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 September 30, 2011

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 September 30, 2011, is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.10 per share	497,971,511

TABLE OF CONTENTS

PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Nine Months Ended September 30,  2011 and 2010		2
	Consolidated Balance Sheets as of September 30, 2011, and December 31, 2010		3
	Consolidated Statement of Equity for the Nine Months Ended September 30, 2011		4
	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September  30, 2011 and 2010		5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010		6
	Notes to Consolidated Financial Statements		7
Item 2.	Management’s Discussion and Analysis		33
	Financial Results		38
	Operating Results		48
	Liquidity and Capital Resources		50
	Regulatory Matters, Environmental and Additional Factors Affecting Business		54
	Critical Accounting Estimates		55
	Recent Accounting Developments		55
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		55
Item 4.	Controls and Procedures		57
PART II
Item 1.	Legal Proceedings		58
Item 1A.	Risk Factors		62
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		66
Item 6.	Exhibits		67

PART I. FINANCIAL INFORMATION

Item  1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months  Ended September 30,				Nine Months  Ended September 30,
millions except per-share amounts		2011		2010		2011		2010
Revenues and Other
Natural-gas sales	$	840	$	809	$	2,564	$	2,692
Oil and condensate sales		1,905		1,298		5,948		4,138
Natural-gas liquids sales		377		227		1,080		736
Gathering, processing, and marketing sales		262		182		750		643
Gains (losses) on divestitures and other, net		(185)		34		(214)		84
Total		3,199		2,550		10,128		8,293
Costs and Expenses
Oil and gas operating		262		207		730		590
Oil and gas transportation and other		217		220		633		607
Exploration		307		296		722		649
Gathering, processing, and marketing		214		134		590		466
General and administrative		293		273		806		686
Depreciation, depletion, and amortization		932		962		2,902		2,845
Other taxes		375		240		1,132		809
Impairments		183		20		287		147
Deepwater Horizon settlement and related costs		4,042		2		4,055		2
Total		6,825		2,354		11,857		6,801
Operating Income (Loss)		(3,626)		196		(1,729)		1,492
Other (Income) Expense
Interest expense		206		218		642		642
(Gains) losses on commodity derivatives, net		(230)		(200)		(317)		(1,052)
(Gains) losses on other derivatives, net		854		221		939		656
Other (income) expense, net		40		(129)		(2)		(106)
Total		870		110		1,262		140
Income (Loss) Before Income Taxes		(4,496)		86		(2,991)		1,352
Income Tax Expense (Benefit)		(1,468)		94		(762)		660
Net Income (Loss)		(3,028)		(8)		(2,229)		692
Net Income Attributable to Noncontrolling Interests		23		18		62		42
Net Income (Loss) Attributable to Common Stockholders	$	(3,051)	$	(26)	$	(2,291)	$	650
Per Common Share:
Net income (loss) attributable to common stockholders—basic	$	(6.12)	$	(0.05)	$	(4.60)	$	1.30
Net income (loss) attributable to common stockholders—diluted	$	(6.12)	$	(0.05)	$	(4.60)	$	1.30
Average Number of Common Shares Outstanding—Basic		498		496		498		495
Average Number of Common Shares Outstanding—Diluted		498		496		498		496
Dividends (per Common Share)	$	0.09	$	0.09	$	0.27	$	0.27

See accompanying Notes to Consolidated Financial Statements.

2

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,		December 31,
millions	2011		2010
ASSETS
Current Assets
Cash and cash equivalents	$	3,487	$	3,680
Accounts receivable, net of allowance:
Customers		1,169		1,032
Others		2,259		1,391
Other current assets		689		572
Total		7,604		6,675
Properties and Equipment
Cost		58,185		54,815
Less accumulated depreciation, depletion, and amortization		20,069		16,858
Net properties and equipment		38,116		37,957
Other Assets		1,510		1,616
Goodwill and Other Intangible Assets		5,832		5,311
Total Assets	$	53,062	$	51,559
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	2,446	$	2,726
Accrued expenses		1,259		1,097
Current portion of long-term debt		141		291
Deepwater Horizon settlement and related costs		4,017		—
Total		7,863		4,114
Long-term Debt		12,808		12,722
Other Long-term Liabilities
Deferred income taxes		8,670		9,861
Asset retirement obligations		1,584		1,529
Other		2,638		1,894
Total		12,892		13,284
Equity
Stockholders’ equity
Common stock, par value $0.10 per share
(1.0 billion shares authorized, 515.5 million and 513.3 million shares issued as of September 30, 2011, and December 31, 2010, respectively)		51		51
Paid-in capital		7,845		7,496
Retained earnings		12,023		14,449
Treasury stock (17.5 million and 17.1 million shares as of September 30, 2011, and December 31, 2010, respectively)		(794)		(763)
Accumulated other comprehensive income (loss)		(501)		(549)
Total Stockholders’ Equity		18,624		20,684
Noncontrolling interests		875		755
Total Equity		19,499		21,439
Total Liabilities and Equity	$	53,062	$	51,559

See accompanying Notes to Consolidated Financial Statements.

3

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, 2010	$	51	$	7,496	$	14,449	$	(763)	$	(549)	$	755	$	21,439
Net income (loss)		—		—		(2,291)		—		—		62		(2,229)
Common stock issued		—		155		—		—		—		—		155
Dividends—common		—		—		(135)		—		—		—		(135)
Repurchase of common stock		—		—		—		(31)		—		—		(31)
Sale of subsidiary units (1)		—		32		—		—		—		269		301
Conversion of subordinated limited partner units to common units (2)		—		162		—		—		—		(162)		—
Contributions from (distributions to) noncontrolling interest owners and other, net		—		—		—		—		—		(49)		(49)
Reclassification of previously deferred derivative losses to net income		—		—		—		—		7		—		7
Adjustments for pension and other postretirement plans		—		—		—		—		41		—		41
Balance at September 30, 2011	$	51	$	7,845	$	12,023	$	(794)	$	(501)	$	875	$	19,499

⁽¹⁾  Paid-in capital and noncontrolling interests includes $18 million and $9 million, respectively, of tax associated with subsidiary equity transactions that occurred during the current year.

⁽²⁾  Includes $82 million of tax associated with subsidiary equity transactions that occurred prior to the conversion of subordinated limited partner units to common units.

See accompanying Notes to Consolidated Financial Statements.

4

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months  Ended September 30,				Nine Months Ended September 30,
millions	2011		2010		2011		2010
Net Income (Loss)	$	(3,028)	$	(8)	$	(2,229)	$	692
Other Comprehensive Income (Loss), net of taxes
Reclassification of previously deferred derivative losses to net income (1)		2		5		7		13
Adjustments for pension and other postretirement plans:
Net gain (loss) incurred during period (2)		—		—		—		(21)
Prior service credit (cost) incurred during period (3)		—		—		—		(4)
Amortization of net actuarial loss and prior service cost to net periodic benefit cost (4)		14		9		41		31
Total adjustments for pension and other postretirement plans		14		9		41		6
Total		16		14		48		19
Comprehensive Income (Loss)		(3,012)		6		(2,181)		711
Comprehensive Income Attributable to Noncontrolling Interests		23		18		62		42
Comprehensive Income (Loss) Attributable to Common Stockholders	$	(3,035)	$	(12)	$	(2,243)	$	669

⁽¹⁾  Net of income tax benefit (expense) of $(1) million and $(2) million for the three months ended September 30, 2011 and 2010, respectively, and $(4) million and $(7) million for the nine months ended September 30, 2011 and 2010, respectively.

⁽²⁾  Net of income tax benefit (expense) of zero for the three months ended September 30, 2011 and 2010, and zero and $12 million for the nine months ended September 30, 2011 and 2010, respectively.

⁽³⁾  Net of income tax benefit (expense) of zero for the three months ended September 30, 2011 and 2010, and zero and $2 million for the nine months ended September 30, 2011 and 2010, respectively.

⁽⁴⁾  Net of income tax benefit (expense) of $(8) million and $(5) million for the three months ended September 30, 2011 and 2010, respectively, and $(24) million and $(17) million for the nine months ended September 30, 2011 and 2010, respectively.

See accompanying Notes to Consolidated Financial Statements.

5

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months  Ended September 30,
millions	2011		2010
Cash Flows from Operating Activities
Net income (loss)	$	(2,229)	$	692
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		2,902		2,845
Deferred income taxes		(1,195)		(142)
Dry hole expense and impairments of unproved properties		423		473
Impairments		287		147
(Gains) losses on divestitures, net		243		(12)
Unrealized (gains) losses on derivatives, net		767		(66)
Deepwater Horizon settlement and related costs		4,055		2
Other		151		145
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		(939)		15
Increase (decrease) in accounts payable and accrued expenses		215		(293)
Other items—net		(88)		126
Net cash provided by (used in) operating activities		4,592		3,932
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs		(4,110)		(3,563)
Acquisition of midstream businesses		(802)		—
Divestitures of properties and equipment and other assets		75		44
Other—net		(52)		(30)
Net cash provided by (used in) investing activities		(4,889)		(3,549)
Cash Flows from Financing Activities
Borrowings, net of issuance costs		1,051		3,199
Repayments of debt		(1,154)		(1,173)
Repayment of midstream subsidiary note payable to a related party		—		(1,599)
Increase (decrease) in accounts payable, banks		39		(70)
Dividends paid		(135)		(136)
Repurchase of common stock		(31)		(35)
Issuance of common stock, including tax benefit on stock option exercises		57		90
Sale of subsidiary units		328		97
Distributions to noncontrolling interest owners		(57)		(36)
Other financing activities		9		(24)
Net cash provided by (used in) financing activities		107		313
Effect of Exchange Rate Changes on Cash		(3)		(9)
Net Increase (Decrease) in Cash and Cash Equivalents		(193)		687
Cash and Cash Equivalents at Beginning of Period		3,680		3,531
Cash and Cash Equivalents at End of Period	$	3,487	$	4,218

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 September 30, 2011, and December 31, 2010, the Consolidated Statements of Income and Comprehensive Income for the three and nine months ended September 30, 2011 and 2010, the Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010, and the Consolidated Statement of Equity for the nine months ended September 30, 2011. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

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.

Recently Issued Accounting Standards Not Yet Adopted  The Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that further addresses fair-value-measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair-value-measurement accounting and disclosure requirements, changes fair-value-measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair-value measurements. The ASU is required to be adopted on a prospective basis by Anadarko beginning January 1, 2012. The Company does not expect adoption of this ASU to have an impact on its consolidated financial statements, other than requiring revised disclosures, where appropriate.

In September 2011, the FASB issued an ASU that permits an initial assessment of qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount for goodwill impairment testing purposes. Thus, determining a reporting unit’s fair value is not required unless, as a result of a qualitative assessment, it is more likely than not that the fair value of the reporting unit is less than its carrying amount. This ASU is effective for periods beginning after December 15, 2011. Adoption of this ASU will have no impact on the Company’s consolidated financial statements.

2. Deepwater Horizon Events

Background, Settlement, and BP Indemnification  In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating leasehold interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. The Macondo well was plugged on September 19, 2010.

BP Exploration & Production Inc. (BP), the operator of Mississippi Canyon Block 252 in which the Macondo well is located (Lease), is funding claims and coordinating cleanup efforts. BP invoiced the Company $6.1 billion for what BP considered to be Anadarko’s proportionate share of actual costs and anticipated near-term future costs related to these activities. Anadarko withheld payment to BP for all Deepwater Horizon event-related invoices pending the completion of various ongoing investigations into and litigation regarding the cause of the well blowout, explosion, and subsequent release of hydrocarbons.

7

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify, whereby the Company and BP agreed to a mutual release of claims against each other relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company has agreed to pay $4.0 billion in cash and transfer its interest in the Lease to BP (subject to required governmental approvals of the transfer), and BP has agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued to date and to forgo reimbursement for all future costs arising from the Deepwater Horizon events, including future costs under the Operating Agreement (OA). In addition, BP has fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related 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 OA. This indemnification has been 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. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder, derivative, or security laws claims, or certain other claims. The Company believes that costs associated with non-indemnified items, individually or in the aggregate, will not materially impact the Company’s consolidated financial position, results of operations, or cash flows.

Liability Accrual  As of September 30, 2011, the Company has recorded a liability for Deepwater Horizon-related settlement costs of approximately $4.0 billion, which includes the cash payment to be remitted to BP in accordance with the Settlement Agreement, as well as Deepwater Horizon event-related legal fees. These legal fees were previously recorded in general and administrative expenses in the Consolidated Statements of Income and have been reclassified for all periods presented to conform to the current-period presentation.

Below is a discussion of the Company’s current analysis, under applicable accounting guidance, of its potential liability for (i) amounts invoiced by BP under the OA (OA Liabilities), (ii) OPA-related environmental costs, and (iii) other contingent liabilities. Accounting rules require loss recognition only where a potential loss is considered probable and can be reasonably estimated.

The Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and 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. The Company has not recorded a liability for any costs that are subject to indemnification by BP.

OA Liabilities  Under the Settlement Agreement, all amounts deemed by BP to have been due under the OA, as well as all future amounts that otherwise would be invoiced to Anadarko under the OA, have been satisfied.

OPA-Related Environmental Costs  BP, Anadarko, and other parties, including parties that do not own an interest in the Lease, such as the drilling contractor, have received correspondence from the United States Coast Guard (USCG) referencing their identification as a “responsible party or guarantor” (RP) under OPA. Under OPA, RPs, including Anadarko, may be jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims related to the spill and spill cleanup. The USCG’s identification of Anadarko as an RP arises as a result of Anadarko’s status as a co-lessee in the Lease.

8

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

Applicable accounting guidance requires the Company to accrue an environmental liability if it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Under accounting guidance applicable to environmental liabilities, a liability is presumed probable if the entity is both identified as an RP and associated with the environmental event. The Company’s co-lessee status in the Lease and the subsequent identification and treatment of the Company as an RP satisfies these standards and therefore establishes the presumption that the Company’s potential environmental liabilities related to the Deepwater Horizon events are probable. Given that such liabilities are probable, the Company must separately assess and estimate the Company’s allocable share of gross estimated OPA-related environmental costs.

As BP funds OPA-related environmental costs, any potential joint and several liability for these costs is satisfied for all RPs, including Anadarko. This bears significance in that once these costs are funded by BP, such costs are no longer analyzed as OPA-related environmental costs, but are instead analyzed as OA Liabilities. As discussed above, Anadarko has agreed with BP to settle its current and future OA Liabilities. Thus, potential liability to the Company for OPA-related environmental costs can only arise where BP does not, or otherwise is unable to fund all of the OPA-related environmental costs. Under this scenario, the joint and several nature of the liability for these costs could cause the Company to recognize a liability for OPA-related environmental costs. However, the Company is fully indemnified by BP against these costs (including guarantees by BPCNA or BP p.l.c.).

Gross OPA-Related Environmental Cost Estimate  In prior periods, the Company provided an estimated range of gross OPA-related environmental costs for all identified RPs. This estimate was comprised of spill-response costs and OPA damage claims and was derived from cost information received by the Company from BP. As a result of the Settlement Agreement, the Company no longer expects to receive cost and claims data related to the Deepwater Horizon events. Accordingly, the OPA-related environmental cost estimate included in BP’s public releases is the best data available to the Company and therefore herein and hereafter will be utilized by the Company in its accounting analysis.

Based on information included in BP p.l.c.’s public release on October 25, 2011, the range of gross OPA-related environmental costs is estimated to be $7.0 billion to $11.0 billion, excluding (i) amounts BP has already funded, which constitute settled OA Liabilities; (ii) amounts that cannot reasonably be estimated by BP, which include NRD claims and other litigation damages; and (iii) non-OPA-related fines and penalties that may be assessed against Anadarko, including assessments under the Clean Water Act (CWA). The Company believes that actual gross OPA-related environmental costs may vary from those estimated by BP p.l.c. in its public releases, perhaps materially from the above cost estimate.

Allocable Share of Gross OPA-Related Environmental Costs  Under applicable accounting guidance, the Company is required to estimate its allocable share of gross OPA-related environmental costs based on the Company’s estimate of the allocation method and percentage that may ultimately apply to it. To date, BP has paid all Deepwater Horizon event-related costs, which satisfies the Company’s potential liability for these costs. Additionally, BP has repeatedly stated publicly and in prior congressional testimony that it will continue to pay these costs. BP’s funding and public commentary has continued subsequent to the release of BP’s own investigation report, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling’s final report, and the Deepwater Horizon Joint Investigation Team final report, which the Company considers to be significant positive indications in assessing the likelihood of BP continuing to fund all of these costs. Based on BP’s stated intent to continue funding these costs, the Company’s assessment of BP’s financial ability to continue funding these costs, and the impact of BP’s settlements with both of its OA partners, the Company believes the likelihood of BP not continuing to satisfy these claims to be remote. Accordingly, at September 30, 2011, the Company considers zero to be its allocable percentage share of gross OPA-related environmental costs and, consistent with applicable accounting guidance, continues to have a liability accrual of zero for these amounts.

9

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

Other Contingencies

Penalties and Fines  These costs include amounts that may be assessed as a result of potential civil and/or criminal penalties under various federal, state, and/or local statutes and/or regulations as a result of the Deepwater Horizon events, including, for example, the CWA, the Outer Continental Shelf Lands Act, the Migratory Bird Treaty Act, and possibly other federal, state, and local laws. The foregoing does not represent an exhaustive list of statutes and regulations that potentially could trigger a penalty or fine assessment against the Company.

To date, no penalties or fines have been assessed against the Company. However, on December 15, 2010, the United States Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the United States 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 CWA in an amount to be determined by the Louisiana District Court. The DOJ complaint seeks separate penalty assessments against both Anadarko Petroleum Corporation and AE&P (based on a temporary interest that AE&P at one time held in the Lease). In April 2011, the Company moved to dismiss AE&P from the DOJ lawsuit because the effective date of AE&P’s transfer of its interest in the Lease to Anadarko Petroleum Corporation pre-dated the Deepwater Horizon events. The Company currently believes it is probable that AE&P will not be found liable for CWA penalties upon the presentation of evidence. The Company believes the outcome of this decision will not have a material impact on Anadarko’s potential liability.

Although Anadarko was named in the DOJ civil lawsuit, its status as a defendant does not mean that Anadarko will be assessed a CWA penalty in that action. First, the Company has a defense to liability under the CWA based on the location from which the discharge occurred. If the court finds that the discharge of hydrocarbons came from the vessel (which includes the riser pipe), the Company may not be liable under the CWA because it neither owned nor operated the Deepwater Horizon drilling rig. Second, because CWA penalties, in practice, are generally assessed on a party-specific basis and take into account several factors including the party’s degree of fault, the Company considers its lack of direct involvement in the operation of the drilling rig and the spill itself significant in concluding that losses from CWA penalty assessments are not probable. This view was reinforced by the Louisiana District Court’s decision that dismissed all negligence claims against the Company based on the court’s finding that the Company did not exercise operational control over the events that led to the oil spill. Accordingly, the Company does not consider a CWA penalty assessment to be probable and, therefore, has not recorded a liability for potential CWA penalties at September 30, 2011.

In addition to concluding that any liability for CWA penalties is not probable, the Company currently cannot estimate the amount of any potential penalty. The CWA sets forth subjective criteria, including degree of fault and history of prior violations, which influence CWA penalty assessments. Thus, as a result of the subjective nature of CWA penalty assessments, the Company currently cannot estimate the amount of any such penalty. However, given the Company’s lack of direct operational involvement in the event, as recently confirmed by the Louisiana District Court, the Company believes that its potential exposure to CWA penalties will not materially impact the Company’s consolidated financial position, results of operations, or cash flows.

Natural Resource Damages  This category includes future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of injury assessments and restoration planning. Natural resources generally include land, fish, water, air, wildlife, and other such resources belonging to, managed by, held in trust by, or otherwise controlled by, the federal, state, or local government.

The NRD-assessment process is led by government agencies that act as trustees of natural resources on behalf of the public. Government agencies involved in the process include the Department of Commerce, the Department of the Interior (DOI), and the Department of Defense. These governmental departments, along with the five affected states – Alabama, Florida, Louisiana, Mississippi, and Texas – are referred to as the “Co-Trustees.” The Co-Trustees continue to conduct injury assessment and restoration planning.

10

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

The DOJ civil lawsuit filed against BP, the Company, and others seeks unspecified damages for injury to federal natural resources. Not all of the Co-Trustees were a party to this lawsuit; however, during the second quarter of 2011, the states of Alabama and Louisiana each filed NRD-related state law claims against the Company in the Louisiana District Court. The Company filed a motion to dismiss all of the claims in both of these complaints in June 2011. The Court heard oral arguments on these and other parties’ motions in September 2011 and has taken the motions under advisement.

NRD claims are generally sought after the damage assessment and restoration planning is completed, which may take several years. Thus, the Company remains unable to reasonably estimate the magnitude of any NRD claim. The Company anticipates that BP will satisfy any NRD claim, which eliminates any potential liability to Anadarko for such costs. In the event any NRD damage claim is made directly against Anadarko, the Company is fully indemnified by BP against such claims (including guarantees by BPCNA or BP p.l.c.).

Civil Litigation Damage Claims  Numerous civil lawsuits have been filed against BP and other parties, including the Company, by, among others, fishing, boating, and shrimping enterprises and industry groups; restaurants; commercial and residential property owners; certain rig workers or their families; the State of Alabama and several of its political subdivisions; the DOJ; environmental non-governmental organizations; the State of Louisiana and certain of its political subdivisions; and certain Mexican states. Many of the lawsuits filed assert various claims of negligence, gross negligence, and violations of several federal and state laws and regulations, including, among others, OPA; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Air Act; the CWA; and the Endangered Species Act; or challenge existing permits for operations in the Gulf of Mexico. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment, and/or injunctive relief.

In August 2010, the United States Judicial Panel on Multidistrict Litigation created Multidistrict Litigation No. 2179 (MDL) to administer essentially all pretrial matters for litigation filed in federal court involving Deepwater Horizon event-related claims. Federal Judge Carl Barbier presides over this MDL in the Louisiana District Court. The Louisiana District Court has issued a number of case-management orders that establish a schedule for procedural matters, discovery, and trial of certain of the MDL cases. The parties to the MDL are actively engaged in discovery. In May 2011 and September 2011, Judge Barbier heard oral arguments on the numerous motions to dismiss filed by the multiple defendants named in this litigation. While a number of the motions remain pending, Judge Barbier has dismissed all maritime and state law claims filed against the Company by private plaintiffs seeking damages for economic loss. All negligence claims filed by these private plaintiffs against the Company have been dismissed based upon Judge Barbier’s finding that the Company did not exercise operational control over the events that led to the oil spill. In a separate order, Judge Barbier reached similar findings and dismissed all claims against the Company filed by private plaintiffs alleging personal injury caused by exposure to oil, fumes or other contaminants from the blowout or the chemical dispersants used during the post-spill cleanup operations. Judge Barbier further found that federal law exclusively applies to the private plaintiffs’ claims for property damage and economic loss and dismissed all state law claims against the Company asserting liability for such damages and losses. Only OPA claims asserted by private plaintiffs seeking economic loss damages against the Company remain. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against such OPA claims.

11

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2.  Deepwater Horizon Events (Continued)

The Louisiana District Court has scheduled a February 2012 trial in Transocean’s Limitation of Liability case in the MDL. This trial is to be the first phase of a three-phase trial, each phase designed to address different issues. 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 April 2011, the Company filed its answer in this Limitation of Liability case and cross-claimed against affiliates of BP and Transocean Ltd. (Transocean), Halliburton Energy Services, Inc. (Halliburton), Cameron International Corporation (Cameron), and other third-party defendants. Transocean, Halliburton, and Cameron subsequently filed cross-claims against the Company, and BP filed a motion to stay the litigation in the MDL between BP and the non-operating OA parties. In the motion to stay, BP argued that the cross-claims asserted against BP by the Company and the other non-operating OA party are covered by the dispute resolution procedures under the OA and should be stayed. As a result of the Settlement Agreement, a mutual release of all claims, including those that could have been made in arbitration, was agreed to by the Company and BP. The Company has also assigned all rights, title, and interest to all claims that have been or could be asserted against third parties, including cross-claims filed against other third-party defendants, to BP, with the exception of rights to claims the Company may assert under its insurance policies.

Two separate class action complaints were filed in June and August 2010, in the United States 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 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In November 2010, the New York District Court consolidated the two cases and appointed The Pension Trust Fund for Operating Engineers and Employees’ Retirement System of the Government of the Virgin Islands (Virgin Islands Group) to act as Lead Plaintiff. In January 2011, the Lead Plaintiff filed its Consolidated Amended Complaint. Prior to filing its Consolidated Amended Complaint, the Lead Plaintiff requested leave from the New York District Court to transfer this lawsuit to the United States District Court for the Southern District of Texas. The Company opposes the Lead Plaintiff’s request to transfer the case to the District Court for the Southern District of Texas. The parties have submitted briefs to the New York District Court concerning the transfer of venue issue. In March 2011, the Company moved to dismiss the Consolidated Amended Complaint of the Lead Plaintiff, and in April 2011, the Lead Plaintiff filed its opposition to the motion to dismiss. The motion to transfer and motion to dismiss remain under advisement of the New York District Court.

Also in June 2010, a shareholder derivative petition was filed in the 152^nd Judicial District Court of Harris County, Texas (Harris County District Court), by a shareholder of the Company against Anadarko (as a nominal defendant), certain of its officers, and current and certain former directors. The petition alleged breaches of fiduciary duties, unjust enrichment, and waste of corporate assets in connection with the Deepwater Horizon events. The plaintiffs sought certain changes to the Company’s governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs. In November 2010, the Harris County District Court granted Anadarko’s Motion to Dismiss for Lack of Jurisdiction and Special Exceptions, and granted the plaintiffs 120 days to file an Amended Petition. In March 2011, the plaintiffs filed an Amended Petition. The Company filed Special Exceptions and a Motion to Dismiss the Amended Petition in April 2011. In June 2011, the Harris County District Court heard oral arguments on these matters and granted the motion to dismiss. The time for the plaintiffs to appeal has expired.

In September 2010, a purported shareholder made a demand of the Company’s Board of Directors (Board) to investigate allegations of breaches of duty by members of management. The Board duly considered the demand, and in January 2011 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter.

Given the early 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 directors in all proceedings, and will avail itself of any and all indemnities provided by BP against civil damages.

12

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2.  Deepwater Horizon Events (Continued)

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.

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 the investigation by the United States 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.

Insurance and Other Recoveries    The Company carries insurance to protect against potential financial losses. At the time of the Deepwater Horizon events, the Company’s insurance coverage applied to gross covered costs up to a level of approximately $710 million, less up to $60 million of deductibles. Based on Anadarko’s 25% non-operated leasehold interest in the Lease, the Company estimates its net insurance coverage will total not less than $178 million, less deductibles of $15 million. The Company has not recognized a receivable for any potential insurance recoveries in its Consolidated Balance Sheets, but expects to recover, at a minimum, the first $163 million of insured costs under its then-existing insurance policy. At this time, recovery of these amounts is not considered probable because the Company has not yet filed a claim. The Company also carries directors’ and officers’ insurance which covers certain risks associated with certain of the above-described legal proceedings.

As part of the Settlement Agreement, BP has agreed that, to the extent it receives value in the future from claims that it has asserted or could assert against third parties arising from or relating to the Deepwater Horizon events, it will make cash payments (not to exceed $1.0 billion in the aggregate) to Anadarko, on a current and continuing basis, of 12.5% of the aggregate value received by BP in excess of $1.5 billion. Any payments received by the Company pursuant to this arrangement will be accounted for as a reimbursement of the $4.0 billion payment made by the Company to BP as part of the Settlement Agreement.

3.  Acquisitions

In May 2011, Anadarko increased its ownership interest in a natural-gas processing plant (Wattenberg Plant), located in northeast Colorado, by acquiring an additional 93% interest for $576 million. Anadarko operates and now owns a 100% interest in the Wattenberg Plant.

In February 2011, Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, acquired a natural-gas processing plant and related gathering systems (Platte Valley), located in northeast Colorado, for $302 million.

These acquisitions, along with future expansion plans, align Anadarko’s natural-gas processing capacity with the Company’s anticipated production growth in the Rocky Mountains Region (Rockies). In addition, these acquisitions position the Company to improve field recoveries and realize operational cost efficiencies.

13

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

3.  Acquisitions (Continued)

The Wattenberg Plant and Platte Valley acquisitions constitute business combinations and were accounted for using the acquisition method. The following summarizes the preliminary fair value of assets acquired and liabilities assumed at the acquisition dates:

millions
Properties and equipment	$	298
Intangible assets		165
Deferred income taxes		31
Other assets		4
Other liabilities		(21	)
Goodwill		362
Total assets acquired and liabilities assumed		839
Less: Fair value of Anadarko’s pre-acquisition 7% equity interest in the Wattenberg Plant		37
Acquisition of midstream businesses		802
Loss on Anadarko’s preexisting contracts with the previous Wattenberg Plant owner		76
Total consideration paid	$	878

All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties and equipment is based on market and cost approaches. Intangible assets consist of customer contracts, the fair value of which was determined using an income approach. Deferred tax assets represent the tax effects of differences in the tax basis and acquisition-date fair values of assets acquired and liabilities assumed. Liabilities assumed include asset retirement obligations existing at the date of acquisition, and were valued consistent with the Company’s policy for estimating its asset retirement obligations.

Assets acquired and liabilities assumed are included within the midstream reporting segment, except for $335 million of goodwill and a portion of the related deferred tax asset recognized in connection with the Wattenberg Plant acquisition, which are included in the oil and gas exploration and production reporting segment. Goodwill of $469 million related to the Wattenberg Plant acquisition is amortizable for tax purposes.

Goodwill from these acquisitions is included in the oil and gas exploration and production reporting segment and the midstream reporting segment based on the increase in fair value to each of the respective reporting segments. The increase in fair value to these reporting segments is derived from improved NGLs volume retention from equity production and the alignment of Company-controlled natural-gas processing capacity with future production growth plans in the Rockies. Goodwill is not subject to amortization, but will be subject to annual impairment testing (or more frequent testing as circumstances dictate). At September 30, 2011, the Company had $5.6 billion of goodwill allocated as follows: $5.4 billion to oil and gas exploration and production; $102 million to other gathering and processing; $59 million to WES gathering and processing; and $5 million to transportation.

Prior to the Wattenberg Plant acquisition, the Company was party to natural-gas processing contracts with the previous Wattenberg Plant owner. As a result of the acquisition, these preexisting contracts were terminated, causing the Company to recognize a $76 million loss, which is included in gains (losses) on divestitures and other, net in the Consolidated Statements of Income for the nine months ended September 30, 2011. This loss represents the aggregate amount by which the contracts were unfavorable as compared to current market transactions for the same or similar services at the date of the Company’s acquisition of the Wattenberg Plant.

The Company also recognized a gain of $21 million from the acquisition-date fair-value remeasurement of its pre-acquisition 7% equity interest in the Wattenberg Plant. The gain is included in gains (losses) on divestitures and other, net in the Consolidated Statements of Income for the nine months ended September 30, 2011.

14

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

3.  Acquisitions (Continued)

Results of operations attributable to the Wattenberg Plant and Platte Valley acquisitions are included in the Company’s Consolidated Statements of Income from the dates acquired. The amounts of revenue and earnings included in the Company’s Consolidated Statements of Income for the three and nine months ended September 30, 2011, and the amounts of revenue and earnings that would have been recognized had the acquisitions occurred on January 1, 2010, are not material.

4.  Inventories

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

	September 30,		December 31,
millions	2011		2010
Crude oil	$	133	$	126
Natural gas		34		64
NGLs		60		61
Total	$	227	$	251

5.  Properties and Equipment

Suspended Exploratory Drilling Costs  The Company’s capitalized suspended well costs at September 30, 2011, and December 31, 2010, were $1.2 billion and $935 million, respectively. The increase in suspended exploratory drilling costs during 2011 primarily relates to the capitalization of costs associated with successful exploration drilling in Mozambique, Ghana and Brazil. For the nine months ended September 30, 2011, $32 million of exploratory well costs previously capitalized as suspended well costs for greater than one year were charged to dry hole expense and $116 million of capitalized suspended well costs were reclassified to proved properties.

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

Impairments  Impairment expense for the three and nine months ended September 30, 2011, was $183 million and $287 million, respectively. During the third quarter of 2011, the Company recognized impairments of $93 million related to United States offshore properties and $87 million related to the Company’s investment in Venezuelan assets due to changes in expected recoverable reserves in these areas. At September 30, 2011, the Company’s after-tax net investment in the Venezuelan assets was $38 million. During the second quarter of 2011, the Company recognized impairments of $100 million related to United States onshore properties due to a change in projected cash flows resulting from the Company’s intent to divest of the properties. All of these assets are included in the oil and gas exploration and production operating segment and were impaired to fair value, estimated using Level 3 fair-value inputs.

Impairment expense for the three and nine months ended September 30, 2010, was $20 million and $147 million, respectively, including $114 million recognized in the second quarter of 2010 related to a production platform included in the oil and gas exploration and production operating segment that remains idle with no identifiable plans for use, and for which a limited market currently exists. The platform was impaired to fair value, estimated using Level 3 fair-value inputs.

15

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5.  Properties and Equipment (Continued)

Assets Held for Sale   During the third quarter of 2011, the Company began marketing certain onshore domestic properties from both the oil and gas exploration and production operating segment and the other midstream operating segment in order to redirect its operating activities and capital to other areas. At September 30, 2011, net properties and equipment, goodwill and other intangible assets, and other long-term liabilities on the Company’s Consolidated Balance Sheets included $273 million, $42 million, and $6 million, respectively, associated with assets held for sale. The Company also recognized losses on assets held for sale of $268 million related to oil and gas exploration and production operating segment properties and $31 million related to other midstream operating segment properties. The assets were impaired to fair value, estimated using Level 3 fair-value inputs, with resulting losses included in gains (losses) on divestitures and other, net in the Consolidated Statements of Income for the three and nine months ended September 30, 2011.

6.  Noncontrolling Interests

In March and September 2011, WES issued approximately four million and six million common units to the public, respectively, raising net proceeds of $130 million and $198 million, respectively, which increased the noncontrolling interest component of total equity.

In August 2011, the WES subordinated limited partner units held by Anadarko converted to common limited partner units on a one-for-one basis. Upon this conversion, $162 million related to pre-conversion changes in the Company’s ownership interest in WES was transferred from noncontrolling interests to paid-in capital. Additionally, $32 million was recorded to paid-in capital as a result of WES’s third-quarter issuance of common units. The Company’s net income (loss) attributable to common stockholders, together with the above-described increases to Anadarko’s paid-in capital, for the three and nine months ended September 30, 2011, totaled $(2,857) million and $(2,097) million, respectively. At September 30, 2011, Anadarko’s ownership interest in WES consists of a 43.3% limited partner interest, a 2% general partner interest, and incentive distribution rights.

7.  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 this 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 $113 million ($72 million after tax) and $125 million ($79 million after tax) at September 30, 2011, and December 31, 2010, respectively, relate to interest-rate derivatives that were previously subject to hedge accounting.

16

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7.  Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities  Below is a summary of the Company’s derivative instruments at September 30, 2011, related to its Oil and Natural-Gas Production/Processing Activities. The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are NYMEX Cushing prices.

	2011		2012		2013
Natural Gas
Three-Way Collars (thousand MMBtu/d)		480		500		450
Average price per MMBtu
Ceiling sold price (call)	$	8.29	$	9.03	$	6.57
Floor purchased price (put)	$	6.50	$	6.50	$	5.00
Floor sold price (put)	$	5.00	$	5.00	$	4.00
Fixed-Price Contracts (thousand MMBtu/d)		90		—		—
Average price per MMBtu	$	6.17	$	—	$	—
Basis Swaps (thousand MMBtu/d)		45		—		—
Average price per MMBtu	$	(1.74)	$	—	$	—

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

	2011		2012
Crude Oil
Three-Way Collars (MBbls/d)		126		2
Average price per barrel
Ceiling sold price (call)	$	99.95	$	92.50
Floor purchased price (put)	$	79.29	$	50.00
Floor sold price (put)	$	64.29	$	35.00

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 September 30, 2011, and December 31, 2010, the Company had fixed-price physical transactions related to natural gas totaling 28 billion cubic feet (Bcf) and 32 Bcf, respectively, offset by derivative transactions for 15 Bcf and 28 Bcf, respectively, for net positions of 13 Bcf and 4 Bcf, respectively.

