2(d) above.

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8.        Use of Aircraft. Passenger warrants that:

a. Passenger has all necessary powers to enter into the transactions contemplated in this Agreement and has taken actions required to authorize and approve this Agreement;

b. Passenger will use the Aircraft under this Agreement for and only for its own account, including the carriage of its guests, and will not use the Aircraft for the purpose of providing transportation of passengers or cargo for compensation or hire or for common carriage;

c. Passenger will not permit any lien, security interest or other charge or encumbrance to attach against the Aircraft as a result of his actions or inactions, and shall not attempt to convey, mortgage, assign, lease or in any way alienate the Aircraft or Operator’s rights hereunder or create any kind of lien or security interest involving the Aircraft or do anything or take any action that might mature into such a lien;

d. During the Term of this Agreement, Passenger will abide by and conform to all such laws, governmental and airport orders, rules, and regulations as shall from time to time be in effect relating in any way to the operation or use of the Aircraft by a lessee under a time sharing arrangement and all applicable policies of Operator; and

e. Passenger acknowledges that its discretion in determining the origin and destination of flights under this Agreement shall be subject to the following: such origin and destination, and the routes to reach such origin and destination, are not within or over (i) an area of hostilities, (ii) an area excluded from coverage under the insurance policies maintained by Operator with respect to the Aircraft, or (iii) a country or jurisdiction for which exports or transactions are subject to specific restrictions under any United States export or other law or United Nations Security Council Directive, including without limitation, the Trading with the Enemy Act, 50 U.S.C. App. Section 1 et seq., the International Emergency Economic Powers Act, 50 U.S.C. App. Section 1700 et seq., and the Export Administration Act, 50 U.S.C. App. Sections 2401 et seq.

9.        Limitation of Liability.  NEITHER OPERATOR (NOR ITS AFFILIATES) MAKES, HAS MADE OR SHALL BE DEEMED TO MAKE OR HAVE MADE ANY WARRANTY OR REPRESENTATION, EITHER EXPRESS OR IMPLIED, WRITTEN OR ORAL, WITH RESPECT TO ANY AIRCRAFT TO BE USED HEREUNDER OR ANY ENGINE OR COMPONENT THEREOF INCLUDING, WITHOUT LIMITATION, ANY WARRANTY AS TO DESIGN, COMPLIANCE WITH SPECIFICATIONS, QUALITY OF MATERIALS OR WORKMANSHIP, MERCHANTABILITY, FITNESS FOR ANY PURPOSE, USE OR OPERATION, AIRWORTHINESS, SAFETY, PATENT,

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TRADEMARK OR COPYRIGHT INFRINGEMENT OR TITLE. IN NO EVENT SHALL OPERATOR OR ITS AFFILIATES BE LIABLE FOR OR HAVE ANY DUTY FOR INDEMNIFICATION OR CONTRIBUTION TO PASSENGER OR ITS EMPLOYEES, AGENTS OR GUESTS FOR ANY CLAIMED INDIRECT, SPECIAL, CONSEQUENTIAL, OR PUNITIVE DAMAGES, REGARDLESS OF WHETHER IT KNEW OR SHOULD HAVE KNOWN OF THE POSSIBILITY OF SUCH DAMAGE, LOSS OR EXPENSE. The provisions of this Section 9 shall survive the termination or expiration of this Agreement.

10.      Base of Operations. For purposes of this Agreement, the base of operation of the Aircraft is Houston, Texas, provided that such base may be changed at Operator’s sole discretion upon notice from Operator to Passenger.

11.      Notices and Communications. All notices and other communications under this Agreement shall be in writing (except as permitted in Section 4) and shall be given (and shall be deemed to have been duly given upon receipt or refusal to accept receipt) by personal delivery, by facsimile or electronic mail (with a simultaneous confirmation copy sent by first class mail properly addressed and postage prepaid), or by a reputable overnight courier service, addressed as follows:

If to Operator:	Anadarko Petroleum Corporation
	c/o Director of Aviation
	17320 Chanute Road
	Houston, TX 77032
If to Passenger:	R. A. Walker
	1201 Lake Robbins Dr.
	The Woodlands, TX 77380

Or, to such other person or address as either party may from time to time designate in writing to the other party.

12.      Entire Agreement.  This Agreement constitutes the entire understanding between the parties with respect to its subject matter, and there are no representations, warranties, rights, obligations, liabilities, conditions, covenants, or agreements relating to such subject matter that are not expressly set forth herein. There are no third-party beneficiaries of this Agreement.

13.      Further Acts.  Operator and Passenger shall from time to time perform such other and further acts and execute such other and further instruments as may be required by law or may be reasonably necessary (i) to carry out the intent and purpose of this Agreement, and (ii) to establish, maintain and protect the respective rights and remedies of the other party.

14.      Successors and Assigns.  Passenger shall not have the right to assign, transfer or pledge this Agreement. This Agreement shall be binding on the parties hereto and their

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respective heirs, executors, administrators, successors and assigns, and shall inure to the benefit of the parties hereto, and, except as otherwise provided herein, their respective heirs, executors, administrators, other legal representatives, successors and permitted assigns.

15.      Taxes.    Passenger shall be responsible for paying, and Operator shall be responsible for collecting from Passenger and paying over to the appropriate authorities, all applicable Federal excise taxes imposed under IRC §4261 and all sales, use and other excise taxes imposed by any authority in connection with the use of the Aircraft by Passenger hereunder.

16.      Governing Law and Consent to Jurisdiction.  This Agreement shall be governed by the laws of the State of Texas, without regard to its choice of law principles. The parties hereby consent and agree to submit to the exclusive jurisdiction and venue of any state or federal court in Texas in any proceedings hereunder, and each hereby waives any objection to any such proceedings based on improper venue or forum non-conveniens or similar principles. The parties hereto hereby further consent and agree to the exercise of such personal jurisdiction over them by such courts with respect to any such proceedings, waive any objection to the assertion or exercise of such jurisdiction and consent to process being served in any such proceedings in the manner provided for the giving of notices hereunder.

17.      Severability.  If any provision of this Agreement is held to be illegal, invalid or unenforceable, the legality, validity and enforceability of the remaining provisions shall not be affected or impaired.

18.      Amendment or Modification.  This Agreement may be amended, modified or terminated only in writing duly executed by the parties hereto.

19.      Counterparts.  This Agreement may be executed in any number of counterparts, each of which shall be deemed an original, and all of which shall constitute one and the same Agreement, binding on all the parties notwithstanding that all the parties are not signatories to the same counterpart. Each party may transmit its signature by facsimile, and any faxed counterpart of this Agreement shall have the same force and effect as a manually-executed original.

20.      Truth-in-Leasing Compliance.  Operator, on behalf of Passenger, shall (i) deliver a copy of this Agreement to the Federal Aviation Administration, Aircraft Registration Branch, Attn: Technical Section, P.O. Box 25724, Oklahoma City, Oklahoma 73125 within 24 hours of its execution, (ii) notify the appropriate Flight Standards District Office at least 48 hours prior to the first flight under this Agreement of the registration number of the Aircraft, and the location of the airport of departure and departure time for such flight, and (iii) carry a copy of this Agreement onboard the Aircraft at all times when the Aircraft is being operated under this Agreement.

20A.    Subordination; Consent to Assignment.

I. 5169 Aircraft/680-0024 Aircraft

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This Agreement, to the extent it relates to the 5169 Aircraft (as such term is defined below) and/or the 680-0024 Aircraft (as such term is defined below), as the case may be, is subject to the terms and provisions of:

(i)  that certain Aircraft Lease (S/N 5169) dated as of September 26, 2007 (as amended, collectively, the “5169 Aircraft Lease”) between APC Aviation, Inc. (“APC”) and Bank of America, N.A. (“Bank of America”) regarding that certain Gulfstream Aerospace GV-SP (G550) (shown on the International Registry as Gulfstream GV-SP (G550)) aircraft, bearing U.S. Registration Mark N203A (formerly N569GA) and manufacturer’s serial number 5169 (the “5169 Aircraft”);

(ii)  that certain Aircraft Lease (S/N 680-0024) dated as of April 27, 2005 (as amended, collectively, the “680-0024 Aircraft Lease”) between APC and Banc of America Leasing & Capital, LLC (“Banc of America Leasing”) regarding that certain Cessna 680 (a/k/a Citation Sovereign) aircraft bearing U.S. Registration Mark N565A and manufacturer’s serial no. 680-0024 (the “680-0024 Aircraft”);

(iii)  that certain Aircraft Sublease dated as of February 14, 2008 (as amended, collectively, the “5169 Aircraft Sublease”) between APC and Operator regarding the 5169 Aircraft;

(iv) that certain Consent to Sublease and Assignment dated as of February 14, 2008 (the “5169 Consent to Sublease”) between Bank of America, APC and Operator regarding the 5169 Aircraft;

(v) that certain Aircraft Sublease dated as of April 29, 2005 (as amended, collectively, the “680-0024 Aircraft Sublease”) between APC and Operator;

(vi) that certain Consent to Sublease and Assignment dated as of April 29, 2005 (the “680-0024 Consent to Sublease”) between Banc of America Leasing, APC and Operator regarding the 680-0024 Aircraft; and

(vii) any related documents, agreements or instruments of any kind whatsoever relating to any of the 5169 Aircraft Lease, the 680-0024 Aircraft Lease, the 5169 Aircraft Sublease, the 680-0024 Aircraft Sublease, the 5169 Consent to Sublease and/or the 680-0024 Consent to Sublease.

Without limiting the generality of the foregoing, the rights of APC, Operator, Passenger and any other party, person or entity of any kind whatsoever claiming through any of APC, Operator or Passenger with respect to the 5169 Aircraft and/or the 680-0024 Aircraft (and any and all proceeds thereof, including, any insurance proceeds) shall be subject and subordinate in all respects to any and all of the rights, privileges, powers, entitlements, benefits, remedies, title or interests of Bank of America in or to the 5169 Aircraft (and any and all proceeds thereof, including, any insurance proceeds) and of Banc of America Leasing in or to the 680-0024 Aircraft (and any and all proceeds thereof, including, any insurance proceeds), including, all of their respective rights and remedies under or in connection with any of the 5169 Aircraft Lease, the 680-0024 Aircraft Lease, the 5169 Aircraft Sublease, the 680-0024 Aircraft Sublease, the 5169 Consent to Sublease, the 680-0024 Consent to Sublease and any related documents, agreements or instruments of any kind whatsoever (including, without limitation, Bank of America’s and Banc of America

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Leasing’s respective right to repossess the 5169 Aircraft and/or 680-0024 Aircraft, as the case may be, and to terminate this Agreement with respect to the 5169 Aircraft and/or 680-0024 Aircraft, as the case may be, pursuant to the 5169 Aircraft Lease, the 680-0024 Aircraft Lease and this Section). In addition, and notwithstanding anything to the contrary set forth in this Agreement or otherwise, upon the occurrence of any Event of Default (as such term is defined in each of the 5169 Aircraft Lease and the 680-0024 Aircraft Lease) under or in connection with 5169 Aircraft Lease and/or the 680-0024 Aircraft Lease, this Agreement shall automatically and immediately terminate with respect to the 5169 Aircraft and/or 680-0024 Aircraft, as the case may be.

II. 5307 Aircraft

This Agreement, to the extent it relates to the 5307 Aircraft (as such term is defined below), is subject to the terms and provisions of:

(i)  that certain Aircraft Lease (S/N 5307) dated as of November 15, 2010 (as amended, the “5307 Aircraft Lease”) between APC Aviation, Inc. (“APC”) and Wells Fargo Equipment Finance, Inc. (“WFEFI”) regarding that certain Gulfstream Aerospace GV-SP (G550) (shown on the International Registry as Gulfstream GV-SP (G550)) aircraft, bearing U.S. Registration Mark N288A (formerly N507GA) and manufacturer’s serial number 5307 (the “5307 Aircraft”);

(ii)    that certain Aircraft Sublease dated as of March 3, 2011 (as amended, collectively, the “5307 Aircraft Sublease”) between APC and Operator regarding the 5307 Aircraft;

(iii) that certain Collateral Assignment of Agreement dated March 3, 2011 between APC and WFEFI and

(iv)  any related documents, agreements or instruments of any kind whatsoever relating to any of the 5307 Aircraft Lease and the 5307 Aircraft Sublease

(collectively, the “5307 Documents”).

Without limiting the generality of the foregoing, the rights of APC, Operator, Passenger and any other party, person or entity of any kind whatsoever claiming through any of APC, Operator or Passenger with respect to the 5307 Aircraft (and any and all proceeds thereof, including, any insurance proceeds) shall be subject and subordinate in all respects to any and all of the rights, privileges, powers, entitlements, benefits, remedies, title or interests of WFEFI in or to the 5307 Aircraft (and any and all proceeds thereof, including, any insurance proceeds), including, all of WFEFI’s rights and remedies under or in connection with any of the 5307 Documents (including, without limitation, WFEFI’s right to repossess the 5307 Aircraft and to terminate this Agreement with respect to the 5307 Aircraft. In addition, and notwithstanding anything to the contrary set forth in this Agreement or otherwise, upon the occurrence of any Event of Default (as such term is defined in the 5307 Aircraft Lease and the 5307 Aircraft Sublease), this Agreement shall automatically and immediately terminate with respect to the 5307 Aircraft.

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Without limiting the generality of any terms or provisions of this Agreement or otherwise, Passenger hereby acknowledges and consents to the assignment by Operator of Operator’s right, title and interest in and to this Agreement (i) as it relates to the 5169 Aircraft to Bank of America and its successors and assigns, (ii) as it relates to the 680-0024 Aircraft to Banc of America Leasing and its successors and assigns and (iii) as it relates to the 5307 Aircraft to WFEFI and its successors and assigns.