17

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Derivative Instruments (Continued)

Interest-Rate Derivatives  In December 2008 and January 2009, Anadarko entered into interest-rate swap contracts as a fixed-rate payor to mitigate the interest-rate risk associated with anticipated 2011 and 2012 debt issuances. Due to rising interest rates thereafter, the fair value of the swap contracts increased and, in 2009, the Company revised the swap contract terms to increase the weighted-average interest rate of the swap portfolio from approximately 3.25% to approximately 4.80%, and realized a $552 million gain. During the third quarter of 2011, in order to better align the swap portfolio with the anticipated timing of future debt refinancing, the Company extended the swap maturity dates from October 2011 to June 2014 for interest-rate swaps with an aggregate notional principal amount of $1.85 billion. In connection with these extensions, the swap interest rates were also adjusted.

A summary of outstanding interest-rate swaps at September 30, 2011, is presented below.

millions except percentages	Reference Period		Weighted-Average   Interest Rate
Notional Principal Amount:	Start	End
$         150	October 2011	October 2041	4.65 %
$         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 Derivative Assets				Gross Derivative Liabilities
millions Derivatives	Balance Sheet         Classification	September 30, 2011		December 31, 2010		September 30, 2011		December 31,  2010
Commodity
	Other Current Assets	$	428	$	444	$	(81)	$	(274)
	Other Assets		166		242		(9)		(56)
	Accrued Expenses		4		89		(17)		(131)
	Other Liabilities		1		26		(8)		(28)
			599		801		(115)		(489)
Interest Rate and Other
	Accrued Expenses		—		—		(185)		(190)
	Other Liabilities		—		—		(987)		(45)
			—		—		(1,172)		(235)
Total Derivatives		$	599	$	801	$	(1,287)	$	(724)

18

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7.  Derivative Instruments (Continued)

Effect of Derivative Instruments—Statement of Income  The realized and unrealized gain or loss amounts and classification of derivative instruments for the respective three and nine months ended September 30 are as follows:

		(Gain) Loss
millions Derivatives	Classification of (Gain)         Loss Recognized	Three Months Ended September 30, 2011						Nine Months Ended September 30, 2011
		Realized		Unrealized		Total		Realized		Unrealized		Total
Commodity
	Gathering, Processing, and Marketing Sales(1)	$	1	$	(3)	$	(2)	$	17	$	(8)	$	9
	(Gains) Losses on Commodity Derivatives, net		(71)		(159)		(230)		(155)		(162)		(317)
Interest Rate and Other
	(Gains) Losses on Other Derivatives, net		—		854		854		2		937		939
Derivative (Gain) Loss, net		$	(70)	$	692	$	622	$	(136)	$	767	$	631

		(Gain) Loss
millions Derivatives	Classification of (Gain)         Loss Recognized	Three Months Ended September 30, 2010						Nine Months Ended September 30, 2010
		Realized		Unrealized		Total		Realized		Unrealized		Total
Commodity
	Gathering, Processing, and Marketing Sales(1)	$	—	$	(4)	$	(4)	$	1	$	(9)	$	(8)
	(Gains) Losses on Commodity Derivatives, net		(157)		(43)		(200)		(339)		(713)		(1,052)
Interest Rate and Other
	(Gains) Losses on Other Derivatives, net		—		221		221		—		656		656
Derivative (Gain) Loss, net		$	(157)	$	174	$	17	$	(338)	$	(66)	$	(404)

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

Credit-Risk Considerations  The financial integrity of exchange-traded contracts is assured by NYMEX or the Intercontinental Exchange through systems of financial safeguards and transaction guarantees and is subject to nominal credit risk. 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.

19

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7.  Derivative Instruments (Continued)

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 September 30, 2011, $340 million of the Company’s $1.3 billion gross derivative liability balance, and at December 31, 2010, $394 million of the Company’s $724 million 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 commodity and interest-rate derivatives, as settlement timing differs.

Some of the Company’s derivative instruments are subject to provisions that may require collateralization of the Company’s obligations. 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 (the $5.0 billion Facility), the available capacity of which is sufficient to secure potential obligations to such counterparties.

Unsecured derivative obligations may require immediate settlement or full collateralization if certain credit-risk-related provisions are triggered, such as the Company’s credit rating declining to a level below investment grade by major credit rating agencies. For these counterparties, the aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed was $10 million (net of collateral) at September 30, 2011 and December 31, 2010, and is 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 following tables set forth, by input level within the fair-value hierarchy, the fair value of the Company’s derivative financial assets and liabilities.

		$000,000		$000,000		$000,000		$000,000		$000,000		$000,000
September 30, 2011
millions	Level 1		Level 2		Level 3		Netting (1)		Collateral		Total
Assets:
Commodity derivatives
Financial institutions	$	2	$	466	$	—	$	(84)	$	(5)	$	379
Other counterparties		—		131		—		(11)		—		120
Interest-rate and other derivatives		—		—		—		—		—		—
Total derivative assets	$	2	$	597	$	—	$	(95)	$	(5)	$	499
Liabilities:
Commodity derivatives
Financial institutions	$	(3)	$	(88)	$	—	$	84	$	5	$	(2)
Other counterparties		—		(24)		—		11		—		(13)
Interest-rate and other derivatives		—		(1,172)		—		—		110		(1,062)
Total derivative liabilities	$	(3)	$	(1,284)	$	—	$	95	$	115	$	(1,077)

⁽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.

20

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7.  Derivative Instruments (Continued)

December 31, 2010
millions	Level 1		Level 2		Level 3		Netting (1)		Collateral		Total
Assets:
Commodity derivatives
Financial institutions	$	3	$	557	$	—	$	(298)	$	(15)	$	247
Other counterparties		—		241		—		(148)		—		93
Total derivative assets	$	3	$	798	$	—	$	(446)	$	(15)	$	340
Liabilities:
Commodity derivatives
Financial institutions	$	(2)	$	(333)	$	—	$	298	$	—	$	(37)
Other counterparties		—		(154)		—		148		—		(6)
Interest-rate and other derivatives		—		(235)		—		—		15		(220)
Total derivative liabilities	$	(2)	$	(722)	$	—	$	446	$	15	$	(263)

⁽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.

8.  Debt and Interest Expense

Debt  The following presents the Company’s outstanding debt and capital lease obligations. All of the Company’s outstanding debt is senior unsecured.

		$ 1,000,000		$ 1,000,000		$ 1,000,000		$ 1,000,000		$ 1,000,000		$ 1,000,000
	September 30, 2011						December 31, 2010
millions	Principal		Carrying   Value		Fair     Value		Principal		Carrying   Value		Fair     Value
Long-term notes and debentures	$	13,952	$	12,226	$	13,752	$	14,237	$	12,488	$	13,459
WES borrowings		500		494		503		299		299		299
Total borrowings	$	14,452	$	12,720	$	14,255	$	14,536	$	12,787	$	13,758
Capital lease obligations		229		229		N/A		226		226		N/A
Less: Current portion of long-term debt		141		141		134		289		291		296
Total long-term debt	$	14,540	$	12,808	$	14,121	$	14,473	$	12,722	$	13,462

21

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Debt and Interest Expense (Continued)

Debt Activity  The following presents the Company’s debt activity during the nine months ended September 30, 2011.

millions	Principal		Carrying   Value		Description
Balance at December 31, 2010	$	14,536	$	12,787
Borrowings		560		560	WES credit facility
Repayments(1)		(389)		(389)	WES credit facility and WES term loan
Other, net		—		8	Changes in debt premium or discount
Balance at March 31, 2011	$	14,707	$	12,966
Issuance		500		494	WES 5.375% Senior Notes due 2021
Repayments(1)		(470)		(470)	WES credit facility
Other, net		—		8	Changes in debt premium or discount
Balance at June 30, 2011	$	14,737	$	12,998
Borrowings		10		10	WES credit facility
Repayments(1)		(285)		(285)	6.875% Senior Notes due 2011
		(10)		(10)	WES credit facility
Other, net		—		7	Changes in debt premium or discount
Balance at September 30, 2011	$	14,452	$	12,720

⁽¹⁾  Debt repayment activity includes both scheduled repayments and retirements before scheduled maturity.

Anadarko Revolving Credit Facility and Letter of Credit Facility  During the third quarter of 2011, the Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit (the LOC Facility). Compensating balances deposited at the financial institution provide for reduced fees under the LOC Facility. These compensating balances may be withdrawn at any time, resulting in higher fees under the LOC Facility. At September 30, 2011, cash and cash equivalents includes $325 million of demand deposits serving as compensating balances. The LOC Facility also requires the Company to maintain a senior debt revolving credit facility with minimum commitments of at least $1.0 billion and the availability to issue letters of credit of at least $400 million.

In August 2011, the Company amended the $5.0 billion Facility to reduce the maintenance costs and to lower the interest rates under the facility. At September 30, 2011, the $5.0 billion Facility was undrawn with available capacity of $4.6 billion ($5.0 billion undrawn capacity, less $400 million of letter-of-credit capacity maintained pursuant to the terms of the LOC Facility).

WES Revolving Credit Facility  During the first quarter of 2011, WES borrowed $310 million under its $450 million senior unsecured revolving credit facility, primarily to fund the Platte Valley acquisition. In March 2011, WES entered into a five-year, $800 million senior unsecured revolving credit facility (RCF), which amended and restated the $450 million senior unsecured revolving credit facility, and borrowed $250 million under the RCF to repay a senior unsecured term loan. Also during the first quarter of 2011, WES repaid $139 million of borrowings under its RCF primarily from proceeds related to its public offering of four million common units, which raised net proceeds of $130 million. During the second quarter of 2011, WES repaid the outstanding RCF borrowings with net proceeds from the public offering of $500 million 5.375% Senior Notes due 2021. At September 30, 2011, WES was in compliance with all covenants contained in the RCF, had no outstanding borrowings under the RCF, and had the full $800 million of RCF borrowing capacity available.

22

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8.  Debt and Interest Expense (Continued)

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
millions	2011		2010		2011		2010
Current debt, long-term debt, and other(1)	$	245	$	235	$	743	$	642
Loss on early debt retirements and commitment termination(2)		—		17		—		89
Capitalized interest		(39)		(34)		(101)		(89)
Interest expense	$	206	$	218	$	642	$	642

⁽¹⁾  Included in the three and nine months ended September 30, 2010, is $7 million and $9 million, respectively, of unamortized debt issuance costs associated with the retirement of the midstream subsidiary note payable to a related party (Midstream Subsidiary Note).

⁽²⁾  Loss on early debt retirements in 2010 is the result of repurchasing $1.0 billion aggregate principal amount of debt due 2011 and 2012. Also included in the three and nine months ended September 30, 2010, is $17 million for commitment and structuring costs associated with a contemplated term-loan facility.

9. Stockholders’ Equity

The reconciliation between basic and diluted EPS from continuing operations attributable to common stockholders is as follows:

		0,000,000		0,000,000		0,000,000		0,000,000
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
millions except per-share amounts	2011		2010		2011		2010
Income (loss):
Net income (loss) attributable to common stockholders	$	(3,051)	$	(26)	$	(2,291)	$	650
Less: Distributions on participating securities		—		—		—		1
Less: Undistributed income allocated to participating securities		—		—		—		4
Basic	$	(3,051)	$	(26)	$	(2,291)	$	645
Diluted	$	(3,051)	$	(26)	$	(2,291)	$	645
Shares:
Average number of common shares outstanding—basic		498		496		498		495
Dilutive effect of stock options and performance-based stock awards		—		—		—		1
Average number of common shares outstanding—diluted		498		496		498		496
Excluded (1)		12		12		12		6
Income (loss) per common share:
Basic	$	(6.12)	$	(0.05)	$	(4.60)	$	1.30
Diluted	$	(6.12)	$	(0.05)	$	(4.60)	$	1.30
Dividends per common share	$	0.09	$	0.09	$	0.27	$	0.27

⁽¹⁾  Inclusion of the average shares for these awards would have had an anti-dilutive effect.

23

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. Commitments

In May 2011, Anadarko entered into two five-year lease agreements for deepwater drilling rigs. The rigs are expected to be delivered in late 2013 and early 2014. The lease obligations total approximately $1.2 billion, with aggregate future annual minimum lease payments of $30 million in 2013, $209 million in 2014, $238 million in 2015, and $715 million for the remaining lease term.

In October 2011, the Company and BP entered into the Settlement Agreement, pursuant to which the Company has agreed to pay $4.0 billion in cash and transfer its interest in the Lease to BP (subject to required governmental approvals of the transfer), and BP has agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued to date and to forgo reimbursement for all future costs arising from the Deepwater Horizon events, including future costs under the OA. In addition, BP has fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related OPA damage claims, NRD claims and associated damage-assessment costs, and any claims arising under the OA. This indemnification has been guaranteed by 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. See Note 2 for additional information.

11. Contingencies

The following discussion of the Company’s contingencies excludes the Deepwater Horizon events discussed in Note 2.

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

Litigation  The Company is subject to various claims by its royalty owners in the regular course of business as an oil and gas producer, including disputes regarding measurement, post-production costs and expenses, and royalty valuations. The Company and certain of its subsidiaries (collectively, the Anadarko Defendants) were named as defendants in a case styled U.S. of America ex rel. Harrold E. Wright v. AGIP Petroleum Co., et al. filed in September 2000 in the United States District Court for the Eastern District of Texas, Lufkin Division. This lawsuit generally alleged that the Anadarko Defendants and other industry defendants violated the False Claims Act by knowingly undervaluing natural gas in connection with royalty payments on production from federal and Indian lands. In June 2011, the Company finalized its settlement of this litigation for approximately $19 million that was previously expensed. The settlement has been approved by the United States government and resolves all claims related to this litigation, as well as several related administrative matters, against the Anadarko Defendants.

SM Energy has alleged that AE&P breached a Joint Exploration Agreement (JEA) originally executed between Anadarko and TXCO Energy Corp. (TXCO) in March 2008 relating to an oil and gas development project in Maverick, Dimmitt, Webb and LaSalle Counties in the Eagleford shale in South Texas. SM Energy is a party to the JEA through two letter agreements with TXCO dated April of 2008, to which Anadarko consented. SM Energy contends that Anadarko is required under the agreements to tender to them a proportionate share of the leasehold interests that Anadarko acquired in TXCO’s bankruptcy proceeding in February 2010. The arbitration hearing related to this dispute was held in September 2011. If the Company does not prevail in this matter, Anadarko could be obligated to sell a portion of its leasehold interest in the JEA to SM Energy or pay damages. The Company is vigorously defending this matter.

24

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Contingencies (Continued)

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 its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court). 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. Tronox seeks, among other things, to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko, as well as litigation fees and costs. Anadarko and Kerr-McGee moved to dismiss the complaint in its entirety. In March 2010, the Bankruptcy Court issued an opinion granting in part and denying in part Anadarko’s and Kerr-McGee’s motion to dismiss the complaint. Notably, the Bankruptcy Court dismissed, with prejudice, Tronox’s request for punitive damages relating to the fraudulent-conveyance claims. The Bankruptcy Court granted Tronox leave to replead certain of its common law claims, and Tronox filed an amended complaint in April 2010. In May 2010, Anadarko and Kerr-McGee moved to dismiss certain claims in the amended complaint. In May 2011, the Bankruptcy Court dismissed two claims against Anadarko for conspiracy and aiding and abetting, and declined to dismiss a breach of fiduciary duty claim against Kerr-McGee. In August 2011, Tronox filed a motion for partial summary judgment on the issue of whether damages in the Adversary Proceeding are limited to the amount of Tronox’s environmental and tort creditor claims. Kerr-McGee and Anadarko filed a response and cross-motion in September 2011. Expert discovery is ongoing. The Adversary Proceeding is set for trial in April 2012.

The United States government was granted authority to intervene in the Adversary Proceeding, and it has asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act. Anadarko and Kerr-McGee have moved to dismiss the claims of the United States government, but that motion has been stayed by the Bankruptcy Court.

In August 2010, the Bankruptcy Court entered a Stipulation and Agreed Order among Tronox, Anadarko, and Kerr-McGee authorizing the rejection of the Master Separation Agreement (together with all annexes, related agreements, and ancillary agreements to it, the MSA). Anadarko and Kerr-McGee filed Proofs of Claim, which included claims for damages arising from the MSA rejection. In January 2011, the Bankruptcy Court entered a Stipulation and Agreed Order approving a settlement of Anadarko and Kerr-McGee’s rejection damage claims against Tronox. The settlement provided Anadarko a general unsecured claim against Tronox. In February 2011, in settlement of its claim, Anadarko received shares of Tronox stock, which were assigned to a financial institution in exchange for $46 million, included as a credit to general and administrative expenses in the Company’s Consolidated Statements of Income for the nine months ended September 30, 2011. The Company will continue to monitor the impact that the rejection of the MSA may have on other litigation and other proceedings, including the Adversary Proceeding, and will assess the impact of future events on the Company’s consolidated financial position, results of operations, and cash flows.

In February 2011, in accordance with Chapter 11 of the United States Bankruptcy Code, Tronox emerged from bankruptcy pursuant to an August 2010 Bankruptcy Court approved Plan of Reorganization (Plan). The terms of the Plan, which were confirmed by the Bankruptcy Court in the third quarter of 2010, contemplate that the claims of the United States government (together with other federal, state, local, or tribal governmental entities having regulatory authority or responsibilities for environmental laws, the Governmental Entities) related to Tronox’s environmental liabilities will be settled through certain environmental response trusts and a litigation trust (Anadarko Litigation Trust). The Plan provides that the Governmental Entities will receive, among other things, 88% of the proceeds from the Adversary Proceeding. Additionally, certain creditors asserting tort claims against Tronox may receive, among other things, 12% of the proceeds from the Adversary Proceeding. Certain documents central to the Plan and the Adversary Proceeding were approved by the Bankruptcy Court in the fourth quarter of 2010 and in February 2011, including the Environmental Claims Settlement Agreement, the Tort Claims Trust Agreement, the Environmental Response Trust Agreement, and the Anadarko Litigation Trust Agreement (ALTA). In accordance with the Plan, the Adversary Proceeding will be prosecuted by the Anadarko Litigation Trust. Pursuant to the ALTA, 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.

25

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Contingencies (Continued)

In addition, 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 (Class Period), against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors, and Ernst & Young LLP (collectively, the Securities Defendants). The complaint alleges causes of action arising under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (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. Anadarko, Kerr-McGee, and other defendants moved to dismiss the consolidated class action complaint and in August 2010 moved to dismiss an amended consolidated class action complaint that had been filed in July 2010. The New York District Court issued the second of two opinions and orders on the motions (Orders). Following the Orders, only the plaintiffs’ Section 20(a) claims under the Exchange Act remain against Anadarko and Kerr-McGee. The plaintiffs’ claims against Anadarko are limited to the period beginning on August 10, 2006, through the end of the Class Period. In August 2011, plaintiffs filed a motion for class certification. The Securities Defendants filed briefs in opposition to class certification in September 2011. The court denied class certification in October 2011 and has requested the parties to re-brief the class certification motion. The discovery process is ongoing.

Discovery and motions are still underway in the Tronox proceedings. The Company does not consider a loss related to this matter to be probable; however, a loss is possible, and such loss, if realized, could have a material adverse effect on the Company. At this time the Company cannot reasonably estimate a range of potential losses related to the proceedings described above because the amount of potential damages will depend on circumstances that have not yet occurred, including the outcome of expert testimony and certain determinations to be made by the Bankruptcy Court. The Company intends to continue to vigorously defend itself, its officers, and its directors in these proceedings.

Deepwater Drilling Moratorium and Other Related Matters  In May and July 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), previously known as the Minerals Management Service, an agency of the DOI, issued directives requiring lessees and operators of federal oil and gas leases in the Outer Continental Shelf regions of the Gulf of Mexico and Pacific Ocean to cease drilling all new deepwater wells, including wellbore sidetracks and bypasses, through November 30, 2010 (the Moratorium). Anadarko ceased all drilling operations in the Gulf of Mexico in accordance with the Moratorium, which resulted in the suspension of operations of two operated deepwater wells (Lucius and Nansen) and one non-operated deepwater well (Vito). The Moratorium was lifted effective October 12, 2010. In July and August 2011, the DOI issued drilling permits to Anadarko for the Heidelberg appraisal well, the Cheyenne East exploration well near the Independence Hub facility, and a development well in the Nansen field. Drilling activity at these locations is expected to begin in late 2011. Anadarko is awaiting additional DOI approvals for other exploration plans and drilling permits.

As a result of the Moratorium and additional inspection and safety requirements issued by the BOEMRE in May and June 2010, the Company provided notification of force majeure to drilling contractors of four of the Company’s contracted deepwater rigs in the Gulf of Mexico. Some of the contracts have provisions that authorize contract termination by either party if force majeure conditions continue for a specified number of consecutive days.

26

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Contingencies (Continued)

In June 2010, the Company gave written notice of termination to the drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit in the United States District Court for the Southern District of Houston, Texas (Houston, 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 asserted that Anadarko had breached the drilling contract. If the Company does not prevail in its claim, the Company could be obligated to pay the rig contract rate from the contract-termination date through March 2011, the end of the original contract term. The disputed rental for the contract period is $116 million; however, any potential damages would be reduced by, among other things, amounts resulting from the drilling contractor’s ability to mitigate damages by leasing the drilling rig to another third party, as well as cost savings realized by the drilling contractor as a result of not operating the drilling rig for the entire original contract period. At September 30, 2011, the Company has not recognized a liability for costs associated with this dispute as management believes payment related to this matter is not probable. The Company intends to vigorously pursue this claim.

In September 2010, the Company gave written notice of termination to another drilling contractor of a rig that had previously been placed in force majeure, and the Company filed a lawsuit in the Houston, 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 September 18, 2010. The drilling contractor filed a Motion to Dismiss and an Original Answer in October 2010. The Houston, Texas District Court, acting on its discretion, converted the Motion to Dismiss into a Motion for Summary Judgment and entered a scheduling order for submission of briefs during February and March 2011. In May 2011, the Company and the drilling contractor mutually agreed to dismiss all claims related to this dispute. The resolution of this dispute did not have an impact on Anadarko’s consolidated financial position, results of operations, or cash flows.

12. Income Taxes

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

	Three Months Ended September 30,				Nine Months Ended September 30,
millions except percentages	2011		2010		2011		2010
Income tax expense (benefit)	$	(1,468)	$	94	$	(762)	$	660
Effective tax rate		33 %		109 %		25 %		49 %

The Company reported a loss before income taxes for the three and nine months ended September 30, 2011. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% statutory rate for the three and nine months ended September 30, 2011, is primarily attributable to tax expense associated with the accrual of the Algerian exceptional profits tax (which is non-deductible for Algerian income tax purposes), U.S. tax on foreign income, foreign tax rates in excess of the U.S. statutory rate and valuation allowances on foreign losses. The decrease from the 35% statutory rate for the nine months ended September 30, 2011, is also attributable to items resulting from business acquisitions. The decrease from the 35% statutory rate for the three and nine months ended September 30, 2011, is partially offset by U.S. income tax benefits associated with foreign losses and the restructuring of foreign operations, state income taxes, and other items.

The increase from the 35% statutory rate for the three and nine months ended September 30, 2010, is primarily attributable to tax expense associated with the accrual of the Algerian exceptional profits tax, U.S. tax on foreign income, foreign tax rates in excess of the U.S. statutory rate, valuation allowances on foreign losses, and unfavorable resolution of tax contingencies. The increase from the 35% statutory rate for the three and nine months ended September 30, 2010, is partially reduced by U.S. income tax benefits associated with foreign losses, the federal manufacturing deduction, and other items.

27

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

13. Supplemental Cash Flow Information

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

	Nine Months Ended September 30,
millions	2011		2010
Cash paid:
Interest	$	708	$	579
Income taxes	$	238	$	209
Non-cash investing activities:
Fair value of properties and equipment received in non-cash exchange transactions	$	4	$	32
Gain related to the fair-value remeasurement of Anadarko’s pre-acquisition 7% equity interest in the Wattenberg Plant	$	21	$	—

14. Segment Information

Anadarko’s primary business segments are vertically integrated within the oil and gas industry. These 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 marketing segment sells most of Anadarko’s production, as well as third-party purchased volumes.

During the first quarter of 2011, the chief operating decision maker (CODM) began separately assessing the performance of, and resource allocation to, the WES operating segment. As a result, the midstream operating segment was separated into two operating segments, WES and other midstream activities. The WES and other midstream activities operating segments are aggregated into a single midstream reporting segment due to similar financial and operating characteristics.

To assess the performance of Anadarko’s operating segments, the CODM analyzes income (loss) before income taxes, interest expense, exploration expense, depreciation, depletion, and amortization (DD&A), impairments, Deepwater Horizon settlement and related costs, and unrealized (gains) losses on derivative instruments, 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. Anadarko’s definition of Adjusted EBITDAX also excludes exploration expense, as exploration expense 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 as these costs are outside the normal operations of the Company. See Note 2 for a discussion of Deepwater Horizon Events. Finally, unrealized (gains) losses on derivative instruments, net are excluded from Adjusted EBITDAX because unrealized (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.

28

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. Segment Information (Continued)

Adjusted EBITDAX 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 September 30,				Nine Months Ended September 30,
millions	2011		2010		2011		2010
Income (loss) before income taxes	$	(4,496)	$	86	$	(2,991)	$	1,352
Exploration expense		307		296		722		649
DD&A		932		962		2,902		2,845
Impairments		183		20		287		147
Deepwater Horizon settlement and related costs(1)		4,042		2		4,055		2
Interest expense		206		218		642		642
Unrealized (gains) losses on derivative instruments, net(2)		692		174		767		(66)
Less: Net income attributable to noncontrolling interests		23		18		62		42
Consolidated Adjusted EBITDAX	$	1,843	$	1,740	$	6,322	$	5,529

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

⁽²⁾  In the fourth quarter of 2010, the Company revised the definition of Adjusted EBITDAX to exclude the impact of unrealized (gains) losses on derivative instruments, net. The prior periods have been adjusted to reflect this change.

29

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. 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.

		Intersegment		Intersegment		Intersegment		Intersegment		Intersegment
millions	Oil and Gas Exploration & Production		Midstream		Marketing		Other and Intersegment Eliminations		Total
Three Months Ended September 30, 2011:
Sales revenues	$	1,801	$	76	$	1,507	$	—	$	3,384
Intersegment revenues		1,244		251		(1,386)		(109)		—
Gains (losses) on divestitures and other, net		(193)		(31)		—		39		(185)
Total revenues and other		2,852		296		121		(70)		3,199
Operating costs and expenses(1)		955		210		143		53		1,361
Realized (gains) losses on derivatives, net		—		—		—		(71)		(71)
Other (income) expense, net		—		—		—		40		40
Net income attributable to noncontrolling interests		—		23		—		—		23
Total expenses and other		955		233		143		22		1,353
Unrealized (gains) losses on derivatives, net included in marketing revenue		—		—		(3)		—		(3)
Adjusted EBITDAX	$	1,897	$	63	$	(25)	$	(92)	$	1,843
Three Months Ended September 30, 2010:
Sales revenues	$	1,318	$	45	$	1,153	$	—	$	2,516
Intersegment revenues		950		198		(1,051)		(97)		—
Gains (losses) on divestitures and other, net		(3)		—		—		37		34
Total revenues and other		2,265		243		102		(60)		2,550
Operating costs and expenses(1)		723		152		116		83		1,074
Realized (gains) losses on derivatives, net		—		—		—		(157)		(157)
Other (income) expense, net		—		—		—		(129)		(129)
Net income attributable to noncontrolling interests		—		18		—		—		18
Total expenses and other		723		170		116		(203)		806
Unrealized (gains) losses on derivatives, net included in marketing revenue		—		—		(4)		—		(4)
Adjusted EBITDAX	$	1,542	$	73	$	(18)	$	143	$	1,740

⁽¹⁾ Operating costs and expenses exclude exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. For the three months ended September 30, 2010, $25 million has been reclassified from the oil and gas exploration and production segment to the midstream segment to properly reflect the previously reported amounts.

30

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. Segment Information (Continued)

		Intersegment		Intersegment		Intersegment		Intersegment		Intersegment
millions	Oil and Gas Exploration & Production		Midstream		Marketing		Other and Intersegment Eliminations		Total
Nine Months Ended September 30, 2011:
Sales revenues	$	5,668	$	238	$	4,436	$	—	$	10,342
Intersegment revenues		3,699		684		(4,066)		(317)		—
Gains (losses) on divestitures and other, net		(307)		(11)		—		104		(214)
Total revenues and other		9,060		911		370		(213)		10,128
Operating costs and expenses(1)		2,739		575		414		163		3,891
Realized (gains) losses on derivatives, net		—		—		—		(153)		(153)
Other (income) expense, net		—		—		—		(2)		(2)
Net income attributable to noncontrolling interests		—		62		—		—		62
Total expenses and other		2,739		637		414		8		3,798
Unrealized (gains) losses on derivatives, net included in marketing revenue		—		—		(8)		—		(8)
Adjusted EBITDAX	$	6,321	$	274	$	(52)	$	(221)	$	6,322
Nine Months Ended September 30, 2010:
Sales revenues	$	4,117	$	145	$	3,947	$	—	$	8,209
Intersegment revenues		3,259		630		(3,593)		(296)		—
Gains (losses) on divestitures and other, net		(15)		—		—		99		84
Total revenues and other		7,361		775		354		(197)		8,293
Operating costs and expenses(1)		2,169		501		349		139		3,158
Realized (gains) losses on derivatives, net		—		—		—		(339)		(339)
Other (income) expense, net		—		—		—		(106)		(106)
Net income attributable to noncontrolling interests		—		42		—		—		42
Total expenses and other		2,169		543		349		(306)		2,755
Unrealized (gains) losses on derivatives, net included in marketing revenue		—		—		(9)		—		(9)
Adjusted EBITDAX	$	5,192	$	232	$	(4)	$	109	$	5,529

⁽¹⁾  Operating costs and expenses exclude exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. For the nine months ended September 30, 2010, $57 million has been reclassified from the oil and gas exploration and production segment to the midstream segment to properly reflect the previously reported amounts.

31

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. 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 generally 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 nine months ended September 30, 2011, the Company made contributions of $269 million to its funded pension plans, $8 million to its unfunded pension plans, and $13 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 2011, the Company expects to contribute approximately $3 million to its funded pension plans, approximately $21 million to its unfunded pension plans, and approximately $5 million to its unfunded other postretirement benefit plans.

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

	Pension Benefits				Other Benefits
	Three Months Ended September 30,				Three Months Ended September 30,
millions	2011		2010		2011		2010
Components of net periodic benefit cost
Service cost	$	20	$	17	$	3	$	3
Interest cost		21		21		4		4
Expected return on plan assets		(21)		(21)		—		—
Amortization of net actuarial loss (gain)		22		14		—		(1)
Amortization of net prior service cost (credit)		—		1		—		—
Net periodic benefit cost	$	42	$	32	$	7	$	6
	Pension Benefits				Other Benefits
	Nine Months Ended September 30,				Nine Months Ended September 30,
millions	2011		2010		2011		2010
Components of net periodic benefit cost
Service cost	$	59	$	52	$	7	$	7
Interest cost		64		63		12		12
Expected return on plan assets		(64)		(62)		—		—
Amortization of net actuarial loss (gain)		64		49		—		(2)
Amortization of net prior service cost (credit)		1		2		—		(1)
Net periodic benefit cost	$	124	$	104	$	19	$	16

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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 guarantee such indemnification obligations;

33

• the outcome of events in the Gulf of Mexico and the impact of remaining claims related to the Deepwater Horizon events, including, but not limited to, fines, penalties and punitive damages for which the Company is not indemnified by BP, and the Company’s ability to successfully collect insurance proceeds;

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

• the Company’s ability to fully resume drilling operations in the Gulf of Mexico;

• current and potential legal proceedings, 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;

• 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;

• the outcome of proceedings related to the Algerian exceptional profits tax; 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 2010 Annual Report on Form 10-K, the Company’s Quarterly Report on Form 10-Q for the quarters ended March 31 and June 30, 2011, 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 2010 Annual Report on Form 10-K, and the information set forth in the Risk Factors under Part I, Item 1A of the 2010 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 oil and natural-gas 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 operates worldwide, including activities in the United States, Algeria, Brazil, East and West Africa, China, Indonesia, and New Zealand.

34

Deepwater Horizon Settlement and Indemnity

In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify, whereby the Company and BP agreed to a mutual release of claims against each other relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company has agreed to pay $4.0 billion in cash and transfer its interest in the Mississippi Canyon Block 252 lease (Lease) to BP (subject to required governmental approvals of the transfer), and BP has agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued to date and to forgo reimbursement for all future costs arising from the Deepwater Horizon events, including future costs under the OA. In addition, BP has fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related OPA damage claims, NRD claims and associated damage-assessment costs, and any claims arising under the OA. This indemnification has been guaranteed by 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. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder, derivative, or security laws claims, or certain other claims. The Company believes that costs associated with any non-indemnified items, individually or in the aggregate, will not materially impact the Company’s consolidated financial position, results of operations, or cash flows. Refer to Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for discussion and analysis of these events.

Operating Highlights

Significant operating highlights during the third quarter of 2011 include the following:

Overall

• Anadarko’s third-quarter sales volumes totaled 660 thousand barrels of oil equivalent per day (MBOE/d), representing a 5% increase over the third quarter of 2010.

• Anadarko achieved liquid sales volumes of 281 MBOE/d, representing a 10% increase over the third quarter of 2010.

United States Onshore

• The Company’s Rocky Mountains Region (Rockies) achieved third-quarter sales volumes of 304 MBOE/d, representing an 11% increase over the third quarter of 2010, with liquids sales volumes increasing 28% over the same period.

• The Company’s Southern and Appalachia Region achieved third-quarter sales volumes of 143 MBOE/d, representing a 12% increase over the third quarter of 2010, primarily due to increased drilling in the Eagleford and Marcellus shales.

Gulf of Mexico

• The Company’s Gulf of Mexico third-quarter sales volumes were 120 MBOE/d, representing a 19% decrease from the third quarter of 2010.

• Anadarko and its partners finalized a unitization agreement to develop the Lucius field. Anadarko will operate the unit with a 35% working interest.

• The Company received drilling permits for the Heidelberg appraisal well, the Cheyenne East exploration well near the Independence Hub facility, and a development well in the Nansen field.

35

International

• The Company’s International third-quarter sales volumes were 78 MBOE/d, representing a 27% increase from the third quarter of 2010 primarily due to the start of liftings in Ghana in 2011.

• The Barquentine-2 appraisal well (36.5% working interest) encountered more than 230 net feet of natural-gas pay in high-quality Oligocene-age reservoirs located in Mozambique’s Offshore Area 1 of the Rovuma Basin.

• The Camarão exploration well (36.5% working interest) encountered approximately 240 net feet of natural-gas pay in a reservoir with previously announced discoveries in the Offshore Area 1 of the deepwater Rovuma Basin in Mozambique. In addition, the Camarão well discovered approximately 140 net feet of natural-gas pay in shallower Miocene and Oligocene sand packages.

• The Akasa-1 exploration well (30.875% working interest) encountered 108 net feet of primarily high-quality, oil-bearing pay from Turonian-aged sand packages located in the West Cape Three Points Block offshore Ghana.

• The Tweneboa-4 well (18% working interest) in the Deepwater Tano Block offshore Ghana was successfully tested, which resulted in sustained flow rates of approximately 3.5 MBOE/d of condensate and 30 million cubic feet per day (MMcf/d) of natural gas.

• The Enyenra-3A appraisal well (18% working interest) confirmed an updip extension of the Enyenra oil field and encountered 56 net feet of oil pay in the Deepwater Tano Block offshore Ghana.

Financial Highlights

Significant financial highlights during the third quarter of 2011 include the following:

• Anadarko’s net loss attributable to common stockholders for the third quarter of 2011, including the $4.0 billion effect of the Settlement Agreement, totaled $3.1 billion.

• The Company generated $1.5 billion of cash flows from operations and ended the quarter with $3.5 billion of cash on hand.

• The Company amended its $5.0 billion senior secured revolving credit facility (the $5.0 billion Facility) to reduce maintenance costs and to lower applicable interest rates under the facility by 125 basis points on borrowings and 30 basis points on undrawn amounts.

• The Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit (the LOC Facility) which lowered the Company’s cost to issue letters of credit.

• Anadarko modified and extended swap maturity dates from October 2011 to June 2014 for certain of its interest-rate swaps with an aggregate notional principal amount of $1.85 billion to better align the swap portfolio with the anticipated timing of future debt issuances and adjusted the interest rates on these swaps.

• The Company recognized losses of $299 million on assets held for sale, and impairments of $183 million, which related to onshore United States properties and the Company’s investment in Venezuelan assets.