[Truth-in-Leasing and Signature Page Follows]

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21.      TRUTH-IN-LEASING STATEMENT PURSUANT TO SECTION 91.23 OF THE FEDERAL AVIATION REGULATIONS.

OPERATOR CERTIFIES THAT EACH OF THE AIRCRAFT HAS BEEN INSPECTED AND MAINTAINED DURING THE 12-MONTH PERIOD PRECEDING THE DATE OF THIS AGREEMENT (OR SUCH SHORTER PERIOD AS OPERATOR SHALL HAVE POSSESSED THE AIRCRAFT) IN ACCORDANCE WITH THE PROVISIONS OF PART 91 OF THE FEDERAL AVIATION REGULATIONS. EACH OF THE AIRCRAFT WILL BE MAINTAINED AND INSPECTED IN COMPLIANCE WITH THE MAINTENANCE AND INSPECTION REQUIREMENTS FOR ALL OPERATIONS TO BE CONDUCTED UNDER THIS AGREEMENT.

OPERATOR AGREES, CERTIFIES AND ACKNOWLEDGES, AS EVIDENCED BY ITS SIGNATURE BELOW, THAT WHENEVER ANY OF THE AIRCRAFT IS OPERATED UNDER THIS AGREEMENT, OPERATOR SHALL BE KNOWN AS, CONSIDERED, AND SHALL IN FACT BE THE OPERATOR OF THE AIRCRAFT, AND THAT OPERATOR UNDERSTANDS ITS RESPONSIBILITIES FOR COMPLIANCE WITH APPLICABLE FEDERAL AVIATION REGULATIONS.

THE PARTIES UNDERSTAND THAT AN EXPLANATION OF FACTORS AND PERTINENT FEDERAL AVIATION REGULATIONS BEARING ON OPERATIONAL CONTROL CAN BE OBTAINED FROM THE NEAREST FAA FLIGHT STANDARDS DISTRICT OFFICE.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed on the day and year first above written. The persons signing below warrant their authority to sign.

Anadarko Petroleum Corporation		R. A. WALKER
By:	/s/ Robert K. Reeves	/s/ R. A. Walker
	Robert K. Reeves
	Senior Vice President, General Counsel
	and Chief Administrative Officer

A legible copy of this Agreement shall be kept in the Aircraft

for all operations conducted hereunder.

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SCHEDULE A

Type of Aircraft	U.S. Registration Number	Manufacturer Serial Number
Cessna Sovereign	N565A	024
Gulfstream G550	N288A	5307
Gulfstream G550	N273A	5273
Gulfstream G550	N203A	5169

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EX-31.(I)

EXHIBIT 31(i)

CERTIFICATIONS

I, R. A. Walker, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Anadarko Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations, and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 8, 2012

/s/ R. A. WALKER

R. A. Walker

President and Chief Executive Officer

EX-31.(II)

EXHIBIT 31(ii)

CERTIFICATIONS

I, Robert G. Gwin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Anadarko Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations, and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 8, 2012

/s/ ROBERT G. GWIN

Robert G. Gwin

Senior Vice President, Finance and Chief Financial Officer        

EX-32

EXHIBIT 32

SECTION 1350 CERTIFICATION OF PERIODIC REPORT

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, R. A. Walker, President and Chief Executive Officer of Anadarko Petroleum Corporation (Company) and Robert G. Gwin, Senior Vice President, Finance and Chief Financial Officer of the Company, certify that:

(1) the Quarterly Report on Form 10-Q of the Company for the period ending June 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (Report), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

August 8, 2012
	/s/ R. A. WALKER
	R. A. Walker
	President and Chief Executive Officer
August 8, 2012
	/s/ ROBERT G. GWIN
	Robert G. Gwin
	Senior Vice President, Finance and Chief Financial Officer

This certification is made solely pursuant to 18 U.S.C. Section 1350, and not for any other purpose. A signed original of this written statement required by Section 906 will be retained by Anadarko and furnished to the Securities and Exchange Commission or its staff upon request.

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Derivative Instruments - Interest Rate Derivative Positions Outstanding Table (Detail) (USD $)	Jun. 30, 2012
Reference Period Start End Dates - October 2012 to October 2022 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 250,000,000
Weighted-average interest rate for interest-rate swap	4.91%
Reference Period Start End Dates - October 2012 to October 2042 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	750,000,000
Weighted-average interest rate for interest-rate swap	4.80%
Reference Period Start End Dates - June 2014 to June 2024 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	750,000,000
Weighted-average interest rate for interest-rate swap	6.00%
Reference Period Start End Dates - June 2014 to June 2044 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 1,100,000,000
Weighted-average interest rate for interest-rate swap	5.57%

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Income Taxes - Summary of Income Tax Expense (Benefit) and Effective Tax Rates Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income tax expense (benefit)	$ 164	$ 440	$ 516	$ 706
Effective tax rate	174.00%	44.00%	20.00%	47.00%

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Stockholders' Equity - Reconciliation between Basic and Diluted EPS Table (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Net income (loss)
Net income (loss) attributable to common stockholders	$ (89)		$ 544		$ 2,067		$ 760
Less: Distributions on participating securities			1		1		1
Less: Undistributed income allocated to participating securities			3		12		4
Basic	(89)		540		2,054		755
Diluted	$ (89)		$ 540		$ 2,054		$ 755
Shares
Average number of common shares outstanding - basic	500		498		499		497
Dilutive effect of stock options and performance-based stock awards			2		2		2
Average number of common shares outstanding - diluted	500		500		501		499
Excluded	12	[1]	6	[1]	5	[1]	6	[1]
Net income (loss) per common share
Basic	$ (0.18)		$ 1.09		$ 4.11		$ 1.52
Diluted	$ (0.18)		$ 1.08		$ 4.10		$ 1.51
Dividends per common share	$ 0.09		$ 0.09		$ 0.18		$ 0.18

[1] Inclusion of certain shares would have had an anti-dilutive effect.

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Income Taxes - Additional Information (Detail)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Income Tax Disclosure [Abstract]
U.S. federal statutory rate	35.00%	35.00%	35.00%	35.00%

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Debt and Interest Expense - Western Gas Partners, LP (Detail) (USD $)					6 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 Western Gas Partners Limited Partnership [Member]	Dec. 31, 2011 Western Gas Partners Limited Partnership [Member]	Jun. 30, 2012 Western Gas Partners Limited Partnership [Member] Senior Notes, 4 Point 00 Percent, Due 2022 [Member]
Line of Credit Facility [Line Items]
Debt instrument, principal amount	$ 16,541,000,000	$ 16,952,000,000	$ 1,020,000,000	$ 500,000,000	$ 520,000,000
Debt instrument, stated interest rate					4.00%
Debt instrument, maturity date					Apr. 01, 2022

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Inventories - Major Classes of Inventories (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Energy Related Inventory [Abstract]
Crude oil	$ 69	$ 103
Natural gas	31	49
NGLs	41	59
Total	$ 141	$ 211

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Segment Information - Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) before Income Taxes Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) before Income Taxes [Abstract]
Income (loss) before income taxes	$ 94		$ 1,002		$ 2,629		$ 1,505
Exploration expense	1,121		236		1,365		415
DD&A	1,027		985		1,957		1,970
Impairments	112		102		162		104
Deepwater Horizon settlement and related costs	3	[1]	9	[1]	11	[1]	35	[1]
Algeria exceptional profits tax settlement					(1,804)	[2]
Interest expense	190		216		376		436
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net					83		75
Less: Net income attributable to noncontrolling interests	19		18		46		39
Consolidated Adjusted EBITDAX	2,230		2,356		4,485		4,503
Tronox Litigation [Member]
Segment Reporting Information [Line Items]
Tronox-related contingent loss	(525)	[2]			(250)	[2]
Nondesignated [Member]
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net	225		(178)		83		75
Realized (gains) losses on derivatives, net	(262)		(21)		(401)		(66)
Nondesignated [Member] | (Gains) Losses on Other Derivatives, net [Member] | Interest Rate Contract and Other [Member]
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net	374		142		138		83
Realized (gains) losses on derivatives, net	$ 2	[2]	$ 2	[2]	$ 2	[2]	$ 2	[2]

[1] In the third quarter of 2011, the Company revised the definition of Adjusted EBITDAX to exclude Deepwater Horizon settlement and related costs. Prior periods have been adjusted to reflect this change.

[2] In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. Prior periods have been adjusted to reflect this change.

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Inventories (Tables)

6 Months Ended

Jun. 30, 2012

Table Text Block [Abstract]

Inventory Disclosure Table

	June 30,		December 31,
millions	2012		2011
Crude oil	$	69	$	103
Natural gas		31		49
NGLs		41		59
Total	$	141	$	211

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Contingencies - Deepwater Horizon Events (Detail) (USD $)	Sep. 30, 2011 Macondo Exploration Well [Member]	Jun. 30, 2012 Deepwater Horizon [Member] BP indemnification liability [Member]
Loss Contingencies [Line Items]
Anadarko's non-operated interest	25.00%
Loss contingency accrual at carrying value		$ 0

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Derivative Instruments - Fair Value of Derivative Financial Assets and Liabilities by Level within Fair Value Hierarchy Table (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012		Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	$ 986		$ 1,080
Gross derivative liabilities	(1,606)		(1,617)
Derivative assets netting	(252)	[1]	(374)	[1]
Derivative liabilities netting	252	[1]	374	[1]
Cash collateral from counterparties	(41)		(52)
Cash collateral held by counterparties	1		137
Derivative financial assets	693		654
Derivative financial liabilities	(1,353)		(1,106)
Interest Rate Contract and Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash collateral held by counterparties			130
Derivative financial liabilities	(1,337)		(1,069)
Financial Institutions [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	(219)	[1]	(323)	[1]
Derivative liabilities netting	219	[1]	361	[1]
Cash collateral from counterparties	(41)		(52)
Cash collateral held by counterparties	1		7
Derivative financial assets	625		537
Derivative financial liabilities			(11)
Other Counterparties [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	(33)	[1]	(51)	[1]
Derivative liabilities netting	33	[1]	13	[1]
Derivative financial assets	68		117
Derivative financial liabilities	(16)		(26)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	2		3
Gross derivative liabilities	(3)		(4)
Fair Value, Inputs, Level 1 [Member] | Financial Institutions [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	2		3
Gross derivative liabilities	(3)		(4)
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	984		1,077
Gross derivative liabilities	(1,603)		(1,613)
Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract and Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative liabilities	(1,337)		(1,199)
Fair Value, Inputs, Level 2 [Member] | Financial Institutions [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	883		909
Gross derivative liabilities	(217)		(375)
Fair Value, Inputs, Level 2 [Member] | Other Counterparties [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	101		168
Gross derivative liabilities	$ (49)		$ (39)

[1] Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

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Derivative Instruments - Derivative Instruments Related to Natural Gas Production/Processing Derivative Activities Table (Detail) (Natural Gas [Member])	Jun. 30, 2012
Contracted Commodities in 2012 [Member] | Three-Way Collars [Member] | Offsetting Purchased and Sold Positions For Five Hundred Thousand Million British Thermal Units Per Day [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments	0	[1]
Contracted Commodities in 2012 [Member] | Fixed-Price Contracts [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments	1,000
Average price per MMBtu
Average price per MMBtu	4.69
Contracted Commodities in 2013 [Member] | Three-Way Collars [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments	450
Contracted Commodities in 2013 [Member] | Three-Way Collars [Member] | Call Options Sold [Member]
Average price per MMBtu
Average ceiling price	6.57
Contracted Commodities in 2013 [Member] | Three-Way Collars [Member] | Put Options Purchased [Member]
Average price per MMBtu
Average floor price	5.00
Contracted Commodities in 2013 [Member] | Three-Way Collars [Member] | Put Options Sold [Member]
Average price per MMBtu
Average floor price	4.00

[1] Includes the effects of offsetting purchased and sold natural-gas three-way collars of 500,000 MMBtu/d.

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Contingencies - Other Litigation (Detail) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Loss Contingencies [Line Items]
Amount of tax in dispute	$ 1,661,000,000	$ 1,516,000,000
Peregrino Litigation [Member]
Loss Contingencies [Line Items]
Amount of tax in dispute	169,000,000
Loss contingency accrual at carrying value	$ 0

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Debt and Interest Expense - Interest Expense Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Interest Expense [Abstract]
Current debt, long-term debt, and other	$ 236	$ 250	$ 486	$ 498
Capitalized interest	(46)	(34)	(110)	(62)
Total interest expense	$ 190	$ 216	$ 376	$ 436

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Cash Flows from Operating Activities
Net income (loss)	$ 2,113	$ 799
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	1,957	1,970
Deferred income taxes	143	258
Dry hole expense and impairments of unproved properties	1,187	227
Impairments	162	104
(Gains) losses on divestitures, net	29	18
Unrealized (gains) losses on derivatives, net	83	75
Other	120	61
Changes in assets and liabilities:
Deepwater Horizon settlement and related costs	24
Algeria exceptional profits tax settlement	(1,691)
Tronox-related contingent loss	(250)
(Increase) decrease in accounts receivable	351	(535)
Increase (decrease) in accounts payable and accrued expenses	(486)	241
Other items - net	148	(92)
Net cash provided by (used in) operating activities	3,890	3,126
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	(3,553)	(2,799)
Acquisition of midstream businesses		(804)
Divestitures of properties and equipment and other assets	258	55
Other - net	(112)	(41)
Net cash provided by (used in) investing activities	(3,407)	(3,589)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	886	1,046
Repayments of debt	(1,305)	(859)
Increase (decrease) in accounts payable, banks	(39)	(38)
Dividends paid	(91)	(90)
Repurchase of common stock	(23)	(30)
Issuance of common stock, including tax benefit on stock option exercises	38	49
Sale of subsidiary units	212	130
Distributions to noncontrolling interest owners	(52)	(37)
Contributions from noncontrolling interest owners	11	4
Net cash provided by (used in) financing activities	(363)	175
Effect of Exchange Rate Changes on Cash	(23)	14
Net Increase (Decrease) in Cash and Cash Equivalents	97	(274)
Cash and Cash Equivalents at Beginning of Period	2,697	3,680
Cash and Cash Equivalents at End of Period	$ 2,794	$ 3,406

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Debt and Interest Expense - Outstanding Debt Table (Detail) (USD $)	Jun. 30, 2012		Mar. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Principal	$ 16,541,000,000			$ 16,952,000,000
Net unamortized discounts and premiums	(1,709,000,000)	[1]		(1,722,000,000)	[1]
Total borrowings	14,832,000,000		15,386,000,000	15,230,000,000
Less: Current portion of long-term debt	1,739,000,000			170,000,000
Total long-term debt	13,093,000,000			15,060,000,000
Western Gas Partners Limited Partnership [Member]
Debt Instrument [Line Items]
Principal	1,020,000,000			500,000,000
Long-term notes and debentures [Member]
Debt Instrument [Line Items]
Principal	$ 15,521,000,000			$ 16,452,000,000

[1] Unamortized discounts and premiums are amortized over the term of the related debt.