Gulf of Mexico Deepwater Drilling Update

In July and August 2011, the Bureau of Ocean Energy Management, Regulation and Enforcement, an agency of the Department of the Interior (DOI), issued drilling permits to Anadarko for the Heidelberg appraisal well, the Cheyenne East exploration well near the Independence Hub facility, and a development well in the Nansen field. Drilling activity at these locations is expected to begin in late 2011. Anadarko is awaiting additional DOI approvals for other exploration plans and drilling permits. See Note 11—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 on the Moratorium.

36

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 September 30, 2011,” refers to the comparison of the three months ended September 30, 2011, to the three months ended September 30, 2010, and any increases or decreases “for the nine months ended September 30, 2011,” refers to the comparison of the nine months ended September 30, 2011, to the nine months ended September 30, 2010. The primary factors that affect the Company’s results of operations include, among other things, 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 September 30,				Nine Months Ended September 30,
millions except per-share amounts	2011		2010		2011		2010
Financial Results
Revenues and other	$	3,199	$	2,550	$	10,128	$	8,293
Costs and expenses		6,825		2,354		11,857		6,801
Other (income) expense		870		110		1,262		140
Income tax expense (benefit)		(1,468)		94		(762)		660
Net income (loss) attributable to common stockholders	$	(3,051)	$	(26)	$	(2,291)	$	650
Net income (loss) per common share attributable to common stockholders—diluted	$	(6.12)	$	(0.05)	$	(4.60)	$	1.30
Average number of common shares outstanding—diluted		498		496		498		496
Operating Results
Adjusted EBITDAX(1)	$	1,843	$	1,740	$	6,322	$	5,529
Sales volumes (MMBOE)		61		58		185		179

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.

37

FINANCIAL RESULTS

Net Income (Loss) Attributable to Common Stockholders  For the third quarter of 2011, Anadarko’s net loss attributable to common stockholders totaled $3.1 billion, or $6.12 per share (diluted), compared to a net loss attributable to common stockholders of $26 million, or $0.05 per share (diluted) for the third quarter of 2010. For the nine months ended September 30, 2011, Anadarko’s net loss attributable to common stockholders totaled $2.3 billion, or $4.60 per share (diluted), compared to net income attributable to common stockholders of $650 million, or $1.30 per share (diluted) for the same period of 2010. Anadarko’s net loss for the three and nine months ended September 30, 2011 includes the effects of the $4.0 billion Settlement Agreement with BP related to the Deepwater Horizon events.

Sales Revenues and Volumes

	Three Months Ended September 30,						Nine Months Ended September 30,
	Inc/(Dec)						Inc/(Dec)
millions except percentages	2011		vs. 2010		2010		2011		vs. 2010		2010
Sales Revenues
Natural-gas sales	$	840		4%	$	809	$	2,564		(5)%	$	2,692
Oil and condensate sales		1,905		47		1,298		5,948		44		4,138
Natural-gas liquids sales		377		66		227		1,080		47		736
Total	$	3,122		34	$	2,334	$	9,592		27	$	7,566

Anadarko’s sales revenues for the three months ended September 30, 2011, increased primarily due to higher commodity prices and increased liquids sales volumes. Anadarko’s sales revenues for the nine months ended September 30, 2011, increased primarily due to higher prices for crude oil and NGLs, as well as increased liquids sales volumes, partially offset by lower average natural-gas prices.

	Three Months Ended September 30,
millions	Natural Gas		Oil and Condensate		NGLs		Total
2010 sales revenues	$	809	$	1,298	$	227	$	2,334
Changes associated with sales volumes		14		106		32		152
Changes associated with prices		17		501		118		636
2011 sales revenues	$	840	$	1,905	$	377	$	3,122
	Nine Months Ended September 30,
	Natural Gas		Oil and Condensate		NGLs		Total
2010 sales revenues	$	2,692	$	4,138	$	736	$	7,566
Changes associated with sales volumes		24		232		96		352
Changes associated with prices		(152)		1,578		248		1,674
2011 sales revenues	$	2,564	$	5,948	$	1,080	$	9,592

38

	Three Months Ended September 30,						Nine Months Ended September 30,
	Inc/(Dec)						Inc/(Dec)
Sales Volumes	2011		vs. 2010		2010		2011		vs. 2010		2010
Barrels of Oil Equivalent (MMBOE except percentages)
United States		53		2 %		53		162		2 %		160
International		8		27		5		23		18		19
Total		61		5		58		185		4		179
Barrels of Oil Equivalent per Day (MBOE/d except percentages)
United States		582		2 %		568		595		2 %		584
International		78		27		61		83		18		71
Total		660		5		629		678		4		655

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 Other (Income) Expense—(Gains) Losses on Commodity Derivatives, net. Production of natural gas, crude oil, and NGLs usually is not affected by seasonal changes in demand.

Natural-Gas Sales Volumes, Average Prices, and Revenues

	Three Months Ended September 30,						Nine Months Ended September 30,
	Inc/(Dec)						Inc/(Dec)
	2011		vs. 2010		2010		2011		vs. 2010		2010
United States
Sales volumes—Bcf		209		2 %		205		638		1 %		632
MMcf/d		2,271		2		2,234		2,336		1		2,316
Price per Mcf	$	4.02		2	$	3.94	$	4.02		(6)	$	4.26
Natural-gas sales revenues (millions)	$	840		4	$	809	$	2,564		(5)	$	2,692

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

The Company’s natural-gas sales volumes increased 37 MMcf/d and 20 MMcf/d for the three and nine months ended September 30, 2011, respectively. Increases during these periods were as follows: 66 MMcf/d and 64 MMcf/d, respectively, from increased drilling in the Rockies primarily in the Greater Natural Buttes area and the Wattenberg field, and 53 MMcf/d and 45 MMcf/d, respectively, in the Southern and Appalachia Region from increased drilling in the Marcellus shale. These increases were partially offset by lower sales volumes in the Gulf of Mexico of 82 MMcf/d and 89 MMcf/d, respectively, primarily due to natural production declines, downtime for scheduled maintenance and well testing across all facilities, and weather-related downtime. For the nine months ended September 30, 2011, the increase was also partially offset by lower sales volumes in the Gulf of Mexico that resulted from 2010 price-related royalty relief that does not apply for 2011.

The average natural-gas price Anadarko received increased for the three months ended September 30, 2011, primarily due to increased demand and lower year-over-year natural-gas inventory levels. The average natural-gas price Anadarko received decreased for the nine months ended September 30, 2011, primarily due to the industry’s supply growing at a faster pace than demand in 2011 relative to 2010.

39

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	Inc/(Dec)						Inc/(Dec)
	2011		vs. 2010		2010		2011		vs. 2010		2010
United States
Sales volumes—MMBbls		12		(1) %		13		36		(1) %		37
MBbls/d		129		(1)		131		132		(1)		133
Price per barrel	$	94.02		29	$	72.65	$	96.84		31	$	73.85
International
Sales volumes—MMBbls		8		27 %		5		23		18 %		19
MBbls/d		78		27		61		83		18		71
Price per barrel	$	109.69		45	$	75.83	$	108.47		43	$	75.66
Total
Sales volumes—MMBbls		20		8 %		18		59		6 %		56
MBbls/d		207		8		192		215		6		204
Total price per barrel	$	99.92		36	$	73.67	$	101.35		36	$	74.48
Oil and condensate sales revenues (millions)	$	1,905		47	$	1,298	$	5,948		44	$	4,138

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s crude-oil and condensate sales volumes increased 15 MBbls/d for the three months ended September 30, 2011. This increase was attributable to sales-volume increases of 17 MBbls/d resulting from the 2011 start of production in Ghana and the timing of cargo liftings in Algeria, and 7 MBbls/d in the Rockies resulting from increased drilling at Wattenberg. Additionally, the Eagleford shale and Permian basin areas increased sales volumes approximately 150%, contributing to an additional 7 MBbls/d in the Southern and Appalachia Region during the period. Partially offsetting these increases was a 13 MBbls/d sales-volume decline in the Gulf of Mexico which resulted from natural production declines, downtime for scheduled maintenance and well testing, and weather-related downtime. For the nine months ended September 30, 2011, crude-oil and condensate sales volumes increased 11 MBbls/d for the reasons discussed above, with cumulative nine-month geographic sales-volume increases as follows: 12 MBbls/d from Ghana; 8 MBbls/d primarily from the Eagleford shale and Permian basin; and 5 MBbls/d from Wattenberg. These sales-volume increases were partially offset by lower sales volumes of 12 MBbls/d in the Gulf of Mexico, as discussed above.

Anadarko’s average crude-oil price received increased for the three and nine months ended September 30, 2011, as a result of increased global demand, as well as supply disruptions and unrest in the Middle East and North Africa. The crude-oil price realized by the Company was enhanced by the widening differential between West Texas Intermediate and Brent crude, as approximately 70% of Anadarko’s crude-oil sales volumes are sold based on prices that are either directly indexed to, or highly correlated to, Brent crude.

40

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	Inc/(Dec)						Inc/(Dec)
	2011		vs. 2010		2010		2011		vs. 2010		2010
United States
Sales volumes—MMBbls		7		14 %		6		20		13 %		18
MBbls/d		74		14		65		74		13		65
Price per barrel	$	55.47		46	$	38.11	$	53.48		30	$	41.23
Natural-gas liquids sales revenues (millions)	$	377		66	$	227	$	1,080		47	$	736

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. The Company’s NGLs sales volumes increased by 9 MBbls/d for the three and nine months ended September 30, 2011. These increases were the result of the Company’s increased focus on liquids-rich areas and expanded horizontal drilling programs at Wattenberg. Also, the current-year NGLs sales-volume increases were aided by operational improvements that decreased maintenance downtime relative to 2010.

The average NGLs price increased for the three and nine months ended September 30, 2011, primarily due to higher crude-oil prices and sustained global petrochemical demand.

Gathering, Processing, and Marketing Margin

	Three Months Ended September 30,						Nine Months Ended September 30,
	Inc/(Dec)						Inc/(Dec)
millions except percentages	2011		vs. 2010		2010		2011		vs. 2010		2010
Gathering, processing, and marketing sales	$	262		44 %	$	182	$	750		17 %	$	643
Gathering, processing, and marketing expenses		214		60		134		590		27		466
Margin	$	48		—	$	48	$	160		(10)	$	177

The gathering, processing, and marketing margin was $48 million for the three months ended September 30, 2011 and 2010. For the current period, higher NGLs prices and volumes, and additional margin attributable to newly acquired midstream assets located in northeast Colorado were offset by higher transportation expense due to new transportation agreements effective in January 2011. For the nine months ended September 30, 2011, the gathering, processing, and marketing margin decreased $17 million primarily due to lower margins associated with natural-gas sales from inventory and an increase in transportation expense as discussed above. These decreases were partially offset by increased natural-gas processing margins due to higher NGLs prices and volumes, lower prices for natural-gas purchases, and favorable impacts attributable to 2011 asset acquisitions.

41

Gains (Losses) on Divestitures and Other, net

For the three and nine months ended September 30, 2011, gains (losses) on divestitures and other, net includes losses on assets held for sale of $299 million. These losses relate to properties in the oil and gas exploration and production operating segment and the other midstream operating segment. Partially offsetting these losses were gains on divestitures for the three and nine months ended September 30, 2011, of $73 million and $76 million, respectively, related to oil and gas exploration and production operating segment properties located in various international locations, including a gain on sale of $18 million and $21 million, respectively, related to contingent consideration to be received by the Company relative to its 2008 divestiture of its interest in the Peregrino field offshore Brazil. The contingent consideration is based on the value of oil produced from the divested properties. The Company expects to receive contingent consideration in excess of $400 million over the next several years. Also, for the nine months ended September 30, 2011, gains (losses) on divestitures and other, net includes a $76 million loss related to the effective termination of natural-gas processing contracts between the Company and the previous owner of the Wattenberg Plant that occurred as a result of the Company’s purchase of the Wattenberg Plant. The loss represents the aggregate amount by which the contracts were unfavorable as compared to current market transactions for the same or similar services at the date of the Company’s acquisition of the Wattenberg 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 7% equity interest in the Wattenberg Plant.

Costs and Expenses

	Three Months Ended September 30,						Nine Months Ended September 30,
	Inc/(Dec)						Inc/(Dec)
millions except percentages	2011		vs. 2010		2010		2011		vs. 2010		2010
Oil and gas operating	$	262		27 %	$	207	$	730		24 %	$	590
Oil and gas transportation and other		217		(1)		220		633		4		607
Exploration		307		4		296		722		11		649

Oil and gas operating expenses increased by $55 million and $140 million for the three and nine months ended September 30, 2011, respectively. These increases were primarily due to higher workover costs of $15 million and $44 million, respectively, primarily in the Gulf of Mexico and the Rockies; increased operating costs of $21 million and $49 million, respectively, resulting from the 2011 start of production in Ghana and increased outside-operated activity at Greater Green River basin in the Rockies and the Permian basin in the Southern and Appalachia Region.

For the three months ended September 30, 2011, oil and gas transportation and other expenses decreased $3 million. This decrease resulted from the Company expensing (rather than capitalizing) $15 million of drilling rig lease payments during the third quarter of 2010 as a result of rigs having to sit idle during the Gulf of Mexico deepwater drilling moratorium. This decrease was partially offset by higher oil and gas transportation expenses resulting from increased sales volumes, and by higher natural-gas processing fees that increase with increases in NGLs prices. For the nine months ended September 30, 2011, oil and gas transportation and other expenses increased by $26 million as a result of increased sales volumes and higher natural-gas processing fees, as discussed above, partially offset by the 2010 expensing of $27 million of drilling rig lease payments, as discussed above.

Exploration expense increased by $11 million for the three months ended September 30, 2011. This increase was due to $55 million of higher impairments of unproved properties, primarily in the Gulf of Mexico, and $29 million of higher geological and geophysical expense, primarily associated with increased seismic purchases in East Africa. These increases were partially offset by lower dry hole expense in East Africa of $41 million and Brazil of $34 million. For the nine months ended September 30, 2011, exploration expense increased $73 million primarily due to $101 million of higher geological and geophysical expense, primarily associated with increased seismic purchases in the Rockies, Gulf of Mexico, the Marcellus shale, Indonesia, and East Africa, as well as $22 million of higher impairments of unproved properties, primarily in the Gulf of Mexico. These increases were partially offset by $72 million of lower dry hole expense, primarily in East Africa, Brazil, and Alaska.

42

		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)
	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2011		Inc/(Dec) vs. 2010		2010		2011		Inc/(Dec) vs. 2010		2010
General and administrative	$	293		7%	$	273	$	806		17%	$	686
Depreciation, depletion, and amortization		932		(3)		962		2,902		2		2,845
Other taxes		375		56		240		1,132		40		809
Impairments		183		NM		20		287		95		147
Deepwater Horizon settlement and related costs		4,042		NM		2		4,055		NM		2

NM—percentage change does not provide

meaningful information

For the three months ended September 30, 2011, general and administrative (G&A) expense increased by $20 million primarily due to higher employee-related costs of $21 million. For the nine months ended September 30, 2011, G&A expense increased by $120 million primarily due to higher employee-related costs of $82 million; higher legal, consulting, and other expenses of $53 million related to ongoing litigation and other matters; and increased insurance costs of $15 million primarily related to higher industry-specific rates as a result of the Deepwater Horizon events. These increased costs are partially offset by a gain of $46 million from a settlement in the first quarter of 2011 related to Tronox’s rejection of the Master Separation Agreement (together with all annexes, related agreements, and ancillary agreements thereto, the MSA) discussed in Note 11—Contingencies—Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. During the third quarter of 2011, legal expenses associated with the Deepwater Horizon events for all periods presented were reclassified from G&A expense to Deepwater Horizon settlement and related costs.

For the three months ended September 30, 2011, depreciation, depletion, and amortization (DD&A) expense decreased by $30 million. Overall, the Company’s DD&A rates were lower for the quarter, largely the result of a $70 million DD&A expense that was taken in 2010 as a result of the watering out of a field in the Gulf of Mexico. Lower DD&A rates for the quarter were partially offset by a $47 million increase in DD&A that resulted from increased sales volumes. For the nine months ended September 30, 2011, DD&A expense increased by $57 million primarily due to $87 million attributable to increased production volumes, partially offset by $43 million related to lower DD&A rates as discussed above.

For the three months ended September 30, 2011, other taxes increased by $135 million primarily due to higher crude-oil prices and increased sales volumes, which resulted in increased Algerian exceptional profits tax of $54 million, increased U.S. production and severance taxes of $42 million, and increased Chinese windfall profits tax of $21 million, as well as higher ad valorem taxes of $14 million due to higher assessed property values. For the nine months ended September 30, 2011, other taxes increased by $323 million primarily due to higher crude-oil prices and increased sales volumes, resulting in increased Algerian exceptional profits tax of $121 million, increased U.S. production and severance taxes of $106 million, and increased Chinese windfall profits tax of $58 million, as well as higher ad valorem taxes of $39 million due to higher assessed property values.

The arbitration hearing related to Anadarko’s dispute regarding the imposition of the Algerian exceptional profits tax was held in June 2011. Any decision issued by the arbitration panel is binding on the parties. Although the Company cannot reasonably determine the timing of a decision by the arbitration panel, the Company anticipates a decision could be issued by the arbitration panel prior to the end of 2011. Additional information regarding the Algerian exceptional profits tax is included in the Company’s 2010 Annual Report on Form 10-K.

43

Impairment expense was $183 million and $287 million for the three and nine months ended September 30, 2011, respectively. During the third quarter of 2011, the Company recognized impairments of $93 million related to United States offshore properties and $87 million related to the Company’s investment in Venezuelan assets due to changes in expected recoverable reserves in these areas. During the second quarter of 2011, the Company recognized impairments of $100 million related to United States onshore properties due to a change in projected cash flows resulting from the Company’s intent to divest of the properties. All of these assets are included in the oil and gas exploration and production operating segment and were impaired to fair value, estimated using Level 3 fair-value inputs. Impairment expense for the three months ended September 30, 2010, was primarily attributable to $18 million of oil and gas exploration and production operating segment properties located in the United States. Impairments for the nine months ended September 30, 2010, included $137 million of oil and gas exploration and production operating segment properties located in the United States, $114 million of which related to a production platform that remains idle with no identifiable plans for use, and for which a limited market currently exists.

In October 2011, the Company and BP entered into the Settlement Agreement, pursuant to which the Company has agreed to pay $4.0 billion in cash and transfer its interest in the Lease to BP (subject to required governmental approvals of the transfer), and BP has agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued to date and to forgo reimbursement for all future costs arising from the Deepwater Horizon events, including future costs under the OA. The Company recorded a $4.0 billion expense for the settlement during the third quarter of 2011. In addition, BP has fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related OPA damage claims, NRD claims and associated damage-assessment costs, and any claims arising under the OA. 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. Additionally, as part of the Settlement Agreement BP has agreed that, to the extent it receives value in the future from claims that it has asserted or could assert against third parties arising from or relating to the Deepwater Horizon events, it will make cash payments (not to exceed $1.0 billion in the aggregate) to Anadarko, on a current and continuing basis, of 12.5% of the aggregate value received by BP in excess of $1.5 billion. Any payments received by the Company pursuant to this arrangement will be accounted for as a reimbursement of the $4.0 billion payment made by the Company to BP as part of the Settlement Agreement. During the third quarter of 2011, legal expenses associated with the Deepwater Horizon events for all periods presented were reclassified from G&A expense to Deepwater Horizon settlement and related costs. The Company expects legal costs to continue in future periods as the Deepwater Horizon litigation progresses through the court system. Refer to Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.

Other (Income) Expense

		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)
	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2011		Inc/(Dec) vs. 2010		2010		2011		Inc/(Dec) vs. 2010		2010
Interest Expense
Current debt, long-term debt, and other	$	245		4 %	$	235	$	743		16 %	$	642
Loss on early debt retirements and commitment termination		—		(100)		17		—		(100)		89
Capitalized interest		(39)		(15)		(34)		(101)		(13)		(89)
Interest expense	$	206		(6)	$	218	$	642		—	$	642

44

For the three months ended September 30, 2011, interest expense decreased by $12 million due to $17 million of commitment and structuring costs expensed in 2010 associated with a contemplated term-loan facility and $7 million related to unamortized debt issuance costs associated with the retirement of the Midstream Subsidiary Note Payable to a Related Party in 2010, partially offset by $9 million of interest related to the Company’s capital lease obligations incurred in 2011.

Interest expense was $642 million for the nine months ended September 30, 2011 and 2010. For the current period, higher interest costs were attributable to $48 million related to increases in the Company’s average outstanding debt balance and weighted-average interest rate on outstanding debt, $26 million of interest on capital lease obligations incurred in 2011, $23 million attributable to increased amortization of prepaid debt-issuance and credit-facility origination costs, and $22 million related to increased letter-of-credit and credit-facility commitment fees. These items were offset by $72 million related to 2010 losses on early debt retirements, $17 million of commitment and structuring costs, as discussed above, $12 million of increased capitalized interest in 2011 due to higher construction-in-progress balances related to long-term capital projects, and $9 million related to unamortized debt issuance costs associated with the retirement of the Midstream Subsidiary Note Payable to a Related Party in 2010. For additional information regarding the Company’s financing activities, see Liquidity and Capital Resources.

In October 2011, Anadarko entered into the Settlement Agreement with BP for $4.0 billion in cash. Anadarko is required to remit the settlement amount to BP on or before November 30, 2011, and expects to fund such payment with a combination of cash on hand and borrowings under the $5.0 billion Facility. The Company expects interest expense to increase while such borrowings under the $5.0 billion Facility remain outstanding.

		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)
	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2011		Inc/(Dec) vs. 2010		2010		2011		Inc/(Dec) vs. 2010		2010
(Gains) Losses on Commodity Derivatives, net
Realized (gains) losses
Natural gas	$	(72)		(54)%	$	(155)	$	(215)		(36)%	$	(337)
Oil and condensate		—		(100)		(2)		59		NM		(2)
Natural gas liquids		1		(100)		—		1		(100)		—
Total realized (gains) losses		(71)		(55)		(157)		(155)		(54)		(339)
Unrealized (gains) losses
Natural gas		(7)		(94)		(122)		54		(110)		(522)
Oil and condensate		(133)		NM		79		(197)		3		(191)
Natural gas liquids		(19)		100		—		(19)		100		—
Total unrealized (gains) losses		(159)		NM		(43)		(162)		(77)		(713)
Total (gain) loss on commodity derivatives, net	$	(230)		15	$	(200)	$	(317)		(70)	$	(1,052)

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 September 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 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

45

		Inc/(Dec)		Inc/(Dec)			Inc/(Dec)		Inc/(Dec)		Inc/(Dec)			Inc/(Dec)
	Three Months Ended September 30,							Nine Months Ended September 30,
millions except percentages	2011		Inc/(Dec) vs. 2010			2010		2011		Inc/(Dec) vs. 2010			2010
(Gains) Losses on Other Derivatives, net
Realized (gains) losses—interest-rate derivatives and other	$	—		—	%	$	—	$	2		(100	)%	$	—
Unrealized (gains) losses—interest-rate derivatives and other		854		NM			221		937		(43	)		656
Total (gain) loss on other derivatives, net	$	854		NM		$	221	$	939		(43	)	$	656

Anadarko enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage interest-rate risk. In December 2008 and January 2009, Anadarko entered into interest-rate swap contracts as a fixed-rate payor to mitigate the interest-rate risk associated with anticipated 2011 and 2012 debt issuances. Due to rising interest rates thereafter, the fair value of the swap contracts increased and, in 2009, the Company revised the swap contract terms to increase the weighted-average interest rate of the swap portfolio from approximately 3.25% to approximately 4.80%, and realized a $552 million gain. During the third quarter of 2011, in order to better align the swap portfolio with the anticipated timing of future debt refinancing, the Company extended the swap maturity dates from October 2011 to June 2014 for interest-rate swaps with an aggregate notional principal amount of $1.85 billion. In connection with these extensions, the swap interest rates were also adjusted. For additional information, see Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)
	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2011		Inc/(Dec) vs. 2010		2010		2011		Inc/(Dec) vs. 2010		2010
Other (Income) Expense, net
Interest income	$	(4)		33 %	$	(3)	$	(16)		60 %	$	(10)
Other		44		(135)		(126)		14		(115)		(96)
Total other (income) expense, net	$	40		(131)	$	(129)	$	(2)		(98)	$	(106)

Under the terms of the MSA entered into between Kerr-McGee Corporation (Kerr-McGee) and Tronox, a former subsidiary of Kerr-McGee that held Kerr-McGee’s chemical business, Kerr-McGee agreed to reimburse Tronox for 50% of certain qualifying environmental-remediation costs incurred and paid by Tronox and its subsidiaries before November 28, 2012, subject to certain limitations and conditions. The reimbursement obligation under the MSA was limited to a maximum aggregate reimbursement of $100 million. Total other income for the three and nine months ended September 30, 2010, includes the impact of the Company’s reversal of the remaining $95 million reimbursement obligation that was provided by Kerr-McGee to Tronox pursuant to the terms of the MSA.

In addition, total other income for the three months ended September 30, 2011, decreased $76 million due to exchange-rate changes applicable to foreign currency purchased in anticipation of funding future expenditures on major development projects and cash held in escrow of $186 million as of September 30, 2011, pending final determination of the Company’s Brazilian tax liability attributable to its 2008 divestiture of the Peregrino field offshore Brazil. The Brazilian tax matter is currently being considered by the Brazilian courts, and the Company expects a decision in the near term. An unfavorable decision may require the Company to record an additional tax liability in its financial statements. For the nine months ended September 30, 2011, total other income also decreased $13 million due to exchange-rate changes applicable to foreign currency, as discussed above.

46

Income Tax Expense

		2010		2010		2010		2010
	Three Months Ended September 30,				Nine Months Ended September 30,
millions except percentages	2011		2010		2011		2010
Income tax expense (benefit)	$	(1,468)	$	94	$	(762)	$	660
Effective tax rate		33 %		109 %		25 %		49 %

The Company reported a loss before income taxes for the three and nine months ended September 30, 2010. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% statutory rate for the three and nine months ended September 30, 2011, is primarily attributable to the following:

• tax expense associated with the accrual of the Algerian exceptional profits tax, which is non-deductible for Algerian income tax purposes;

• U.S. tax on foreign income; and

• foreign tax rates in excess of the U.S. statutory rate and valuation allowances on foreign losses.

The decrease from the 35% statutory rate for the nine months ended September 30, 2011, is also attributable to items resulting from business acquisitions.

The decrease from the 35% statutory rate for the three and nine months ended September 30, 2011, is partially offset by U.S. income tax benefits associated with foreign losses and the restructuring of foreign operations, state income taxes, and other items.

The increase from the 35% statutory rate for the three and nine months ended September 30, 2010, is primarily attributable to the following:

• tax expense associated with the accrual of the Algerian exceptional profits tax;

• U.S. tax on foreign income;

• foreign tax rates in excess of the U.S. statutory rate and valuation allowances on foreign losses; and

• unfavorable resolution of tax contingencies.

The increase from the 35% statutory rate for the three and nine months ended September 30, 2010, is partially reduced by U.S. income tax benefits associated with foreign losses, the federal manufacturing deduction, and other items.

Net Income Attributable to Noncontrolling Interests

For the three and nine months ended September 30, 2011, the Company’s net income attributable to noncontrolling interests of $23 million and $62 million, respectively, primarily related to the public ownership interest in Western Gas Partners, LP (WES), of 54.7% at September 30, 2011. For the three and nine months ended September 30, 2010, the Company’s net income attributable to noncontrolling interests of $18 million and $42 million, respectively, primarily related to the public ownership in WES, of 45.8% at September 30, 2010. See Note 6—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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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, and unrealized (gains) losses on derivative instruments, 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. Anadarko’s definition of Adjusted EBITDAX also excludes exploration expense because 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 as these costs are outside the normal operations of the Company. See Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for discussion of the Deepwater Horizon events. In addition, unrealized (gains) losses on derivative instruments, net are excluded from Adjusted EBITDAX because unrealized (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. 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.

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Adjusted EBITDAX

		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)		Inc/(Dec)
	Three Months Ended September 30,						Nine Months Ended September 30,
	Inc/(Dec)						Inc/(Dec)
millions except percentages	2011		vs. 2010		2010		2011		vs. 2010		2010
Income (loss) before income taxes	$	(4,496)		NM	$	86	$	(2,991)		NM	$	1,352
Exploration expense		307		4 %		296		722		11 %		649
DD&A		932		(3)		962		2,902		2		2,845
Impairments		183		NM		20		287		95		147
Deepwater Horizon settlement and related costs(1)		4,042		NM		2		4,055		NM		2
Interest expense		206		(6)		218		642		—		642
Unrealized (gains) losses on derivative instruments, net(2)		692		NM		174		767		NM		(66)
Less: Net income attributable to noncontrolling interests		23		28		18		62		48		42
Consolidated Adjusted EBITDAX	$	1,843		6	$	1,740	$	6,322		14	$	5,529
Adjusted EBITDAX by reporting segment
Oil and gas exploration and production	$	1,897		23 %	$	1,542	$	6,321		22 %	$	5,192
Midstream		63		(14)		73		274		18		232
Marketing		(25)		(39)		(18)		(52)		NM		(4)
Other and intersegment eliminations		(92)		(164)		143		(221)		NM		109

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

⁽²⁾  In the fourth quarter of 2010, the Company revised the definition of Adjusted EBITDAX to exclude the impact of unrealized (gains) losses on derivative instruments, net. The prior periods have been adjusted to reflect this change.

Oil and Gas Exploration and Production  Adjusted EBITDAX for the three and nine months ended September 30, 2011, increased primarily due to the impact of higher commodity prices and higher sales volumes partially offset by losses on oil and gas assets held for sale and increased operating expenses, primarily other taxes, which increased as a result of higher sales volumes and commodity prices. The increase for the nine months ended September 30, 2011, was also partially offset by a $76 million loss related to the effective termination of natural-gas processing contracts between the Company and the previous owner of the Wattenberg Plant that occurred as a result of the Company’s purchase of the Wattenberg Plant. The loss represents the aggregate amount by which the contracts were unfavorable compared to current market transactions for the same or similar services at the date of the Company’s acquisition of the Wattenberg Plant.

Midstream  Adjusted EBITDAX for the three months ended September 30, 2011, decreased due to losses on assets held for sale, partially offset by increased margins due to an increase in NGLs prices and volumes, as well as favorable impacts from the 2011 asset acquisitions. The increase in Adjusted EBITDAX for the nine months ended September 30, 2011, resulted from increased margins due to higher NGLs prices and volumes, lower prices for natural-gas purchases, and increases related to the 2011 asset acquisitions. Also contributing to the increase in Adjusted EBITDAX for the nine months ended September 30, 2011, was the recognition of a $21 million gain from the acquisition-date fair-value remeasurement of the Company’s pre-acquisition 7% equity interest in the Wattenberg Plant. These increases were partially offset by losses on midstream assets held for sale.

Marketing  Marketing earnings primarily represent the margin earned on sales of natural gas, oil, and NGLs purchased from third parties. Adjusted EBITDAX for the three months ended September 30, 2011, decreased primarily due to an increase in transportation expense related to new transportation agreements effective January 2011, partially offset by higher margins associated with natural-gas sales. Adjusted EBITDAX for the nine months ended September 30, 2011, decreased primarily due to lower margins associated with natural-gas sales from inventory and an increase in transportation expense as discussed above.

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Other and Intersegment Eliminations  Other and intersegment eliminations consist primarily of corporate costs, realized gains and losses on derivatives, and income from hard minerals investments and royalties. The decrease in Adjusted EBITDAX for the three and nine months ended September 30, 2011, was primarily due to lower realized gains on commodity derivatives in 2011, exchange-rate changes applicable to foreign currency, and the 2010 reversal of the remaining $95 million reimbursement obligation that was provided by Kerr-McGee to Tronox pursuant to the terms of the MSA.

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 nine months ended September 30, 2011, 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 expected cash flows and its projected debt-repayment schedule, and evaluates available funding alternatives in light of both current and expected conditions.

At September 30, 2011, the $5.0 billion Facility was undrawn, providing available borrowing capacity of $4.6 billion ($5.0 billion undrawn capacity, less $400 million of letter-of-credit capacity maintained pursuant to the terms of the LOC Facility discussed below). The Company plans to fund Anadarko’s $4.0 billion cash obligation to BP using a combination of cash on hand and borrowings from the $5.0 billion Facility on or before November 30, 2011. Additionally, the Company plans to repay Deepwater Horizon settlement-related borrowings with a portion of the proceeds from a possible monetization of its Brazilian subsidiary. The Company has opened a data room for its Brazilian properties, with anticipated closing of a sale in 2012, subject to the Company achieving its desired value threshold through the bid process and subsequent regulatory approval.

At September 30, 2011, Anadarko’s scheduled 2012 debt maturities, excluding capital lease obligations, were $170 million. In addition, the Zero-Coupon Senior Notes can be put to the Company in October 2012 at an accreted value of $682 million. The Company has a variety of funding sources available to satisfy these obligations, including cash on hand, an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through divestitures or joint-venture arrangements, and available capacity under the $5.0 billion Facility. Additionally, 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.

Revolving Credit Facility and Letter of Credit Facility    In August 2011, the Company amended the $5.0 billion Facility to reduce maintenance costs and to lower the interest rates under the facility to (i) LIBOR plus a margin ranging from 1.25% to 2.50%, depending on the Company’s current credit rating, or (ii) the greatest of (a) the JPMorgan Chase Bank, N.A. prime rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) one-month LIBOR plus 1%, plus in each case, an applicable margin ranging from 0.25% to 1.50%.

Obligations incurred under the $5.0 billion Facility 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 at September 30, 2011, and there were no restrictions on the Company’s ability to access the available capacity under the $5.0 billion Facility. The Company plans to make a draw on the $5.0 billion Facility to fund a portion of its obligation to remit $4.0 billion to BP pursuant to the Settlement Agreement.

Also, during the third quarter of 2011, the Company entered into the LOC Facility. Compensating balances deposited at the financial institution provide for reduced fees under the LOC Facility. These compensating balances may be withdrawn at any time, resulting in higher fees under the LOC Facility. At September 30, 2011, cash and cash equivalents includes $325 million of demand deposits serving as compensating balances. The LOC Facility also requires the Company to maintain a senior debt revolving credit facility with minimum commitments of at least $1.0 billion and the availability to issue letters of credit of at least $400 million.

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WES Funding Sources  Anadarko’s consolidated subsidiary, WES, primarily 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 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 (RCF).

In March 2011, WES entered into its RCF which amended and restated its $450 million senior unsecured revolving credit facility. Borrowings under the RCF bear interest at (i) LIBOR plus an applicable margin ranging from 1.30% to 1.90%, or (ii) the greatest of (a) the Wells Fargo Bank, National Association prime rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) one-month LIBOR plus 1%, plus in each case, an applicable margin ranging from 0.30% to 0.90%. At September 30, 2011, WES was in compliance with all covenants contained in the RCF, had no outstanding borrowings under the RCF, and had the full $800 million of RCF borrowing capacity available. See Financing Activities below.

Sources of Cash

Operating Activities  Anadarko’s cash flows from operating activities during the nine months ended September 30, 2011, was $4.6 billion, compared to $3.9 billion for the same period of 2010. Cash flows for 2011 increased primarily due to higher crude-oil and NGLs prices and higher sales volumes, but were partially offset by lower natural-gas prices, the impact of changes in working capital, and increased operating expenses primarily due to other taxes which increased as a result of higher sales volumes and commodity 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 from time-to-time by entering into commodity derivatives. Sales-volume changes also impact cash flows, but have not been as volatile as commodity prices. Anadarko’s long-term cash flows from operating activities are dependent on commodity prices, sales volumes, the amount of costs and expenses required for continued operations and debt service.

Financing Activities  During the nine months ended September 30, 2011, Anadarko’s consolidated subsidiary, WES, borrowed $320 million under its RCF primarily to fund a third-party asset acquisition and $250 million under its RCF to repay the senior unsecured term loan (Term Loan) as discussed in Uses of Cash. Also, in March and September 2011, WES issued approximately four million and six million common units to the public, respectively, raising net proceeds of $130 million and $198 million, respectively, which were used to repay outstanding RCF borrowings and for other general partnership purposes. During the second quarter of 2011, WES completed a public offering of $500 million aggregate principal amount of 5.375% Senior Notes due 2021, with net proceeds from the offering used to repay amounts then outstanding under its RCF.

During the nine months ended September 30, 2011, Anadarko received $57 million from the issuance of common stock as a result of employee exercises of stock options and the associated income tax benefit, and used $31 million to repurchase a portion of the shares of common stock issued to employees to satisfy withholding tax requirements.

Uses of Cash

In addition to ongoing funding of operating costs and expenses, including interest, employee compensation and benefits, and taxes, Anadarko invests significant capital to acquire, explore, and develop oil and natural-gas resources and midstream infrastructure. Anadarko also uses cash to pay dividends and make debt repayments. During the fourth quarter of 2011, Anadarko will remit $4.0 billion of cash to BP pursuant to the terms of the Settlement Agreement. The Company plans to fund this payment with a combination of cash on hand and borrowings under the Company’s $5.0 billion Facility.

Pension Contributions    During the nine months ended September 30, 2011, the Company made contributions of $269 million to its funded pension plans, $8 million to its unfunded pension plans, and $13 million to its unfunded other postretirement benefit plans. During the remainder of 2011, the Company expects to contribute approximately $3 million to its funded pension plans, approximately $21 million to its unfunded pension plans, and approximately $5 million to its unfunded other postretirement benefit plans. The increase in contributions to the funded pension plans during 2011 is the result of lower discount rates compared to the prior measurement period, which increased the pension liability and related funding target.

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

		2010		2010
	Nine Months Ended September 30,
millions	2011		2010
Property acquisition
Exploration—unproved	$	387	$	457
Exploration		581		723
Development		2,284		2,262
Capitalized interest		101		87
Total oil and gas capital expenditures		3,353		3,529
Gathering, processing, and marketing and other(1)		1,258		363
Total capital expenditures(2)	$	4,611	$	3,892

⁽¹⁾  Includes WES capital expenditures of $383 million and $65 million for the nine months ended September 30, 2011 and 2010, 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 18% for the nine months ended September 30, 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 the Platte Valley plant and related gathering systems from a third party for $302 million. These acquisitions, along with future expansion plans, align Anadarko’s natural-gas processing capacity with the Company’s anticipated production growth in the Rockies. In addition, these acquisitions position the Company to improve field recoveries and realize operational cost efficiencies. These increases were partially offset by lower exploration expenditures of $142 million and lower property acquisitions of $70 million primarily in the Gulf of Mexico. For additional information, see Note 3—Acquisitions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Debt Retirements and Repayments  During the nine months ended September 30, 2011, WES repaid $619 million of borrowings under its RCF and a $250 million Term Loan, primarily from proceeds from public debt and equity offerings, as discussed in Sources of Cash. In addition, the Company repaid $285 million principal amount on a 6.875% Senior Note that matured in September 2011.

Common Stock Dividends and Distributions to WES Noncontrolling Interest Owners  During the nine months ended September 30, 2011 and 2010, Anadarko paid $135 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 $30 million during the nine months ended September 30, 2011 and 2010, 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 $0.42 per common unit for the third quarter of 2011 (to be paid in November 2011).

In August 2011, the WES subordinated limited partner units held by Anadarko converted to common limited partner units on a one-for-one basis. Upon this conversion, $162 million related to pre-conversion changes in the Company’s ownership interest in WES was transferred from noncontrolling interests to paid-in capital. Additionally, $32 million was recorded to paid-in capital as a result of WES’s third-quarter issuance of common units. At September 30, 2011, Anadarko’s ownership interest in WES consists of a 43.3% limited partner interest, a 2% general partner interest, and incentive distribution rights.

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Outlook

The Company is committed to the execution of its worldwide exploration, appraisal, and development programs. The Company estimates a 2011 capital spending range of $6.5 billion to $6.8 billion, including approximately $400 million for WES capital expenditures.

Anadarko believes that its expected level of 2011 operating cash flows, cash on hand at September 30, 2011, and available capacity under the $5.0 billion Facility will be sufficient to fund the Company’s projected operational and capital programs for 2011, while continuing to satisfy other obligations, including the $4.0 billion obligation arising as a result of the Company’s Settlement Agreement with BP. See Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. The Company has begun marketing certain onshore domestic properties and its Brazilian subsidiary, as well as certain midstream assets in order to redirect its operating activities and capital to other areas and to repay anticipated borrowings under the $5.0 billion Facility.

In response to the Company’s Settlement Agreement with BP, the various credit rating agencies have reviewed the credit ratings each assigns to Anadarko. Moody’s Investors Services placed the Company’s senior unsecured credit rating under review for upgrade. Standard & Poor’s affirmed its rating and revised its outlook from negative to stable. Any changes to the Company’s credit ratings could affect the Company’s requirement to provide financial assurance of its performance under certain contractual arrangements and derivative agreements, as well as the Company’s cost of future borrowing, and ability to access capital markets.

The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with expected cash flows and its projected debt-repayment schedule, and evaluates available funding alternatives in light of both current and expected conditions. In order to increase the predictability of 2011 cash flows, Anadarko entered into commodity derivative positions, which, at September 30, 2011, cover approximately 25% and 59% of its anticipated natural-gas sales volumes and oil and condensate sales volumes, respectively, for the remainder of 2011. In addition, the Company has commodity derivative positions in place for 2012 and 2013. In October 2011, the Company entered into instruments that will effectively offset its outstanding 2012 natural-gas three-way collars for 500,000 million British thermal units per day (MMBtu/d). In addition, the Company entered into fixed-price swaps for 1 million MMBtu/d at an average price of $4.69 per MMBtu/d. See Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

In the first quarter of 2011, the Company entered into a joint-venture agreement 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, to earn a one-third interest in Anadarko’s Eagleford shale assets. The third party will fund 100% of Anadarko’s 2011 post-closing capital costs in the basin, and up to 90% thereafter until the carry is exhausted, which is expected to occur by year-end 2013. At September 30, 2011, $324 million of the total $1.6 billion obligation had been funded.

In the first quarter of 2010, the Company entered into a joint-venture agreement whereby a third-party partner agreed to fund up to $1.5 billion of Anadarko’s share of future acquisition, drilling, completion, equipment, and other capital expenditures to earn a 32.5% interest in Anadarko’s Marcellus shale assets, primarily located in north-central Pennsylvania. At September 30, 2011, $828 million of the total $1.5 billion obligation had been funded.

Obligations and Commitments

Settlement Agreement with BP    In October 2011, the Company and BP entered into the Settlement Agreement, pursuant to which the Company has agreed to pay $4.0 billion in cash and transfer its interest in the Lease to BP (subject to required governmental approvals of the transfer), and BP has agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued to date and to forgo reimbursement for all future costs arising from the Deepwater Horizon events, including future costs under the OA. In addition, BP has fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related OPA damage claims, NRD claims and associated damage-assessment costs, and any claims arising under the OA. This indemnification has been guaranteed by 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. See Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Operating Leases    In May 2011, Anadarko entered into two five-year lease agreements for deepwater drilling rigs. The rigs are expected to be delivered in late 2013 and early 2014. The lease obligations total approximately $1.2 billion, with aggregate future annual minimum lease payments of $30 million in 2013, $209 million in 2014, $238 million in 2015, and $715 million for the remaining lease term. In addition, Anadarko expects to incur approximately $640 million in operating costs related to these leases with aggregate payments of $15 million in 2013, $110 million in 2014, $130 million in 2015 and $385 million for the remaining lease term.

REGULATORY MATTERS, ENVIRONMENTAL AND ADDITIONAL FACTORS AFFECTING BUSINESS

Oil Spill-Response Plan

As part of the Company’s oil spill-response preparedness, Anadarko maintains membership in Clean Gulf Associates (CGA, a not-for-profit association of production and pipeline companies operating in the Gulf of Mexico), and has an employee representative on the executive committee of CGA. CGA has contracted with Helix Energy Solutions Group for access to the Helix Fast Response System (the Helix System) for subsea intervention, containment, capture, and shut-in capacity for deepwater exploration wells. The Helix System currently provides processing capacity of 45 MBbls/d of oil and flaring of 80 MMcf/d of natural gas from the vessel Helix Producer 1, and processing capacity of 10 MBbls/d of oil and flaring of 15 MMcf/d of natural gas from the vessel Q4000. The Helix System currently operates at deepwater depths of up to 10,000 feet, and is rated at 15 thousand pounds per square inch (kpsi) shut-in capability.

In addition, during the first quarter of 2011, the Company became an investing member in the Marine Well Containment Company (MWCC), which is open to all oil and gas operators in the U.S. Gulf of Mexico and provides members access to oil spill-response equipment and services on a per-well fee basis. Anadarko has an employee representative on the Executive Committee of MWCC and this employee currently serves as its Chair. MWCC members have access to an interim containment system, which includes a 15-kpsi capping stack and dispersant capability. The interim containment system is engineered to operate in deepwater depths of up to 10,000 feet, and has the capacity to contain 60 MBbls/d of liquids and flare 120 MMcf/d of natural gas. The DOI has reviewed the functional specifications of the MWCC interim containment system, and DOI input has been included in the final specifications.

MWCC members also expect to have access to an expanded containment system that is planned for use in deepwater depths of up to 10,000 feet with containment capacity of 100 MBbls/d of liquids and flare 200 MMcf/d of natural gas. The expanded system is planned to include a 15-kpsi subsea containment assembly with three rams stack, dedicated capture vessels, and a dispersant injection system. The expanded containment system may also be further expanded with additional capture vessels, modified tankers, drill ships, and extended well-test vessels, all of which may process, store, and offload oil to shuttle tankers, which may then take the oil to shore for further processing. This expanded containment system is on schedule for delivery in 2012. Additional information regarding the Company’s access to oil spill-response resources is included in the Company’s 2010 Annual Report on Form 10-K.

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CRITICAL ACCOUNTING ESTIMATES

Business Combinations

Accounting for the acquisition of a business requires the assets and liabilities of the acquired business to be recorded at fair value. Deferred taxes are recorded for any differences between asset and liability fair value and the tax basis of acquired assets and liabilities. Any excess of the purchase price over the amounts assigned to the identifiable assets and liabilities is recorded as goodwill.

Goodwill    As a result of the Wattenberg Plant acquisition, goodwill of $335 million and a portion of the related deferred tax asset were included in the oil and gas exploration and production reporting segment based on the increase in fair value to that segment resulting from improved NGLs volume retention from equity production and the alignment of Company-controlled natural-gas processing capacity with future production growth plans in the Rockies. The remaining $27 million of goodwill was included in the midstream reporting segment. Goodwill is not subject to amortization, but will be subject to recurring impairment testing.

Fair Value    The Company uses the market approach to measure the fair value of land and facilities and the cost approach to measure the fair value of equipment. The market approach is based on management’s best assumptions regarding prices and other relevant information from market transactions involving comparable assets. The cost approach is based on management’s best estimate of the current asset replacement cost.

RECENT ACCOUNTING DEVELOPMENTS

The Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that further addresses fair-value-measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair-value-measurement accounting and disclosure requirements, changes fair-value-measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair-value measurements. The ASU is required to be adopted on a prospective basis by Anadarko beginning January 1, 2012. The Company does not expect the adoption of this ASU to have an impact on its consolidated financial statements, other than requiring revised disclosures, where appropriate.

In September 2011, the FASB issued an ASU that permits an initial assessment of qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount for goodwill impairment testing purposes. Thus, determining a reporting unit’s fair value is not required unless, as a result of a qualitative assessment, it is more likely than not that the fair value of the reporting unit is less than its carrying amount. This ASU is effective for periods beginning after December  15, 2011. Adoption of this ASU will have no impact on the Company’s consolidated financial statements.

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 information regarding the Company’s accounting policies and additional information related to the Company’s derivative and financial instruments, see Note 1—Summary of Significant Accounting Policies, Note 7—Derivative Instruments, and Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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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 flow 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 and sustained decline. Below is a sensitivity analysis for the Company’s commodity-price-related derivative instruments.

Derivative Instruments Held for Non-Trading Purposes  At September 30, 2011, the Company had derivative instruments in place to reduce the price risk associated with future production of 532 Bcf of natural gas and 12 MMBbls of crude oil, with a net derivative asset position of $444 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $101 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $97 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes  At September 30, 2011, the Company had a net derivative asset position of $40 million (gains of $62 million and losses of $22 million) on derivative instruments entered into for trading purposes. 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.

INTEREST-RATE RISK  At September 30, 2011, all of the reported balance of Anadarko’s long-term debt in the Company’s Consolidated Balance Sheet was subject to fixed interest rates. However, the Company’s $2.9 billion of LIBOR-based obligations, which are presented net of preferred investments in two non-controlled entities in the Company’s Consolidated Balance Sheets, give rise to minimal net interest-rate risk exposure as 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 debt already outstanding, but would affect fair value of outstanding debt, as well as interest cost associated with future debt issuances.

In December 2008 and January 2009, Anadarko entered into interest-rate swap contracts as a fixed-rate payor to mitigate the interest-rate risk associated with anticipated 2011 and 2012 debt issuances. Due to rising interest rates thereafter, the fair value of the swap contracts increased and, in 2009, the Company revised the swap contract terms to increase the weighted-average interest rate of the swap portfolio from approximately 3.25% to approximately 4.80%, and realized a $552 million gain. During the third quarter of 2011, in order to better align the swap portfolio with the anticipated timing of future debt refinancing, the Company extended the swap maturity dates from October 2011 to June 2014 for interest-rate swaps with an aggregate notional principal amount of $1.85 billion. In connection with these extensions, the swap interest rates were also adjusted. At September 30, 2011, the Company had a net derivative liability position of $1.2 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 $118 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 7—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. At September 30, 2011, 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 containing commitments extending through November 2012 that are impacted by euro-to-U.S. dollar exchange rates. During the first quarter of 2010, the Company purchased approximately $210 million U.S. dollar equivalent of euros (€) and entered into euro-U.S. dollar collars with an aggregate notional principal amount of €113 million, to manage euro exchange-rate risk relative to the U.S. dollar for euro-denominated expenditures. During the first three quarters of 2011, existing collars matured and new collars were put in place with an aggregate notional principal amount of €30 million at September 30, 2011. The remaining collars mature in the fourth quarter of 2011. At September 30, 2011, euro-denominated cash of approximately €114 million, or $152 million in U.S. dollar equivalent, is included in cash and cash equivalents. The combination of euro purchases and financial collars mitigate the Company’s exposure to fluctuations in the euro-to-U.S. dollar exchange rate inherent in its existing capital expenditure commitments.

The Company also has risk related to exchange-rate changes applicable to cash held in escrow of $186 million as of September 30, 2011, pending final determination of the Company’s Brazilian tax liability attributable to its 2008 divestiture of the Peregrino field offshore Brazil. A 10% increase or decrease in the foreign-currency exchange rate would not materially impact the Company’s gain or loss related to foreign currency.

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 September 30, 2011.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the third quarter of 2011 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

DEEPWATER HORIZON EVENT—RELATED PROCEEDINGS  In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating leasehold interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. The Macondo well was plugged on September 19, 2010.

BP Exploration & Production Inc. (BP), the operator of Mississippi Canyon Block 252 in which the Macondo well is located (Lease), is funding claims and coordinating cleanup efforts. BP invoiced the Company $6.1 billion for what BP considered to be Anadarko’s proportionate share of actual costs and anticipated near-term future costs related to these activities. Anadarko withheld payment to BP for all Deepwater Horizon event-related invoices pending the completion of various ongoing investigations into and litigation regarding the cause of the well blowout, explosion, and subsequent release of hydrocarbons.

BP, Anadarko, and other parties, including parties that do not own an interest in the Lease, such as the drilling contractor, have received correspondence from the United States Coast Guard (USCG) referencing their identification as a “responsible party or guarantor” (RP) under the Oil Pollution Act of 1990 (OPA). The United States Department of Justice (DOJ) has also filed a civil lawsuit against such parties seeking, among other things, to confirm each party’s identified RP status. Under OPA, RPs, including Anadarko, may be jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims related to the spill and spill cleanup.

In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify, whereby the Company and BP agreed to a mutual release of claims against each other relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company has agreed to pay $4.0 billion in cash and transfer its interest in the Lease to BP (subject to required governmental approvals of the transfer), and BP has agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued to date and to forgo reimbursement for all future costs arising from the Deepwater Horizon events, including future costs under the Operating Agreement (OA). In addition, BP has fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims arising under OPA, claims for natural resource damages (NRD) and associated damage-assessment costs, and any claims arising under the OA. This indemnification has been 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. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder, derivative, or security laws claims, or certain other claims. The Company believes that costs associated with non-indemnified items, individually or in the aggregate, will not materially impact the Company’s consolidated financial position, results of operations, or cash flows.

Numerous civil lawsuits have been filed against BP and other parties, including the Company, by, among others, fishing, boating, and shrimping enterprises and industry groups; restaurants; commercial and residential property owners; certain rig workers or their families; the State of Alabama and several of its political subdivisions; the DOJ; environmental non-governmental organizations; the State of Louisiana and certain of its political subdivisions; and certain Mexican states. Many of the lawsuits filed assert various claims of negligence, gross negligence, and violations of several federal and state laws and regulations, including, among others, OPA; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Air Act; the Clean Water Act (CWA); and the Endangered Species Act; or challenge existing permits for operations in the Gulf of Mexico. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment, and/or injunctive relief.

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In August 2010, the United States Judicial Panel on Multidistrict Litigation created Multidistrict Litigation No. 2179 (MDL) to administer essentially all pretrial matters for litigation filed in federal court involving Deepwater Horizon event-related claims. Federal Judge Carl Barbier presides over this MDL in the United States District Court in New Orleans, Louisiana (Louisiana District Court). The Louisiana District Court has issued a number of case-management orders that establish a schedule for procedural matters, discovery, and trial of certain of the MDL cases. The parties to the MDL are actively engaged in discovery. In May 2011 and September 2011, Judge Barbier heard oral arguments on the numerous motions to dismiss filed by the multiple defendants named in this litigation. While a number of the motions remain pending, Judge Barbier has dismissed all maritime and state law claims filed against the Company by private plaintiffs seeking damages for economic loss. All negligence claims filed by these private plaintiffs against the Company have been dismissed based upon Judge Barbier’s finding that the Company did not exercise operational control over the events that led to the oil spill. In a separate order, Judge Barbier reached similar findings and dismissed all claims against the Company filed by private plaintiffs alleging personal injury caused by exposure to oil, fumes or other contaminants from the blowout or the chemical dispersants used during the post-spill clean-up operations. Judge Barbier further found that federal law exclusively applies to the private plaintiffs’ claims for property damage and economic loss and dismissed all state law claims against the Company asserting liability for such damages and losses. Only OPA claims asserted by private plaintiffs seeking economic loss damages against the Company remain. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against such OPA claims.

The Louisiana District Court has scheduled a February 2012 trial in Transocean’s Limitation of Liability case in the MDL. This trial is to be the first phase of a three-phase trial, each phase designed to address different issues. 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 April 2011, the Company filed its answer in this Limitation of Liability case and cross-claimed against affiliates of BP and Transocean Ltd. (Transocean), Halliburton Energy Services, Inc. (Halliburton), Cameron International Corporation (Cameron), and other third-party defendants. Transocean, Halliburton, and Cameron subsequently filed cross-claims against the Company, and BP filed a motion to stay the litigation in the MDL between BP and the non-operating OA parties. In the motion to stay, BP argued that the cross-claims asserted against BP by the Company and the other non-operating OA party are covered by the dispute resolution procedures under the OA and should be stayed. As a result of the Settlement Agreement, a mutual release of all claims, including those that could have been made in arbitration was agreed to by the Company and BP. The Company has also assigned all rights, title, and interest to all claims that have been or could be asserted against third parties, including cross-claims filed against other third-party defendants, to BP, with the exception of rights to claims the Company may assert under its insurance policies.

On December 15, 2010, the DOJ, on behalf of the United States, filed a civil lawsuit in the 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 CWA in an amount to be determined by the Louisiana District Court. The DOJ complaint seeks separate penalty assessments against both Anadarko Petroleum Corporation and AE&P (based on a temporary interest that AE&P at one time held in the Lease). In April 2011, the Company moved to dismiss AE&P from the DOJ lawsuit because the effective date of AE&P’s transfer of its interest in the Lease to Anadarko pre-dated the Deepwater Horizon events. The Company currently believes that it is probable AE&P will not be found liable for CWA penalties upon the presentation of evidence. The Company believes the outcome of this decision will not have a material impact on the Anadarko’s potential liability.

Lawsuits seeking to place limitations on the oil and gas industry’s operations in the Gulf of Mexico, including those of the Company, have also been filed outside of the MDL by non-governmental organizations against various governmental agencies. These cases are filed in the Louisiana District Court, the United States District Courts for the Southern District of Alabama and the District of Columbia, and in the United States Court of Appeals for the Fifth Circuit.

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Two separate class action complaints were filed in June and August 2010, in the United States 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 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In November 2010, the New York District Court consolidated the two cases and appointed The Pension Trust Fund for Operating Engineers and Employees’ Retirement System of the Government of the Virgin Islands (Virgin Islands Group) to act as Lead Plaintiff. In January 2011, the Lead Plaintiff filed its Consolidated Amended Complaint. Prior to filing its Consolidated Amended Complaint, the Lead Plaintiff requested leave from the New York District Court to transfer this lawsuit to the United States District Court for the Southern District of Texas. The Company opposes the Lead Plaintiff’s request to transfer the case to the District Court for the Southern District of Texas. The parties have submitted briefs to the New York District Court concerning the transfer of venue issue. In March 2011, the Company moved to dismiss the Consolidated Amended Complaint of the Lead Plaintiff, and in April 2011, the Lead Plaintiff filed its opposition to the motion to dismiss. The motion to transfer and motion to dismiss remain under advisement of the New York District Court.

Also in June 2010, a shareholder derivative petition was filed in the 152^nd Judicial District Court of Harris County, Texas (Harris County District Court), by a shareholder of the Company against Anadarko (as a nominal defendant), certain of its officers, and current and certain former directors. The petition alleged breaches of fiduciary duties, unjust enrichment, and waste of corporate assets in connection with the Deepwater Horizon events. The plaintiffs sought certain changes to the Company’s governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs. In November 2010, the Harris County District Court granted Anadarko’s Motion to Dismiss for Lack of Jurisdiction and Special Exceptions, and granted the plaintiffs 120 days to file an Amended Petition. In March 2011, the plaintiffs filed an Amended Petition. The Company filed Special Exceptions and a Motion to Dismiss the Amended Petition in April 2011. In June 2011, the Harris County District Court heard oral arguments on these matters and granted the motion to dismiss. The time for the plaintiffs to appeal has expired.

In September 2010, a purported shareholder made a demand of the Company’s Board of Directors (Board) to investigate allegations of breaches of duty by members of management. The Board duly considered the demand, and in January 2011 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter.

Given the early 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 directors in all proceedings, and will avail itself of any and all indemnities provided by BP against civil damages.

See Note 2—Deepwater Horizon Events under Part I, Item 1 of this Form 10-Q.

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TRONOX 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 its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court). 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. Tronox seeks, among other things, to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko, as well as litigation fees and costs. Anadarko and Kerr-McGee moved to dismiss the complaint in its entirety. In March 2010, the Bankruptcy Court issued an opinion granting in part and denying in part Anadarko’s and Kerr-McGee’s motion to dismiss the complaint. Notably, the Bankruptcy Court dismissed, with prejudice, Tronox’s request for punitive damages relating to the fraudulent conveyance claims. The Bankruptcy Court granted Tronox leave to replead certain of its common law claims, and Tronox filed an amended complaint in April 2010. In May 2010, Anadarko and Kerr-McGee moved to dismiss certain claims in the amended complaint. In May 2011, the Bankruptcy Court dismissed two claims against Anadarko for conspiracy and aiding and abetting, and declined to dismiss a breach of fiduciary duty claim against Kerr-McGee. In August 2011, Tronox filed a motion for partial summary judgment on the issue of whether damages in the Adversary Proceeding are limited to the amount of Tronox’s environmental and tort creditor claims. Kerr-McGee and Anadarko filed a response and cross-motion in September 2011. Expert discovery is ongoing. The Adversary Proceeding is set for trial in April 2012.

The United States government was granted authority to intervene in the Adversary Proceeding, and it has asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act. Anadarko and Kerr-McGee have moved to dismiss the claims of the United States government, but that motion has been stayed by the Bankruptcy Court.

In August 2010, the Bankruptcy Court entered a Stipulation and Agreed Order among Tronox, Anadarko, and Kerr-McGee authorizing the rejection of the Master Separation Agreement (together with all annexes, related agreements, and ancillary agreements to it, the MSA). Anadarko and Kerr-McGee filed Proofs of Claim, which included claims for damages arising from the MSA rejection. In January 2011, the Bankruptcy Court entered a Stipulation and Agreed Order approving a settlement of Anadarko and Kerr-McGee’s rejection damage claims against Tronox. The settlement provided Anadarko a general unsecured claim against Tronox. In February 2011, in settlement of its claim, Anadarko received shares of Tronox stock, which were assigned to a financial institution in exchange for $46 million. The Company will continue to monitor the impact that the rejection of the MSA may have on other litigation and other proceedings, including the Adversary Proceeding, and will assess the impact of future events on the Company’s consolidated financial position, results of operations, and cash flows.

In February 2011, in accordance with Chapter 11 of the United States Bankruptcy Code, Tronox emerged from bankruptcy pursuant to an August 2010 Bankruptcy Court approved Plan of Reorganization (Plan). The terms of the Plan, which were confirmed by the Bankruptcy Court in the third quarter of 2010, contemplate that the claims of the United States government (together with other federal, state, local, or tribal governmental entities having regulatory authority or responsibilities for environmental laws, the Governmental Entities) related to Tronox’s environmental liabilities will be settled through certain environmental response trusts and a litigation trust (Anadarko Litigation Trust). The Plan provides that the Governmental Entities will receive, among other things, 88% of the proceeds from the Adversary Proceeding. Additionally, certain creditors asserting tort claims against Tronox may receive, among other things, 12% of the proceeds from the Adversary Proceeding. Certain documents central to the Plan and the Adversary Proceeding were approved by the Bankruptcy Court in the fourth quarter of 2010 and in February 2011, including the Environmental Claims Settlement Agreement, the Tort Claims Trust Agreement, the Environmental Response Trust Agreement, and the Anadarko Litigation Trust Agreement (ALTA). In accordance with the Plan, the Adversary Proceeding will be prosecuted by the Anadarko Litigation Trust. Pursuant to the ALTA, 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.

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In addition, 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 (Class Period), against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors, and Ernst & Young LLP (collectively, the Securities Defendants). The complaint alleges causes of action arising under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (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. Anadarko, Kerr-McGee, and other defendants moved to dismiss the consolidated class action complaint and in August 2010 moved to dismiss an amended consolidated class action complaint that had been filed in July 2010. The New York District Court issued the second of two opinions and orders on the motions (Orders). Following the Orders, only the plaintiffs’ Section 20(a) claims under the Exchange Act remain against Anadarko and Kerr-McGee. The plaintiffs’ claims against Anadarko are limited to the period beginning on August 10, 2006, through the end of the Class Period. In August 2011, plaintiffs filed a motion for class certification. The Securities Defendants filed briefs in opposition to class certification in September 2011. The court denied class certification in October 2011 and has requested the parties to re-brief the class certification motion. The discovery process is ongoing.

Discovery and motions are still underway in the Tronox proceedings. The Company does not consider a loss related to this matter to be probable; however, a loss is possible, and such loss, if realized, could have a material adverse effect on the Company. At this time the Company cannot reasonably estimate a range of potential losses related to the proceedings described above because the amount of potential damages will depend on circumstances that have not yet occurred, including the outcome of expert testimony and certain determinations to be made by the Bankruptcy Court. The Company intends to continue to vigorously defend itself, its officers, and its directors in these proceedings.

See Note 11—Contingencies under Part I, Item 1 of this Form 10-Q.

Item 1A.  Risk Factors

Consider carefully the risk factors 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, 2010, 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, 2010; and in the Company’s other public filings, press releases, and discussions with Company management.

We may be subject to claims and liabilities relating to the Deepwater Horizon events that are not covered by BP’s indemnification obligations under our Settlement Agreement with BP, or if BP is unable for any reason to satisfy its indemnification obligations under the Settlement Agreement.

In October 2011, the Company and BP entered into the Settlement Agreement, pursuant to which the Company has agreed to pay $4.0 billion in cash and transfer its interest in the Lease to BP (subject to required governmental approvals of the transfer), and BP has agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued to date and to forgo reimbursement for all future costs arising from the Deepwater Horizon events, including future costs under the OA.

Under the Settlement Agreement, BP has also agreed to fully indemnify Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims arising under OPA, NRD claims and associated damage-assessment costs, and any claims arising under the OA. This indemnification has been guaranteed by 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.

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Any failure or inability on the part of BP to satisfy its indemnification obligations under the Settlement Agreement, or on the part of BPCNA or BP p.l.c. to satisfy their respective guarantee obligations, could subject us to significant monetary liability beyond the terms of the Settlement Agreement, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Furthermore, in certain instances we may be required to recognize a liability for amounts for which we are indemnified in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. Any such liability recognition without collection of the offsetting receivable could adversely impact our results of operations, our financial condition, and our ability to make borrowings. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder, derivative, or security laws claims, or certain other claims. The adverse resolution of any current or future proceeding related to the Deepwater Horizon events for which we are not indemnified by BP could subject us to significant monetary liability, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

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, a former subsidiary of Kerr-McGee, which is a current subsidiary of Anadarko, and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. 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. Tronox seeks, among other things, to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko, as well as litigation fees and costs. Anadarko and Kerr-McGee moved to dismiss the complaint in its entirety. In March 2010, the Bankruptcy Court issued an opinion granting in part and denying in part Anadarko’s and Kerr-McGee’s motion to dismiss the complaint. Notably, the Bankruptcy Court dismissed, with prejudice, Tronox’s request for punitive damages relating to the fraudulent conveyance claims. The Bankruptcy Court granted Tronox leave to replead certain of its common law claims, and Tronox filed an amended complaint in April 2010. In May 2010, Anadarko and Kerr-McGee moved to dismiss certain claims in the amended complaint. In May 2011, the Bankruptcy Court dismissed two claims against Anadarko for conspiracy and aiding and abetting, and declined to dismiss a breach of fiduciary duty claim against Kerr-McGee. In August 2011, Tronox filed a motion for partial summary judgment on the issue of whether damages in the Adversary Proceeding are limited to the amount of Tronox’s environmental and tort creditor claims. Kerr-McGee and Anadarko filed a response and cross-motion in September 2011. Expert discovery is ongoing. The Adversary Proceeding is set for trial in April 2012.

The United States government was granted authority to intervene in the Adversary Proceeding, and it has asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act. Anadarko and Kerr-McGee have moved to dismiss the claims of the United States government, but that motion has been stayed by the Bankruptcy Court.

In August 2010, the Bankruptcy Court entered a Stipulation and Agreed Order among Tronox, Anadarko, and Kerr-McGee authorizing the rejection of the MSA. Anadarko and Kerr-McGee filed Proofs of Claim, which included claims for damages arising from the MSA rejection. In January 2011, the Bankruptcy Court entered a Stipulation and Agreed Order approving a settlement of Anadarko and Kerr-McGee’s rejection damage claims against Tronox. The settlement provided Anadarko a general unsecured claim against Tronox. In February 2011, in settlement of its claim, Anadarko received shares of Tronox stock, which were assigned to a financial institution in exchange for $46 million. The Company will continue to monitor the impact that the rejection of the MSA may have on other litigation and other proceedings, including the Adversary Proceeding, and will assess the impact of future events on the Company’s consolidated financial position, results of operations, and cash flows.

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In February 2011, in accordance with Chapter 11 of the United States Bankruptcy Code, Tronox emerged from bankruptcy pursuant to an August 2010 Bankruptcy Court approved Plan of Reorganization. The terms of the Plan, which were confirmed by the Bankruptcy Court in the third quarter of 2010, contemplate that the claims of the Governmental Entities related to Tronox’s environmental liabilities will be settled through certain environmental response trusts and the Anadarko Litigation Trust. The Plan provides that the Governmental Entities will receive, among other things, 88% of the proceeds from the Adversary Proceeding. Additionally, certain creditors asserting tort claims against Tronox may receive, among other things, 12% of the proceeds from the Adversary Proceeding. Certain documents central to the Plan and the Adversary Proceeding were approved by the Bankruptcy Court in the fourth quarter of 2010 and in February 2011 including, the Environmental Claims Settlement Agreement, the Tort Claims Trust Agreement, the Environmental Response Trust Agreement, and the ALTA. In accordance with the Plan, the Adversary Proceeding will be prosecuted by the Anadarko Litigation Trust. Pursuant to the ALTA, 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.

In addition, 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 during the Class Period, against the Securities Defendants. The complaint alleges causes of action arising under 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. Anadarko, Kerr-McGee, and other defendants moved to dismiss the consolidated class action complaint and in August 2010 moved to dismiss an amended consolidated class action complaint that had been filed in July 2010. The New York District Court issued the second of two opinions and Orders. Following the Orders, only the plaintiffs’ Section 20(a) claims under the Exchange Act remain against Anadarko and Kerr-McGee. The plaintiffs’ claims against Anadarko are limited to the period beginning on August 10, 2006, through the end of the Class Period. In August 2011, plaintiffs filed a motion for class certification. The Securities Defendants filed briefs in opposition to class certification in September 2011. The discovery process is ongoing.

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.

For additional information regarding the nature and status of these and other material legal proceedings, see Legal Proceedings under Part II, Item 1 of this Form 10-Q.

Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities could result in increased costs, additional operating restrictions or delays, and adversely affect our production.

Hydraulic fracturing is an essential and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations such as shales that generally exist between 4,000 and 14,000 feet below ground. We routinely apply hydraulic-fracturing techniques in many of our U.S. onshore oil and natural-gas drilling and completion programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The process is typically regulated by state oil and natural-gas commissions; however, the U.S. Environmental Protection Agency (EPA), recently asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process.

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Certain states in which we operate, including Colorado, Pennsylvania, Texas and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, transparency and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (RCT) and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic-fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. Additionally, certain members of the Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the U.S. Securities and Exchange Commission to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural-gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural-gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These on-going or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanism.

If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, the Company’s fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves.

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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 third quarter of 2011.

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
July 1-31		1,640	$	78.70		—
August 1-31		1,157	$	73.98		—
September 1-30		825	$	70.21		—
Third-Quarter 2011		3,622	$	75.25		—	$	—

⁽¹⁾  During the third quarter of 2011, 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 22, 2009	3.4 to Form 8-K filed on May 22, 2009	1-8968
*	10	(i)	First Amendment to Revolving Credit Agreement, dated as of August 3, 2011, to the Revolving Credit Agreement dated as of September 2, 2010, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A. as Administrative Agent, Bank of America, N.A., DnB Nor Bank ASA, The Royal Bank of Scotland plc, Société Générale, and Wells Fargo Bank, N.A., as co-syndication agents, and each of the Lenders from time to time party thereto.
*	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

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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
October 31, 2011	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Senior Vice President, Finance and Chief Financial Officer

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EX-10.(I)

EXHIBIT 10(i)

EXECUTION VERSION

FIRST AMENDMENT TO REVOLVING CREDIT AGREEMENT

FIRST AMENDMENT TO REVOLVING CREDIT AGREEMENT, dated as of August 3, 2011 (this “Amendment”), to the Revolving Credit Agreement dated as of September 2, 2010 ( the “Credit Agreement”) among ANADARKO PETROLEUM CORPORATION, a corporation organized under the laws of the State of Delaware, as Borrower, JPMORGAN CHASE BANK, N.A., as Administrative Agent, BANK OF AMERICA, N.A., DNB NOR BANK ASA, THE ROYAL BANK OF SCOTLAND PLC, SOCIETE GENERALE, and WELLS FARGO BANK, N.A, as co-syndication agents, and each of the Lenders from time to time party thereto.

W I T N E S S E T H:

WHEREAS, pursuant to the Credit Agreement, the Lenders have agreed to make, and have made, certain loans and other extensions of credit to the Borrower;

WHEREAS, the Borrower has requested that certain provisions of the Credit Agreement be amended as set forth in this Amendment; and

WHEREAS, the Lenders are willing to agree to such amendment on the terms and subject to the conditions set forth in this Amendment;

NOW THEREFORE, in consideration of the premises and mutual covenants contained in this Amendment, the undersigned hereby agree as follows:

I.           Defined Terms; Interpretation; Etc. Capitalized terms used but not defined in this Amendment shall have the meanings given to them in the Credit Agreement.