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2012

Table Text Block [Abstract]

Schedule of Income Taxes and Effective Tax Rate

	Three Months Ended						Six Months Ended
	June 30,						June 30,
millions except percentages	2012			2011			2012			2011
Income tax expense (benefit)	$	164		$	440		$	516		$	706
Effective tax rate		174	%		44	%		20	%		47	%

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Stockholders' Equity (Tables)

6 Months Ended

Jun. 30, 2012

Table Text Block [Abstract]

Earnings Per Share Table

			Three Months Ended				Six Months Ended
			June 30,				June 30,
millions except per-share amounts			2012		2011		2012		2011
Net income (loss)
	Net income (loss) attributable to common stockholders		$	(89)	$	544	$	2,067	$	760
	Less: Distributions on participating securities			—		1		1		1
	Less: Undistributed income allocated to participating securities			—		3		12		4
Basic			$	(89)	$	540	$	2,054	$	755
Diluted			$	(89)	$	540	$	2,054	$	755
Shares
	Average number of common shares outstanding—basic			500		498		499		497
	Dilutive effect of stock options and performance-based
		stock awards		—		2		2		2
	Average number of common shares outstanding—diluted			500		500		501		499
	Excluded (1)			12		6		5		6
Net income (loss) per common share
	Basic		$	(0.18)	$	1.09	$	4.11	$	1.52
	Diluted		$	(0.18)	$	1.08	$	4.10	$	1.51
	Dividends per common share		$	0.09	$	0.09	$	0.18	$	0.18

_________________________________________________________

(1)Inclusion of certain shares would have had an anti-dilutive effect.

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Supplemental Cash Flow Information - Supplemental Cash Flow Information Table (Detail) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2011 Wattenberg Natural-Gas Processing Plant [Member]	May 31, 2011 Wattenberg Natural-Gas Processing Plant [Member]
Cash paid (received)
Interest	$ 354	$ 415
Income taxes	(40)	82
Non-cash investing activities
Fair value of properties and equipment received in non-cash exchange transactions	31	4
Business Acquisition [Line Items]
Gain related to the fair-value remeasurement of Anadarko's pre-acquisition 7% equity interest in the Wattenberg Plant			$ 21
Business combination, equity interest in acquiree, percentage				7.00%

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Debt and Interest Expense - Anadarko (Detail) (USD $)	Jun. 30, 2012	Jun. 30, 2012 Fair Value, Inputs, Level 2 [Member]	Dec. 31, 2011 Fair Value, Inputs, Level 2 [Member]	Jun. 30, 2012 Five Billion Dollar Facility [Member]	Jun. 30, 2012 LOC Facility [Member]	Jun. 19, 2012 LOC Facility [Member]
Debt Instrument [Line Items]
Total borrowings, fair value		$ 17,100,000,000	$ 17,300,000,000
Line of credit, outstanding borrowings				1,700,000,000
Line of credit, interest rate				1.75%
Line of credit, available borrowing capacity				3,200,000,000
Line of credit, maximum capacity				5,000,000,000
Letter of credit facility, borrowing capacity covenant					150,000,000
Letter of credit facility, maximum capacity					150,000,000	400,000,000
Demand deposits serving as compensating balances for outstanding letters of credit included in cash and cash equivalents	$ 23,000,000

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2012

Table Text Block [Abstract]

Supplemental Cash Flow Table

			Six Months Ended
			June 30,
millions			2012		2011
Cash paid (received)
	Interest		$	354	$	415
	Income taxes		$	(40)	$	82
Non-cash investing activities
	Fair value of properties and equipment received in non-cash exchange transactions		$	31	$	4
	Gain related to the fair-value remeasurement of Anadarko's pre-acquisition 7% equity
		interest in the Wattenberg Plant	$	—	$	21

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2012

Table Text Block [Abstract]

Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) before Income Taxes

	Three Months Ended				Six Months Ended
	June 30,				June 30,
millions	2012		2011		2012		2011
Income (loss) before income taxes	$	94	$	1,002	$	2,629	$	1,505
Exploration expense		1,121		236		1,365		415
DD&A		1,027		985		1,957		1,970
Impairments		112		102		162		104
Deepwater Horizon settlement and related costs (1)		3		9		11		35
Algeria exceptional profits tax settlement (2)		—		—		(1,804)		—
Tronox-related contingent loss (2)		(525)		—		(250)		—
Interest expense		190		216		376		436
Unrealized (gains) losses on derivatives, net		225		(178)		83		75
Realized (gains) losses on other derivatives, net (2)		2		2		2		2
Less: Net income attributable to noncontrolling interests		19		18		46		39
Consolidated Adjusted EBITDAX	$	2,230	$	2,356	$	4,485	$	4,503

_________________________________________________________

(1)In the third quarter of 2011, the Company revised the definition of Adjusted EBITDAX to exclude Deepwater Horizon settlement and related costs. Prior periods havebeen adjusted to reflect this change.

(2)In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. Prior periods have been adjusted to reflect this change.

Schedule of Segment Reporting Information, by Segment

		Oil and Gas						Other and
		Exploration						Intersegment
millions		& Production		Midstream		Marketing		Eliminations		Total
Three Months Ended June 30, 2012
Sales revenues		$	1,888	$	81	$	1,231	$	—	$	3,200
Intersegment revenues			1,035		220		(1,124)		(131)		—
Gains (losses) on divestitures and other, net			(12)		(1)		—		35		22
	Total revenues and other		2,911		300		107		(96)		3,222
Operating costs and expenses (1)			873		174		158		33		1,238
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(263)		(263)
Other (income) expense, net (2)			—		—		—		6		6
Net income attributable to
	noncontrolling interests		—		19		—		—		19
	Total expenses and other		873		193		158		(224)		1,000
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		8		—		8
Adjusted EBITDAX		$	2,038	$	107	$	(43)	$	128	$	2,230
Three Months Ended June 30, 2011
Sales revenues		$	2,071	$	98	$	1,565	$	—	$	3,734
Intersegment revenues			1,330		223		(1,448)		(105)		—
Gains (losses) on divestitures and other, net			(114)		20		—		36		(58)
	Total revenues and other		3,287		341		117		(69)		3,676
Operating costs and expenses (1)			921		199		135		88		1,343
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(27)		(27)
Other (income) expense, net (2)			—		—		—		(18)		(18)
Net income attributable to
	noncontrolling interests		—		18		—		—		18
	Total expenses and other		921		217		135		43		1,316
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(4)		—		(4)
Adjusted EBITDAX		$	2,366	$	124	$	(22)	$	(112)	$	2,356

_________________________________________________________

(1) Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.

(2) Other (income) expense, net excludes Tronox-related contingent loss since this expense is excluded from Adjusted EBITDAX.

		Oil and Gas						Other and
		Exploration						Intersegment
millions		& Production		Midstream		Marketing		Eliminations		Total
Six Months Ended June 30, 2012
Sales revenues		$	3,787	$	168	$	2,657	$	—	$	6,612
Intersegment revenues			2,209		469		(2,419)		(259)		—
Gains (losses) on divestitures and other, net			(29)		(2)		—		88		57
	Total revenues and other		5,967		635		238		(171)		6,669
Operating costs and expenses (1)			1,799		363		312		81		2,555
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(400)		(400)
Other (income) expense, net (2)			—		—		—		(4)		(4)
Net income attributable to
	noncontrolling interests		—		46		—		—		46
	Total expenses and other		1,799		409		312		(323)		2,197
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		13		—		13
Adjusted EBITDAX		$	4,168	$	226	$	(61)	$	152	$	4,485
Six Months Ended June 30, 2011
Sales revenues		$	3,867	$	162	$	2,929	$	—	$	6,958
Intersegment revenues			2,455		433		(2,680)		(208)		—
Gains (losses) on divestitures and other, net			(114)		20		—		65		(29)
	Total revenues and other		6,208		615		249		(143)		6,929
Operating costs and expenses (1)			1,762		365		271		110		2,508
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(84)		(84)
Other (income) expense, net (2)			—		—		—		(42)		(42)
Net income attributable to
	noncontrolling interests		—		39		—		—		39
	Total expenses and other		1,762		404		271		(16)		2,421
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(5)		—		(5)
Adjusted EBITDAX		$	4,446	$	211	$	(27)	$	(127)	$	4,503

_________________________________________________________

(1) Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.

(2) Other (income) expense, net excludes Tronox-related contingent loss since this expense is excluded from Adjusted EBITDAX.

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CONSOLIDATED STATEMENT OF EQUITY (Parenthetical) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Statement of Stockholders' Equity [Abstract]
Increase to paid-in capital for change in ownership interest upon equity issuance	$ 34
Net income (loss) attributable to common stockholders, including increase to paid-in capital related to subsidiary equity transactions	$ 2,101

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Pension Plans and Other Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2012

Table Text Block [Abstract]

Components of Net Periodic Benefit Cost Table

	Pension Benefits				Other Benefits
millions	2012		2011		2012		2011
Three Months Ended June 30
Service cost	$	19	$	19	$	3	$	2
Interest cost		22		22		4		4
Expected return on plan assets		(22)		(22)		—		—
Amortization of net actuarial loss (gain)		23		21		—		—
Amortization of net prior service cost (credit)		—		—		1		—
Net periodic benefit cost	$	42	$	40	$	8	$	6

Six Months Ended June 30
Service cost	$	38	$	39	$	5	$	4
Interest cost		43		43		8		8
Expected return on plan assets		(45)		(43)		—		—
Amortization of net actuarial loss (gain)		46		42		—		—
Amortization of net prior service cost (credit)		—		1		1		—
Net periodic benefit cost	$	82	$	82	$	14	$	12

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Derivative Instruments - Effect of Derivative Instruments - Balance Sheet Table (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Derivatives Fair Value [Line Items]
Gross derivative assets	$ 986	$ 1,080
Gross derivative liabilities	(1,606)	(1,617)
Commodity Contract [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	986	1,080
Gross derivative liabilities	(269)	(418)
Commodity Contract [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	860	924
Gross derivative liabilities	(212)	(353)
Commodity Contract [Member] | Other Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	111	150
Gross derivative liabilities	(25)	(15)
Commodity Contract [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	8	5
Gross derivative liabilities	(18)	(33)
Commodity Contract [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	7	1
Gross derivative liabilities	(14)	(17)
Interest Rate Contract and Other [Member]
Derivatives Fair Value [Line Items]
Gross derivative liabilities	(1,337)	(1,199)
Interest Rate Contract and Other [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative liabilities	(439)	(391)
Interest Rate Contract and Other [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative liabilities	$ (898)	$ (808)

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Contingencies - Algeria Exceptional Profits Tax Settlement (Detail) (USD $) In Millions, unless otherwise specified	6 Months Ended			3 Months Ended	6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011	Mar. 31, 2012 Algeria Exceptional Profits Tax Settlement [Member]	Jun. 30, 2012 Algeria Exceptional Profits Tax Settlement [Member]	Jun. 30, 2012 Algeria Exceptional Profits Tax Settlement [Member] Oil and Gas Exploration and Production Reporting Segment [Member]
Commitments and Contingencies [Line Items]
Algeria exceptional profits tax settlement, current	$ 1,629			$ 1,700		$ 1,629
(Increase) decrease in accounts payable and accrued expenses	486		(241)	62
Algeria exceptional profits tax settlement	$ 1,804	[1]			$ 1,804

[1] In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. Prior periods have been adjusted to reflect this change.

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Revenues and Other
Natural-gas sales	$ 496		$ 870		$ 1,069		$ 1,724
Oil and condensate sales	2,222		2,236		4,466		4,043
Natural-gas liquids sales	282		370		624		703
Gathering, processing, and marketing sales	200		258		453		488
Gains (losses) on divestitures and other, net	22		(58)		57		(29)
Total	3,222		3,676		6,669		6,929
Costs and Expenses
Oil and gas operating	249		236		491		468
Oil and gas transportation and other	223		207		463		416
Exploration	1,121		236		1,365		415
Gathering, processing, and marketing	178		205		367		376
General and administrative	262		282		531		491
Depreciation, depletion, and amortization	1,027		985		1,957		1,970
Other taxes	326		413		703		757
Impairments	112		102		162		104
Algeria exceptional profits tax settlement					(1,804)	[1]
Deepwater Horizon settlement and related costs	3	[2]	9	[2]	11	[2]	35	[2]
Total	3,501		2,675		4,246		5,032
Operating Income (Loss)	(279)		1,001		2,423		1,897
Other (Income) Expense
Interest expense	190		216		376		436
Other (income) expense, net	(519)		(18)		(254)		(42)
Total	(373)		(1)		(206)		392
Income (Loss) Before Income Taxes	94		1,002		2,629		1,505
Income Tax Expense (Benefit)	164		440		516		706
Net Income (Loss)	(70)		562		2,113		799
Net Income Attributable to Noncontrolling Interests	19		18		46		39
Net Income (Loss) Attributable to Common Stockholders	(89)		544		2,067		760
Per Common Share
Net income (loss) attributable to common stockholders - basic	$ (0.18)		$ 1.09		$ 4.11		$ 1.52
Net income (loss) attributable to common stockholders - diluted	$ (0.18)		$ 1.08		$ 4.10		$ 1.51
Average Number of Common Shares Outstanding - Basic	500		498		499		497
Average Number of Common Shares Outstanding - Diluted	500		500		501		499
Dividends (per Common Share)	$ 0.09		$ 0.09		$ 0.18		$ 0.18
Commodity Contract [Member] | (Gains) Losses on Commodity Derivatives, net [Member]
(Gains) losses on derivative instruments, net	(420)		(343)		(468)		(87)
Interest Rate Contract and Other [Member] | (Gains) Losses on Other Derivatives, net [Member]
(Gains) losses on derivative instruments, net	$ 376		$ 144		$ 140		$ 85

[1] In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. Prior periods have been adjusted to reflect this change.

[2] In the third quarter of 2011, the Company revised the definition of Adjusted EBITDAX to exclude Deepwater Horizon settlement and related costs. Prior periods have been adjusted to reflect this change.

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Debt and Interest Expense - Debt Activity Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Jun. 30, 2012	Mar. 31, 2012
Debt Instrument [Line Items]
Carrying value, beginning balance	$ 15,386	$ 15,230
Other, net	9	8
Carrying value, ending balance	14,832	15,386
Line of Credit Facility [Member] | Western Gas Partners Limited Partnership [Member]
Debt Instrument [Line Items]
Borrowings	55	319
Repayments	(334)	(40)
Senior Notes, 6 Point 125 Percent, Due 2012 [Member]
Debt Instrument [Line Items]
Repayments		(131)
Senior Notes, 4 Point 00 Percent, Due 2022 [Member] | Western Gas Partners Limited Partnership [Member]
Debt Instrument [Line Items]
Issuance	516
Five Billion Dollar Facility [Member]
Debt Instrument [Line Items]
Repayments	$ (800)

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.1	$ 0.1
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	517,600,000	516,000,000
Treasury stock, shares	17,900,000	17,600,000

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Pension Plans and Other Postretirement Benefits - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Pension Plans, Defined Benefit [Member] | Funded Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 32
Expected employer contributions during the remainder of 2012	88
Pension Plans, Defined Benefit [Member] | Unfunded Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	2
Expected employer contributions during the remainder of 2012	32
Other Postretirement Benefit Plans, Defined Benefit [Member] | Unfunded Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	9
Expected employer contributions during the remainder of 2012	$ 10

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Noncontrolling Interests - Additional Information (Detail) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended		3 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 Western Gas Partners Limited Partnership [Member]	Jun. 30, 2012 Western Gas Partners Limited Partnership [Member] Limited Partner [Member]	Jun. 30, 2012 Western Gas Partners Limited Partnership [Member] General Partner [Member]
Noncontrolling Interest [Line Items]
Common units issued to the public			5,000,000
Net proceeds raised from offering by subsidiary	$ 212	$ 130	$ 212
Anadarko's ownership interest in Western Gas Partners, LP				41.40%	2.00%

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Segment Information

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Segment Information

13.  Segment Information

Anadarko's business segments are separately managed due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company's three reporting segments are oil and gas exploration and production, midstream, and marketing. The oil and gas exploration and production segment explores for and produces natural gas, crude oil, condensate, and NGLs. The midstream segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production. The midstream reporting segment consists of two operating segments, WES and other midstream activities, which are aggregated into one reporting segment due to similar financial and operating characteristics. The marketing segment sells most of Anadarko's production, as well as third-party purchased volumes.

To assess the performance of Anadarko's operating segments, the chief operating decision maker analyzes income (loss) before income taxes; interest expense; exploration expense;depreciation, depletion, and amortization (DD&A); impairments; Deepwater Horizon settlement and related costs;Algeria exceptional profits tax settlement; Tronox-related contingent loss; unrealized (gains) losses on derivatives, net; and realized (gains) losses on other derivatives, net, less net income attributable to noncontrolling interests (Adjusted EBITDAX). The Company's definition of Adjusted EBITDAX excludes interest expense to allow for assessment of segment operating results without regard to Anadarko's financing methods or capital structure. Adjusted EBITDAX also excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Anadarko's definition of Adjusted EBITDAX excludes Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, and Tronox-related contingent loss, as these costs are outside the normal operations of the Company. See Note 10—Contingencies. Finally, unrealized (gains) losses on derivatives, net andrealized (gains) losses on other derivatives, netare excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company's financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company's ability to incur and service debt, fund capital expenditures, and make distributions to stockholders.

Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income or cash flows from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
millions	2012		2011		2012		2011
Income (loss) before income taxes	$	94	$	1,002	$	2,629	$	1,505
Exploration expense		1,121		236		1,365		415
DD&A		1,027		985		1,957		1,970
Impairments		112		102		162		104
Deepwater Horizon settlement and related costs (1)		3		9		11		35
Algeria exceptional profits tax settlement (2)		—		—		(1,804)		—
Tronox-related contingent loss (2)		(525)		—		(250)		—
Interest expense		190		216		376		436
Unrealized (gains) losses on derivatives, net		225		(178)		83		75
Realized (gains) losses on other derivatives, net (2)		2		2		2		2
Less: Net income attributable to noncontrolling interests		19		18		46		39
Consolidated Adjusted EBITDAX	$	2,230	$	2,356	$	4,485	$	4,503

_________________________________________________________

(1)In the third quarter of 2011, the Company revised the definition of Adjusted EBITDAX to exclude Deepwater Horizon settlement and related costs. Prior periods havebeen adjusted to reflect this change.

(2)In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. Prior periods have been adjusted to reflect this change.

The following presents selected financial information for Anadarko's reporting segments. Information presented below as “Other and Intersegment Eliminations” includes results from hard-minerals non-operated joint ventures androyalty arrangements,and corporate, financing, and certain hedging activities.

		Oil and Gas						Other and
		Exploration						Intersegment
millions		& Production		Midstream		Marketing		Eliminations		Total
Three Months Ended June 30, 2012
Sales revenues		$	1,888	$	81	$	1,231	$	—	$	3,200
Intersegment revenues			1,035		220		(1,124)		(131)		—
Gains (losses) on divestitures and other, net			(12)		(1)		—		35		22
	Total revenues and other		2,911		300		107		(96)		3,222
Operating costs and expenses (1)			873		174		158		33		1,238
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(263)		(263)
Other (income) expense, net (2)			—		—		—		6		6
Net income attributable to
	noncontrolling interests		—		19		—		—		19
	Total expenses and other		873		193		158		(224)		1,000
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		8		—		8
Adjusted EBITDAX		$	2,038	$	107	$	(43)	$	128	$	2,230
Three Months Ended June 30, 2011
Sales revenues		$	2,071	$	98	$	1,565	$	—	$	3,734
Intersegment revenues			1,330		223		(1,448)		(105)		—
Gains (losses) on divestitures and other, net			(114)		20		—		36		(58)
	Total revenues and other		3,287		341		117		(69)		3,676
Operating costs and expenses (1)			921		199		135		88		1,343
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(27)		(27)
Other (income) expense, net (2)			—		—		—		(18)		(18)
Net income attributable to
	noncontrolling interests		—		18		—		—		18
	Total expenses and other		921		217		135		43		1,316
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(4)		—		(4)
Adjusted EBITDAX		$	2,366	$	124	$	(22)	$	(112)	$	2,356

_________________________________________________________

(1) Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.

(2) Other (income) expense, net excludes Tronox-related contingent loss since this expense is excluded from Adjusted EBITDAX.

		Oil and Gas						Other and
		Exploration						Intersegment
millions		& Production		Midstream		Marketing		Eliminations		Total
Six Months Ended June 30, 2012
Sales revenues		$	3,787	$	168	$	2,657	$	—	$	6,612
Intersegment revenues			2,209		469		(2,419)		(259)		—
Gains (losses) on divestitures and other, net			(29)		(2)		—		88		57
	Total revenues and other		5,967		635		238		(171)		6,669
Operating costs and expenses (1)			1,799		363		312		81		2,555
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(400)		(400)
Other (income) expense, net (2)			—		—		—		(4)		(4)
Net income attributable to
	noncontrolling interests		—		46		—		—		46
	Total expenses and other		1,799		409		312		(323)		2,197
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		13		—		13
Adjusted EBITDAX		$	4,168	$	226	$	(61)	$	152	$	4,485
Six Months Ended June 30, 2011
Sales revenues		$	3,867	$	162	$	2,929	$	—	$	6,958
Intersegment revenues			2,455		433		(2,680)		(208)		—
Gains (losses) on divestitures and other, net			(114)		20		—		65		(29)
	Total revenues and other		6,208		615		249		(143)		6,929
Operating costs and expenses (1)			1,762		365		271		110		2,508
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(84)		(84)
Other (income) expense, net (2)			—		—		—		(42)		(42)
Net income attributable to
	noncontrolling interests		—		39		—		—		39
	Total expenses and other		1,762		404		271		(16)		2,421
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(5)		—		(5)
Adjusted EBITDAX		$	4,446	$	211	$	(27)	$	(127)	$	4,503

_________________________________________________________

(1) Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.

(2) Other (income) expense, net excludes Tronox-related contingent loss since this expense is excluded from Adjusted EBITDAX.

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Derivative Instruments - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Derivative Instrument Detail [Abstract]
Accumulated other comprehensive loss, before tax	$ 103	$ 109
Accumulated other comprehensive loss, after tax	66	70
Derivative [Line Items]
Gross derivative liability	1,606	1,617
Aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed	156	2
Eligible for setoff against gross derivative asset in the event of default [Member]
Derivative [Line Items]
Gross derivative liability	$ 470	$ 749
Marketing and Trading Derivative [Member] | Natural Gas [Member]
Derivative [Line Items]
Fixed-price physical transactions	12	22
Derivative transactions	12	21
Net position		1

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2012

Policy Text Block [Abstract]

Use of Estimates

Use of EstimatesIn preparing financial statements in accordance with accounting principles generally accepted in the United States, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to the value of properties and equipment; proved reserves; goodwill; intangible assets; asset retirement obligations; litigation reserves; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

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CONSOLIDATED STATEMENT OF EQUITY (USD $) In Millions	Total		Common Stock [Member]	Paid-in Capital [Member]		Retained Earnings [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]
Balance at Dec. 31, 2011	$ 18,983		$ 51	$ 7,851		$ 11,619	$ (804)	$ (612)	$ 878
Net income (loss)	2,113					2,067			46
Common stock issued	110			110
Dividends - common	(91)					(91)
Repurchase of common stock	(23)						(23)
Subsidiary equity transactions	193			34	[1]				159
Distributions to noncontrolling interest owners	(52)								(52)
Contributions from noncontrolling interest owners	11								11
Reclassification of previously deferred derivative losses to net income	4	[2]						4
Adjustments for pension and other postretirement plans	30							30
Balance at Jun. 30, 2012	$ 21,278		$ 51	$ 7,995		$ 13,595	$ (827)	$ (578)	$ 1,042

[1] The $34 million increase to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders, totaled $2,101 million for the six months ended June 30, 2012.

[2] Net of income tax benefit (expense) of $(1) million and $(1) million for the three months ended June 30, 2012 and 2011, respectively, and $(2) million and $(3) million for the six months ended June 30, 2012 and 2011, respectively.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ (70)		$ 562		$ 2,113		$ 799
Other Comprehensive Income (Loss), net of taxes
Reclassification of previously deferred derivative losses to net income	2	[1]	3	[1]	4	[1]	5	[1]
Amortization of net actuarial loss and prior service cost to net periodic benefit cost	15	[2]	13	[2]	30	[2]	27	[2]
Total	17		16		34		32
Comprehensive Income (Loss)	(53)		578		2,147		831
Comprehensive Income Attributable to Noncontrolling Interests	19		18		46		39
Comprehensive Income (Loss) Attributable to Common Stockholders	$ (72)		$ 560		$ 2,101		$ 792

[1] Net of income tax benefit (expense) of $(1) million and $(1) million for the three months ended June 30, 2012 and 2011, respectively, and $(2) million and $(3) million for the six months ended June 30, 2012 and 2011, respectively.

[2] Net of income tax benefit (expense) of $(9) million and $(8) million for the three months ended June 30, 2012 and 2011, respectively, and $(17) million and $(16) million for the six months ended June 30, 2012 and 2011, respectively.