II.          Amendment to the Credit Agreement.

(a)         The definition of “Applicable Margin” set forth in Section 1.01 of the Credit Agreement is hereby deleted and replaced in its entirety as follows:

“Applicable Margin” — for any day, with respect to any Loan that is an Alternate Base Rate Loan or Eurodollar Loan, or with respect to the commitment fees payable hereunder, as the case may be, the applicable rate per annum set forth below under the caption “Alternate Base Rate Spread”, “Eurodollar Spread” or “Commitment Fee Rate”, as the case may be, based upon the rating for the senior, unsecured, long-term indebtedness for borrowed money of the Borrower that is not guaranteed by any other Person or subject to any other credit enhancement (an “Index Debt Rating”) by each of Moody’s and S&P:

Index Debt Ratings:	Alternate   Base Rate   Spread	Eurodollar   Spread	Commitment Fee Rate
Category 1: Index Debt Rating of at least BBB+ by S&P or at least Baa1 by Moody’s	0.25%	1.25%	0.15%
Category 2: Index Debt Rating of at least BBB by S&P or at least Baa2 by Moody’s and not Category 1	0.50%	1.50%	0.20%
Category 3: Index Debt Rating of at least BBB- by S&P or at least Baa3 by Moody’s and not Category 2	0.75%	1.75%	0.25%
Category 4: Index Debt Rating of at least BB+ by S&P or at least Ba1 by Moody’s and not Category 1, 2 or 3	1.00%	2.00%	0.30%
Category 5: Index Debt Ratings below Category 4	1.50%	2.50%	0.40%

For purposes of the foregoing, (i) if Moody’s or S&P shall not have in effect an Index Debt Rating for the Borrower (other than by reason of the circumstances referred to in the last sentence of this definition), then such rating agency shall be deemed to have established a rating in Category 5; (ii) if the Index Debt Rating established or deemed to have been established by Moody’s and S&P shall fall within different Categories, the Applicable Margin shall be based on the higher of the two ratings unless one of the two ratings is two or more Categories lower than the other, in which case the Applicable Margin shall be determined by reference to the Category next above that of the lower of the two ratings; and (iii) if the Index Debt Rating established or deemed to have been established by Moody’s or S&P shall be changed (other than as a result of a change in the rating system of Moody’s or S&P), such change shall be effective as of the date on which it is first announced by the applicable rating agency. Each change in the Applicable Margin shall apply during the period commencing on the date of such change and ending on the date immediately preceding the date of the next such change. If the rating system of Moody’s or S&P changes, or if either such rating agency ceases to be in the business of rating corporate debt obligations, the Borrower and the Lenders shall negotiate in good faith to amend this definition to reflect such changed rating system or the unavailability of ratings from such rating agency and, pending the effectiveness of any such amendment, the Applicable Margin shall be determined by reference to the rating most recently in effect prior to such change or cessation. Notwithstanding the foregoing, (x) unless and until all or substantially all of the Collateral shall have been released with the written consent of all Lenders pursuant to clause (iv) of the proviso in Section 9.02(b) and (y) the Applicable Margin shall not then be determined by the provisions of clause (i) of this paragraph, the Applicable Margin shall be determined by reference to the Category immediately above the Category that would otherwise apply.

(b)        The definition of “Indebtedness” set forth in Section 1.01 of the Credit Agreement is hereby amended to add the following sentence following the last sentence of such definition:

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“Notwithstanding anything to the contrary set forth above, obligations of the kind referred to in clauses (a) through (i) of the first sentence hereof will not constitute “Indebtedness” of the Borrower or such Subsidiary if such obligations would not constitute “Indebtedness” of the Borrower or such Subsidiary but for the pledge by the Borrower or such Subsidiary of equity interests in any Person that is not a Subsidiary to secure an obligation of any Person that is not a Subsidiary.”

(c)        Section 4.08 of the Credit Agreement is hereby deleted and replaced in its entirety as follows:

            Section 4.08 Ratings.  Use commercially reasonable efforts to cause Moody’s and S&P to have in effect an Index Debt Rating for the Borrower.

(d)        Section 5.05(w) of the Credit Agreement is hereby deleted and replaced in its entirety as follows:

(w)           Liens on property other than on Principal Property or on other property purported to be Collateral not otherwise permitted by this Section so long as (i) the aggregate outstanding principal amount of the obligations secured thereby does not exceed $1,000,000,000 at any one time (as to the Borrower and all Subsidiaries) and (ii) the aggregate fair market value (determined as of the date such Lien is incurred) of the assets subject thereto does not exceed $1,000,000,000 at any one time.

(e)        Section 5.05 of the Credit Agreement is hereby amended to add a new clause (x) to read in its entirety as follows:

(x)            Liens consisting of pledges, by the Borrower or a Subsidiary, of equity interests in any Person that is not a Subsidiary so long as the aggregate fair market value (determined as of the date such Lien is incurred) of the equity interests subject thereto does not exceed $300,000,000 at any one time.

III.        Conditions Precedent to the Effectiveness of this Amendment.

(a)  This Amendment shall become effective as of, and with effect from, the date (the “Effective Date”) on which the Administrative Agent has received:

(i) duly executed signature pages to this Amendment from the Borrower and each Lender party to the Credit Agreement as of the date hereof; and

(ii) payment by the Borrower, for the account of each Lender that has returned an executed signature page to this Amendment to the Administrative Agent, of an amendment fee in an amount equal to 0.10% of the Commitment of such Lender in effect as of the date hereof.

(b)  All corporate and other proceedings required in connection with this Amendment, and all documents, instruments and other legal matters in connection with the transactions contemplated by this Amendment, shall be satisfactory in all respects to

3

the Lenders, which satisfaction shall be evidenced by the execution and delivery by the Lenders of this Amendment.

(c)  Each of the representations and warranties made by any Loan Party in or pursuant to the Loan Documents shall be true and correct in all material respects on and as of such date as if made on and as of such date, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, on and as of the Effective Date, such representations and warranties shall continue to be true and correct as of such specified earlier date; provided, however, that references therein to the “Credit Agreement” shall be deemed to refer to the Credit Agreement as amended by this Amendment after giving effect to the amendments set forth herein.

(d)  After giving effect to this Amendment, no Default or Event of Default shall have occurred and be continuing as of the date hereof.

(e)  No litigation shall have been commenced against any Loan Party or any of its Subsidiaries, either on the date hereof or the Effective Date, seeking to restrain or enjoin (whether temporarily, preliminarily or permanently) the performance of any action by any Loan Party required or contemplated by this Amendment or the Credit Agreement.

IV.        No Other Amendments; Confirmation. Except as expressly set forth herein, this Amendment shall not by implication or otherwise limit, impair, constitute a waiver of, or otherwise affect the rights and remedies of the Lenders, the Agents, the Borrower or any other Loan Party under the Credit Agreement or any other Loan Document, and shall not alter, modify, amend or in any way affect any of the terms, conditions, obligations, covenants or agreements contained in the Credit Agreement or any other Loan Document, all of which are ratified and affirmed in all respects and shall continue in full force and effect. Nothing herein shall be deemed to entitle the Borrower to any future consent to, or a waiver, amendment, modification or other change of, any of the terms, conditions, obligations, covenants or agreements contained in the Credit Agreement or any other Loan Document in similar or different circumstances. This Amendment shall apply and be effective only with respect to the provisions of the Credit Agreement specifically referred to herein. After the Effective Date, any reference in any Loan Document to the Credit Agreement shall mean the Credit Agreement as modified hereby. As of the Effective Date, each reference in the Credit Agreement to “this Agreement,” “hereunder,” “hereof,” “herein,” or words of like import, and each reference in the other Loan Documents to the Credit Agreement (including, without limitation, by means of words like “thereunder”, “thereof” and words of like import), shall mean and be a reference to the Credit Agreement as amended hereby, and this Amendment and the Credit Agreement shall be read together and construed as a single instrument. Each of the table of contents and lists of Exhibits and Schedules of the Credit Agreement shall be amended to reflect the changes made in this Amendment as of the Effective Date.

V.         Expenses. The Borrower agrees to reimburse the Administrative Agent and the Lenders for their respective reasonable and documented out-of-pocket expenses incurred in connection with this Amendment (including the reasonable fees, disbursements and other charges of Simpson Thacher & Bartlett LLP). Notwithstanding the foregoing, nothing in this Section V shall be deemed or construed to amend, modify or limit the scope of Section 9.03 of the Credit Agreement or any of the Credit Parties’ rights thereunder.

VI.        Governing Law. THIS AMENDMENT, THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AMENDMENT AND ANY CLAIM OR CONTROVERSY ARISING OUT OF OR RELATED TO THIS AMENDMENT SHALL BE GOVERNED BY, AND

4

CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

VII.       Counterparts. This Amendment may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. Delivery of an executed counterpart of a signature page of this Amendment by email or facsimile transmission shall be effective as delivery of a manually executed counterpart of this Amendment.

VIII.      Headings. The Section headings used herein are for convenience of reference only, are not part of this Amendment and are not to affect the construction of, or to be taken into consideration in interpreting, this Amendment.

IX.        Notices. All communications and notices hereunder shall be given as provided in the Credit Agreement.

X.         Severability. Any provision of this Amendment held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

XI.        Successors. The terms of this Amendment shall be binding upon, and shall inure to the benefit of, the parties hereto and their respective successors and assigns.

XII.       Waiver of Jury Trial. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THE LOAN DOCUMENTS OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (a) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (b) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AMENDMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

XIII.     Submission to Jurisdiction. Each party hereto hereby irrevocably and unconditionally submits, for itself and its property, to the nonexclusive jurisdiction of the courts of the Supreme Court of the State of New York, sitting in New York County and of the United States District Court of the Southern District of New York, and any appellate court from either thereof, in any action or proceeding arising out of or relating to this Amendment, or for recognition or enforcement of any judgment, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such New York State court or, to the extent permitted by law, in such Federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Amendment shall affect any right that the Administrative Agent, any of the other agents, any Issuing Lender or any Lender may otherwise have to bring any action or proceeding relating to this Amendment against the Borrower or its properties in the courts of any jurisdiction and agrees that nothing herein shall affect the right to effect

5

service of process in any other manner permitted by law or shall limit the right to sue in any other jurisdiction.

[Signature Pages Follow]

6

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly authorized as of the day and year first above written.

ANADARKO PETROLEUM CORPORATION
By:	/s/    Bruce W. Busmire

Name: Bruce W. Busmire

Title: Vice President, Finance and Treasurer

[Signature Page – First Amendment to Revolving Credit Agreement]

JPMORGAN CHASE BANK, N.A.,
as Administrative Agent and as a Lender
By:	/s/ Muhammad Hasan

Name: Muhammad Hasan

Title: Vice President

[Signature Page – First Amendment to Revolving Credit Agreement]

Bank of America, N.A.,

as a Lender

By: /s/    Ronald E. McKaig

Name: Ronald E. McKaig

Title: Managing Director

[Signature Page – First Amendment to Revolving Credit Agreement]

DnB NOR Bank ASA,

as a Lender

By: /s/    Barbara Gromquist

Name: Barbara Gromquist

Title:	Senior Vice President
By:	/s/    Evan Uhlick
Name:	Evan Uhlick
Title:	Vice President

The Royal Bank of Scotland plc,

as a Lender

By: /s/    Nathan Bautista

Name: Nathan Bautista

Title: Authorised Signatory

Societe Generale

as a Lender

By: /s/    Stephen Warfel

Name: Stephen Warfel

Title: Managing Director

Wells Fargo Bank, National Association,

as a Lender

By: /s/    Leanne S. Phillips

Name: Leanne S. Phillips

Title: Director

Barclays Bank PLC,

as a Lender

By: /s/    May Huang

Name: May Huang

Title: Assistant Vice President

Citibank, N.A.,

as a Lender

By: /s/    John F. Miller

Name: John F. Miller

Title: Attorney-in-Fact

DEUTSCHE BANK AG NEW YORK

BRANCH,

as a Lender

By: /s/    Philippe Sandmeier

Name: Philippe Sandmeier

Title: Managing Director

By: /s/    Yvonne Tilden

Name: Yvonne Tilden

Title: Director

GOLDMAN SACHS BANK USA,

as a Lender

By: /s/    Rick Canonico

Name: Rick Canonico

Title: Authorized Signatory

MORGAN STANLEY BANK, N.A.,

as a Lender

By: /s/    Sherrese Clarke

Name: Sherrese Clarke

Title: Authorized Signatory

UBS Loan Finance LLC,

as a Lender

By: /s/    Irja R. Otsa

Name: Irja R. Otsa

Title: Associate Director

By: /s/    Omar Musule

Name: Omar Musule

Title: Associate Director

CREDIT SUISSE AG, Cayman Islands Branch,

as a Lender

By: /s/    Nupur Kumar

Name: Nupur Kumar

Title: Vice President

By: /s/    Vipul Dhadda

Name: Vipul Dhadda

Title: Associate

The Bank of Nova Scotia,

as a Lender

By: /s/    John Frazell

Name: John Frazell

Title: Director

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.

as a Lender

By: /s/    Andrew Oram

Name: Andrew Oram

Title: Managing Director

BNP Paribas,

as a Lender

By: /s/    Courtney Kubesch

Name: Courtney Kubesch

Title: Vice President

By: /s/    Edward Pak

Name: Edward Pak

Title: Director

STANDARD CHARTERED BANK,

as a Lender

By: /s/    James P. Hughes

Name: James P. Hughes A2386

Title: Director

By: /s/    Robert K. Reddington

Name: Robert K. Reddington

Title: Credit Documentation Manager Credit Documentation Unit, WB Legal-Americas

The Bank of New York Mellon,

as a Lender

By: /s/    Hussam S. Alsahlani

Name: Hussam S. Alsahlani

Title: Vice President

AMEGY BANK NATIONAL ASSOCIATION,

as a Lender

By: /s/    C. Wakeford Thompson

Name: C. Wakeford Thompson

Title: Vice President

ING CAPITAL, LLC,

as a Lender

By: /s/    Huma Manal

Name: Huma Manal

Title: Director

EX-31.(I)

EXHIBIT 31(i)

CERTIFICATIONS

I, James T. Hackett, 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.

October 31, 2011

/s/ JAMES T. HACKETT

James T. Hackett

Chairman 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.

October 31, 2011

/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, James T. Hackett, Chairman 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 September 30, 2011, 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.

October 31, 2011
	/s/ JAMES T. HACKETT
	James T. Hackett
	Chairman and Chief Executive Officer
October 31, 2011
	/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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Fair Value of Derivative Financial Assets and Liabilities by Level within Fair Value Hierarchy Table (Detail) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	$ 599		$ 801
Gross derivative liabilities	(1,287)		(724)
Derivative assets netting	(95)	[1]	(446)	[1]
Derivative liabilities netting	95	[1]	446	[1]
Cash collateral from counterparties	(5)		(15)
Cash collateral held by counterparties	115		15
Derivative financial assets	499		340
Derivative financial liabilities	(1,077)		(263)
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)		(2)
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)		(2)
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	597		798
Gross derivative liabilities	(1,284)		(722)
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	466		557
Gross derivative liabilities	(88)		(333)
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	131		241
Gross derivative liabilities	(24)		(154)
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	(1,172)		(235)
Financial Institutions [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	(84)	[1]	(298)	[1]
Derivative liabilities netting	84	[1]	298	[1]
Cash collateral from counterparties	(5)		(15)
Cash collateral held by counterparties	5
Derivative financial assets	379		247
Derivative financial liabilities	(2)		(37)
Other Counterparties [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	(11)	[1]	(148)	[1]
Derivative liabilities netting	11	[1]	148	[1]
Derivative financial assets	120		93
Derivative financial liabilities	(13)		(6)
Interest Rate Contract and Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash collateral held by counterparties	110		15
Derivative financial liabilities	$ (1,062)		$ (220)

[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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CONSOLIDATED BALANCE SHEETS (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 3,487	$ 3,680
Accounts receivable, net of allowance:
Customers	1,169	1,032
Others	2,259	1,391
Other current assets	689	572
Total	7,604	6,675
Properties and Equipment
Cost	58,185	54,815
Less accumulated depreciation, depletion, and amortization	20,069	16,858
Net properties and equipment	38,116	37,957
Other Assets	1,510	1,616
Goodwill and Other Intangible Assets	5,832	5,311
Total Assets	53,062	51,559
Current Liabilities
Accounts payable	2,446	2,726
Accrued expenses	1,259	1,097
Current portion of long-term debt	141	291
Deepwater Horizon settlement and related costs	4,017
Total	7,863	4,114
Long-term Debt	12,808	12,722
Other Long-term Liabilities
Deferred income taxes	8,670	9,861
Asset retirement obligations	1,584	1,529
Other	2,638	1,894
Total	12,892	13,284
Stockholders' equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 515.5 million and 513.3 million shares issued as of September 30, 2011, and December 31, 2010, respectively)	51	51
Paid-in capital	7,845	7,496
Retained earnings	12,023	14,449
Treasury stock (17.5 million and 17.1 million shares as of September 30, 2011, and December 31, 2010, respectively)	(794)	(763)
Accumulated other comprehensive income (loss)	(501)	(549)
Total Stockholders' Equity	18,624	20,684
Noncontrolling interests	875	755
Total Equity	19,499	21,439
Total Liabilities and Equity	$ 53,062	$ 51,559

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Sep. 30, 2011	Dec. 31, 2010
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	515,500,000	513,300,000
Treasury stock, shares	17,500,000	17,100,000

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Debt and Interest Expense - Anadarko (Detail) (USD $)	Sep. 30, 2011
Debt Instrument [Line Items]
Compensating balances included in cash and cash equivalents	$ 325,000,000
Minimum [Member] | The LOC Facility [Member]
Debt Instrument [Line Items]
Letter of credit facility, commitment covenant	1,000,000,000
Letter of credit facility, borrowing capacity covenant	400,000,000
The LOC Facility [Member]
Debt Instrument [Line Items]
Letter of credit facility, maximum borrowing capacity	400,000,000
Five Billion Dollar Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum borrowing capacity	5,000,000,000
Line of credit, outstanding borrowings	0
Line of credit, remaining borrowing capacity	$ 4,600,000,000

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Segment Information

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Segment Information

14.  Segment Information

       Anadarko's primary business segments are vertically integrated within the oil and gas industry. These 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 marketing segment sells most of Anadarko's production, as well as third-party purchased volumes.

During the first quarter of 2011, the chief operating decision maker (CODM) began separately assessing the performance of, and resource allocation to, the WES operating segment. As a result, the midstream operating segment was separated into two operating segments, WES and other midstream activities. The WES and other midstream activities operating segments are aggregated into a single midstream reporting segmentdue to similar financial and operating characteristics.

To assess the performance of Anadarko's operating segments, the CODM analyzes income (loss) before income taxes, interest expense, exploration expense, depreciation, depletion, and amortization (DD&A), impairments,Deepwater Horizon settlement and related costs, and unrealized (gains) losses on derivative instruments, 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. Anadarko's definition of Adjusted EBITDAX also excludes exploration expense, as exploration expense 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 as these costs are outside the normal operations of the Company. See Note 2 for a discussion of Deepwater Horizon Events. Finally, unrealized (gains) losses on derivative instruments, net are excluded from Adjusted EBITDAX because unrealized (gains) losses are not considered a measure of assetoperating 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 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				Nine Months Ended
	September 30,				September 30,
millions	2011		2010		2011		2010
Income (loss) before income taxes	$	(4,496)	$	86	$	(2,991)	$	1,352
Exploration expense		307		296		722		649
DD&A		932		962		2,902		2,845
Impairments		183		20		287		147
Deepwater Horizon settlement and related costs(1)		4,042		2		4,055		2
Interest expense		206		218		642		642
Unrealized (gains) losses on derivative instruments, net(2)		692		174		767		(66)
Less: Net income attributable to noncontrolling interests		23		18		62		42
Consolidated Adjusted EBITDAX	$	1,843	$	1,740	$	6,322	$	5,529

_________________________________________________________

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

(2)In the fourth quarter of 2010, the Company revised the definition of Adjusted EBITDAX to exclude the impact of unrealized (gains) losses on derivative instruments, net. The 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 September 30, 2011:
Sales revenues		$	1,801	$	76	$	1,507	$	—	$	3,384
Intersegment revenues			1,244		251		(1,386)		(109)		—
Gains (losses) on divestitures and other, net			(193)		(31)		—		39		(185)
	Total revenues and other		2,852		296		121		(70)		3,199
Operating costs and expenses(1)			955		210		143		53		1,361
Realized (gains) losses on derivatives, net			—		—		—		(71)		(71)
Other (income) expense, net			—		—		—		40		40
Net income attributable to
	noncontrolling interests		—		23		—		—		23
	Total expenses and other		955		233		143		22		1,353
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(3)		—		(3)
Adjusted EBITDAX		$	1,897	$	63	$	(25)	$	(92)	$	1,843
Three Months Ended September 30, 2010:
Sales revenues		$	1,318	$	45	$	1,153	$	—	$	2,516
Intersegment revenues			950		198		(1,051)		(97)		—
Gains (losses) on divestitures and other, net			(3)		—		—		37		34
	Total revenues and other		2,265		243		102		(60)		2,550
Operating costs and expenses(1)			723		152		116		83		1,074
Realized (gains) losses on derivatives, net			—		—		—		(157)		(157)
Other (income) expense, net			—		—		—		(129)		(129)
Net income attributable to
	noncontrolling interests		—		18		—		—		18
	Total expenses and other		723		170		116		(203)		806
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(4)		—		(4)
Adjusted EBITDAX		$	1,542	$	73	$	(18)	$	143	$	1,740

_________________________________________________________

(1) Operating costs and expenses exclude exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. For the three months ended September 30, 2010, $25million has been reclassified from the oil and gas exploration and production segment to the midstream segment to properly reflect the previously reported amounts.

		Oil and Gas						Other and
		Exploration						Intersegment
millions		& Production		Midstream		Marketing		Eliminations		Total
Nine Months Ended September 30, 2011:
Sales revenues		$	5,668	$	238	$	4,436	$	—	$	10,342
Intersegment revenues			3,699		684		(4,066)		(317)		—
Gains (losses) on divestitures and other, net			(307)		(11)		—		104		(214)
	Total revenues and other		9,060		911		370		(213)		10,128
Operating costs and expenses(1)			2,739		575		414		163		3,891
Realized (gains) losses on derivatives, net			—		—		—		(153)		(153)
Other (income) expense, net			—		—		—		(2)		(2)
Net income attributable to
	noncontrolling interests		—		62		—		—		62
	Total expenses and other		2,739		637		414		8		3,798
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(8)		—		(8)
Adjusted EBITDAX		$	6,321	$	274	$	(52)	$	(221)	$	6,322
Nine Months Ended September 30, 2010:
Sales revenues		$	4,117	$	145	$	3,947	$	—	$	8,209
Intersegment revenues			3,259		630		(3,593)		(296)		—
Gains (losses) on divestitures and other, net			(15)		—		—		99		84
	Total revenues and other		7,361		775		354		(197)		8,293
Operating costs and expenses(1)			2,169		501		349		139		3,158
Realized (gains) losses on derivatives, net			—		—		—		(339)		(339)
Other (income) expense, net			—		—		—		(106)		(106)
Net income attributable to
	noncontrolling interests		—		42		—		—		42
	Total expenses and other		2,169		543		349		(306)		2,755
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(9)		—		(9)
Adjusted EBITDAX		$	5,192	$	232	$	(4)	$	109	$	5,529

_________________________________________________________

(1) Operating costs and expenses exclude exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. For the nine months ended September 30, 2010, $57million has been reclassified from the oil and gas exploration and production segment to the midstream segment to properly reflect the previously reported amounts.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2011
Document and Entity Information [Abstract]
Entity Registrant Name	ANADARKO PETROLEUM CORP
Entity Central Index Key	0000773910
Document Type	10-Q
Document Period End Date	Sep. 30, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	497,971,511

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Effect of Derivative Instruments - Balance Sheet Table (Detail) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Derivatives Fair Value [Line Items]
Gross derivative assets	$ 599	$ 801
Gross derivative liabilities	(1,287)	(724)
Commodity Contract [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	599	801
Gross derivative liabilities	(115)	(489)
Commodity Contract [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	428	444
Gross derivative liabilities	(81)	(274)
Commodity Contract [Member] | Other Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	166	242
Gross derivative liabilities	(9)	(56)
Commodity Contract [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	4	89
Gross derivative liabilities	(17)	(131)
Commodity Contract [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	1	26
Gross derivative liabilities	(8)	(28)
Interest Rate Contract and Other [Member]
Derivatives Fair Value [Line Items]
Gross derivative liabilities	(1,172)	(235)
Interest Rate Contract and Other [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative liabilities	(185)	(190)
Interest Rate Contract and Other [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative liabilities	$ (987)	$ (45)

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Acquisitions (Tables)

9 Months Ended

Sep. 30, 2011

Table Text Block [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

millions
Properties and equipment		$	298
Intangible assets			165
Deferred income taxes			31
Other assets			4
Other liabilities			(21)
Goodwill			362
	Total assets acquired and liabilities assumed		839
Less: Fair value of Anadarko's pre-acquisition 7% equity interest in the Wattenberg Plant			37
	Acquisition of midstream businesses		802
Loss on Anadarko's preexisting contracts with the previous Wattenberg Plant owner			76
	Total consideration paid	$	878

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Interest Rate Derivative Positions Outstanding Table (Detail) (USD $)	Dec. 31, 2009	Mar. 31, 2009	Sep. 30, 2011 Reference Period Start End Dates - October 2011 to October 2041 [Member]	Sep. 30, 2011 Reference Period Start End Dates - October 2012 to October 2022 [Member]	Sep. 30, 2011 Reference Period Start End Dates - October 2012 to October 2042 [Member]	Sep. 30, 2011 Reference Period Start End Dates - June 2014 to June 2024 [Member]	Sep. 30, 2011 Reference Period Start End Dates - June 2014 to June 2044 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap			$ 150,000,000	$ 250,000,000	$ 750,000,000	$ 750,000,000	$ 1,100,000,000
Weighted-average interest rate for interest-rate swap	4.80%	3.25%	4.65%	4.91%	4.80%	6.00%	5.57%

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Acquisitions

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Acquisitions

3.  Acquisitions

In May 2011, Anadarko increased its ownership interest in a natural-gas processing plant (Wattenberg Plant), located in northeast Colorado, by acquiring an additional 93% interest for $576 million. Anadarko operates and now owns a 100% interest in the Wattenberg Plant.

In February 2011, Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, acquired a natural-gasprocessing plant and related gathering systems (Platte Valley),located in northeast Colorado,for $302 million.

These acquisitions,along with future expansion plans,align Anadarko's natural-gas processing capacity with the Company's anticipated production growth in the Rocky Mountains Region (Rockies). In addition, these acquisitions position the Company to improve field recoveries and realize operational cost efficiencies.

The Wattenberg Plant and Platte Valley acquisitions constitute business combinations and were accounted for using the acquisition method.The following summarizes the preliminary fair value of assets acquired and liabilities assumed at the acquisition dates:

millions
Properties and equipment		$	298
Intangible assets			165
Deferred income taxes			31
Other assets			4
Other liabilities			(21)
Goodwill			362
	Total assets acquired and liabilities assumed		839
Less: Fair value of Anadarko's pre-acquisition 7% equity interest in the Wattenberg Plant			37
	Acquisition of midstream businesses		802
Loss on Anadarko's preexisting contracts with the previous Wattenberg Plant owner			76
	Total consideration paid	$	878

All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties and equipment is based on market and cost approaches. Intangible assets consist of customer contracts, the fair value of which was determined using an income approach. Deferred tax assets represent the tax effects of differences in the tax basis and acquisition-date fair values of assets acquired and liabilities assumed. Liabilities assumed include asset retirement obligations existing at the date of acquisition, and were valuedconsistent with the Company's policy for estimating its asset retirement obligations.

Assets acquired and liabilities assumed are included within the midstream reporting segment, except for $335 million of goodwill and a portion of the related deferred tax asset recognized in connection with the Wattenberg Plant acquisition, which are included in the oil and gas exploration and production reporting segment. Goodwill of $469 million related to the Wattenberg Plant acquisitionis amortizable for tax purposes.

Goodwill from these acquisitions is included in the oil and gas exploration and production reporting segment and the midstream reporting segment based on the increase in fair value to each of the respective reporting segments.The increase in fair value to these reporting segmentsis derived from improved NGLs volume retention from equity productionand the alignment of Company-controlled natural-gas processing capacity with future production growth plans in the Rockies. Goodwill is not subject to amortization, but will be subject to annualimpairment testing (or more frequent testing as circumstances dictate).At September 30, 2011, the Company had$5.6 billion of goodwill allocated as follows: $5.4 billion to oil and gas exploration and production; $102million to othergathering and processing; $59 million to WES gathering and processing; and $5 million totransportation.

Prior to the Wattenberg Plant acquisition, the Company was party to natural-gasprocessing contracts with the previous Wattenberg Plant owner. As a result of the acquisition, these preexisting contractswereterminated, causing the Company to recognize a$76 million loss,which is included in gains (losses) on divestitures and other, netin the Consolidated Statements of Income for the nine months ended September 30, 2011. This loss represents the aggregate amount by which the contractswere unfavorable as compared to current market transactions for the same or similar services at the date of the Company's acquisition of the Wattenberg Plant.

The Companyalso recognized a gain of $21 million from the acquisition-date fair-value remeasurement ofits pre-acquisition 7% equity interest in the Wattenberg Plant. The gain is included in gains (losses) on divestitures and other, net in the Consolidated Statements of Income for the nine months ended September 30, 2011.

Results of operations attributable to the Wattenberg Plant and PlatteValley acquisitions are included in the Company's Consolidated Statements of Income from the dates acquired. The amounts of revenue and earnings included in the Company's Consolidated Statements of Income for the three and nine months ended September 30, 2011, and the amounts of revenue and earnings that would have been recognized had the acquisitions occurred on January 1, 2010, are not material.

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Inventories (Tables)

9 Months Ended

Sep. 30, 2011

Table Text Block [Abstract]

Inventory Disclosure Table

	September 30,		December 31,
millions	2011		2010
Crude oil	$	133	$	126
Natural gas		34		64
NGLs		60		61
Total	$	227	$	251

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Noncontrolling Interests - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended		1 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 Western Gas Partners Limited Partnership [Member]	Mar. 31, 2011 Western Gas Partners Limited Partnership [Member]	Sep. 30, 2011 Western Gas Partners Limited Partnership [Member]	Sep. 30, 2011 Western Gas Partners Limited Partnership [Member] Limited Partner [Member]	Sep. 30, 2011 Western Gas Partners Limited Partnership [Member] General Partner [Member]
Noncontrolling Interest [Line Items]
Common units issued to the public				6	4	6
Proceeds raised from offering by subsidiary		$ 328	$ 97	$ 198	$ 130
Amount of noncontrolling interests transferred to paid-in capital upon conversion of subordinated limited partner units to common units						162
Amount recorded to paid-in capital for change in ownership interest upon equity issuance						32
Anadarko's ownership interest in Western Gas Partners, LP							43.30%	2.00%
Net income (loss) attributable to common stockholders, including increases in paid-in-capital related to sale of subsidiary units and conversion of subordinated limited partner units to common units	$ (2,857)	$ (2,097)

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Deepwater Horizon Events - Insurance and Other Recoveries (Detail) (USD $)	Sep. 30, 2011 Deepwater Horizon [Member]	Sep. 30, 2011 Deepwater Horizon [Member] Non-Operated Leasehold Interest, 25 Percent [Member] Operating Agreement [Member] Minimum [Member]	Apr. 19, 2010 Deepwater Horizon [Member] Non-Operated Leasehold Interest, 25 Percent [Member] Maximum [Member]	Oct. 16, 2011 Deepwater Horizon [Member] BP Exploration and Production Inc. [Member] BP Settlement Agreement [Member]	Oct. 16, 2011 Deepwater Horizon [Member] Maximum [Member] BP Settlement Agreement [Member]	Apr. 19, 2010 Maximum [Member]
Loss Contingencies [Line Items]
Insurance coverage for potential financial losses			$ 178,000,000			$ 710,000,000
Insurance coverage for potential financial losses, deductibles			15,000,000			60,000,000
Receivable for any potential insurance recoveries related to the Deepwater Horizon Events	0
Potential net insurance recoveries		163,000,000
Gain contingency, unrecorded amount					1,000,000,000
Third party receivable from future claims percentage				12.50%
Minimum threshold required from future claims for third party receivable				$ 1,500,000,000

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2011

Policy Text Block [Abstract]

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.

Acquisitions

The Wattenberg Plant and Platte Valley acquisitions constitute business combinations and were accounted for using the acquisition method.

All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties and equipment is based on market and cost approaches. Intangible assets consist of customer contracts, the fair value of which was determined using an income approach. Deferred tax assets represent the tax effects of differences in the tax basis and acquisition-date fair values of assets acquired and liabilities assumed. Liabilities assumed include asset retirement obligations existing at the date of acquisition, and were valuedconsistent with the Company's policy for estimating its asset retirement obligations.

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Debt and Interest Expense

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Debt and Interest Expense

8.  Debt and Interest Expense

Debt   The following presents the Company's outstanding debt and capital lease obligations. All of the Company's outstanding debt is senior unsecured.

	September 30, 2011						December 31, 2010
			Carrying		Fair				Carrying		Fair
millions	Principal		Value		Value		Principal		Value		Value
Long-term notes and debentures	$	13,952	$	12,226	$	13,752	$	14,237	$	12,488	$	13,459
WES borrowings		500		494		503		299		299		299
Total borrowings	$	14,452	$	12,720	$	14,255	$	14,536	$	12,787	$	13,758
Capital lease obligations		229		229		N/A		226		226		N/A
Less: Current portion of long-term debt		141		141		134		289		291		296
Total long-term debt	$	14,540	$	12,808	$	14,121	$	14,473	$	12,722	$	13,462

Debt Activity   The following presentsthe Company's debt activity duringthe nine months ended September 30, 2011.

				Carrying
millions		Principal		Value		Description
Balance at December 31, 2010		$	14,536	$	12,787
	Borrowings		560		560	WES credit facility
	Repayments(1)		(389)		(389)	WES credit facility and WES term loan
	Other, net		—		8	Changes in debt premium or discount
Balance at March 31, 2011		$	14,707	$	12,966
	Issuance		500		494	WES 5.375% Senior Notes due 2021
	Repayments(1)		(470)		(470)	WES credit facility
	Other, net		—		8	Changes in debt premium or discount
Balance at June 30, 2011		$	14,737	$	12,998
	Borrowings		10		10	WES credit facility
	Repayments(1)		(285)		(285)	6.875% Senior Notes due 2011
			(10)		(10)	WES credit facility
	Other, net		—		7	Changes in debt premium or discount
Balance at September 30, 2011		$	14,452	$	12,720

__________________________________________________________________________

(1)Debt repayment activity includes both scheduled repayments and retirements before scheduled maturity.

Anadarko Revolving Credit Facility and Letter of Credit FacilityDuringthe third quarter of 2011, the Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit (the LOC Facility). Compensating balances deposited at the financial institution provide for reduced fees under the LOC Facility. These compensating balances may be withdrawn at any time, resulting in higher fees under the LOC Facility. At September 30, 2011, cash and cash equivalents includes $325 million of demand deposits serving as compensating balances. The LOC Facility also requires the Company to maintain a senior debt revolving credit facility with minimum commitments of at least $1.0 billion and the availability to issue letters of credit of at least $400 million.

In August 2011, the Company amended the $5.0 billion Facility to reduce the maintenance costs and to lower the interest rates under the facility. At September 30, 2011, the $5.0 billion Facility was undrawn with available capacity of $4.6 billion ($5.0 billion undrawn capacity, less $400 million of letter-of-credit capacity maintained pursuant to the terms of the LOC Facility).

WES Revolving Credit FacilityDuring the first quarter of 2011, WES borrowed $310 million under its $450 million senior unsecured revolving credit facility, primarily to fund the Platte Valley acquisition. In March 2011, WES entered into a five-year, $800 million senior unsecured revolving credit facility (RCF), which amended and restatedthe $450 million senior unsecured revolving credit facility, andborrowed $250 million under the RCF to repay a senior unsecured term loan.Also during the first quarter of 2011, WES repaid $139 million of borrowings under its RCF primarily from proceeds related to its public offering of four million common units, which raised net proceeds of $130 million.During the second quarter of 2011, WES repaid the outstanding RCF borrowings with net proceeds from the public offering of $500 million 5.375% Senior Notes due 2021. At September 30, 2011, WES was in compliance with all covenants contained in the RCF, had no outstanding borrowings under the RCF, and had the full $800 million of RCF borrowing capacity available.

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

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
millions		2011		2010		2011		2010
Current debt, long-term debt, and other(1)		$	245	$	235	$	743	$	642
Loss on early debt retirements and commitment
	termination(2)		—		17		—		89
Capitalized interest			(39)		(34)		(101)		(89)
Interest expense		$	206	$	218	$	642	$	642

__________________________________________________________________________

(1)Included in the three and ninemonths ended September 30, 2010, is $7 million and $9 million, respectively, of unamortized debt issuance costs associated with the retirement of the midstream subsidiary note payable to a related party (Midstream Subsidiary Note).