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Stockholders' Equity

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Stockholders' Equity

8.  Stockholders' Equity

The reconciliation between basic and diluted earnings per share attributable to common stockholders is as follows:

			Three Months Ended				Six Months Ended
			June 30,				June 30,
millions except per-share amounts			2012		2011		2012		2011
Net income (loss)
	Net income (loss) attributable to common stockholders		$	(89)	$	544	$	2,067	$	760
	Less: Distributions on participating securities			—		1		1		1
	Less: Undistributed income allocated to participating securities			—		3		12		4
Basic			$	(89)	$	540	$	2,054	$	755
Diluted			$	(89)	$	540	$	2,054	$	755
Shares
	Average number of common shares outstanding—basic			500		498		499		497
	Dilutive effect of stock options and performance-based
		stock awards		—		2		2		2
	Average number of common shares outstanding—diluted			500		500		501		499
	Excluded (1)			12		6		5		6
Net income (loss) per common share
	Basic		$	(0.18)	$	1.09	$	4.11	$	1.52
	Diluted		$	(0.18)	$	1.08	$	4.10	$	1.51
	Dividends per common share		$	0.09	$	0.09	$	0.18	$	0.18

_________________________________________________________

(1)Inclusion of certain shares would have had an anti-dilutive effect.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012	Jul. 31, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	ANADARKO PETROLEUM CORP
Entity Central Index Key	0000773910
Document Type	10-Q
Document Period End Date	Jun. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		499,678,984

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Commitments

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Commitments

9.  Commitments

In January 2012, the Company entered into a two-and-a-half-year lease agreement for a deepwater drilling rig expected to be delivered in late 2012. In July 2012, the Company entered into a three-year lease agreement for a deepwater drilling rig expected to be delivered in late 2013. These lease obligations total approximately $875million, with aggregate future annual minimum lease payments of $13million in 2012, $192million in 2013, $317million in 2014, $228million in 2015, and $125million in 2016.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Statement of Comprehensive Income [Abstract]
Reclassification of previously deferred derivative losses to net income, income tax benefit (expense)	$ (1)	$ (1)	$ (2)	$ (3)
Amortization of net actuarial loss and prior service cost to net periodic benefit cost, income tax benefit (expense)	$ (9)	$ (8)	$ (17)	$ (16)

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Inventories

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Inventories

3.  Inventories

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

	June 30,		December 31,
millions	2012		2011
Crude oil	$	69	$	103
Natural gas		31		49
NGLs		41		59
Total	$	141	$	211

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Acquisitions

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Acquisitions

2.  Acquisitions

The acquisitions of the Platte Valley assets in February 2011 and the Wattenberg Plant in May 2011 constitute business combinations and were accounted for using the acquisition method.Preliminary fair-value measurements made at the acquisition dates were finalized in the first quarter of 2012. There were no changes to the fair value of assets acquired and liabilities assumed from the amounts included on the Company's Consolidated Balance Sheet as of December 31, 2011.

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Pension Plans and Other Postretirement Benefits

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Pension Plans and Other Postretirement Benefits

14.  Pension Plans and Other Postretirement Benefits

The Company has non-contributory U.S. defined-benefit pension plans, including both qualified and supplemental plans, and a foreign contributory defined-benefit pension plan. The Company also provides certain health care and lifeinsurance benefits for certain retired employees. Retiree healthcare benefits are funded by contributions from the retiree, and in certain circumstances, contributions from the Company. The Company's retiree lifeinsurance plan is noncontributory.

During the six months ended June 30, 2012, the Company made contributions of $32 million to its funded pension plans, $2 million to its unfunded pension plans, and $9 million to its unfunded other postretirement benefit plans. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. During the remainder of 2012, the Company expects to contribute approximately $88 million to its funded pension plans, approximately $32 million to its unfunded pension plans, and approximately $10 million to its unfunded other postretirement benefit plans.

The following sets forth the components of net periodic benefit cost for the Company's pension and other postretirement benefit plans.

	Pension Benefits				Other Benefits
millions	2012		2011		2012		2011
Three Months Ended June 30
Service cost	$	19	$	19	$	3	$	2
Interest cost		22		22		4		4
Expected return on plan assets		(22)		(22)		—		—
Amortization of net actuarial loss (gain)		23		21		—		—
Amortization of net prior service cost (credit)		—		—		1		—
Net periodic benefit cost	$	42	$	40	$	8	$	6

Six Months Ended June 30
Service cost	$	38	$	39	$	5	$	4
Interest cost		43		43		8		8
Expected return on plan assets		(45)		(43)		—		—
Amortization of net actuarial loss (gain)		46		42		—		—
Amortization of net prior service cost (credit)		—		1		1		—
Net periodic benefit cost	$	82	$	82	$	14	$	12

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Contingencies

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Contingencies

10.Contingencies

GeneralThe Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims, title disputes, tax disputes, royalty claims, contract claims, oil-field contamination claims, and environmental claims, including claims involving assets owned by acquired companies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company's consolidated financial position, results of operations, or cash flows.

The following discussion of the Company's contingencies includes material developments with respect to matters previously reported in the Company's Annual Report on Form 10-K for the year ended December 31, 2011. There have been no new significant matters sincethe Company's Annual Report on Form 10-K for the year ended December 31, 2011.

Deepwater Horizon EventsIn April 2010, the Macondo well in the Gulf of Mexicoblew out and an explosion occurred on the Deepwater Horizon drilling rig. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% non-operated interest.In October 2011, the Company and BPentered into a settlement agreement, mutual releases, and agreement to indemnify, relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against claims and damages arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and other potential damages. This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-upon amount, BP p.l.c. has agreed to become the sole guarantor. The Settlement Agreement does not indemnify Anadarko against potential fines, penalties, or punitive damages. The Company has not recorded a liability for any costs that are subject to indemnification by BP. For additional disclosure of the Deepwater Horizon events, the Company's Settlement Agreement with BP, environmental claims under OPA, NRD claims, potential penalties and fines, and civil litigation, see Note 2—Deepwater Horizon Eventsin the Notes to the Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2011.

Penalties and FinesIn December 2010, the U.S. Department of Justice, on behalf of the United States, filed a civil lawsuit in the U.S. District Court in New Orleans, Louisiana (Louisiana District Court) against several parties, including Anadarko Petroleum Corporation and Anadarko E&P Company LP (AE&P), a subsidiary of Anadarko, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. In February 2012, the Louisiana District Court entered a declaratory judgment that, as a partial owner of the Macondo well, Anadarko is liable for civil penalties under Section 311 of the CWA and denied both the Company's and the United States' motions for summary judgment with respect to the liability of AE&P. The declaratory judgment addresses liability only, and does not address the amount of any civil penalty. In February2012, the Louisiana District Court entered a stipulated order (Stipulated Order), agreed to by the Company and the United States, that the United States will not assert any claim for a CWA penalty against AE&P, and that the United States will not assert any other theories of liability under the CWA (e.g., operator or person-in-charge liability) against either Anadarko or AE&P. Further, the Stipulated Order reserved the issue of an assessment of a civil penalty against Anadarko until a later proceeding to be scheduled by the Louisiana District Court. The Company believes that the Stipulated Order does not have a material impact on Anadarko's potential liability.

As discussed below, numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. Certain state and local governments have appealed, or have provided indication of a likely appeal of the Louisiana District Court's decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. If such an appeal is successful, state and/or local laws and regulations could become sources of penalties or fines against the Company.

       Applicable accounting guidance requires the Company to accrue a liability if it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. The Louisiana District Court's declaratory judgment in February 2012, satisfies the requirement that a loss, arising from the future assessment of a civil penalty against Anadarko, is probable. Notwithstanding, the Company currently cannot estimate the amount of any potential civil penalty. The CWA sets forth subjective criteria, including degree of fault and history of prior violations, which significantly influence the magnitude of CWA penalty assessments. As a result of the subjective nature of CWA penalty assessments, the Company currently cannot estimate the amount of any such penalty. Furthermore, the February 2012 settlement of Deepwater Horizon-related civil penalties (including those under the CWA) by the other non-operating partner with the United States and five affected Gulf states (Texas, Louisiana, Mississippi, Alabama, and Florida) does not affect the Company's current conclusion regarding its ability to estimate potential fines and penalties. The Company lacks insight into those settlement discussions, retains legal counsel separate from the other non-operating party, and was not involved in any manner with respect to that settlement.

Given the Company's lack of direct operational involvement in the event, as confirmed by the Louisiana District Court, and the subjective criteria of the CWA, the Company believes that its exposure to CWA penalties will not materially impact the Company's consolidated financial position, results of operations, or cash flows.

Civil Litigation Damage ClaimsNumerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court. Only OPA claims seeking economic loss damages against the Company remain. In addition, certain state and local governments have appealed, or have provided indication of a likely appeal of, the MDL court's decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages, irrespective of whether such claims are based on federal (including OPA) or state law.

       The Louisiana District Court plans to hold a trial in Transocean's Limitation of Liability case in the MDL. The first phase of the trial is to determine certain liability issues and the liability allocation among the parties alleged to be involved in or liable for the Deepwater Horizon events. In March 2012, BP and the Plaintiffs' Steering Committee (PSC) entered into a tentative settlement agreement to resolve the substantial majority of economic loss and medical claims stemming from the Deepwater Horizon events. In light of this settlement agreement, the Louisiana District Court postponed the start of the trial until a future date and requested that the parties submit separate briefs that explain the parties' opinions as to the impact of the tentative settlement on the Louisiana District Court's previously issued trial plan. BP and the PSC jointly filed the proposed settlement agreement with the Louisiana District Court in April2012.In May 2012, the Louisiana District Court issued its revised case management order (CMO) ruling that the first phase of the trial will commence in January 2013, and will address issues arising out of the conduct of various parties involved with the Deepwater Horizon events. The CMO provides that the Stipulated Order excusing Anadarko from participation in the first phase of the trial remains in effect. The CMO also provides that the second phase of trial will follow the first phase after a two-to-three week recess and will address source-control and qualification issues.

       Two separate class action complaints were filed in June and August 2010, in the U.S. District Court for the Southern District of New York (New York District Court) on behalf of purported purchasers of the Company's stock between June 9, 2009, and June 12, 2010, against Anadarko and certain of its officers. The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 (Exchange Act) for purported misstatements and omissions regarding, among other things, the Company's liability related to the Deepwater Horizon events. In March 2012, the New York District Court granted the Lead Plaintiff's motion to transfer venue to the U.S. District Court for the Southern District of Texas – Houston Division (Texas District Court). In May 2012, the Texas District Court granted the defendants' motion to transfer the consolidated action within the district to Judge Keith P. Ellis.

In November 2011, the Company's Board of Directors (Board) received a letter from a purported shareholder demanding that the Board investigate, address, remedy, and commence derivative proceedings against certain officers and directors for their alleged breach of fiduciary duty related to the Deepwater Horizon events. The Board has considered this demand and in February 2012 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter. In March 2012, the Company's Board received a similar demand letter from a purported shareholder supplementing an original demand that had been made by the shareholder in September 2010 related to the Deepwater Horizon events. The Board has considered this demand and in April 2012 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter.

 Given the various stages of these proceedings, the Company currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses, related to ongoing proceedings. The Company intends to vigorously defend itself, its officers, and its directors in each of these proceedings, and will avail itself of any and all indemnities provided by BP against civil damages.

Remaining Liability Outlook   It is reasonably possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential fines and penalties, shareholder claims, and certain other claims not covered by the indemnification provisions of the Settlement Agreement; however, the Company does not believe that any potential liability attributable to the foregoing items, individually or in the aggregate, will have a material impact on the Company's consolidated financial position, results of operations, or cash flows. This assessment takes into account certain qualitative factors, including the subjective and fault-based nature of CWA penalties, the Company's indemnification by BP against certain damage claims as discussed above, BP's creditworthiness, the merits of the shareholder claims, and directors and officers insurance coverage related to outstanding shareholder claims.

       The Company will continue to monitor the MDL and other legal proceedings discussed above as well as federal investigations related to the Deepwater Horizon events, including review of the preliminary investigatory findings recently announced by the U.S. Chemical Safety Board. The Company cannot predict the nature of evidence that may be discovered during the course of legal proceedings and investigations, the timing of discovery, or the timing of completion of any legal proceedings or investigations.

       Although the Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and certain other potential liabilities, the Company may be required to recognize a liability for these amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c.

Tronox Litigation   In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox's subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee and seeks, among other things, to recover damages, including interest, in excess of $18.9billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. In accordance with Tronox's Plan of Reorganization, the Adversary Proceeding is being prosecuted by the Anadarko Litigation Trust. Pursuant to the Anadarko Litigation Trust Agreement, the Anadarko Litigation Trust was “deemed substituted” for Tronox in the Adversary Proceeding as the party in such litigation. For purposes of this Form 10-Q, references to “Tronox” after February 2011 refer to the Anadarko Litigation Trust. For additional disclosure related to the Tronox Litigation, see Note 16—Contingencies—Tronox Litigation in the Notes to the Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2011.

       The U.S. government was granted authority to intervene in the Adversary Proceeding, and in May 2009 asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act (FDCPA Complaint). In April 2012, Anadarko and Kerr-McGee filed an answer to the FDCPA Complaint.

In February 2012, the Company filed a motion for partial summary judgment seeking dismissal of several claims, including all actual and constructive fraudulent transfer claims protected by Section 546(e) of the U.S. Bankruptcy Code. The court has not yet ruled on that issue. Trial began in May2012 and is expected to last through September 2012.

The Company's recent attempts to resolve the Adversary Proceeding through mediation and settlement discussions have reached an impasse and at this time the Company believes the likelihood of settlement is remote. The Company now considers litigation the probable form of final resolution of the Adversary Proceeding. Previously, the Company believed it probable that the parties would reach a settlement on reasonable terms and thus the Company considered a loss, via settlement, related to the Adversary Proceeding probable. Based on this assumption, a $275 million loss contingency was accrued in the first quarter of 2012, which increased the Company's total estimated contingent loss accrual related to the Adversary Proceeding to $525 million as of March 31, 2012. Due to the change in the Company's opinion as to the probable form of resolution of this matter, the Company reversed the settlement-based $525million contingent loss accrual related to this matter in the second quarter of 2012.

The Company remains confident in the merits of its position, and continues to vigorously defend the claims asserted in the Adversary Proceeding.The Company does not believe a loss resulting from litigating the Adversary Proceeding is probable. Accounting guidance requires that contingent losses be probable in nature for loss recognition to be appropriate. Accordingly, the Company's Consolidated Balance Sheet as of June 30, 2012, does not include a loss-contingency liability related to the litigation of the Adversary Proceeding.

Although the Company does not consider a loss related to the litigation of the Adversary Proceeding probable, it is reasonably possible that the Company could incur a loss as a result of litigating this matter. Despite the plaintiffs' damage claims in excess of $18.9 billion, the Company currently believes a reasonable range of potential loss is zero to $1.4 billion. The low end of the Company's estimated range of potential loss is based on the Company's current belief that it will more likely than not prevail in defending against the claims asserted in the Adversary Proceeding. The high end of the Company's estimated range of potential loss represents the amount of consideration received by Kerr-McGee at the time of the Tronox spin-off, approximately $985 million, plus interest thereon.

The Company's estimated range of potential loss is based on the Company's opinion regarding the current status of and likelihood of final resolution through litigation and could change as a result of developments in the Adversary Proceeding, or if the likelihood of settlement ceases to be remote. The Company's ultimate financial obligation resulting from resolution of the Adversary Proceeding could vary, perhaps materially, from the Company's above-stated estimated range of potential loss.

Separately, in July 2009, a consolidated class action complaint was filed in the New York District Court on behalf of purported purchasers of Tronox's equity and debt securities between November 21, 2005, and January 12, 2009, against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors, and Ernst & Young LLP (Securities Case). The complaint alleges causes of action arising under Sections 10(b) and 20(a) of the Exchange Act for purported misstatements and omissions regarding, among other things, Tronox's environmental-remediation and tort-claim liabilities. The plaintiffs allege, among other things, that these purported misstatements and omissions are contained in certain of Tronox's public filings, including filings made in connection with Tronox's initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. Certain parties, including Anadarko, Kerr-McGee, and the former Kerr-McGee officers and directors, reached a tentative settlement in this matterin April 2012, subject to approval by the court. The tentative settlement amount will be directly funded by the insurers for Tronox, Anadarko, and Kerr-McGee. As a result, offsetting gains and losses have been recorded to reflect the impact of the tentative settlement of the Securities Case.

Other Litigation   In December 2008, Anadarko sold its interest in the Peregrino heavy-oil field offshore Brazil. The Company is currently litigating a dispute with the Brazilian tax authorities regarding the tax rate applicable to the transaction. Currently, $169million, the amount of tax in dispute, resides in a judicially controlled Brazilian bank account, pending final resolution of the matter and is included in other assets on the Company's Consolidated Balance Sheet as of June 30, 2012.

In July 2009, the lower judicial court ruled in favor of the Brazilian tax authorities. The Company appealed this decision to the Brazilian Regional courts, which upheld the lower court's ruling in favor of the Brazilian tax authorities in December 2011. In April 2012, the Company filed simultaneous appeals to the Brazilian Superior court and the Brazilian Supreme court. The Brazilian Supreme court is not required to hear the case.

The Company believes that it will, more likely than not, prevail in Brazilian courts. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation as of June 30, 2012. The Company continues to vigorously defend itself in Brazilian courts.

Deepwater Drilling Moratorium and Other Related MattersIn June 2010, as a result of the moratorium on drilling in the Gulf of Mexico between mid-May 2010 and mid-October 2010 (Moratorium), the Company gave written notice of termination to a drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit in the Texas District Court against the drilling contractor seeking a judicial declaration that the Company's interpretation of the drilling contract was correct and that the contract terminated on June 19, 2010. The drilling contractor filed an Original Answer in July 2010 denying the Moratorium constituted a force majeure event and asserting that Anadarko had breached the drilling contract. In the second quarter of 2012, the Company and the drilling contractor mutually agreed to dismiss all claims related to this dispute. The resolution of this dispute did not have a material impact on Anadarko's consolidated financial position, results of operations, or cash flows.

Algeria Exceptional Profits Tax SettlementIn 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies' Algerian oil production and issued regulations implementing this legislation. The Company notified Sonatrach of the Company's disagreement with Sonatrach's collection of the exceptional profits tax and initiated arbitration against Sonatrach in February 2009. The arbitration hearing was held in June2011.

       In March 2012, Anadarko reached anagreement with Sonatrach to resolve the exceptional profits tax dispute. The agreement was approved by the Algerian government and provides for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company's previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period which began in June 2012. At June 30, 2012, a receivable of $1.6billionon the Company's Consolidated Balance Sheetwas included in the oil and gas exploration and production reporting segment. The Company recognized a$1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for the six months ended June 30, 2012, to reflect the effect of this agreementon previously recorded expenses.Additionally, the parties agreed to an amendment to the existing Production Sharing Agreement (PSA) that providesthe Company increased sales volumes in future periods. The amendment also confirms the duration for each exploitation license granted under the PSAwill be 25 years from the date the license was awarded.

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Derivative Instruments

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Derivative Instruments

6.  Derivative Instruments

Objective and StrategyThe Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks.Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company's oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as Henry Hub for natural gas and Cushing for oil. Basis swaps are used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company's leased storage facilities (Marketing and Trading Derivative Activities).

Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company's existing or anticipated exposure to unfavorable interest-rate changes. The fair value of the Company's interest-rate swap portfolio increases (decreases) when interest rates increase (decrease).

The Company does not apply hedge accounting to any of its derivative instruments. As a result, both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings. Accumulated other comprehensive loss balances of $103 million ($66 million after tax) and $109 million ($70 million after tax) at June 30, 2012, and December 31, 2011, respectively, relate to interest-rate derivatives that were previously subject to hedge accounting.

Oil and Natural-Gas Production/Processing Derivative ActivitiesBelow is a summary of the Company's derivative instruments related to its Oil and Natural-Gas Production/Processing Activities at June 30, 2012.The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are a combination of NYMEX Cushing and London Brent Dated prices.

		2012			2013
Natural Gas
	Three-Way Collars (thousand MMBtu/d)		—	(1)		450
	Average price per MMBtu
	Ceiling sold price (call)	$	—		$	6.57
	Floor purchased price (put)	$	—		$	5.00
	Floor sold price (put)	$	—		$	4.00
	Fixed-Price Contracts (thousand MMBtu/d)		1,000			—
	Average price per MMBtu	$	4.69		$	—
Crude Oil
	Three-Way Collars (MBbls/d)		62			—
	Average price per barrel
	Ceiling sold price (call)	$	122.30		$	—
	Floor purchased price (put)	$	101.22		$	—
	Floor sold price (put)	$	81.34		$	—
	Fixed-Price Contracts (MBbls/d)		60			—
	Average price per barrel	$	107.19		$	—

_______________________________________________________

(1)Includes the effects of offsetting purchased and sold natural-gas three-way collars of 500,000 MMBtu/d.

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

       A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

Marketing and Trading Derivative Activities   In addition to the positions in the above tables, the Company also engages in marketing and trading activities, which include physical product sales and related derivative transactions used to manage commodity-price risk. At June 30, 2012, the Company had fixed-price physical transactions related to natural gas totaling 12 billion cubic feet (Bcf), offset by derivative transactions for 12 Bcf.At December 31, 2011,the Company had fixed-price physical transactions related to natural gas totaling 22 Bcf, offset by derivative transactions for 21 Bcf, for a net position of 1 Bcf.

Interest-Rate DerivativesAnadarko has outstanding interest-rate swap contracts as a fixed-rate payor to mitigate the interest-rate risk associated with anticipated debt issuances. The Company locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR. The swap instruments include a provision that requires both the termination of the swaps and cash settlement in full at the start of the reference period.

       The Company had the following outstanding interest-rate swaps at June 30, 2012:

millions except percentages		Reference Period		Weighted-Average
Notional Principal Amount		Start	End	Interest Rate
$	250	October 2012	October 2022	4.91	%
$	750	October 2012	October 2042	4.80	%
$	750	June 2014	June 2024	6.00	%
$	1,100	June 2014	June 2044	5.57	%

Effect of Derivative Instruments—Balance SheetThe fair value of the Company's derivative instruments is presented below.

		Gross				Gross
		Derivative Assets				Derivative Liabilities
millions		June 30,		December 31,		June 30,		December 31,
Balance Sheet Classification		2012		2011		2012		2011
Commodity derivatives
	Other current assets	$	860	$	924	$	(212)	$	(353)
	Other assets		111		150		(25)		(15)
	Accrued expenses		8		5		(18)		(33)
	Other liabilities		7		1		(14)		(17)
			986		1,080		(269)		(418)
Interest-rate and other derivatives
	Accrued expenses		—		—		(439)		(391)
	Other liabilities		—		—		(898)		(808)
			—		—		(1,337)		(1,199)
Total Derivatives		$	986	$	1,080	$	(1,606)	$	(1,617)

Effect of Derivative Instruments—Statement of IncomeThe realized and unrealized gain or loss amounts related to derivative instruments are presented below.

		Three Months Ended						Six Months Ended
millions		June 30, 2012						June 30, 2012
Classification of (Gain) Loss Recognized		Realized		Unrealized		Total		Realized		Unrealized		Total
Commodity derivatives
	Gathering, processing, and marketing sales (1)	$	(1)	$	8	$	7	$	(3)	$	13	$	10
	(Gains) losses on commodity derivatives, net		(263)		(157)		(420)		(400)		(68)		(468)
Interest-rate and other derivatives
	(Gains) losses on other derivatives, net		2		374		376		2		138		140
Derivative (gain) loss, net		$	(262)	$	225	$	(37)	$	(401)	$	83	$	(318)

		Three Months Ended						Six Months Ended
millions		June 30, 2011						June 30, 2011
Classification of (Gain) Loss Recognized		Realized		Unrealized		Total		Realized		Unrealized		Total
Commodity derivatives
	Gathering, processing, and marketing sales (1)	$	4	$	(4)	$	—	$	16	$	(5)	$	11
	(Gains) losses on commodity derivatives, net		(27)		(316)		(343)		(84)		(3)		(87)
Interest-rate and other derivatives
	(Gains) losses on other derivatives, net		2		142		144		2		83		85
Derivative (gain) loss, net		$	(21)	$	(178)	$	(199)	$	(66)	$	75	$	9

_______________________________________________________

(1)Represents the effect of marketing and trading derivative activities.

Credit-Risk Considerations   The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or the Intercontinental Exchange through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company's credit policies and guidelines, and assesses the impact of a counterparty's creditworthiness on fair value. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure. The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and routinely exercises its contractual right to offset realized gains against realized losses when settling with derivative counterparties.

       In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across all derivative types. At June 30, 2012, $470 million of the Company's $1.6 billion gross derivative liability balance, and at December 31, 2011, $749 million of the Company's $1.6 billion gross derivative liability balance, would have been eligible for setoff against the Company's gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types, as settlement timing differs.     

       Some of the Company's derivative instruments are subject to provisions that can require full or partial collateralization or immediate settlement of the Company's obligations if certain credit-risk-related provisions are triggered. However, most of the Company's derivative counterparties maintain secured positions with respect to the Company's derivative liabilities under the Company's $5.0 billion senior secured revolving credit facility ($5.0 billion Facility), the available capacity of which is sufficient to secure potential obligations to such counterparties.

       At June 30, 2012, and December 31, 2011, the aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed was $156 million and $2 million (net of collateral), respectively, included in accrued expenses on the Company's Consolidated Balance Sheets.

Fair Value   Fair value of futures contracts is based on quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, implied market volatility and discount factors. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments.

       The fair value of the Company's derivative financial assets and liabilities, by input level within the fair-value hierarchy, is presented below.

millions
June 30, 2012			Level 1		Level 2		Level 3		Netting (1)		Collateral		Total
Assets
	Commodity derivatives
		Financial institutions	$	2	$	883	$	—	$	(219)	$	(41)	$	625
		Other counterparties		—		101		—		(33)		—		68
Total derivative assets			$	2	$	984	$	—	$	(252)	$	(41)	$	693
Liabilities
	Commodity derivatives
		Financial institutions	$	(3)	$	(217)	$	—	$	219	$	1	$	—
		Other counterparties		—		(49)		—		33		—		(16)
	Interest-rate and other derivatives			—		(1,337)		—		—		—		(1,337)
Total derivative liabilities			$	(3)	$	(1,603)	$	—	$	252	$	1	$	(1,353)

December 31, 2011
Assets
	Commodity derivatives
		Financial institutions	$	3	$	909	$	—	$	(323)	$	(52)	$	537
		Other counterparties		—		168		—		(51)		—		117
Total derivative assets			$	3	$	1,077	$	—	$	(374)	$	(52)	$	654
Liabilities
	Commodity derivatives
		Financial institutions	$	(4)	$	(375)	$	—	$	361	$	7	$	(11)
		Other counterparties		—		(39)		—		13		—		(26)
	Interest-rate and other derivatives			—		(1,199)		—		—		130		(1,069)
Total derivative liabilities			$	(4)	$	(1,613)	$	—	$	374	$	137	$	(1,106)

_______________________________________________________

(1)Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

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Pension Plans and Other Postretirement Benefits - Components of Net Periodic Benefit Cost Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pension Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	$ 19	$ 19	$ 38	$ 39
Interest cost	22	22	43	43
Expected return on plan assets	(22)	(22)	(45)	(43)
Amortization of net actuarial loss (gain)	23	21	46	42
Amortization of net prior service cost (credit)				1
Net periodic benefit cost	42	40	82	82
Other Postretirement Benefit Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	3	2	5	4
Interest cost	4	4	8	8
Amortization of net prior service cost (credit)	1		1
Net periodic benefit cost	$ 8	$ 6	$ 14	$ 12

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Properties and Equipment

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Properties and Equipment

4.  Properties and Equipment

Suspended Exploratory Well CostsThe Company's suspended exploratory well costs at June 30, 2012, and December 31, 2011, were $1.9billion and $1.4billion, respectively. The increase in suspended exploratory well costs during 2012primarily relates to the capitalization of costs associated with successful exploration drilling inMozambique, the Gulf of Mexico, the Utica and Marcellus shales in the Southern and Appalachia Region, Ghana, and Côte d'Ivoire.For the sixmonths ended June 30, 2012, $39 million of exploratory well costs previously capitalized as suspended well costs for greater than one yearwere charged to dry hole expense and $82 million of capitalized suspended well costs were reclassified to proved properties.

Management believes projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development and is actively pursuing efforts to assess whether reserves can be attributed to theseprojects. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time.