(2)Loss on early debt retirements in 2010 is the result of repurchasing $1.0 billion aggregate principal amount of debt due 2011 and 2012. Also included in the three and ninemonths ended September 30, 2010, is $17 million for commitment and structuring costs associated with a contemplated term-loan facility.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Statement of Comprehensive Income
Reclassification of previously deferred derivative losses to net income, income tax benefit (expense)	$ (1)	$ (2)	$ (4)	$ (7)
Net gain (loss) incurred during period, income tax benefit (expense)				12
Prior service credit (cost) incurred during period, income tax benefit (expense)				2
Amortization of net actuarial loss and prior service cost to net periodic benefit cost, income tax benefit (expense)	$ (8)	$ (5)	$ (24)	$ (17)

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Deepwater Horizon Events - Background, Settlement, and BP Indemnification (Detail) (USD $)	18 Months Ended	11 Months Ended
	Oct. 16, 2011 Deepwater Horizon [Member] Operating Agreement [Member] BP Exploration and Production Inc. [Member]	Nov. 30, 2011 Deepwater Horizon [Member] BP Settlement Agreement [Member]	Sep. 30, 2011 Macondo Exploration Well [Member]
Loss Contingencies [Line Items]
Percentage of Anadarko's holding of non-operating leasehold interest			25.00%
Amounts invoiced to Anadarko by BP for costs related to the Deepwater Horizon incident	$ 6,100,000,000
Payments for Deepwater Horizon settlement costs		$ 4,000,000,000

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Properties and Equipment

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Properties and Equipment

5.  Properties and Equipment

Suspended Exploratory Drilling CostsThe Company's capitalized suspended well costs at September 30, 2011, and December 31, 2010, were $1.2billion and $935 million, respectively. The increase in suspended exploratory drilling costs during 2011 primarily relates to the capitalization of costs associated with successful exploration drilling inMozambique, Ghana and Brazil.For the nine months ended September 30, 2011, $32 million of exploratory well costs previously capitalized as suspended well costs for greater than one year were charged to dry hole expense and $116 million of capitalized suspended well costs were reclassified to proved properties.

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

ImpairmentsImpairment expense for the three and nine months ended September 30, 2011, was $183 million and $287 million, respectively. During the third quarter of 2011, the Company recognized impairments of $93 million related to United States offshore properties and $87 millionrelated to the Company's investment in Venezuelan assets due to changes in expected recoverable reserves in these areas. At September 30, 2011, the Company's after-tax net investment in the Venezuelan assets was $38million. During the second quarter of 2011, the Company recognized impairments of $100 millionrelated to United States onshore properties due toa change in projected cash flowsresulting from the Company's intent to divest of the properties. All of these assets are included in the oil and gas exploration and production operating segment and were impaired to fair value, estimated using Level 3 fair-value inputs.

Impairment expense for the three and nine months ended September 30, 2010, was $20 million and $147 million, respectively, including $114 million recognized in the second quarter of 2010 related to a production platform included in the oil and gas exploration and production operating segment that remains idle with no identifiable plans for use, and for which a limited market currently exists. The platform was impaired to fair value, estimated using Level 3 fair-value inputs.

Assets Held for SaleDuringthe third quarter of 2011, the Company began marketing certain onshore domestic properties from both the oil and gas exploration and productionoperatingsegment andthe other midstreamoperating segment in order to redirect its operating activities and capital to other areas. At September 30, 2011, net properties and equipment, goodwill and other intangible assets, and other long-term liabilities on the Company's Consolidated Balance Sheets included $273 million, $42 million, and $6 million, respectively, associated with assets held for sale. The Company also recognized losseson assets held for sale of $268 million related to oil and gas exploration and production operating segment properties and $31 million related to other midstream operating segment properties. The assets were impaired to fair value, estimated using Level 3 fair-value inputs, with resulting lossesincluded in gains (losses) on divestitures and other, net in the Consolidated Statements of Income for the three and nine months ended September 30, 2011.

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Commitments

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Commitments

10.  Commitments

In May 2011, Anadarko entered into two five-year lease agreements for deepwater drilling rigs. The rigs are expected to be delivered in late 2013 and early 2014. The lease obligations total approximately $1.2 billion, withaggregate future annual minimum lease payments of $30 million in 2013, $209 million in 2014, $238 millionin 2015, and$715 million for the remaining lease term.

In October 2011, the Company and BP entered into the Settlement Agreement, pursuant to which the Company has agreed to pay $4.0 billion in cash and transfer its interest in the Lease to BP (subject to required governmental approvals of the transfer), and BP has agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued to date and to forgo reimbursement for all future costs arising from the Deepwater Horizon events, including future costs under the OA. In addition, BP has fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related OPA damage claims, NRD claims and associated damage-assessment costs, and any claims arising under the OA. This indemnification has been guaranteed by 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.See Note 2 for additional information.

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Noncontrolling Interests

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Noncontrolling Interests

6.  Noncontrolling Interests

InMarch and September2011, WES issued approximately four million and six million common units to the public, respectively, raising net proceeds of $130 million and $198 million, respectively, which increased the noncontrolling interest component of total equity.

In August 2011, the WES subordinated limited partner units held by Anadarko converted to common limited partner units on a one-for-one basis. Upon this conversion, $162 millionrelated to pre-conversion changes in the Company's ownership interest in WES was transferred from noncontrolling interests to paid-in capital. Additionally, $32 millionwas recorded to paid-in capital as a result of WES's third-quarter issuance of common units. The Company's net income (loss) attributable to common stockholders, together with the above-described increasesto Anadarko's paid-in capital, for the threeand nine months ended September 30, 2011, totaled $(2,857) million and $(2,097) million, respectively. At September 30, 2011, Anadarko's ownership interest in WES consists of a 43.3% limited partner interest, a 2% general partner interest, and incentive distribution rights.

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2011

Table Text Block [Abstract]

Supplemental Cash Flow Table

			Nine Months Ended
			September 30,
millions			2011		2010
Cash paid:
	Interest		$	708	$	579
	Income taxes		$	238	$	209
Non-cash investing activities:
	Fair value of properties and equipment received in non-cash exchange transactions		$	4	$	32
	Gain related to the fair-value remeasurement of Anadarko's pre-acquisition 7% equity
		interest in the Wattenberg Plant	$	21	$	—

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Inventories

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Inventories

4.  Inventories

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

	September 30,		December 31,
millions	2011		2010
Crude oil	$	133	$	126
Natural gas		34		64
NGLs		60		61
Total	$	227	$	251

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Debt Activity Table (Detail) (USD $) In Millions, unless otherwise specified					3 Months Ended
	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Jun. 30, 2011 Western Gas Partners Limited Partnership [Member] Debt Outstanding Principal Amount [Member] Senior Notes, 5 Point 375 Percent, Due 2021 [Member]	Mar. 31, 2011 Western Gas Partners Limited Partnership [Member] Debt Outstanding Principal Amount [Member] Credit facility and term loan [Member]		Sep. 30, 2011 Western Gas Partners Limited Partnership [Member] Debt Outstanding Principal Amount [Member] Credit facility [Member]		Jun. 30, 2011 Western Gas Partners Limited Partnership [Member] Debt Outstanding Principal Amount [Member] Credit facility [Member]		Mar. 31, 2011 Western Gas Partners Limited Partnership [Member] Debt Outstanding Principal Amount [Member] Credit facility [Member]	Sep. 30, 2011 Debt Outstanding Principal Amount [Member] Senior Notes, 6 Point 875 Percent, Due 2011 [Member]		Jun. 30, 2011 Western Gas Partners Limited Partnership [Member] Debt Outstanding Carrying Amount [Member] Senior Notes, 5 Point 375 Percent, Due 2021 [Member]	Mar. 31, 2011 Western Gas Partners Limited Partnership [Member] Debt Outstanding Carrying Amount [Member] Credit facility and term loan [Member]		Sep. 30, 2011 Western Gas Partners Limited Partnership [Member] Debt Outstanding Carrying Amount [Member] Credit facility [Member]		Jun. 30, 2011 Western Gas Partners Limited Partnership [Member] Debt Outstanding Carrying Amount [Member] Credit facility [Member]		Mar. 31, 2011 Western Gas Partners Limited Partnership [Member] Debt Outstanding Carrying Amount [Member] Credit facility [Member]	Sep. 30, 2011 Debt Outstanding Carrying Amount [Member]	Jun. 30, 2011 Debt Outstanding Carrying Amount [Member]	Mar. 31, 2011 Debt Outstanding Carrying Amount [Member]	Sep. 30, 2011 Debt Outstanding Carrying Amount [Member] Senior Notes, 6 Point 875 Percent, Due 2011 [Member]		Sep. 30, 2011 Western Gas Partners Limited Partnership [Member] Long-term debt [Member]	Dec. 31, 2010 Western Gas Partners Limited Partnership [Member] Long-term debt [Member]	Sep. 30, 2011 Long-term debt [Member]	Jun. 30, 2011 Long-term debt [Member]	Mar. 31, 2011 Long-term debt [Member]	Dec. 31, 2010 Long-term debt [Member]	Jun. 30, 2011 Western Gas Partners Limited Partnership [Member] Senior Notes, 5 Point 375 Percent, Due 2021 [Member]	Sep. 30, 2011 Senior Notes, 6 Point 875 Percent, Due 2011 [Member]	Sep. 30, 2011 Western Gas Partners Limited Partnership [Member]	Dec. 31, 2010 Western Gas Partners Limited Partnership [Member]
Debt Instrument [Line Items]
Principal amount, beginning balance																												$ 500	$ 299	$ 14,452	$ 14,737	$ 14,707	$ 14,536
Carrying amount, beginning balance	12,720	12,998	12,966	12,787																																494	299
Issuance					500										494
Borrowings								10				560						10				560
Repayments						(389)	[1]	(10)	[1]	(470)	[1]		(285)	[1]		(389)	[1]	(10)	[1]	(470)	[1]					(285)	[1]
Other, net																							7	8	8
Principal amount, ending balance																												500	299	14,452	14,737	14,707	14,536
Carrying amount, ending balance	$ 12,720	$ 12,998	$ 12,966	$ 12,787																																$ 494	$ 299
Debt instrument, interest rate, stated percentage																																		5.375%	6.875%

[1] Debt repayment activity includes both scheduled repayments and retirements before scheduled maturity.

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CONSOLIDATED STATEMENT OF EQUITY (Parenthetical) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011
Paid-in Capital [Member]
Sale of subsidiary units, tax	$ 18
Conversion of subordinated limited partner units to common units, tax	82
Noncontrolling Interests [Member]
Sale of subsidiary units, tax	9
Conversion of subordinated limited partner units to common units, tax	$ (82)

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions	9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010
Cash Flows from Operating Activities
Net income (loss)	$ (2,229)		$ 692
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	2,902		2,845
Deferred income taxes	(1,195)		(142)
Dry hole expense and impairments of unproved properties	423		473
Impairments	287		147
(Gains) losses on divestitures, net	243		(12)
Unrealized (gains) losses on derivatives, net	767		(66)
Deepwater Horizon settlement and related costs	4,055	[1]	2	[1]
Other	151		145
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(939)		15
Increase (decrease) in accounts payable and accrued expenses	215		(293)
Other items - net	(88)		126
Net cash provided by (used in) operating activities	4,592		3,932
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	(4,110)		(3,563)
Acquisition of midstream businesses	(802)
Divestitures of properties and equipment and other assets	75		44
Other - net	(52)		(30)
Net cash provided by (used in) investing activities	(4,889)		(3,549)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	1,051		3,199
Repayments of debt	(1,154)		(1,173)
Repayment of midstream subsidiary note payable to a related party			(1,599)
Increase (decrease) in accounts payable, banks	39		(70)
Dividends paid	(135)		(136)
Repurchase of common stock	(31)		(35)
Issuance of common stock, including tax benefit on stock option exercises	57		90
Sale of subsidiary units	328		97
Distributions to noncontrolling interest owners	(57)		(36)
Other financing activities	9		(24)
Net cash provided by (used in) financing activities	107		313
Effect of Exchange Rate Changes on Cash	(3)		(9)
Net Increase (Decrease) in Cash and Cash Equivalents	(193)		687
Cash and Cash Equivalents at Beginning of Period	3,680		3,531
Cash and Cash Equivalents at End of Period	$ 3,487		$ 4,218

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

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Acquisitions Purchase Price Allocation Table (Detail) (USD $) In Millions	May 31, 2011
Business Combinations [Abstract]
Properties and equipment	$ 298
Intangible assets	165
Deferred income taxes	31
Other assets	4
Other liabilities	(21)
Goodwill	362
Total assets acquired and liabilities assumed	839
Less: Fair value of Anadarko's pre-acquisition 7% equity interest in the Wattenberg Plant	37
Acquisition of midstream businesses	802
Loss on Anadarko's preexisting contracts with the previous Wattenberg Plant owner	76
Total consideration paid	$ 878

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2011

Table Text Block [Abstract]

Schedule of Income Taxes and Effective Tax Rate Table

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions except percentages	2011			2010			2011			2010
Income tax expense (benefit)	$	(1,468)		$	94		$	(762)		$	660
Effective tax rate		33	%		109	%		25	%		49	%

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Contingencies - Wright (Detail) (Wright Litigation [Member], USD $)	6 Months Ended
	Jun. 30, 2011
Wright Litigation [Member]
Commitments and Contingencies Disclosure [Abstract]
Payment for Wright litigation settlement	$ 19,000,000

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Contingencies - Deepwater Drilling Moratorium and Other Related Matters (Detail) (Disputed rig rental cost, contract-termination through March 2011 [Member], USD $)	Sep. 30, 2011
Disputed rig rental cost, contract-termination through March 2011 [Member]
Loss Contingencies [Line Items]
Maximum possible loss from contingency	$ 116,000,000
Loss contingency accrual at carrying value	$ 0

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Outstanding Debt and Capital Lease Obligations Table (Detail) (USD $) In Millions	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010
Debt Instrument [Line Items]
Total borrowings	$ 12,720	$ 12,998	$ 12,966	$ 12,787
Capital lease obligations	229			226
Less: Current portion of long-term debt	141			291
Total long-term debt	12,808			12,722
Long-term notes and debentures [Member]
Debt Instrument [Line Items]
Principal	13,952			14,237
Total borrowings	12,226			12,488
Fair Value	13,752			13,459
Western Gas Partners Limited Partnership [Member] | Total borrowings
Debt Instrument [Line Items]
Principal	500			299
Fair Value	503			299
Total borrowings
Debt Instrument [Line Items]
Principal	14,452	14,737	14,707	14,536
Fair Value	14,255			13,758
Capital lease obligations [Member]
Debt Instrument [Line Items]
Principal	229			226
Current portion of long-term debt [Member]
Debt Instrument [Line Items]
Principal	141			289
Fair Value	134			296
Noncurrent portion of long-term debt [Member]
Debt Instrument [Line Items]
Principal	14,540			14,473
Fair Value	14,121			13,462
Western Gas Partners Limited Partnership [Member]
Debt Instrument [Line Items]
Total borrowings	$ 494			$ 299

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Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) before Income Taxes Table (Detail) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) before Income Taxes [Abstract]
Income (loss) before income taxes	$ (4,496)		$ 86		$ (2,991)		$ 1,352
Exploration expense	307		296		722		649
DD&A	932		962		2,902		2,845
Impairments	183		20		287		147
Deepwater Horizon settlement and related costs	4,042	[1]	2	[1]	4,055	[1]	2	[1]
Interest expense	206		218		642		642
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net					767		(66)
Less: Net income attributable to noncontrolling interests	23		18		62		42
Consolidated Adjusted EBITDAX	1,843		1,740		6,322		5,529
Nondesignated [Member]
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net	$ 692	[2]	$ 174	[2]	$ 767	[2]	$ (66)	[2]

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

[2] In the fourth quarter of 2010, the Company revised the definition of Adjusted EBITDAX to exclude the impact of unrealized (gains) losses on derivative instruments, net. The prior periods have been adjusted to reflect this change.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Summary of Significant Accounting Policies

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 September 30, 2011, and December 31, 2010, the Consolidated Statements of Income and Comprehensive Income for the three and nine months ended September 30, 2011 and 2010, the Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010, and the Consolidated Statement of Equity for the nine months ended September 30, 2011. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

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.

Recently Issued Accounting Standards Not Yet Adopted   The Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that further addresses fair-value-measurement accounting and related disclosure requirements. The ASU clarifies the FASB's intent regarding the application of existing fair-value-measurement accounting and disclosure requirements,changes fair-value-measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair-value measurements. The ASU is required to be adopted on a prospective basis by Anadarko beginning January 1, 2012. The Company does not expect adoption of this ASU to have an impact on its consolidated financial statements, other than requiring revised disclosures, where appropriate.

In September 2011, the FASB issued an ASU that permits an initial assessment of qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount for goodwill impairment testing purposes. Thus, determining a reporting unit's fair value is not required unless, as a result of a qualitative assessment, it is more likely than not that the fair value of the reporting unit is less than its carrying amount. This ASU is effective for periods beginning after December 15, 2011. Adoption of this ASU will have no impact on the Company's consolidated financial statements.

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Properties and Equipment - Additional Information (Detail) (USD $) In Millions	3 Months Ended		9 Months Ended			9 Months Ended	3 Months Ended			9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010	Sep. 30, 2011 Greater than one year [Member]	Sep. 30, 2011 Oil and Gas Exploration and Production Operating Segment [Member]	Jun. 30, 2011 Oil and Gas Exploration and Production Operating Segment [Member]	Jun. 30, 2010 Oil and Gas Exploration and Production Operating Segment [Member]	Sep. 30, 2010 Oil and Gas Exploration and Production Operating Segment [Member]	Sep. 30, 2011 Other Midstream Operating Segment [Member]
Property, Plant, and Equipment [Abstract]
Capitalized suspended well costs	$ 1,200		$ 1,200		$ 935
Capitalized suspended well costs reclassified to proved properties			116
Impairment expense	183	20	287	147
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						32
Impairment of oil and gas properties							93	100	114	114
Impairments related to investment in Venezuelan assets							87
After-tax net investment in the Venezuelan assets							38
Losses on assets held for sale							268				31
Net properties and equipment associated with assets held for sale	273		273
Goodwill and other intangible assets associated with assets held for sale	42		42
Other long-term liabilities associated with assets held for sale	$ 6		$ 6

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2011

Table Text Block [Abstract]

Schedule of Derivative Instruments

		2011		2012		2013
Natural Gas
	Three-Way Collars (thousand MMBtu/d)		480		500		450
	Average price per MMBtu
	Ceiling sold price (call)	$	8.29	$	9.03	$	6.57
	Floor purchased price (put)	$	6.50	$	6.50	$	5.00
	Floor sold price (put)	$	5.00	$	5.00	$	4.00
	Fixed-Price Contracts (thousand MMBtu/d)		90		—		—
	Average price per MMBtu	$	6.17	$	—	$	—
	Basis Swaps (thousand MMBtu/d)		45		—		—
	Average price per MMBtu	$	(1.74)	$	—	$	—
MMBtu—million British thermal units
MMBtu/d—million British thermal units per day

		2011		2012
Crude Oil
	Three-Way Collars (MBbls/d)		126		2
	Average price per barrel
	Ceiling sold price (call)	$	99.95	$	92.50
	Floor purchased price (put)	$	79.29	$	50.00
	Floor sold price (put)	$	64.29	$	35.00
MBbls/d—thousand barrels per day

millions except percentages		Reference Period		Weighted-Average
Notional Principal Amount:		Start	End	Interest Rate
$	150	October 2011	October 2041	4.65	%
$	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	Balance Sheet	September 30,		December 31,		September 30,		December 31,
Derivatives	Classification	2011		2010		2011		2010
Commodity
	Other Current Assets	$	428	$	444	$	(81)	$	(274)
	Other Assets		166		242		(9)		(56)
	Accrued Expenses		4		89		(17)		(131)
	Other Liabilities		1		26		(8)		(28)
			599		801		(115)		(489)
Interest Rate and Other
	Accrued Expenses		—		—		(185)		(190)
	Other Liabilities		—		—		(987)		(45)
			—		—		(1,172)		(235)
Total Derivatives		$	599	$	801	$	(1,287)	$	(724)

			(Gain) Loss
			Three Months Ended						Nine Months Ended
millions		Classification of (Gain)	September 30, 2011						September 30, 2011
Derivatives		Loss Recognized	Realized		Unrealized		Total		Realized		Unrealized		Total
Commodity
		Gathering, Processing,
		and Marketing Sales(1)	$	1	$	(3)	$	(2)	$	17	$	(8)	$	9
		(Gains) Losses on Commodity
		Derivatives, net		(71)		(159)		(230)		(155)		(162)		(317)
Interest Rate
	and Other
		(Gains) Losses on Other
		Derivatives, net		—		854		854		2		937		939
Derivative (Gain) Loss, net			$	(70)	$	692	$	622	$	(136)	$	767	$	631

			(Gain) Loss
			Three Months Ended						Nine Months Ended
millions		Classification of (Gain)	September 30, 2010						September 30, 2010
Derivatives		Loss Recognized	Realized		Unrealized		Total		Realized		Unrealized		Total
Commodity
		Gathering, Processing,
		and Marketing Sales(1)	$	—	$	(4)	$	(4)	$	1	$	(9)	$	(8)
		(Gains) Losses on Commodity
		Derivatives, net		(157)		(43)		(200)		(339)		(713)		(1,052)
Interest Rate
	and Other
		(Gains) Losses on Other
		Derivatives, net		—		221		221		—		656		656
Derivative (Gain) Loss, net			$	(157)	$	174	$	17	$	(338)	$	(66)	$	(404)

__________________________________________________________________________

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

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

September 30, 2011
millions			Level 1		Level 2		Level 3		Netting (1)		Collateral		Total
Assets:
	Commodity derivatives
		Financial institutions	$	2	$	466	$	—	$	(84)	$	(5)	$	379
		Other counterparties		—		131		—		(11)		—		120
	Interest-rate and other derivatives			—		—		—		—		—		—
Total derivative assets			$	2	$	597	$	—	$	(95)	$	(5)	$	499
Liabilities:
	Commodity derivatives
		Financial institutions	$	(3)	$	(88)	$	—	$	84	$	5	$	(2)
		Other counterparties		—		(24)		—		11		—		(13)
	Interest-rate and other derivatives			—		(1,172)		—		—		110		(1,062)
Total derivative liabilities			$	(3)	$	(1,284)	$	—	$	95	$	115	$	(1,077)

__________________________________________________________________________

(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.

December 31, 2010
millions			Level 1		Level 2		Level 3		Netting (1)		Collateral		Total
Assets:
	Commodity derivatives
		Financial institutions	$	3	$	557	$	—	$	(298)	$	(15)	$	247
		Other counterparties		—		241		—		(148)		—		93
Total derivative assets			$	3	$	798	$	—	$	(446)	$	(15)	$	340
Liabilities:
	Commodity derivatives
		Financial institutions	$	(2)	$	(333)	$	—	$	298	$	—	$	(37)
		Other counterparties		—		(154)		—		148		—		(6)
	Interest-rate and other derivatives			—		(235)		—		—		15		(220)
Total derivative liabilities			$	(2)	$	(722)	$	—	$	446	$	15	$	(263)

__________________________________________________________________________

(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 - Additional Information (Detail) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011
Pension Plans, Defined Benefit [Member] | Funded Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 269
Expected employer contributions during the remainder of 2011	3
Pension Plans, Defined Benefit [Member] | Unfunded Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	8
Expected employer contributions during the remainder of 2011	21
Other Postretirement Benefit Plans, Defined Benefit [Member] | Unfunded Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	13
Expected employer contributions during the remainder of 2011	$ 5

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Income Taxes - Additional Information (Detail)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income Tax Disclosure [Abstract]
Statutory tax rate	35.00%	35.00%	35.00%	35.00%

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2011

Table Text Block [Abstract]

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
millions	2011		2010		2011		2010
Income (loss) before income taxes	$	(4,496)	$	86	$	(2,991)	$	1,352
Exploration expense		307		296		722		649
DD&A		932		962		2,902		2,845
Impairments		183		20		287		147
Deepwater Horizon settlement and related costs(1)		4,042		2		4,055		2
Interest expense		206		218		642		642
Unrealized (gains) losses on derivative instruments, net(2)		692		174		767		(66)
Less: Net income attributable to noncontrolling interests		23		18		62		42
Consolidated Adjusted EBITDAX	$	1,843	$	1,740	$	6,322	$	5,529

_________________________________________________________

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

(2)In the fourth quarter of 2010, the Company revised the definition of Adjusted EBITDAX to exclude the impact of unrealized (gains) losses on derivative instruments, net. The 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 September 30, 2011:
Sales revenues		$	1,801	$	76	$	1,507	$	—	$	3,384
Intersegment revenues			1,244		251		(1,386)		(109)		—
Gains (losses) on divestitures and other, net			(193)		(31)		—		39		(185)
	Total revenues and other		2,852		296		121		(70)		3,199
Operating costs and expenses(1)			955		210		143		53		1,361
Realized (gains) losses on derivatives, net			—		—		—		(71)		(71)
Other (income) expense, net			—		—		—		40		40
Net income attributable to
	noncontrolling interests		—		23		—		—		23
	Total expenses and other		955		233		143		22		1,353
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(3)		—		(3)
Adjusted EBITDAX		$	1,897	$	63	$	(25)	$	(92)	$	1,843
Three Months Ended September 30, 2010:
Sales revenues		$	1,318	$	45	$	1,153	$	—	$	2,516
Intersegment revenues			950		198		(1,051)		(97)		—
Gains (losses) on divestitures and other, net			(3)		—		—		37		34
	Total revenues and other		2,265		243		102		(60)		2,550
Operating costs and expenses(1)			723		152		116		83		1,074
Realized (gains) losses on derivatives, net			—		—		—		(157)		(157)
Other (income) expense, net			—		—		—		(129)		(129)
Net income attributable to
	noncontrolling interests		—		18		—		—		18
	Total expenses and other		723		170		116		(203)		806
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(4)		—		(4)
Adjusted EBITDAX		$	1,542	$	73	$	(18)	$	143	$	1,740

_________________________________________________________

(1) Operating costs and expenses exclude exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. For the three months ended September 30, 2010, $25million has been reclassified from the oil and gas exploration and production segment to the midstream segment to properly reflect the previously reported amounts.

		Oil and Gas						Other and
		Exploration						Intersegment
millions		& Production		Midstream		Marketing		Eliminations		Total
Nine Months Ended September 30, 2011:
Sales revenues		$	5,668	$	238	$	4,436	$	—	$	10,342
Intersegment revenues			3,699		684		(4,066)		(317)		—
Gains (losses) on divestitures and other, net			(307)		(11)		—		104		(214)
	Total revenues and other		9,060		911		370		(213)		10,128
Operating costs and expenses(1)			2,739		575		414		163		3,891
Realized (gains) losses on derivatives, net			—		—		—		(153)		(153)
Other (income) expense, net			—		—		—		(2)		(2)
Net income attributable to
	noncontrolling interests		—		62		—		—		62
	Total expenses and other		2,739		637		414		8		3,798
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(8)		—		(8)
Adjusted EBITDAX		$	6,321	$	274	$	(52)	$	(221)	$	6,322
Nine Months Ended September 30, 2010:
Sales revenues		$	4,117	$	145	$	3,947	$	—	$	8,209
Intersegment revenues			3,259		630		(3,593)		(296)		—
Gains (losses) on divestitures and other, net			(15)		—		—		99		84
	Total revenues and other		7,361		775		354		(197)		8,293
Operating costs and expenses(1)			2,169		501		349		139		3,158
Realized (gains) losses on derivatives, net			—		—		—		(339)		(339)
Other (income) expense, net			—		—		—		(106)		(106)
Net income attributable to
	noncontrolling interests		—		42		—		—		42
	Total expenses and other		2,169		543		349		(306)		2,755
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		(9)		—		(9)
Adjusted EBITDAX		$	5,192	$	232	$	(4)	$	109	$	5,529

_________________________________________________________

(1) Operating costs and expenses exclude exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. For the nine months ended September 30, 2010, $57million has been reclassified from the oil and gas exploration and production segment to the midstream segment to properly reflect the previously reported amounts.

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Major Classes of Inventories (Detail) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Energy Related Inventory [Abstract]
Crude oil	$ 133	$ 126
Natural gas	34	64
NGLs	60	61
Total	$ 227	$ 251

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Stockholders' Equity (Tables)

9 Months Ended

Sep. 30, 2011

Table Text Block [Abstract]

Earnings Per Share Table

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
millions except per-share amounts		2011		2010		2011		2010
Income (loss):
	Net income (loss) attributable to common stockholders	$	(3,051)	$	(26)	$	(2,291)	$	650
	Less: Distributions on participating securities		—		—		—		1
	Less: Undistributed income allocated to participating securities		—		—		—		4
Basic		$	(3,051)	$	(26)	$	(2,291)	$	645
Diluted		$	(3,051)	$	(26)	$	(2,291)	$	645
Shares:
	Average number of common shares outstanding—basic		498		496		498		495
	Dilutive effect of stock options and
	performance-based stock awards		—		—		—		1
	Average number of common shares outstanding—diluted		498		496		498		496
	Excluded (1)		12		12		12		6
Income (loss) per common share:
	Basic	$	(6.12)	$	(0.05)	$	(4.60)	$	1.30
	Diluted	$	(6.12)	$	(0.05)	$	(4.60)	$	1.30
	Dividends per common share	$	0.09	$	0.09	$	0.27	$	0.27

_________________________________________________________

(1)Inclusion of the average shares for these awards would have had an anti-dilutive effect.

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Stockholders' Equity

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Stockholders' Equity

9.  Stockholders' Equity

       The reconciliation between basic and diluted EPS from continuing operations attributable to common stockholders is as follows:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
millions except per-share amounts		2011		2010		2011		2010
Income (loss):
	Net income (loss) attributable to common stockholders	$	(3,051)	$	(26)	$	(2,291)	$	650
	Less: Distributions on participating securities		—		—		—		1
	Less: Undistributed income allocated to participating securities		—		—		—		4
Basic		$	(3,051)	$	(26)	$	(2,291)	$	645
Diluted		$	(3,051)	$	(26)	$	(2,291)	$	645
Shares:
	Average number of common shares outstanding—basic		498		496		498		495
	Dilutive effect of stock options and
	performance-based stock awards		—		—		—		1
	Average number of common shares outstanding—diluted		498		496		498		496
	Excluded (1)		12		12		12		6
Income (loss) per common share:
	Basic	$	(6.12)	$	(0.05)	$	(4.60)	$	1.30
	Diluted	$	(6.12)	$	(0.05)	$	(4.60)	$	1.30
	Dividends per common share	$	0.09	$	0.09	$	0.27	$	0.27

_________________________________________________________

(1)Inclusion of the average shares for these awards would have had an anti-dilutive effect.

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Reconciliation between Basic and Diluted EPS Table (Detail) (USD $) In Millions, except Per Share data	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Income (loss):
Net income (loss) attributable to common stockholders	$ (3,051)		$ (26)		$ (2,291)		$ 650
Less: Distributions on participating securities							1
Less: Undistributed income allocated to participating securities							4
Basic	(3,051)		(26)		(2,291)		645
Diluted	$ (3,051)		$ (26)		$ (2,291)		$ 645
Shares:
Average number of common shares outstanding - basic	498		496		498		495
Dilutive effect of stock options and performance-based stock awards							1
Average number of common shares outstanding - diluted	498		496		498		496
Excluded	12	[1]	12	[1]	12	[1]	6	[1]
Income (loss) per common share:
Basic	$ (6.12)		$ (0.05)		$ (4.60)		$ 1.30
Diluted	$ (6.12)		$ (0.05)		$ (4.60)		$ 1.30
Dividends per common share	$ 0.09		$ 0.09		$ 0.27		$ 0.27

[1] Inclusion of the average shares for these awards would have had an anti-dilutive effect.

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Summary of Income Tax Expense (Benefit) and Effective Tax Rates Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income Tax Expense (Benefit) [Abstract]
Income tax expense (benefit)	$ (1,468)	$ 94	$ (762)	$ 660
Effective tax rate	33.00%	109.00%	25.00%	49.00%

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Deepwater Horizon Events

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Deepwater Horizon Events

2.  Deepwater Horizon Events

Background, Settlement, and BP IndemnificationIn April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating leasehold interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. The Macondo well was plugged on September 19, 2010.

BP Exploration & Production Inc. (BP), the operator of Mississippi Canyon Block 252 in which the Macondo well is located (Lease), is funding claims and coordinating cleanup efforts. BP invoiced the Company $6.1 billion for what BP considered to be Anadarko's proportionate share of actual costs and anticipated near-term future costs related to these activities. Anadarkowithheld payment to BP for all Deepwater Horizon event-related invoices pending the completion of various ongoing investigations into and litigation regarding the cause of the well blowout, explosion, and subsequent release of hydrocarbons.

In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify, whereby the Company and BP agreed to a mutual release of claims against each other relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company has agreed to pay $4.0 billion in cash and transfer its interest in the Lease to BP (subject to required governmental approvals of the transfer), and BP has agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued to date and to forgo reimbursement for all future costs arising from the Deepwater Horizon events, including future costs under the Operating Agreement (OA). In addition, BP has fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related 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 OA. This indemnification has been 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. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder, derivative, or security laws claims, or certain other claims. The Company believes that costs associated with non-indemnified items, individually or in the aggregate, will not materially impact the Company's consolidated financial position, results of operations, or cash flows.

Liability AccrualAs of September 30, 2011, the Company has recorded a liability for Deepwater Horizon-related settlement costs of approximately $4.0 billion, which includes the cash payment to be remitted to BP in accordance with the Settlement Agreement, as well as Deepwater Horizon event-related legal fees. These legal fees were previously recorded in general and administrative expenses in the Consolidated Statements of Income and have been reclassified for all periods presented to conform to the current-period presentation.

Below is a discussion of the Company's current analysis, under applicable accounting guidance, of its potential liability for (i) amounts invoiced by BP under the OA (OA Liabilities), (ii) OPA-related environmental costs, and (iii) other contingent liabilities. Accounting rules require loss recognition only where a potential loss is considered probable and can be reasonably estimated.

The Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and 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. The Company has not recorded a liability for any costs that are subject to indemnification by BP.

OA Liabilities Under the Settlement Agreement, all amounts deemed by BP to have been due under the OA, as well as all future amounts that otherwise would be invoiced to Anadarko under the OA,have been satisfied.

OPA-Related Environmental CostsBP, Anadarko, and other parties, including parties that do not own an interest in the Lease, such as the drilling contractor, have received correspondence from the United States Coast Guard (USCG) referencing their identification as a “responsible party or guarantor” (RP) under OPA. Under OPA, RPs, including Anadarko, may be jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims related to the spill and spill cleanup. The USCG's identification of Anadarko as an RP arises as a result of Anadarko's status as a co-lessee in the Lease.

Applicable accounting guidance requires the Company to accrue an environmental liability if it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Under accounting guidance applicable to environmental liabilities, a liability is presumed probable if the entity is both identified as an RP and associated with the environmental event. The Company's co-lessee status in the Lease and the subsequent identification and treatment of the Company as an RP satisfies these standards and therefore establishes the presumption that the Company's potential environmental liabilities related to the Deepwater Horizon events are probable. Given that such liabilities are probable, the Company must separately assess and estimate the Company's allocable share of gross estimated OPA-related environmental costs.

As BP funds OPA-related environmental costs, any potential joint and several liability for these costs is satisfied for all RPs, including Anadarko. This bears significance in that once these costs are funded by BP, such costs are no longer analyzed as OPA-related environmental costs, but are instead analyzed as OA Liabilities. As discussed above, Anadarko has agreed with BP to settle its current and future OA Liabilities. Thus, potential liability to the Company for OPA-related environmental costs can only arise where BP does not, or otherwise is unable to fund all of the OPA-related environmental costs. Under this scenario, the joint and several nature of the liability for these costs could cause the Company to recognize a liability for OPA-related environmental costs. However, the Company is fully indemnified by BP against these costs (including guarantees by BPCNA or BP p.l.c.).

Gross OPA-Related Environmental Cost EstimateIn prior periods, the Company provided an estimated range of gross OPA-related environmental costs for all identified RPs. This estimate was comprised of spill-response costs and OPA damage claims and was derived from cost information received by the Company from BP. As a result of the Settlement Agreement, the Company no longer expects to receive cost and claims data related to the Deepwater Horizon events. Accordingly, the OPA-related environmental cost estimate included in BP's public releases is the best data available to the Company and therefore herein and hereafter will be utilized by the Company in its accounting analysis.