Impairments of Unproved PropertiesIn the second quarter of 2012, the Company recognized a $720 million impairment of unproved Powder River coalbed methane properties primarily due to lower natural-gas prices. The Company also recognized a $124 million impairment of an unproved Gulf of Mexico natural-gas property due to a reduction of estimated recoverable reserves as a result of the forecasted natural-gas price environment.This Gulf of Mexico property is located on a lease that is close to expiration and the Company does not plan to pursue the exploitation of this property under the forecasted natural-gas price environment. These impairments are included in exploration expense in the Company's Consolidated Statements of Income for the three and six months ended June 30, 2012, andthe impacted assets were impaired to fairvalue, estimated using Level 3 fair-value inputs.

ImpairmentsImpairment expense for the three and six months ended June 30, 2012, was $112 million and $162 million, respectively. In the second quarter of 2012, due to lower natural-gas prices, the Company recognized impairments of $79millionrelated to certain onshore domestic oil and gas exploration and production reporting segment properties and $4 million related to midstream reporting segment properties.The Company also recognized impairments of $50million and $17million in the first and second quarter of 2012, respectively,related to downward reserves revisionsfora Gulf of Mexico property included in the oil and gas exploration and production reporting segment that is near the end of its economic life. These properties were impaired to an aggregate fair value of $41million based on an income approach, estimated using Level 3 fair-value inputs.

       Also in the second quarter of 2012, the Company recognized impairment expense of $11 million ($4million net of tax) related to the Company's investment in Venezuelan assets due to declines in estimated recoverable reserves and lower crude-oil prices. These assets are included in the oil and gas exploration and production reporting segment and were impaired to fair value based on an income approach, estimated using Level 3 fair-value inputs. At June 30, 2012, the Company's after-tax net investment in these assets was $34million.

       Impairment expense for the three and six months ended June 30, 2011, was $102 million and $104 million, respectively, including $100 million recognized in the second quarter of 2011 related to onshore domestic properties due to a change in projected cash flows resulting from the Company's intent to divest of the properties. These properties were included in the oil and gas exploration and production reporting segment and were impaired to a fair value of $491 million based on an income approach, estimated using Level 3 fair-value inputs.

Assets Held for SaleIn 2011, the Company began marketing domestic properties from the oil and gas exploration and production reporting segment and the midstream reporting segment in order to redirect its operating activities and capital investment to other areas. During the first quarter of 2012, the Company decided not to proceed with the sale of properties from the midstream reporting segment. In 2012, the Company sold certain domestic oil and gas exploration and production reporting segment propertiesand recognized losses of$13 million and $30 million included in gains (losses) on divestitures and other, net in the Company's Consolidated Statements of Income for the three and six months ended June 30, 2012, respectively. At June 30, 2012, the remaining balances of assets and liabilitiesassociated with assets held for sale were not material.

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Noncontrolling Interests

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Noncontrolling Interests

5.  Noncontrolling Interests

       Western Gas Partners, LP (WES), a consolidated subsidiary, is a limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. In June 2012, WES issued five million common units to the public, raising net proceeds of $212 million, which increased the noncontrolling interest component of total equity.At June 30, 2012, Anadarko's ownership interest in WES consisted of a 41.4% limited partner interest, the entire 2.0% general partner interest, and incentive distribution rights.

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Debt and Interest Expense

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Debt and Interest Expense

7.  Debt and Interest Expense

DebtAll of the Company's outstanding debt is senior unsecured, except for borrowings under the $5.0 billion Facility. The following presents the Company's outstanding debt:

	June 30,		December 31,
millions	2012		2011
Long-term notes and debentures	$	15,521	$	16,452
WES borrowings		1,020		500
Total debt at face value	$	16,541	$	16,952
Net unamortized discounts and premiums (1)		(1,709)		(1,722)
Total borrowings	$	14,832	$	15,230
Less: Current portion of long-term debt		1,739		170
Total long-term debt	$	13,093	$	15,060

__________________________________________________________________________

(1)Unamortized discounts and premiums are amortized over the term of the related debt.

Fair ValueThe Company uses a market approach to determine fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. At June 30, 2012, and December 31, 2011, the estimated fair value of the Company's total borrowings was $17.1 billion and $17.3 billion, respectively.

Debt ActivityThe following presents the Company's debt activity during the six months ended June 30, 2012.

		Carrying
millions		Value		Description
Balance at December 31, 2011		$	15,230
	Borrowings		319	WES revolving credit facility
	Repayments		(131)	6.125% Senior Notes due 2012
			(40)	WES revolving credit facility
	Other, net		8	Changes in debt premium or discount
Balance at March 31, 2012		$	15,386
	Issuance		516	WES 4.00% Senior Notes due 2022
	Borrowings		55	WES revolving credit facility
	Repayments		(800)	$5.0 billion Facility
			(334)	WES revolving credit facility
	Other, net		9	Changes in debt premium or discount
Balance at June 30, 2012		$	14,832

AnadarkoRevolving Credit Facility andLetter of Credit FacilityAt June 30, 2012, the Company was in compliance with all applicable covenants contained in the $5.0 billion Facility, had outstanding borrowings of $1.7 billion at an interest rate of 1.75%, andhad available borrowing capacity of $3.2 billion ($5.0 billion maximum capacity, less $1.7 billion of outstanding borrowings and $150million of letter-of-credit capacity required to be maintained pursuant to the terms of theLOC Facility discussed below). The Company intends to repay the outstanding borrowings under the $5.0 billion Facility with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute within the next year and has classified these borrowings as current portion of long-term debt on the Company's Consolidated Balance Sheet at June 30, 2012.

In 2011, the Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit. In June 2012, the agreement was amended to reduce the amount of letters of credit to a maximum of $150 million (LOC Facility). Compensating balances deposited with the financial institution provide for reduced fees under the LOC Facility. These compensating balances may be withdrawn at any time, resulting in higher fees. At June 30, 2012, cash and cash equivalents includes $23 million of demand deposits serving as compensating balances for outstanding letters of credit.

WES Revolving Credit FacilityIn the second quarter of 2012, WES repaid all outstanding borrowings under its five-year $800 million senior unsecured revolving credit facility (RCF) with net proceeds from its public offering of $520 million aggregate principal amount of 4.00% Senior Notes due 2022. At June 30, 2012, WES was in compliance with all covenants contained in theRCF.

Interest ExpenseThe following summarizes the amounts included in interest expense.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
millions	2012		2011		2012		2011
Current debt, long-term debt, and other	$	236	$	250	$	486	$	498
Capitalized interest		(46)		(34)		(110)		(62)
Total interest expense	$	190	$	216	$	376	$	436

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Properties and Equipment - Additional Information (Detail) (USD $)	3 Months Ended		6 Months Ended			3 Months Ended			6 Months Ended	3 Months Ended						6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Jun. 30, 2012 Oil and Gas Exploration and Production Reporting Segment [Member]	Jun. 30, 2011 Oil and Gas Exploration and Production Reporting Segment [Member]	Jun. 30, 2012 Oil and Gas Exploration and Production Reporting Segment [Member] Assets Held For Sale [Member]	Jun. 30, 2012 Oil and Gas Exploration and Production Reporting Segment [Member] Assets Held For Sale [Member]	Jun. 30, 2012 Onshore Domestic [Member]	Jun. 30, 2012 Onshore Domestic [Member] Oil and Gas Exploration and Production Reporting Segment [Member]	Jun. 30, 2012 Onshore Domestic [Member] Midstream Reporting Segment [Member]	Jun. 30, 2012 Gulf Of Mexico [Member]	Jun. 30, 2012 Gulf Of Mexico [Member] Oil and Gas Exploration and Production Reporting Segment [Member]	Mar. 31, 2012 Gulf Of Mexico [Member] Oil and Gas Exploration and Production Reporting Segment [Member]	Jun. 30, 2012 Greater Than One Year [Member]	Jun. 30, 2012 Fair Value, Inputs, Level 3 [Member]	Jun. 30, 2011 Fair Value, Inputs, Level 3 [Member]
Property, Plant, and Equipment [Line Items]
Exploratory well costs previously capitalized as suspended well costs for greater than one year, charged to dry hole expense																$ 39,000,000
Impairment of unproved property			1,187,000,000	227,000,000						720,000,000			124,000,000
Impairments	112,000,000	102,000,000	162,000,000	104,000,000								4,000,000
Impairment of oil and gas properties							100,000,000				79,000,000			17,000,000	50,000,000
Fair value of impaired property																	41,000,000	491,000,000
Impairment expense related to investment in Venezuelan assets, before tax						11,000,000
Impairment expense related to investment in Venezuelan assets, net of tax						4,000,000
After-tax net investment in Venezuelan assets																	34,000,000
Losses on assets held for sale								13,000,000	30,000,000
Suspended exploratory well costs	1,900,000,000		1,900,000,000		1,400,000,000
Capitalized suspended well costs reclassified to proved properties			$ 82,000,000

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Contingencies - Tronox Litigation (Detail) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Mar. 31, 2012	Jun. 30, 2012
Loss Contingencies [Line Items]
Loss contingency accrual at carrying value, increase (decrease) in the period			$ (250,000,000)
Tronox Litigation [Member]
Loss Contingencies [Line Items]
Damages sought, including interest			18,900,000,000
Loss contingency accrual at carrying value, increase (decrease) in the period	(525,000,000)	275,000,000
Loss contingency accrual at carrying value	0	525,000,000	0
Range of possible loss, minimum	0		0
Range of possible loss, maximum	1,400,000,000		1,400,000,000
Tronox Litigation [Member] | Principal Portion of Maximum Loss Range [Member]
Loss Contingencies [Line Items]
Range of possible loss, maximum	$ 985,000,000		$ 985,000,000

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Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Supplemental Cash Flow Information

12.  Supplemental Cash Flow Information

The following presents cash paid (received) for interest (net of amounts capitalized) and income taxes, as well as non-cash investing transactions.

			Six Months Ended
			June 30,
millions			2012		2011
Cash paid (received)
	Interest		$	354	$	415
	Income taxes		$	(40)	$	82
Non-cash investing activities
	Fair value of properties and equipment received in non-cash exchange transactions		$	31	$	4
	Gain related to the fair-value remeasurement of Anadarko's pre-acquisition 7% equity
		interest in the Wattenberg Plant	$	—	$	21

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2012

Table Text Block [Abstract]

Schedule of Derivative Instruments

		2012			2013
Natural Gas
	Three-Way Collars (thousand MMBtu/d)		—	(1)		450
	Average price per MMBtu
	Ceiling sold price (call)	$	—		$	6.57
	Floor purchased price (put)	$	—		$	5.00
	Floor sold price (put)	$	—		$	4.00
	Fixed-Price Contracts (thousand MMBtu/d)		1,000			—
	Average price per MMBtu	$	4.69		$	—
Crude Oil
	Three-Way Collars (MBbls/d)		62			—
	Average price per barrel
	Ceiling sold price (call)	$	122.30		$	—
	Floor purchased price (put)	$	101.22		$	—
	Floor sold price (put)	$	81.34		$	—
	Fixed-Price Contracts (MBbls/d)		60			—
	Average price per barrel	$	107.19		$	—

_______________________________________________________

(1)Includes the effects of offsetting purchased and sold natural-gas three-way collars of 500,000 MMBtu/d.

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

millions except percentages		Reference Period		Weighted-Average
Notional Principal Amount		Start	End	Interest Rate
$	250	October 2012	October 2022	4.91	%
$	750	October 2012	October 2042	4.80	%
$	750	June 2014	June 2024	6.00	%
$	1,100	June 2014	June 2044	5.57	%

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location

		Gross				Gross
		Derivative Assets				Derivative Liabilities
millions		June 30,		December 31,		June 30,		December 31,
Balance Sheet Classification		2012		2011		2012		2011
Commodity derivatives
	Other current assets	$	860	$	924	$	(212)	$	(353)
	Other assets		111		150		(25)		(15)
	Accrued expenses		8		5		(18)		(33)
	Other liabilities		7		1		(14)		(17)
			986		1,080		(269)		(418)
Interest-rate and other derivatives
	Accrued expenses		—		—		(439)		(391)
	Other liabilities		—		—		(898)		(808)
			—		—		(1,337)		(1,199)
Total Derivatives		$	986	$	1,080	$	(1,606)	$	(1,617)

		Three Months Ended						Six Months Ended
millions		June 30, 2012						June 30, 2012
Classification of (Gain) Loss Recognized		Realized		Unrealized		Total		Realized		Unrealized		Total
Commodity derivatives
	Gathering, processing, and marketing sales (1)	$	(1)	$	8	$	7	$	(3)	$	13	$	10
	(Gains) losses on commodity derivatives, net		(263)		(157)		(420)		(400)		(68)		(468)
Interest-rate and other derivatives
	(Gains) losses on other derivatives, net		2		374		376		2		138		140
Derivative (gain) loss, net		$	(262)	$	225	$	(37)	$	(401)	$	83	$	(318)

		Three Months Ended						Six Months Ended
millions		June 30, 2011						June 30, 2011
Classification of (Gain) Loss Recognized		Realized		Unrealized		Total		Realized		Unrealized		Total
Commodity derivatives
	Gathering, processing, and marketing sales (1)	$	4	$	(4)	$	—	$	16	$	(5)	$	11
	(Gains) losses on commodity derivatives, net		(27)		(316)		(343)		(84)		(3)		(87)
Interest-rate and other derivatives
	(Gains) losses on other derivatives, net		2		142		144		2		83		85
Derivative (gain) loss, net		$	(21)	$	(178)	$	(199)	$	(66)	$	75	$	9

_______________________________________________________

(1)Represents the effect of marketing and trading derivative activities.