Based on information included in BP p.l.c.'s public release on October 25, 2011, the range of gross OPA-related environmental costs is estimated to be $7.0 billion to $11.0 billion, excluding (i) amounts BP has already funded, which constitute settled OA Liabilities; (ii) amounts that cannot reasonably be estimated by BP, which include NRD claims and other litigation damages; and (iii) non-OPA-related fines and penalties that may be assessed against Anadarko, including assessments under the Clean Water Act (CWA). The Company believes that actual gross OPA-related environmental costs may vary from those estimated by BP p.l.c. in its public releases, perhaps materially from the above cost estimate.

Allocable Share of Gross OPA-Related Environmental Costs Under applicable accounting guidance, the Company is required to estimate its allocable share of gross OPA-related environmental costs based on the Company's estimate of the allocation method and percentage that may ultimately apply to it. To date, BP has paid all Deepwater Horizon event-related costs, which satisfies the Company's potential liability for these costs. Additionally, BP has repeatedly stated publicly and in prior congressional testimony that it will continue to pay these costs. BP's funding and public commentary has continued subsequent to the release of BP's own investigation report, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling's final report, and the Deepwater Horizon Joint Investigation Team final report, which the Company considers to be significant positive indications in assessing the likelihood of BP continuing to fund all of these costs. Based on BP's stated intent to continue funding these costs, the Company's assessment of BP's financial ability to continue funding these costs, and the impact of BP's settlements with both of its OA partners, the Company believes the likelihood of BP not continuing to satisfy these claims to be remote. Accordingly, at September 30, 2011, the Company considers zero to be its allocable percentage share of gross OPA-related environmental costs and, consistent with applicable accounting guidance, continues to have a liability accrual of zero for these amounts.

Other Contingencies

Penalties and FinesThese costs include amounts that may be assessed as a result of potential civil and/or criminal penalties under various federal, state, and/or local statutes and/or regulations as a result of the Deepwater Horizon events, including, for example, the CWA, the Outer Continental Shelf Lands Act, the Migratory Bird Treaty Act, and possibly other federal, state, and local laws. The foregoing does not represent an exhaustive list of statutes and regulations that potentially could trigger a penalty or fine assessment against the Company.

To date, no penalties or fines have been assessed against the Company. However, on December 15, 2010, the United States Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the United States 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 CWA in an amount to be determined by the Louisiana District Court. The DOJ complaint seeks separate penalty assessments against both Anadarko Petroleum Corporation and AE&P (based on a temporary interest that AE&P at one time held in the Lease). In April 2011, the Company moved to dismiss AE&P from the DOJ lawsuit because the effective date of AE&P's transfer of its interest in the Lease to Anadarko Petroleum Corporation pre-dated the Deepwater Horizon events. The Company currently believes it is probablethat AE&P will not be found liable for CWA penalties upon the presentation of evidence. The Company believes the outcome of this decision will not have a material impact on Anadarko's potential liability.

Although Anadarko was named in the DOJ civil lawsuit, its status as a defendant does not mean that Anadarko will be assessed a CWA penalty in that action. First, the Company has a defense to liability under the CWA based on the location from which the discharge occurred. If the court finds that the discharge of hydrocarbons came from the vessel (which includes the riser pipe), the Company may not be liable under the CWA because it neither owned nor operated the Deepwater Horizon drilling rig. Second, because CWA penalties, in practice, are generally assessed on a party-specific basis and take into account several factors including the party's degree of fault, the Company considers its lack of direct involvement in the operation of the drilling rig and the spill itself significant in concluding that losses from CWA penalty assessments are not probable. This view was reinforced by the Louisiana District Court's decision that dismissed all negligence claims against the Company based on the court's finding that the Company did not exercise operational control over the events that led to the oil spill. Accordingly, the Company does not consider a CWA penalty assessment to be probable and, therefore, has not recorded a liability for potential CWApenalties at September 30, 2011.

In addition to concluding that any liability for CWA penalties is not probable, the Company currently cannot estimate the amount of any potential penalty. The CWA sets forth subjective criteria, including degree of fault and history of prior violations, which influence CWA penalty assessments. Thus, as a result of the subjective nature of CWA penalty assessments, the Company currently cannot estimate the amount of any such penalty. However, given the Company's lack of direct operational involvement in the event, as recently confirmed by the Louisiana District Court, the Company believes that its potential exposure to CWA penalties will not materially impact the Company's consolidated financial position, results of operations, or cash flows.

Natural Resource DamagesThis category includes future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of injury assessments and restoration planning. Natural resources generally include land, fish, water, air, wildlife, and other such resources belonging to, managed by, held in trust by, or otherwise controlled by, the federal, state, or local government.

The NRD-assessment process is led by government agencies that act as trustees of natural resources on behalf of the public. Government agencies involved in the process include the Department of Commerce, the Department of the Interior (DOI), and the Department of Defense. These governmental departments, along with the five affected states – Alabama, Florida, Louisiana, Mississippi, and Texas – are referred to as the “Co-Trustees.” The Co-Trustees continue to conduct injury assessment and restoration planning.

The DOJ civil lawsuit filed against BP, the Company, and others seeks unspecified damages for injury to federal natural resources. Not all of the Co-Trustees were a party to this lawsuit; however, during the second quarter of 2011, the states of Alabama and Louisiana each filed NRD-related state law claims against the Company in the Louisiana District Court. The Company filed a motion to dismiss all of the claims in both of these complaints in June 2011. The Court heard oral arguments on these and other parties' motions in September 2011 and has taken the motions under advisement.

NRD claims are generally sought after the damage assessment and restoration planning is completed, which may take several years. Thus, the Company remains unable to reasonably estimate the magnitude of any NRD claim. The Company anticipates that BP will satisfy any NRD claim, which eliminates any potential liability to Anadarko for such costs. In the event any NRD damage claim is made directly against Anadarko, the Company is fully indemnified by BP against such claims (including guarantees by BPCNA or BP p.l.c).

Civil Litigation Damage ClaimsNumerous civil lawsuits have been filed against BP and other parties, including the Company, by, among others, fishing, boating, and shrimping enterprises and industry groups; restaurants; commercial and residential property owners; certain rig workers or their families; the State of Alabama and several of its political subdivisions; the DOJ; environmental non-governmental organizations; the State of Louisiana and certain of its political subdivisions; and certain Mexican states. Many of the lawsuits filed assert various claims of negligence, gross negligence, and violations of several federal and state laws and regulations, including, among others, OPA; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Air Act; the CWA; and the Endangered Species Act; or challenge existing permits for operations in the Gulf of Mexico. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment, and/or injunctive relief.

In August 2010, the United States Judicial Panel on Multidistrict Litigation created Multidistrict Litigation No. 2179 (MDL) to administer essentially all pretrial matters for litigation filed in federal court involving Deepwater Horizon event-related claims. Federal Judge Carl Barbier presides over this MDL in the Louisiana District Court. The Louisiana District Court has issued a number of case-management orders that establish a schedule for procedural matters, discovery, and trial of certain of the MDL cases. The parties to the MDL are actively engaged in discovery. In May 2011 and September 2011, Judge Barbier heard oral arguments on the numerous motions to dismiss filed by the multiple defendants named in this litigation. While a number of the motions remain pending, Judge Barbier has dismissed all maritime and state law claims filed against the Company by private plaintiffs seeking damages for economic loss. All negligence claims filed by these private plaintiffs against the Company have been dismissed based upon Judge Barbier's finding that the Company did not exercise operational control over the events that led to the oil spill. In a separate order, Judge Barbier reached similar findings and dismissed all claims against the Company filed by private plaintiffs alleging personal injury caused by exposure to oil, fumes or other contaminants from the blowout or the chemical dispersants used during the post-spill cleanup operations. Judge Barbier further found that federal law exclusively applies to the private plaintiffs' claims for property damage and economic loss and dismissedall state law claims against the Company asserting liability for such damages and losses. Only OPA claims asserted by private plaintiffs seeking economic loss damages against the Company remain. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against such OPA claims.

The Louisiana District Court has scheduled a February 2012 trial in Transocean's Limitation of Liability case in the MDL. This trial is to be the first phase of a three-phase trial, each phase designed to address different issues. 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 April 2011, the Company filed its answer in this Limitation of Liability case and cross-claimed against affiliates of BP and Transocean Ltd. (Transocean), Halliburton Energy Services, Inc. (Halliburton), Cameron International Corporation (Cameron), and other third-party defendants. Transocean, Halliburton, and Cameron subsequently filed cross-claims against the Company, and BP filed a motion to stay the litigation in the MDL between BP and the non-operating OA parties. In the motion to stay, BP argued that the cross-claims asserted against BP by the Company and the other non-operating OA party are covered by the dispute resolution procedures under the OA and should be stayed. As a result of the Settlement Agreement, a mutual release of all claims, including those that could have been made in arbitration, was agreed to by the Company and BP. The Company has also assigned all rights, title, and interest to all claims that have been or could be asserted against third parties, including cross-claims filed against other third-party defendants, to BP, with the exception of rights to claims the Company may assert under its insurance policies.

Two separate class action complaints were filed in June and August 2010, in the United States 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 for purported misstatements and omissions regarding, among other things, the Company's liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In November 2010, the New York District Court consolidated the two cases and appointed The Pension Trust Fund for Operating Engineers and Employees' Retirement System of the Government of the Virgin Islands (Virgin Islands Group) to act as Lead Plaintiff. In January 2011, the Lead Plaintiff filed its Consolidated Amended Complaint. Prior to filing its Consolidated Amended Complaint, the Lead Plaintiff requested leave from the New York District Court to transfer this lawsuit to the United States District Court for the Southern District of Texas. The Company opposes the Lead Plaintiff's request to transfer the case to the District Court for the Southern District of Texas. The parties have submitted briefs to the New York District Court concerning the transfer of venue issue. In March 2011, the Company moved to dismiss the Consolidated Amended Complaint of the Lead Plaintiff, and in April 2011, the Lead Plaintiff filed its opposition to the motion to dismiss. The motion to transfer and motion to dismiss remain under advisement of the New York District Court.

Also in June 2010, a shareholder derivative petition was filed in the 152nd Judicial District Court of Harris County, Texas (Harris County District Court), by a shareholder of the Company against Anadarko (as a nominal defendant), certain of its officers, and current and certain former directors. The petition alleged breaches of fiduciary duties, unjust enrichment, and waste of corporate assets in connection with the Deepwater Horizon events. The plaintiffs sought certain changes to the Company's governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs. In November 2010, the Harris County District Court granted Anadarko's Motion to Dismiss for Lack of Jurisdiction and Special Exceptions, and granted the plaintiffs 120 days to file an Amended Petition. In March 2011, the plaintiffs filed an Amended Petition. The Company filed Special Exceptions and a Motion to Dismiss the Amended Petition in April 2011. In June 2011, the Harris County District Court heard oral arguments on these matters and granted the motion to dismiss. The time for the plaintiffs to appeal has expired.

In September 2010, a purported shareholder made a demand of the Company's Board of Directors (Board) to investigate allegations of breaches of duty by members of management. The Board duly considered the demand, and in January 2011 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter.

Given the early 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 directors in all 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.

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 the investigation by the United States 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.

Insurance and Other Recoveries The Company carries insurance to protect against potential financial losses. At the time of the Deepwater Horizon events, the Company's insurance coverage applied to gross covered costs up to a level of approximately $710 million, less up to $60 million of deductibles. Based on Anadarko's 25% non-operated leasehold interest in the Lease, the Company estimates its net insurance coverage will total not less than $178 million, less deductibles of $15 million. The Company has not recognized a receivable for any potential insurance recoveries in its Consolidated Balance Sheets, but expects to recover, at a minimum, the first $163 million of insured costs under its then-existing insurance policy. At this time, recovery of these amounts is not considered probable because the Company has not yet filed a claim. The Company also carries directors' and officers' insurance which covers certain risks associated with certain of the above-described legal proceedings.

As part of the Settlement Agreement, BP has agreed that, to the extent it receives value in the future from claims that it has asserted or could assert against third parties arising from or relating to the Deepwater Horizon events, it will make cash payments (not to exceed $1.0 billion in the aggregate) to Anadarko, on a current and continuing basis, of 12.5% of the aggregate value received by BP in excess of $1.5 billion. Any payments received by the Company pursuant to this arrangement will be accounted for as a reimbursement of the $4.0 billion payment made by the Company to BP as part of the Settlement Agreement.

11.  Contingencies

The following discussion of the Company's contingencies excludes the Deepwater Horizon events discussed in Note 2.

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

Litigation   The Company is subject to various claims by its royalty owners in the regular course of business as an oil and gas producer, including disputes regarding measurement, post-production costs and expenses, and royalty valuations. The Company and certain of its subsidiaries (collectively, the Anadarko Defendants) were named as defendants in a case styled U.S. of America ex rel. Harrold E. Wright v. AGIP Petroleum Co., et al. filed in September 2000 in the United States District Court for the Eastern District of Texas, Lufkin Division. This lawsuit generally alleged that the Anadarko Defendants and other industry defendants violated the False Claims Act by knowingly undervaluing natural gas in connection with royalty payments on production from federal and Indian lands. In June 2011, the Company finalized its settlement of this litigation for approximately $19 million that was previously expensed. The settlement has been approved by the United States government and resolves all claims related to this litigation, as well as several related administrative matters, against the Anadarko Defendants.

SM Energy has alleged that AE&P breached a Joint Exploration Agreement (JEA) originally executed between Anadarko and TXCO Energy Corp. (TXCO) in March 2008 relating to an oil and gas development project in Maverick, Dimmitt, Webb and LaSalle Counties in the Eagleford shale in South Texas. SM Energy is a party to the JEA through two letter agreements with TXCO dated April of 2008, to which Anadarko consented. SM Energy contends that Anadarko is required under the agreements to tender to them a proportionate share of the leasehold interests that Anadarko acquired in TXCO's bankruptcy proceeding in February 2010. The arbitration hearing related to this dispute was held in September 2011. If the Company does not prevail in this matter, Anadarko could be obligated to sell a portion of its leasehold interest in the JEA to SM Energyor pay damages. The Company is vigorously defending this matter.

       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 its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court). 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. Tronox seeks, among other things, to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko, as well as litigation fees and costs. Anadarko and Kerr-McGee moved to dismiss the complaint in its entirety. In March 2010, the Bankruptcy Court issued an opinion granting in part and denying in part Anadarko's and Kerr-McGee's motion to dismiss the complaint. Notably, the Bankruptcy Court dismissed, with prejudice, Tronox's request for punitive damages relating to the fraudulent-conveyance claims. The Bankruptcy Court granted Tronox leave to replead certain of its common law claims, and Tronox filed an amended complaint in April 2010. In May 2010, Anadarko and Kerr-McGee moved to dismiss certain claims in the amended complaint. In May 2011, the Bankruptcy Court dismissed two claims against Anadarko for conspiracy and aiding and abetting, and declined to dismiss a breach of fiduciary duty claim against Kerr-McGee. In August 2011, Tronox filed a motion for partial summary judgment on the issue of whether damages in the Adversary Proceeding are limited to the amount of Tronox's environmental and tort creditor claims. Kerr-McGee and Anadarko filed a response and cross-motion in September 2011. Expert discovery is ongoing. The Adversary Proceeding is set for trial in April 2012.

       The United States government was granted authority to intervene in the Adversary Proceeding, and it has asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act. Anadarko and Kerr-McGee have moved to dismiss the claims of the United States government, but that motion has been stayed by the Bankruptcy Court.

       In August 2010, the Bankruptcy Court entered a Stipulation and Agreed Order among Tronox, Anadarko, and Kerr-McGee authorizing the rejection of the Master Separation Agreement (together with all annexes, related agreements, and ancillary agreements to it, the MSA). Anadarko and Kerr-McGee filed Proofs of Claim, which included claims for damages arising from the MSA rejection. In January 2011, the Bankruptcy Court entered a Stipulation and Agreed Order approving a settlement of Anadarko and Kerr-McGee's rejection damage claims against Tronox. The settlement provided Anadarko a general unsecured claim against Tronox. In February 2011, in settlement of its claim, Anadarko received shares of Tronox stock, which wereassigned to a financial institution in exchange for $46 million, included as a credit to general and administrative expenses in the Company's Consolidated Statements of Income for the nine months ended September 30, 2011. The Company will continue to monitor the impact that the rejection of the MSA may have on other litigation and other proceedings, including the Adversary Proceeding, and will assess the impact of future events on the Company's consolidated financial position, results of operations,and cash flows.

In February 2011, in accordance with Chapter 11 of the United States Bankruptcy Code, Tronox emerged from bankruptcy pursuant to an August 2010 Bankruptcy Court approved Plan of Reorganization (Plan). The terms of the Plan, which were confirmed by the Bankruptcy Court in the third quarter of 2010, contemplate that the claims of the United States government (together with other federal, state, local, or tribal governmental entities having regulatory authority or responsibilities for environmental laws, the Governmental Entities) related to Tronox's environmental liabilities will be settled through certain environmental response trusts and a litigation trust (Anadarko Litigation Trust). The Plan provides that the Governmental Entities will receive, among other things, 88% of the proceeds from the Adversary Proceeding. Additionally, certain creditors asserting tort claims against Tronox may receive, among other things, 12% of the proceeds from the Adversary Proceeding. Certain documents central to the Plan and the Adversary Proceeding were approved by the Bankruptcy Court in the fourth quarter of 2010 and in February 2011, including the Environmental Claims Settlement Agreement, the Tort Claims Trust Agreement, the Environmental Response Trust Agreement, and the Anadarko Litigation Trust Agreement (ALTA). In accordance with the Plan, the Adversary Proceeding will be prosecuted by the Anadarko Litigation Trust. Pursuant to the ALTA, 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, referencesto “Tronox” after February 2011 refer to the Anadarko Litigation Trust.

       In addition, 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 (Class Period), against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors, and Ernst & Young LLP (collectively, the Securities Defendants). The complaint alleges causes of action arising under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (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. Anadarko, Kerr-McGee, and other defendants moved to dismiss the consolidated class action complaint and in August 2010 moved to dismiss an amended consolidated class action complaint that had been filed in July 2010. The New York District Court issued the second of two opinions and orders on the motions (Orders). Following the Orders, only the plaintiffs' Section 20(a) claims under the Exchange Act remain against Anadarko and Kerr-McGee. The plaintiffs' claims against Anadarko are limited to the period beginning on August 10, 2006, through the end of the Class Period. In August 2011, plaintiffs filed a motion for class certification. The Securities Defendants filed briefs in opposition to class certification in September 2011. The court denied class certification in October 2011 and has requested the parties to re-brief the class certification motion. The discovery process is ongoing.

Discovery and motions are still underway in the Tronox proceedings. The Company does not consider a loss related to this matter to be probable; however, a loss is possible, and such loss, if realized, could have a material adverse effect on the Company. At this time the Company cannot reasonably estimate a range of potential losses related to the proceedings described above because the amount of potential damages will depend on circumstances that have not yet occurred, including the outcome of expert testimony and certain determinations to be made by the Bankruptcy Court. The Company intends to continue to vigorously defend itself, its officers, and its directors in these proceedings.

Deepwater Drilling Moratorium and Other Related Matters   In May and July 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), previously known as the Minerals Management Service, an agency of the DOI, issued directives requiring lessees and operators of federal oil and gas leases in the Outer Continental Shelf regions of the Gulf of Mexico and Pacific Ocean to cease drilling all new deepwater wells, including wellbore sidetracks and bypasses, through November 30, 2010 (the Moratorium). Anadarko ceased all drilling operations in the Gulf of Mexico in accordance with the Moratorium, which resulted in the suspension of operations of two operated deepwater wells (Lucius and Nansen) and one non-operated deepwater well (Vito). The Moratorium was lifted effective October 12, 2010. In July and August 2011, the DOI issued drilling permits to Anadarko for the Heidelberg appraisal well, the Cheyenne East exploration well near the Independence Hub facility, and a development well in the Nansen field. Drilling activity at these locations is expected to begin in late 2011. Anadarko is awaiting additional DOI approvals for other exploration plans and drilling permits.

      As a result of the Moratorium and additional inspection and safety requirements issued by the BOEMRE in May and June 2010, the Company provided notification of force majeure to drilling contractors of four of the Company's contracted deepwater rigs in the Gulf of Mexico. Some of the contracts have provisions that authorize contract termination by either party if force majeure conditions continue for a specified number of consecutive days.

       In June 2010, the Company gave written notice of termination to the drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit in the United States District Court for the Southern District of Houston, Texas (Houston, 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 asserted that Anadarko had breached the drilling contract. If the Company does not prevail in its claim, the Company could be obligated to pay the rig contract rate from the contract-termination date through March 2011, the end of the original contract term. The disputed rental for the contract period is $116 million; however, any potential damages would be reduced by, among other things, amounts resulting from the drilling contractor's ability to mitigate damages by leasing the drilling rig to another third party, as well as cost savingsrealized by the drilling contractor as a result of not operating the drilling rig for the entire original contract period. At September 30, 2011, the Company has not recognized a liability for costs associated with this dispute as management believes payment related to this matter is not probable. The Company intends to vigorously pursue this claim.

       In September 2010, the Company gave written notice of termination to another drilling contractor of a rig that had previously been placed in force majeure, and the Company filed a lawsuit in the Houston, 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 September 18, 2010. The drilling contractor filed a Motion to Dismiss and an Original Answer in October 2010. The Houston, Texas District Court, acting on its discretion, converted the Motion to Dismiss into a Motion for Summary Judgment and entered a scheduling order for submission of briefs during February and March 2011. In May 2011, the Company and the drilling contractor mutually agreed to dismiss all claims related to this dispute. Theresolution of this disputedid not have an impact on Anadarko's consolidated financial position, results of operations, or cash flows.

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Income Taxes

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Income Taxes

12.  Income Taxes

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions except percentages	2011			2010			2011			2010
Income tax expense (benefit)	$	(1,468)		$	94		$	(762)		$	660
Effective tax rate		33	%		109	%		25	%		49	%

The Company reported a loss before income taxes for the three and nine months ended September 30, 2011.As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% statutory rate for the three and nine months ended September 30, 2011, is primarily attributable to tax expense associated with the accrual of the Algerian exceptional profits tax (which is non-deductible for Algerian income tax purposes), U.S. tax on foreign income, foreign tax rates in excess of the U.S. statutory rate and valuation allowances on foreign losses. The decrease from the 35% statutory rate for the nine months ended September 30, 2011, is also attributable to items resulting from business acquisitions.The decrease from the 35% statutory rate for the three and nine months ended September 30, 2011, is partially offsetby U.S. income tax benefits associated with foreign losses andthe restructuring of foreign operations, state income taxes,and other items.

The increase from the 35% statutory rate for the three and nine months ended September 30, 2010, is primarily attributable to tax expense associated with the accrual of the Algerian exceptional profits tax, U.S. tax on foreign income, foreign tax ratesin excess of the U.S. statutory rate, valuation allowances on foreign losses, and unfavorable resolution of tax contingencies. The increase from the 35% statutory rate for the three and nine months ended September 30,2010, is partially reduced by U.S. income tax benefits associated with foreign losses, the federal manufacturing deduction, and other items.

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Selected Financial Information for Anadarko's Reporting Segments Table (Detail) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Segment Reporting Information [Line Items]
Sales revenues	$ 3,384		$ 2,516		$ 10,342		$ 8,209
Gains (losses) on divestitures and other, net	(185)		34		(214)		84
Total revenues and other	3,199		2,550		10,128		8,293
Operating costs and expenses	1,361	[1]	1,074	[1]	3,891	[2]	3,158	[2]
Other (income) expense, net	40		(129)		(2)		(106)
Net income attributable to noncontrolling interests	23		18		62		42
Total expenses and other	1,353		806		3,798		2,755
Unrealized (gains) losses on derivatives, net					767		(66)
Adjusted EBITDAX	1,843		1,740		6,322		5,529
Oil and Gas Exploration and Production Reporting Segment [Member]
Segment Reporting Information [Line Items]
Sales revenues	1,801		1,318		5,668		4,117
Intersegment revenues	1,244		950		3,699		3,259
Gains (losses) on divestitures and other, net	(193)		(3)		(307)		(15)
Total revenues and other	2,852		2,265		9,060		7,361
Operating costs and expenses	955	[1]	723	[1]	2,739	[2]	2,169	[2]
Total expenses and other	955		723		2,739		2,169
Adjusted EBITDAX	1,897		1,542		6,321		5,192
Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Sales revenues	76		45		238		145
Intersegment revenues	251		198		684		630
Gains (losses) on divestitures and other, net	(31)				(11)
Total revenues and other	296		243		911		775
Operating costs and expenses	210	[1]	152	[1]	575	[2]	501	[2]
Net income attributable to noncontrolling interests	23		18		62		42
Total expenses and other	233		170		637		543
Adjusted EBITDAX	63		73		274		232
Commodity Contract [Member] | Nondesignated [Member] | Gathering, Processing, and Marketing Sales [Member] | Marketing Reporting Segment [Member]
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net	(3)		(4)		(8)		(9)
Marketing Reporting Segment [Member]
Segment Reporting Information [Line Items]
Sales revenues	1,507		1,153		4,436		3,947
Intersegment revenues	(1,386)		(1,051)		(4,066)		(3,593)
Total revenues and other	121		102		370		354
Operating costs and expenses	143	[1]	116	[1]	414	[2]	349	[2]
Total expenses and other	143		116		414		349
Adjusted EBITDAX	(25)		(18)		(52)		(4)
Nondesignated [Member] | Other and Intersegment Eliminations [Member] | (Gains) Losses on Commodity Derivatives, Net and (Gains) Losses on Other Derivatives, Net [Member] | Commodity Contract, Interest Rate Contract, and Other [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	(71)		(157)		(153)		(339)
Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Intersegment revenues	(109)		(97)		(317)		(296)
Gains (losses) on divestitures and other, net	39		37		104		99
Total revenues and other	(70)		(60)		(213)		(197)
Operating costs and expenses	53	[1]	83	[1]	163	[2]	139	[2]
Other (income) expense, net	40		(129)		(2)		(106)
Total expenses and other	22		(203)		8		(306)
Adjusted EBITDAX	(92)		143		(221)		109
Commodity Contract [Member] | Nondesignated [Member] | Gathering, Processing, and Marketing Sales [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	1	[3]			17	[3]	1	[3]
Unrealized (gains) losses on derivatives, net	(3)	[3]	(4)	[3]	(8)	[3]	(9)	[3]
Nondesignated [Member] | (Gains) Losses on Commodity Derivatives, Net and (Gains) Losses on Other Derivatives, Net [Member] | Commodity Contract, Interest Rate Contract, and Other [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	(71)		(157)		(153)		(339)
Nondesignated [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	(70)		(157)		(136)		(338)
Unrealized (gains) losses on derivatives, net	692	[4]	174	[4]	767	[4]	(66)	[4]
Restatement Adjustment [Member] | Oil and Gas Exploration and Production Reporting Segment to Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Adjustment amount			$ 25				$ 57

[1] Operating costs and expenses exclude exploration expense; depreciation, depletion, and amortization; impairments; and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. For the three months ended September 30, 2010, $25 million has been reclassified from the oil and gas exploration and production segment to the midstream segment to properly reflect the previously reported amounts.

[2] Operating costs and expenses exclude exploration expense; depreciation, depletion, and amortization; impairments; and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. For the nine months ended September 30, 2010, $57 million has been reclassified from the oil and gas exploration and production segment to the midstream segment to properly reflect the previously reported amounts.

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

[4] In the fourth quarter of 2010, the Company revised the definition of Adjusted EBITDAX to exclude the impact of unrealized (gains) losses on derivative instruments, net. The prior periods have been adjusted to reflect this change.

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Cash Paid for Interest (Net of Amounts Capitalized) and Income Taxes, as well as Non-Cash Transactions Table (Detail) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash paid:
Interest	$ 708	$ 579
Income taxes	238	209
Non-cash investing activities:
Fair value of properties and equipment received in non-cash exchange transactions	4	32
Wattenberg Natural-Gas Processing Plant [Member]
Business Acquisition [Line Items]
Gain related to the fair-value remeasurement of Anadarko's pre-acquisition 7% equity interest in the Wattenberg Plant	$ 21

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Acquisitions - Additional Information (Detail) (USD $) In Millions, unless otherwise specified				9 Months Ended
	Sep. 30, 2011	May 31, 2011	Dec. 31, 2010	Sep. 30, 2011 Wattenberg Natural-Gas Processing Plant [Member]	May 31, 2011 Wattenberg Natural-Gas Processing Plant [Member]	May 31, 2011 Wattenberg Natural-Gas Processing Plant [Member] Oil and Gas Exploration and Production Reporting Segment [Member]	Feb. 28, 2011 Platte Valley Natural-Gas Processing Plant and Related Gathering Systems [Member] Western Gas Partners Limited Partnership [Member]	Sep. 30, 2011 Oil and Gas Exploration and Production Reporting Unit [Member] Excluding Other Intangible Assets [Member]	Sep. 30, 2011 Other Gathering and Processing Reporting Unit [Member] Excluding Other Intangible Assets [Member]	Sep. 30, 2011 WES Gathering and Processing Reporting Unit [Member] Excluding Other Intangible Assets [Member]	Sep. 30, 2011 Transportation Reporting Unit [Member] Excluding Other Intangible Assets [Member]	Sep. 30, 2011 Excluding Other Intangible Assets [Member]
Business Acquisition [Line Items]
Ownership interest purchased					93.00%
Business acquisition, cost of acquired entity, purchase price		$ 878			$ 576		$ 302
Ownership interest					100.00%
Business acquisition, purchase price allocation, goodwill		362				335
Business acquisition, purchase price allocation, goodwill, amortizable for tax purposes					469
Goodwill	5,832		5,311					5,400	102	59	5	5,600
Loss on Anadarko's preexisting contracts with the previous Wattenberg Plant owner		76		76
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 (Tables)

9 Months Ended

Sep. 30, 2011

Table Text Block [Abstract]

Debt Outstanding Table

	September 30, 2011						December 31, 2010
			Carrying		Fair				Carrying		Fair
millions	Principal		Value		Value		Principal		Value		Value
Long-term notes and debentures	$	13,952	$	12,226	$	13,752	$	14,237	$	12,488	$	13,459
WES borrowings		500		494		503		299		299		299
Total borrowings	$	14,452	$	12,720	$	14,255	$	14,536	$	12,787	$	13,758
Capital lease obligations		229		229		N/A		226		226		N/A
Less: Current portion of long-term debt		141		141		134		289		291		296
Total long-term debt	$	14,540	$	12,808	$	14,121	$	14,473	$	12,722	$	13,462

Debt Activity Table

				Carrying
millions		Principal		Value		Description
Balance at December 31, 2010		$	14,536	$	12,787
	Borrowings		560		560	WES credit facility
	Repayments(1)		(389)		(389)	WES credit facility and WES term loan
	Other, net		—		8	Changes in debt premium or discount
Balance at March 31, 2011		$	14,707	$	12,966
	Issuance		500		494	WES 5.375% Senior Notes due 2021
	Repayments(1)		(470)		(470)	WES credit facility
	Other, net		—		8	Changes in debt premium or discount
Balance at June 30, 2011		$	14,737	$	12,998
	Borrowings		10		10	WES credit facility
	Repayments(1)		(285)		(285)	6.875% Senior Notes due 2011
			(10)		(10)	WES credit facility
	Other, net		—		7	Changes in debt premium or discount
Balance at September 30, 2011		$	14,452	$	12,720

__________________________________________________________________________

(1)Debt repayment activity includes both scheduled repayments and retirements before scheduled maturity.

Interest Expense Table

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
millions		2011		2010		2011		2010
Current debt, long-term debt, and other(1)		$	245	$	235	$	743	$	642
Loss on early debt retirements and commitment
	termination(2)		—		17		—		89
Capitalized interest			(39)		(34)		(101)		(89)
Interest expense		$	206	$	218	$	642	$	642

__________________________________________________________________________

(1)Included in the three and ninemonths ended September 30, 2010, is $7 million and $9 million, respectively, of unamortized debt issuance costs associated with the retirement of the midstream subsidiary note payable to a related party (Midstream Subsidiary Note).

(2)Loss on early debt retirements in 2010 is the result of repurchasing $1.0 billion aggregate principal amount of debt due 2011 and 2012. Also included in the three and ninemonths ended September 30, 2010, is $17 million for commitment and structuring costs associated with a contemplated term-loan facility.

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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, 2010		$ 21,439		$ 51	$ 7,496	$ 14,449	$ (763)	$ (549)	$ 755
Net income (loss)		(2,229)				(2,291)			62
Common stock issued		155			155
Dividends - common		(135)				(135)
Repurchase of common stock		(31)					(31)
Sale of subsidiary units	[1]	301			32				269
Conversion of subordinated limited partner units to common units	[2]				162				(162)
Contributions from (distributions to) noncontrolling interest owners and other, net		(49)							(49)
Reclassification of previously deferred derivative losses to net income		7	[3]					7
Adjustments for pension and other postretirement plans		41						41
Balance at Sep. 30, 2011		$ 19,499		$ 51	$ 7,845	$ 12,023	$ (794)	$ (501)	$ 875

[1] Paid-in capital and noncontrolling interests includes $18 million and $9 million, respectively, of tax associated with subsidiary equity transactions that occurred during the current year.

[2] Includes $82 million of tax associated with subsidiary equity transactions that occurred prior to the conversion of subordinated limited partner units to common units.

[3] Net of income tax benefit (expense) of $(1) million and $(2) million for the three months ended September 30, 2011 and 2010, respectively, and $(4) million and $(7) million for the nine months ended September 30, 2011 and 2010, respectively.

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Supplemental Cash Flow Information

13.  Supplemental Cash Flow Information

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

			Nine Months Ended
			September 30,
millions			2011		2010
Cash paid:
	Interest		$	708	$	579
	Income taxes		$	238	$	209
Non-cash investing activities:
	Fair value of properties and equipment received in non-cash exchange transactions		$	4	$	32
	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 - Additional Information (Detail) (USD $)					12 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Dec. 31, 2009	Mar. 31, 2009	Dec. 31, 2009 Interest Rate Contract [Member]	Sep. 30, 2011 Marketing and Trading Derivative [Member] Natural Gas [Member] Bcf	Dec. 31, 2010 Marketing and Trading Derivative [Member] Natural Gas [Member] Bcf	Sep. 30, 2011 Securing most derivative counterparties [Member] Five Billion Dollar Facility [Member]	Sep. 30, 2011 Five Billion Dollar Facility [Member]	Sep. 30, 2011 Reference Period Start End Dates June 2014 to June 2024 and June 2014 to June 2044 [Member]	Sep. 30, 2011 Eligible for setoff against gross derivative asset in the event of default [Member]	Dec. 31, 2010 Eligible for setoff against gross derivative asset in the event of default [Member]
Derivative Instrument Detail [Abstract]
Accumulated other comprehensive loss, before tax	$ 113,000,000	$ 125,000,000
Accumulated other comprehensive loss, after tax	72,000,000	79,000,000
Derivative [Line Items]
Fixed-price physical transactions						28	32
Derivative transactions						15	28
Net positions						13	4
Realized gain on derivative instruments					552,000,000
Notional principal amount of interest-rate swap										1,850,000,000
Gross derivative liability	1,287,000,000	724,000,000									340,000,000	394,000,000
Line of credit, maximum borrowing capacity								5,000,000,000	5,000,000,000
Weighted-average interest rate for interest-rate swap			4.80%	3.25%
Aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed, net of collateral	$ 10,000,000	$ 10,000,000

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Pension Plans and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Pension Plans and Other Postretirement Benefits

15.  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 generally funded by contributions from the retiree, and in certain circumstances, contributions from the Company. The Company's retiree lifeinsurance plan is noncontributory.

During the nine months ended September 30, 2011, the Company made contributions of $269 million to its funded pension plans, $8 million to its unfunded pension plans, and $13 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 2011, the Company expects to contribute approximately $3 million to its funded pension plans, approximately $21 million to its unfunded pension plans, and approximately $5 million to its unfunded other postretirement benefit plans.

       The following sets forth the Company's pension and other postretirement benefit costs.