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

millions
June 30, 2012			Level 1		Level 2		Level 3		Netting (1)		Collateral		Total
Assets
	Commodity derivatives
		Financial institutions	$	2	$	883	$	—	$	(219)	$	(41)	$	625
		Other counterparties		—		101		—		(33)		—		68
Total derivative assets			$	2	$	984	$	—	$	(252)	$	(41)	$	693
Liabilities
	Commodity derivatives
		Financial institutions	$	(3)	$	(217)	$	—	$	219	$	1	$	—
		Other counterparties		—		(49)		—		33		—		(16)
	Interest-rate and other derivatives			—		(1,337)		—		—		—		(1,337)
Total derivative liabilities			$	(3)	$	(1,603)	$	—	$	252	$	1	$	(1,353)

December 31, 2011
Assets
	Commodity derivatives
		Financial institutions	$	3	$	909	$	—	$	(323)	$	(52)	$	537
		Other counterparties		—		168		—		(51)		—		117
Total derivative assets			$	3	$	1,077	$	—	$	(374)	$	(52)	$	654
Liabilities
	Commodity derivatives
		Financial institutions	$	(4)	$	(375)	$	—	$	361	$	7	$	(11)
		Other counterparties		—		(39)		—		13		—		(26)
	Interest-rate and other derivatives			—		(1,199)		—		—		130		(1,069)
Total derivative liabilities			$	(4)	$	(1,613)	$	—	$	374	$	137	$	(1,106)

_______________________________________________________

(1)Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

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Commitments - Additional Information (Detail) (Drilling Rig [Member], USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Operating Leased Assets [Line Items]
Total future minimum lease payments	875
Aggregate future annual minimum lease payments in 2012	13
Aggregate future annual minimum lease payments in 2013	192
Aggregate future annual minimum lease payments in 2014	317
Aggregate future annual minimum lease payments in 2015	228
Aggregate future annual minimum lease payments in 2016	125
Lease Entered Into January 2012 [Member]
Operating Leased Assets [Line Items]
Operating lease, period	2 years 6 months
Lease Entered Into July 2012 [Member]
Operating Leased Assets [Line Items]
Operating lease, period	3 years

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Derivative Instruments - Effect of Derivative Instruments - Statement of Income Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Derivative [Line Items]
Unrealized (gains) losses on derivatives, net					$ 83		$ 75
Commodity Contract [Member] | (Gains) Losses on Commodity Derivatives, net [Member]
Derivative [Line Items]
Derivative (gain) loss, net	(420)		(343)		(468)		(87)
Interest Rate Contract and Other [Member] | (Gains) Losses on Other Derivatives, net [Member]
Derivative [Line Items]
Derivative (gain) loss, net	376		144		140		85
Nondesignated [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	(262)		(21)		(401)		(66)
Unrealized (gains) losses on derivatives, net	225		(178)		83		75
Derivative (gain) loss, net	(37)		(199)		(318)		9
Nondesignated [Member] | Commodity Contract [Member] | Gathering, Processing, and Marketing Sales [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	(1)	[1]	4	[1]	(3)	[1]	16	[1]
Unrealized (gains) losses on derivatives, net	8	[1]	(4)	[1]	13	[1]	(5)	[1]
Derivative (gain) loss, net	7	[1]			10	[1]	11	[1]
Nondesignated [Member] | Commodity Contract [Member] | (Gains) Losses on Commodity Derivatives, net [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	(263)		(27)		(400)		(84)
Unrealized (gains) losses on derivatives, net	(157)		(316)		(68)		(3)
Derivative (gain) loss, net	(420)		(343)		(468)		(87)
Nondesignated [Member] | Interest Rate Contract and Other [Member] | (Gains) Losses on Other Derivatives, net [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	2	[2]	2	[2]	2	[2]	2	[2]
Unrealized (gains) losses on derivatives, net	374		142		138		83
Derivative (gain) loss, net	$ 376		$ 144		$ 140		$ 85

[1] Represents the effect of marketing and trading derivative activities.

[2] In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. Prior periods have been adjusted to reflect this change.

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CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 2,794	$ 2,697
Accounts receivable, net of allowance:
Customers	1,087	1,269
Others	1,864	1,990
Algeria exceptional profits tax settlement	1,629
Other current assets	1,056	975
Total	8,430	6,931
Properties and Equipment
Cost	60,990	60,081
Less accumulated depreciation, depletion, and amortization	23,506	22,580
Net properties and equipment	37,484	37,501
Other Assets	1,661	1,516
Goodwill and Other Intangible Assets	5,757	5,831
Total Assets	53,332	51,779
Current Liabilities
Accounts payable	2,873	3,299
Accrued expenses	1,271	1,430
Current portion of long-term debt	1,739	170
Total	5,883	4,899
Long-term Debt	13,093	15,060
Other Long-term Liabilities
Deferred income taxes	8,809	8,479
Asset retirement obligations	1,662	1,737
Other	2,607	2,621
Total	13,078	12,837
Stockholders' equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 517.6 million and 516.0 million shares issued as of June 30, 2012, and December 31, 2011, respectively)	51	51
Paid-in capital	7,995	7,851
Retained earnings	13,595	11,619
Treasury stock (17.9 million and 17.6 million shares as of June 30, 2012, and December 31, 2011, respectively)	(827)	(804)
Accumulated other comprehensive income (loss)	(578)	(612)
Total Stockholders' Equity	20,236	18,105
Noncontrolling interests	1,042	878
Total Equity	21,278	18,983
Total Liabilities and Equity	$ 53,332	$ 51,779

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Summary of Significant Accounting Policies

1.  Summary of Significant Accounting Policies

GeneralAnadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of natural gas, crude oil, condensate, and natural gas liquids (NGLs). In addition, the Company engages in the gathering, processing, and treating of natural gas, and the transporting of natural gas, crude oil, and NGLs. The Company also participates in the hard minerals business through its ownership of non-operated joint ventures and royalty arrangements. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

Basis of PresentationThe information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company's Consolidated Balance Sheets as of June 30, 2012, and December 31, 2011, the Consolidated Statements of Income andComprehensive Incomefor the three and six months ended June 30, 2012 and 2011, the Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011, and the Consolidated Statement of Equity for the six months ended June 30, 2012. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

Use of EstimatesIn preparing financial statements in accordance with accounting principles generally accepted in the United States, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to the value of properties and equipment; proved reserves; goodwill; intangible assets; asset retirement obligations; litigation reserves; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

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Segment Information - Selected Financial Information for Anadarko's Reporting Segments Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Segment Reporting Information [Line Items]
Sales revenues	$ 3,200		$ 3,734		$ 6,612		$ 6,958
Gains (losses) on divestitures and other, net	22		(58)		57		(29)
Total	3,222		3,676		6,669		6,929
Operating costs and expenses	1,238	[1]	1,343	[1]	2,555	[1]	2,508	[1]
Other (income) expense, net	(519)		(18)		(254)		(42)
Net income attributable to noncontrolling interests	19		18		46		39
Total expenses and other	1,000		1,316		2,197		2,421
Unrealized (gains) losses on derivatives, net					83		75
Adjusted EBITDAX	2,230		2,356		4,485		4,503
Excluding Tronox Related Contingent Loss [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	6	[2]	(18)	[2]	(4)	[2]	(42)	[2]
Nondesignated [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	(262)		(21)		(401)		(66)
Unrealized (gains) losses on derivatives, net	225		(178)		83		75
Gathering, Processing, and Marketing Sales [Member] | Nondesignated [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	(1)	[3]	4	[3]	(3)	[3]	16	[3]
Unrealized (gains) losses on derivatives, net	8	[3]	(4)	[3]	13	[3]	(5)	[3]
(Gains) Losses on Commodity Derivatives, net [Member] | Nondesignated [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	(263)		(27)		(400)		(84)
Unrealized (gains) losses on derivatives, net	(157)		(316)		(68)		(3)
Oil and Gas Exploration and Production Reporting Segment [Member]
Segment Reporting Information [Line Items]
Sales revenues	1,888		2,071		3,787		3,867
Intersegment revenues	1,035		1,330		2,209		2,455
Gains (losses) on divestitures and other, net	(12)		(114)		(29)		(114)
Total	2,911		3,287		5,967		6,208
Operating costs and expenses	873	[1]	921	[1]	1,799	[1]	1,762	[1]
Total expenses and other	873		921		1,799		1,762
Adjusted EBITDAX	2,038		2,366		4,168		4,446
Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Sales revenues	81		98		168		162
Intersegment revenues	220		223		469		433
Gains (losses) on divestitures and other, net	(1)		20		(2)		20
Total	300		341		635		615
Operating costs and expenses	174	[1]	199	[1]	363	[1]	365	[1]
Net income attributable to noncontrolling interests	19		18		46		39
Total expenses and other	193		217		409		404
Adjusted EBITDAX	107		124		226		211
Marketing Reporting Segment [Member]
Segment Reporting Information [Line Items]
Sales revenues	1,231		1,565		2,657		2,929
Intersegment revenues	(1,124)		(1,448)		(2,419)		(2,680)
Total	107		117		238		249
Operating costs and expenses	158	[1]	135	[1]	312	[1]	271	[1]
Total expenses and other	158		135		312		271
Adjusted EBITDAX	(43)		(22)		(61)		(27)
Marketing Reporting Segment [Member] | Gathering, Processing, and Marketing Sales [Member] | Nondesignated [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net	8		(4)		13		(5)
Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Intersegment revenues	(131)		(105)		(259)		(208)
Gains (losses) on divestitures and other, net	35		36		88		65
Total	(96)		(69)		(171)		(143)
Operating costs and expenses	33	[1]	88	[1]	81	[1]	110	[1]
Total expenses and other	(224)		43		(323)		(16)
Adjusted EBITDAX	128		(112)		152		(127)
Other and Intersegment Eliminations [Member] | Excluding Tronox Related Contingent Loss [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	6	[2]	(18)	[2]	(4)	[2]	(42)	[2]
Other and Intersegment Eliminations [Member] | (Gains) Losses on Commodity Derivatives, net [Member] | Nondesignated [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	$ (263)		$ (27)		$ (400)		$ (84)

[1] Operating costs and expenses excludes exploration expense; depreciation, depletion, and amortization; impairments; Deepwater Horizon settlement and related costs; and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.

[2] Other (income) expense, net excludes Tronox-related contingent loss since this expense is excluded from Adjusted EBITDAX.

[3] Represents the effect of marketing and trading derivative activities.

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Debt and Interest Expense (Tables)

6 Months Ended

Jun. 30, 2012

Table Text Block [Abstract]

Debt Outstanding and Debt Activity Tables

	June 30,		December 31,
millions	2012		2011
Long-term notes and debentures	$	15,521	$	16,452
WES borrowings		1,020		500
Total debt at face value	$	16,541	$	16,952
Net unamortized discounts and premiums (1)		(1,709)		(1,722)
Total borrowings	$	14,832	$	15,230
Less: Current portion of long-term debt		1,739		170
Total long-term debt	$	13,093	$	15,060

__________________________________________________________________________

(1)Unamortized discounts and premiums are amortized over the term of the related debt.

		Carrying
millions		Value		Description
Balance at December 31, 2011		$	15,230
	Borrowings		319	WES revolving credit facility
	Repayments		(131)	6.125% Senior Notes due 2012
			(40)	WES revolving credit facility
	Other, net		8	Changes in debt premium or discount
Balance at March 31, 2012		$	15,386
	Issuance		516	WES 4.00% Senior Notes due 2022
	Borrowings		55	WES revolving credit facility
	Repayments		(800)	$5.0 billion Facility
			(334)	WES revolving credit facility
	Other, net		9	Changes in debt premium or discount
Balance at June 30, 2012		$	14,832

Interest Expense Table

	Three Months Ended				Six Months Ended
	June 30,				June 30,
millions	2012		2011		2012		2011
Current debt, long-term debt, and other	$	236	$	250	$	486	$	498
Capitalized interest		(46)		(34)		(110)		(62)
Total interest expense	$	190	$	216	$	376	$	436

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Derivative Instruments - Derivative Instruments Related to Crude Oil Production/Processing Derivative Activities Table (Detail) (Contracted Commodities in 2012 [Member], Crude Oil [Member])	Jun. 30, 2012
Three-Way Collars [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments	62
Three-Way Collars [Member] | Call Options Sold [Member]
Average price per barrel
Average ceiling price	122.30
Three-Way Collars [Member] | Put Options Purchased [Member]
Average price per barrel
Average floor price	101.22
Three-Way Collars [Member] | Put Options Sold [Member]
Average price per barrel
Average floor price	81.34
Fixed-Price Contracts [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments	60
Average price per barrel
Average price per barrel	107.19

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Income Taxes

6 Months Ended

Jun. 30, 2012

Disclosure Text Block [Abstract]

Income Taxes

11.  Income Taxes

The following is a summary of income tax expense (benefit) and effective tax rates.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
millions except percentages	2012			2011			2012			2011
Income tax expense (benefit)	$	164		$	440		$	516		$	706
Effective tax rate		174	%		44	%		20	%		47	%

The increase from the 35% U.S. federal statutory rate for thethree months ended June 30, 2012, was primarily attributable to the foreign tax rate differential and valuation allowances, recurring accrual of the Algerian exceptional profits tax, and U.S. tax impact from losses and restructuring of foreign operations. The decrease from the 35% U.S. federal statutory rate for the six months ended June 30, 2012, was primarily attributable to the resolution of the Algeria exceptional profits tax dispute. This amount was partially offset by the foreign tax rate differential and valuation allowances, recurringaccrual of the Algerian exceptional profits tax, andU.S. tax impact from losses and restructuring of foreign operations.

The increase from the 35% U.S. federal statutory rate for thethree and six months ended June 30, 2011, was primarily attributable to the recurring accrual of the Algerian exceptional profits tax, foreign tax rate differential and valuation allowances, U.S. tax on foreign income inclusions and distributions, state income taxes, and items resulting from business acquisitions. These items were partially offset by the U.S. income tax benefits associated with foreign losses and restructuring of foreign operations.