	Pension Benefits				Other Benefits
	Three Months Ended				Three Months Ended
	September 30,				September 30,
millions	2011		2010		2011		2010
Components of net periodic benefit cost
Service cost	$	20	$	17	$	3	$	3
Interest cost		21		21		4		4
Expected return on plan assets		(21)		(21)		—		—
Amortization of net actuarial loss (gain)		22		14		—		(1)
Amortization of net prior service cost (credit)		—		1		—		—
Net periodic benefit cost	$	42	$	32	$	7	$	6

	Pension Benefits				Other Benefits
	Nine Months Ended				Nine Months Ended
	September 30,				September 30,
millions	2011		2010		2011		2010
Components of net periodic benefit cost
Service cost	$	59	$	52	$	7	$	7
Interest cost		64		63		12		12
Expected return on plan assets		(64)		(62)		—		—
Amortization of net actuarial loss (gain)		64		49		—		(2)
Amortization of net prior service cost (credit)		1		2		—		(1)
Net periodic benefit cost	$	124	$	104	$	19	$	16

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Statement of Comprehensive Income
Net Income (Loss)	$ (3,028)		$ (8)		$ (2,229)		$ 692
Other Comprehensive Income (Loss), net of taxes
Reclassification of previously deferred derivative losses to net income	2	[1]	5	[1]	7	[1]	13	[1]
Adjustments for pension and other postretirement plans:
Net gain (loss) incurred during period							(21)	[2]
Prior service credit (cost) incurred during period							(4)	[3]
Amortization of net actuarial loss and prior service cost to net periodic benefit cost	14	[4]	9	[4]	41	[4]	31	[4]
Total adjustments for pension and other postretirement plans	14		9		41		6
Total	16		14		48		19
Comprehensive Income (Loss)	(3,012)		6		(2,181)		711
Comprehensive Income Attributable to Noncontrolling Interests	23		18		62		42
Comprehensive Income (Loss) Attributable to Common Stockholders	$ (3,035)		$ (12)		$ (2,243)		$ 669

[1] Net of income tax benefit (expense) of $(1) million and $(2) million for the three months ended September 30, 2011 and 2010, respectively, and $(4) million and $(7) million for the nine months ended September 30, 2011 and 2010, respectively.

[2] Net of income tax benefit (expense) of zero for the three months ended September 30, 2011 and 2010, and zero and $12 million for the nine months ended September 30, 2011 and 2010, respectively.

[3] Net of income tax benefit (expense) of zero for the three months ended September 30, 2011 and 2010, and zero and $2 million for the nine months ended September 30, 2011 and 2010, respectively.

[4] Net of income tax benefit (expense) of $(8) million and $(5) million for the three months ended September 30, 2011 and 2010, respectively, and $(24) million and $(17) million for the nine months ended September 30, 2011 and 2010, respectively.

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Derivative Instruments

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Derivative Instruments

7.  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 leasedstoragefacilities (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 this 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 $113 million ($72 million after tax) and $125 million ($79 million after tax) at September 30, 2011, and December 31, 2010, respectively, relate to interest-rate derivatives that were previously subject to hedge accounting.

Oil and Natural-Gas Production/Processing Derivative Activities   Below is a summary of the Company's derivative instruments at September 30, 2011, related to its Oil and Natural-Gas Production/ProcessingActivities. The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are NYMEX Cushing prices.

		2011		2012		2013
Natural Gas
	Three-Way Collars (thousand MMBtu/d)		480		500		450
	Average price per MMBtu
	Ceiling sold price (call)	$	8.29	$	9.03	$	6.57
	Floor purchased price (put)	$	6.50	$	6.50	$	5.00
	Floor sold price (put)	$	5.00	$	5.00	$	4.00
	Fixed-Price Contracts (thousand MMBtu/d)		90		—		—
	Average price per MMBtu	$	6.17	$	—	$	—
	Basis Swaps (thousand MMBtu/d)		45		—		—
	Average price per MMBtu	$	(1.74)	$	—	$	—
MMBtu—million British thermal units
MMBtu/d—million British thermal units per day

		2011		2012
Crude Oil
	Three-Way Collars (MBbls/d)		126		2
	Average price per barrel
	Ceiling sold price (call)	$	99.95	$	92.50
	Floor purchased price (put)	$	79.29	$	50.00
	Floor sold price (put)	$	64.29	$	35.00
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 September 30, 2011, and December 31, 2010, the Company had fixed-price physical transactions related to natural gas totaling28 billion cubic feet (Bcf) and 32 Bcf, respectively, offset by derivative transactions for 15 Bcf and 28 Bcf, respectively, for net positions of 13 Bcf and 4 Bcf, respectively.

Interest-Rate Derivatives In December 2008 and January 2009, Anadarko entered into interest-rate swap contracts as a fixed-rate payor to mitigate the interest-rate risk associated with anticipated 2011 and 2012 debt issuances. Due to rising interest rates thereafter, the fair value of the swap contracts increased and, in 2009, the Company revised the swap contract terms to increase the weighted-average interest rate of the swap portfolio from approximately 3.25% to approximately 4.80%, and realized a $552 million gain. During the third quarter of 2011, in order to better align the swap portfolio with the anticipated timing of future debt refinancing, the Company extended the swap maturity dates from October 2011 to June 2014 for interest-rate swaps with an aggregate notional principal amount of $1.85 billion. In connection with these extensions, the swap interest rates were also adjusted.

A summary of outstanding interest-rate swaps at September 30, 2011, is presented below.

millions except percentages		Reference Period		Weighted-Average
Notional Principal Amount:		Start	End	Interest Rate
$	150	October 2011	October 2041	4.65	%
$	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	Balance Sheet	September 30,		December 31,		September 30,		December 31,
Derivatives	Classification	2011		2010		2011		2010
Commodity
	Other Current Assets	$	428	$	444	$	(81)	$	(274)
	Other Assets		166		242		(9)		(56)
	Accrued Expenses		4		89		(17)		(131)
	Other Liabilities		1		26		(8)		(28)
			599		801		(115)		(489)
Interest Rate and Other
	Accrued Expenses		—		—		(185)		(190)
	Other Liabilities		—		—		(987)		(45)
			—		—		(1,172)		(235)
Total Derivatives		$	599	$	801	$	(1,287)	$	(724)

Effect of Derivative Instruments—Statement of Income   The realized and unrealized gain or loss amounts and classification of derivative instruments for the respective three and nine months ended September 30 are as follows:

			(Gain) Loss
			Three Months Ended						Nine Months Ended
millions		Classification of (Gain)	September 30, 2011						September 30, 2011
Derivatives		Loss Recognized	Realized		Unrealized		Total		Realized		Unrealized		Total
Commodity
		Gathering, Processing,
		and Marketing Sales(1)	$	1	$	(3)	$	(2)	$	17	$	(8)	$	9
		(Gains) Losses on Commodity
		Derivatives, net		(71)		(159)		(230)		(155)		(162)		(317)
Interest Rate
	and Other
		(Gains) Losses on Other
		Derivatives, net		—		854		854		2		937		939
Derivative (Gain) Loss, net			$	(70)	$	692	$	622	$	(136)	$	767	$	631

			(Gain) Loss
			Three Months Ended						Nine Months Ended
millions		Classification of (Gain)	September 30, 2010						September 30, 2010
Derivatives		Loss Recognized	Realized		Unrealized		Total		Realized		Unrealized		Total
Commodity
		Gathering, Processing,
		and Marketing Sales(1)	$	—	$	(4)	$	(4)	$	1	$	(9)	$	(8)
		(Gains) Losses on Commodity
		Derivatives, net		(157)		(43)		(200)		(339)		(713)		(1,052)
Interest Rate
	and Other
		(Gains) Losses on Other
		Derivatives, net		—		221		221		—		656		656
Derivative (Gain) Loss, net			$	(157)	$	174	$	17	$	(338)	$	(66)	$	(404)

__________________________________________________________________________

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

Credit-Risk Considerations   The financial integrity of exchange-traded contracts is assured by NYMEX or the Intercontinental Exchange through systems of financial safeguards and transaction guarantees and is subject to nominal credit risk. 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 September 30, 2011,$340 million of the Company's $1.3billion gross derivative liability balance,and at December 31, 2010, $394 million of the Company's $724 million 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 commodity and interest-rate derivatives, as settlement timing differs.

Some of the Company's derivative instruments are subject to provisions that may require collateralization of the Company's obligations. However, most of the Company's derivative counterparties maintain secured positionswith respect to the Company's derivative liabilities under the Company's $5.0 billion senior secured revolving credit facility (the $5.0 billion Facility), the available capacity of which issufficient to secure potential obligations to such counterparties.

Unsecured derivative obligations may require immediate settlement or full collateralization ifcertain credit-risk-related provisions are triggered, such as the Company's credit rating declining to a level below investment grade by major credit rating agencies. For these counterparties, the aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed was $10 million (net of collateral) at September 30, 2011 and December 31, 2010, and is 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 following tables set forth, by input level within the fair-value hierarchy, the fair value of the Company's derivative financial assets and liabilities.

September 30, 2011
millions			Level 1		Level 2		Level 3		Netting (1)		Collateral		Total
Assets:
	Commodity derivatives
		Financial institutions	$	2	$	466	$	—	$	(84)	$	(5)	$	379
		Other counterparties		—		131		—		(11)		—		120
	Interest-rate and other derivatives			—		—		—		—		—		—
Total derivative assets			$	2	$	597	$	—	$	(95)	$	(5)	$	499
Liabilities:
	Commodity derivatives
		Financial institutions	$	(3)	$	(88)	$	—	$	84	$	5	$	(2)
		Other counterparties		—		(24)		—		11		—		(13)
	Interest-rate and other derivatives			—		(1,172)		—		—		110		(1,062)
Total derivative liabilities			$	(3)	$	(1,284)	$	—	$	95	$	115	$	(1,077)

__________________________________________________________________________

(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.

December 31, 2010
millions			Level 1		Level 2		Level 3		Netting (1)		Collateral		Total
Assets:
	Commodity derivatives
		Financial institutions	$	3	$	557	$	—	$	(298)	$	(15)	$	247
		Other counterparties		—		241		—		(148)		—		93
Total derivative assets			$	3	$	798	$	—	$	(446)	$	(15)	$	340
Liabilities:
	Commodity derivatives
		Financial institutions	$	(2)	$	(333)	$	—	$	298	$	—	$	(37)
		Other counterparties		—		(154)		—		148		—		(6)
	Interest-rate and other derivatives			—		(235)		—		—		15		(220)
Total derivative liabilities			$	(2)	$	(722)	$	—	$	446	$	15	$	(263)

__________________________________________________________________________

(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.

XML

Interest Expense Table (Detail) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Interest Expense [Abstract]
Current debt, long-term debt, and other	$ 245,000,000	[1]	$ 235,000,000	[1]	$ 743,000,000	[1]	$ 642,000,000	[1]
Loss on early debt retirements and commitment termination			17,000,000	[2]			89,000,000	[2]
Capitalized interest	(39,000,000)		(34,000,000)		(101,000,000)		(89,000,000)
Interest expense	206,000,000		218,000,000		642,000,000		642,000,000
Table Text Block Supplement [Abstract]
Unamortized debt issuance costs associated with the retirement of the Midstream Subsidiary Note			7,000,000				9,000,000
Debt retirements, aggregate principal amount							1,000,000,000
Commitment and structuring costs associated with a previously contemplated term-loan facility			$ 17,000,000				$ 17,000,000

[1] Included in the three and nine months ended September 30, 2010, is $7 million and $9 million, respectively, of unamortized debt issuance costs associated with the retirement of the midstream subsidiary note payable to a related party (Midstream Subsidiary Note).

[2] Loss on early debt retirements in 2010 is the result of repurchasing $1.0 billion aggregate principal amount of debt due 2011 and 2012. Also included in the three and nine months ended September 30, 2010, is $17 million for commitment and structuring costs associated with a contemplated term-loan facility.

XML

Contingencies - Tronox (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Commitments and Contingencies Disclosure [Abstract]
Proceed from sale of third party stock received from legal settlement	$ 46
Tronox's Plan of Reorganization [Member] | Tronox Environmental Response Trusts and Anadarko Litigation Trust [Member] | Governmental Entities [Member]
Loss Contingencies [Line Items]
Proposed percentage of proceeds from Adversary Proceeding	88.00%
Tronox's Plan of Reorganization [Member] | Tronox Tort Claims Trust [Member] | Certain creditors asserting tort claims against Tronox [Member]
Loss Contingencies [Line Items]
Proposed percentage of proceeds from Adversary Proceeding	12.00%

XML

Pension Plans and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2011

Table Text Block [Abstract]

Components of Net Periodic Benefit Cost Table

	Pension Benefits				Other Benefits
	Three Months Ended				Three Months Ended
	September 30,				September 30,
millions	2011		2010		2011		2010
Components of net periodic benefit cost
Service cost	$	20	$	17	$	3	$	3
Interest cost		21		21		4		4
Expected return on plan assets		(21)		(21)		—		—
Amortization of net actuarial loss (gain)		22		14		—		(1)
Amortization of net prior service cost (credit)		—		1		—		—
Net periodic benefit cost	$	42	$	32	$	7	$	6

	Pension Benefits				Other Benefits
	Nine Months Ended				Nine Months Ended
	September 30,				September 30,
millions	2011		2010		2011		2010
Components of net periodic benefit cost
Service cost	$	59	$	52	$	7	$	7
Interest cost		64		63		12		12
Expected return on plan assets		(64)		(62)		—		—
Amortization of net actuarial loss (gain)		64		49		—		(2)
Amortization of net prior service cost (credit)		1		2		—		(1)
Net periodic benefit cost	$	124	$	104	$	19	$	16

XML

Contingencies

9 Months Ended

Sep. 30, 2011

Disclosure Text Block [Abstract]

Contingencies

2.  Deepwater Horizon Events

Background, Settlement, and BP IndemnificationIn April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating leasehold interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. The Macondo well was plugged on September 19, 2010.

BP Exploration & Production Inc. (BP), the operator of Mississippi Canyon Block 252 in which the Macondo well is located (Lease), is funding claims and coordinating cleanup efforts. BP invoiced the Company $6.1 billion for what BP considered to be Anadarko's proportionate share of actual costs and anticipated near-term future costs related to these activities. Anadarkowithheld payment to BP for all Deepwater Horizon event-related invoices pending the completion of various ongoing investigations into and litigation regarding the cause of the well blowout, explosion, and subsequent release of hydrocarbons.

In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify, whereby the Company and BP agreed to a mutual release of claims against each other relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company has agreed to pay $4.0 billion in cash and transfer its interest in the Lease to BP (subject to required governmental approvals of the transfer), and BP has agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued to date and to forgo reimbursement for all future costs arising from the Deepwater Horizon events, including future costs under the Operating Agreement (OA). In addition, BP has fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related 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 OA. This indemnification has been 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. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder, derivative, or security laws claims, or certain other claims. The Company believes that costs associated with non-indemnified items, individually or in the aggregate, will not materially impact the Company's consolidated financial position, results of operations, or cash flows.

Liability AccrualAs of September 30, 2011, the Company has recorded a liability for Deepwater Horizon-related settlement costs of approximately $4.0 billion, which includes the cash payment to be remitted to BP in accordance with the Settlement Agreement, as well as Deepwater Horizon event-related legal fees. These legal fees were previously recorded in general and administrative expenses in the Consolidated Statements of Income and have been reclassified for all periods presented to conform to the current-period presentation.

Below is a discussion of the Company's current analysis, under applicable accounting guidance, of its potential liability for (i) amounts invoiced by BP under the OA (OA Liabilities), (ii) OPA-related environmental costs, and (iii) other contingent liabilities. Accounting rules require loss recognition only where a potential loss is considered probable and can be reasonably estimated.

The Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and 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. The Company has not recorded a liability for any costs that are subject to indemnification by BP.

OA Liabilities Under the Settlement Agreement, all amounts deemed by BP to have been due under the OA, as well as all future amounts that otherwise would be invoiced to Anadarko under the OA,have been satisfied.

OPA-Related Environmental CostsBP, Anadarko, and other parties, including parties that do not own an interest in the Lease, such as the drilling contractor, have received correspondence from the United States Coast Guard (USCG) referencing their identification as a “responsible party or guarantor” (RP) under OPA. Under OPA, RPs, including Anadarko, may be jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims related to the spill and spill cleanup. The USCG's identification of Anadarko as an RP arises as a result of Anadarko's status as a co-lessee in the Lease.

Applicable accounting guidance requires the Company to accrue an environmental liability if it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Under accounting guidance applicable to environmental liabilities, a liability is presumed probable if the entity is both identified as an RP and associated with the environmental event. The Company's co-lessee status in the Lease and the subsequent identification and treatment of the Company as an RP satisfies these standards and therefore establishes the presumption that the Company's potential environmental liabilities related to the Deepwater Horizon events are probable. Given that such liabilities are probable, the Company must separately assess and estimate the Company's allocable share of gross estimated OPA-related environmental costs.

As BP funds OPA-related environmental costs, any potential joint and several liability for these costs is satisfied for all RPs, including Anadarko. This bears significance in that once these costs are funded by BP, such costs are no longer analyzed as OPA-related environmental costs, but are instead analyzed as OA Liabilities. As discussed above, Anadarko has agreed with BP to settle its current and future OA Liabilities. Thus, potential liability to the Company for OPA-related environmental costs can only arise where BP does not, or otherwise is unable to fund all of the OPA-related environmental costs. Under this scenario, the joint and several nature of the liability for these costs could cause the Company to recognize a liability for OPA-related environmental costs. However, the Company is fully indemnified by BP against these costs (including guarantees by BPCNA or BP p.l.c.).

Gross OPA-Related Environmental Cost EstimateIn prior periods, the Company provided an estimated range of gross OPA-related environmental costs for all identified RPs. This estimate was comprised of spill-response costs and OPA damage claims and was derived from cost information received by the Company from BP. As a result of the Settlement Agreement, the Company no longer expects to receive cost and claims data related to the Deepwater Horizon events. Accordingly, the OPA-related environmental cost estimate included in BP's public releases is the best data available to the Company and therefore herein and hereafter will be utilized by the Company in its accounting analysis.

Based on information included in BP p.l.c.'s public release on October 25, 2011, the range of gross OPA-related environmental costs is estimated to be $7.0 billion to $11.0 billion, excluding (i) amounts BP has already funded, which constitute settled OA Liabilities; (ii) amounts that cannot reasonably be estimated by BP, which include NRD claims and other litigation damages; and (iii) non-OPA-related fines and penalties that may be assessed against Anadarko, including assessments under the Clean Water Act (CWA). The Company believes that actual gross OPA-related environmental costs may vary from those estimated by BP p.l.c. in its public releases, perhaps materially from the above cost estimate.

Allocable Share of Gross OPA-Related Environmental Costs Under applicable accounting guidance, the Company is required to estimate its allocable share of gross OPA-related environmental costs based on the Company's estimate of the allocation method and percentage that may ultimately apply to it. To date, BP has paid all Deepwater Horizon event-related costs, which satisfies the Company's potential liability for these costs. Additionally, BP has repeatedly stated publicly and in prior congressional testimony that it will continue to pay these costs. BP's funding and public commentary has continued subsequent to the release of BP's own investigation report, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling's final report, and the Deepwater Horizon Joint Investigation Team final report, which the Company considers to be significant positive indications in assessing the likelihood of BP continuing to fund all of these costs. Based on BP's stated intent to continue funding these costs, the Company's assessment of BP's financial ability to continue funding these costs, and the impact of BP's settlements with both of its OA partners, the Company believes the likelihood of BP not continuing to satisfy these claims to be remote. Accordingly, at September 30, 2011, the Company considers zero to be its allocable percentage share of gross OPA-related environmental costs and, consistent with applicable accounting guidance, continues to have a liability accrual of zero for these amounts.

Other Contingencies

Penalties and FinesThese costs include amounts that may be assessed as a result of potential civil and/or criminal penalties under various federal, state, and/or local statutes and/or regulations as a result of the Deepwater Horizon events, including, for example, the CWA, the Outer Continental Shelf Lands Act, the Migratory Bird Treaty Act, and possibly other federal, state, and local laws. The foregoing does not represent an exhaustive list of statutes and regulations that potentially could trigger a penalty or fine assessment against the Company.

To date, no penalties or fines have been assessed against the Company. However, on December 15, 2010, the United States Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the United States 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 CWA in an amount to be determined by the Louisiana District Court. The DOJ complaint seeks separate penalty assessments against both Anadarko Petroleum Corporation and AE&P (based on a temporary interest that AE&P at one time held in the Lease). In April 2011, the Company moved to dismiss AE&P from the DOJ lawsuit because the effective date of AE&P's transfer of its interest in the Lease to Anadarko Petroleum Corporation pre-dated the Deepwater Horizon events. The Company currently believes it is probablethat AE&P will not be found liable for CWA penalties upon the presentation of evidence. The Company believes the outcome of this decision will not have a material impact on Anadarko's potential liability.

Although Anadarko was named in the DOJ civil lawsuit, its status as a defendant does not mean that Anadarko will be assessed a CWA penalty in that action. First, the Company has a defense to liability under the CWA based on the location from which the discharge occurred. If the court finds that the discharge of hydrocarbons came from the vessel (which includes the riser pipe), the Company may not be liable under the CWA because it neither owned nor operated the Deepwater Horizon drilling rig. Second, because CWA penalties, in practice, are generally assessed on a party-specific basis and take into account several factors including the party's degree of fault, the Company considers its lack of direct involvement in the operation of the drilling rig and the spill itself significant in concluding that losses from CWA penalty assessments are not probable. This view was reinforced by the Louisiana District Court's decision that dismissed all negligence claims against the Company based on the court's finding that the Company did not exercise operational control over the events that led to the oil spill. Accordingly, the Company does not consider a CWA penalty assessment to be probable and, therefore, has not recorded a liability for potential CWApenalties at September 30, 2011.

In addition to concluding that any liability for CWA penalties is not probable, the Company currently cannot estimate the amount of any potential penalty. The CWA sets forth subjective criteria, including degree of fault and history of prior violations, which influence CWA penalty assessments. Thus, as a result of the subjective nature of CWA penalty assessments, the Company currently cannot estimate the amount of any such penalty. However, given the Company's lack of direct operational involvement in the event, as recently confirmed by the Louisiana District Court, the Company believes that its potential exposure to CWA penalties will not materially impact the Company's consolidated financial position, results of operations, or cash flows.

Natural Resource DamagesThis category includes future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of injury assessments and restoration planning. Natural resources generally include land, fish, water, air, wildlife, and other such resources belonging to, managed by, held in trust by, or otherwise controlled by, the federal, state, or local government.

The NRD-assessment process is led by government agencies that act as trustees of natural resources on behalf of the public. Government agencies involved in the process include the Department of Commerce, the Department of the Interior (DOI), and the Department of Defense. These governmental departments, along with the five affected states – Alabama, Florida, Louisiana, Mississippi, and Texas – are referred to as the “Co-Trustees.” The Co-Trustees continue to conduct injury assessment and restoration planning.

The DOJ civil lawsuit filed against BP, the Company, and others seeks unspecified damages for injury to federal natural resources. Not all of the Co-Trustees were a party to this lawsuit; however, during the second quarter of 2011, the states of Alabama and Louisiana each filed NRD-related state law claims against the Company in the Louisiana District Court. The Company filed a motion to dismiss all of the claims in both of these complaints in June 2011. The Court heard oral arguments on these and other parties' motions in September 2011 and has taken the motions under advisement.

NRD claims are generally sought after the damage assessment and restoration planning is completed, which may take several years. Thus, the Company remains unable to reasonably estimate the magnitude of any NRD claim. The Company anticipates that BP will satisfy any NRD claim, which eliminates any potential liability to Anadarko for such costs. In the event any NRD damage claim is made directly against Anadarko, the Company is fully indemnified by BP against such claims (including guarantees by BPCNA or BP p.l.c).

Civil Litigation Damage ClaimsNumerous civil lawsuits have been filed against BP and other parties, including the Company, by, among others, fishing, boating, and shrimping enterprises and industry groups; restaurants; commercial and residential property owners; certain rig workers or their families; the State of Alabama and several of its political subdivisions; the DOJ; environmental non-governmental organizations; the State of Louisiana and certain of its political subdivisions; and certain Mexican states. Many of the lawsuits filed assert various claims of negligence, gross negligence, and violations of several federal and state laws and regulations, including, among others, OPA; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Air Act; the CWA; and the Endangered Species Act; or challenge existing permits for operations in the Gulf of Mexico. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment, and/or injunctive relief.

In August 2010, the United States Judicial Panel on Multidistrict Litigation created Multidistrict Litigation No. 2179 (MDL) to administer essentially all pretrial matters for litigation filed in federal court involving Deepwater Horizon event-related claims. Federal Judge Carl Barbier presides over this MDL in the Louisiana District Court. The Louisiana District Court has issued a number of case-management orders that establish a schedule for procedural matters, discovery, and trial of certain of the MDL cases. The parties to the MDL are actively engaged in discovery. In May 2011 and September 2011, Judge Barbier heard oral arguments on the numerous motions to dismiss filed by the multiple defendants named in this litigation. While a number of the motions remain pending, Judge Barbier has dismissed all maritime and state law claims filed against the Company by private plaintiffs seeking damages for economic loss. All negligence claims filed by these private plaintiffs against the Company have been dismissed based upon Judge Barbier's finding that the Company did not exercise operational control over the events that led to the oil spill. In a separate order, Judge Barbier reached similar findings and dismissed all claims against the Company filed by private plaintiffs alleging personal injury caused by exposure to oil, fumes or other contaminants from the blowout or the chemical dispersants used during the post-spill cleanup operations. Judge Barbier further found that federal law exclusively applies to the private plaintiffs' claims for property damage and economic loss and dismissedall state law claims against the Company asserting liability for such damages and losses. Only OPA claims asserted by private plaintiffs seeking economic loss damages against the Company remain. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against such OPA claims.

The Louisiana District Court has scheduled a February 2012 trial in Transocean's Limitation of Liability case in the MDL. This trial is to be the first phase of a three-phase trial, each phase designed to address different issues. 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 April 2011, the Company filed its answer in this Limitation of Liability case and cross-claimed against affiliates of BP and Transocean Ltd. (Transocean), Halliburton Energy Services, Inc. (Halliburton), Cameron International Corporation (Cameron), and other third-party defendants. Transocean, Halliburton, and Cameron subsequently filed cross-claims against the Company, and BP filed a motion to stay the litigation in the MDL between BP and the non-operating OA parties. In the motion to stay, BP argued that the cross-claims asserted against BP by the Company and the other non-operating OA party are covered by the dispute resolution procedures under the OA and should be stayed. As a result of the Settlement Agreement, a mutual release of all claims, including those that could have been made in arbitration, was agreed to by the Company and BP. The Company has also assigned all rights, title, and interest to all claims that have been or could be asserted against third parties, including cross-claims filed against other third-party defendants, to BP, with the exception of rights to claims the Company may assert under its insurance policies.

Two separate class action complaints were filed in June and August 2010, in the United States 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 for purported misstatements and omissions regarding, among other things, the Company's liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In November 2010, the New York District Court consolidated the two cases and appointed The Pension Trust Fund for Operating Engineers and Employees' Retirement System of the Government of the Virgin Islands (Virgin Islands Group) to act as Lead Plaintiff. In January 2011, the Lead Plaintiff filed its Consolidated Amended Complaint. Prior to filing its Consolidated Amended Complaint, the Lead Plaintiff requested leave from the New York District Court to transfer this lawsuit to the United States District Court for the Southern District of Texas. The Company opposes the Lead Plaintiff's request to transfer the case to the District Court for the Southern District of Texas. The parties have submitted briefs to the New York District Court concerning the transfer of venue issue. In March 2011, the Company moved to dismiss the Consolidated Amended Complaint of the Lead Plaintiff, and in April 2011, the Lead Plaintiff filed its opposition to the motion to dismiss. The motion to transfer and motion to dismiss remain under advisement of the New York District Court.

Also in June 2010, a shareholder derivative petition was filed in the 152nd Judicial District Court of Harris County, Texas (Harris County District Court), by a shareholder of the Company against Anadarko (as a nominal defendant), certain of its officers, and current and certain former directors. The petition alleged breaches of fiduciary duties, unjust enrichment, and waste of corporate assets in connection with the Deepwater Horizon events. The plaintiffs sought certain changes to the Company's governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs. In November 2010, the Harris County District Court granted Anadarko's Motion to Dismiss for Lack of Jurisdiction and Special Exceptions, and granted the plaintiffs 120 days to file an Amended Petition. In March 2011, the plaintiffs filed an Amended Petition. The Company filed Special Exceptions and a Motion to Dismiss the Amended Petition in April 2011. In June 2011, the Harris County District Court heard oral arguments on these matters and granted the motion to dismiss. The time for the plaintiffs to appeal has expired.

In September 2010, a purported shareholder made a demand of the Company's Board of Directors (Board) to investigate allegations of breaches of duty by members of management. The Board duly considered the demand, and in January 2011 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter.

Given the early 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 directors in all 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.

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 the investigation by the United States 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.

Insurance and Other Recoveries The Company carries insurance to protect against potential financial losses. At the time of the Deepwater Horizon events, the Company's insurance coverage applied to gross covered costs up to a level of approximately $710 million, less up to $60 million of deductibles. Based on Anadarko's 25% non-operated leasehold interest in the Lease, the Company estimates its net insurance coverage will total not less than $178 million, less deductibles of $15 million. The Company has not recognized a receivable for any potential insurance recoveries in its Consolidated Balance Sheets, but expects to recover, at a minimum, the first $163 million of insured costs under its then-existing insurance policy. At this time, recovery of these amounts is not considered probable because the Company has not yet filed a claim. The Company also carries directors' and officers' insurance which covers certain risks associated with certain of the above-described legal proceedings.

As part of the Settlement Agreement, BP has agreed that, to the extent it receives value in the future from claims that it has asserted or could assert against third parties arising from or relating to the Deepwater Horizon events, it will make cash payments (not to exceed $1.0 billion in the aggregate) to Anadarko, on a current and continuing basis, of 12.5% of the aggregate value received by BP in excess of $1.5 billion. Any payments received by the Company pursuant to this arrangement will be accounted for as a reimbursement of the $4.0 billion payment made by the Company to BP as part of the Settlement Agreement.

11.  Contingencies

The following discussion of the Company's contingencies excludes the Deepwater Horizon events discussed in Note 2.

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

Litigation   The Company is subject to various claims by its royalty owners in the regular course of business as an oil and gas producer, including disputes regarding measurement, post-production costs and expenses, and royalty valuations. The Company and certain of its subsidiaries (collectively, the Anadarko Defendants) were named as defendants in a case styled U.S. of America ex rel. Harrold E. Wright v. AGIP Petroleum Co., et al. filed in September 2000 in the United States District Court for the Eastern District of Texas, Lufkin Division. This lawsuit generally alleged that the Anadarko Defendants and other industry defendants violated the False Claims Act by knowingly undervaluing natural gas in connection with royalty payments on production from federal and Indian lands. In June 2011, the Company finalized its settlement of this litigation for approximately $19 million that was previously expensed. The settlement has been approved by the United States government and resolves all claims related to this litigation, as well as several related administrative matters, against the Anadarko Defendants.

SM Energy has alleged that AE&P breached a Joint Exploration Agreement (JEA) originally executed between Anadarko and TXCO Energy Corp. (TXCO) in March 2008 relating to an oil and gas development project in Maverick, Dimmitt, Webb and LaSalle Counties in the Eagleford shale in South Texas. SM Energy is a party to the JEA through two letter agreements with TXCO dated April of 2008, to which Anadarko consented. SM Energy contends that Anadarko is required under the agreements to tender to them a proportionate share of the leasehold interests that Anadarko acquired in TXCO's bankruptcy proceeding in February 2010. The arbitration hearing related to this dispute was held in September 2011. If the Company does not prevail in this matter, Anadarko could be obligated to sell a portion of its leasehold interest in the JEA to SM Energyor pay damages. The Company is vigorously defending this matter.

       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 its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court). 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. Tronox seeks, among other things, to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko, as well as litigation fees and costs. Anadarko and Kerr-McGee moved to dismiss the complaint in its entirety. In March 2010, the Bankruptcy Court issued an opinion granting in part and denying in part Anadarko's and Kerr-McGee's motion to dismiss the complaint. Notably, the Bankruptcy Court dismissed, with prejudice, Tronox's request for punitive damages relating to the fraudulent-conveyance claims. The Bankruptcy Court granted Tronox leave to replead certain of its common law claims, and Tronox filed an amended complaint in April 2010. In May 2010, Anadarko and Kerr-McGee moved to dismiss certain claims in the amended complaint. In May 2011, the Bankruptcy Court dismissed two claims against Anadarko for conspiracy and aiding and abetting, and declined to dismiss a breach of fiduciary duty claim against Kerr-McGee. In August 2011, Tronox filed a motion for partial summary judgment on the issue of whether damages in the Adversary Proceeding are limited to the amount of Tronox's environmental and tort creditor claims. Kerr-McGee and Anadarko filed a response and cross-motion in September 2011. Expert discovery is ongoing. The Adversary Proceeding is set for trial in April 2012.

       The United States government was granted authority to intervene in the Adversary Proceeding, and it has asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act. Anadarko and Kerr-McGee have moved to dismiss the claims of the United States government, but that motion has been stayed by the Bankruptcy Court.

       In August 2010, the Bankruptcy Court entered a Stipulation and Agreed Order among Tronox, Anadarko, and Kerr-McGee authorizing the rejection of the Master Separation Agreement (together with all annexes, related agreements, and ancillary agreements to it, the MSA). Anadarko and Kerr-McGee filed Proofs of Claim, which included claims for damages arising from the MSA rejection. In January 2011, the Bankruptcy Court entered a Stipulation and Agreed Order approving a settlement of Anadarko and Kerr-McGee's rejection damage claims against Tronox. The settlement provided Anadarko a general unsecured claim against Tronox. In February 2011, in settlement of its claim, Anadarko received shares of Tronox stock, which wereassigned to a financial institution in exchange for $46 million, included as a credit to general and administrative expenses in the Company's Consolidated Statements of Income for the nine months ended September 30, 2011. The Company will continue to monitor the impact that the rejection of the MSA may have on other litigation and other proceedings, including the Adversary Proceeding, and will assess the impact of future events on the Company's consolidated financial position, results of operations,and cash flows.

In February 2011, in accordance with Chapter 11 of the United States Bankruptcy Code, Tronox emerged from bankruptcy pursuant to an August 2010 Bankruptcy Court approved Plan of Reorganization (Plan). The terms of the Plan, which were confirmed by the Bankruptcy Court in the third quarter of 2010, contemplate that the claims of the United States government (together with other federal, state, local, or tribal governmental entities having regulatory authority or responsibilities for environmental laws, the Governmental Entities) related to Tronox's environmental liabilities will be settled through certain environmental response trusts and a litigation trust (Anadarko Litigation Trust). The Plan provides that the Governmental Entities will receive, among other things, 88% of the proceeds from the Adversary Proceeding. Additionally, certain creditors asserting tort claims against Tronox may receive, among other things, 12% of the proceeds from the Adversary Proceeding. Certain documents central to the Plan and the Adversary Proceeding were approved by the Bankruptcy Court in the fourth quarter of 2010 and in February 2011, including the Environmental Claims Settlement Agreement, the Tort Claims Trust Agreement, the Environmental Response Trust Agreement, and the Anadarko Litigation Trust Agreement (ALTA). In accordance with the Plan, the Adversary Proceeding will be prosecuted by the Anadarko Litigation Trust. Pursuant to the ALTA, 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, referencesto “Tronox” after February 2011 refer to the Anadarko Litigation Trust.

       In addition, 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 (Class Period), against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors, and Ernst & Young LLP (collectively, the Securities Defendants). The complaint alleges causes of action arising under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (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. Anadarko, Kerr-McGee, and other defendants moved to dismiss the consolidated class action complaint and in August 2010 moved to dismiss an amended consolidated class action complaint that had been filed in July 2010. The New York District Court issued the second of two opinions and orders on the motions (Orders). Following the Orders, only the plaintiffs' Section 20(a) claims under the Exchange Act remain against Anadarko and Kerr-McGee. The plaintiffs' claims against Anadarko are limited to the period beginning on August 10, 2006, through the end of the Class Period. In August 2011, plaintiffs filed a motion for class certification. The Securities Defendants filed briefs in opposition to class certification in September 2011. The court denied class certification in October 2011 and has requested the parties to re-brief the class certification motion. The discovery process is ongoing.

Discovery and motions are still underway in the Tronox proceedings. The Company does not consider a loss related to this matter to be probable; however, a loss is possible, and such loss, if realized, could have a material adverse effect on the Company. At this time the Company cannot reasonably estimate a range of potential losses related to the proceedings described above because the amount of potential damages will depend on circumstances that have not yet occurred, including the outcome of expert testimony and certain determinations to be made by the Bankruptcy Court. The Company intends to continue to vigorously defend itself, its officers, and its directors in these proceedings.

Deepwater Drilling Moratorium and Other Related Matters   In May and July 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), previously known as the Minerals Management Service, an agency of the DOI, issued directives requiring lessees and operators of federal oil and gas leases in the Outer Continental Shelf regions of the Gulf of Mexico and Pacific Ocean to cease drilling all new deepwater wells, including wellbore sidetracks and bypasses, through November 30, 2010 (the Moratorium). Anadarko ceased all drilling operations in the Gulf of Mexico in accordance with the Moratorium, which resulted in the suspension of operations of two operated deepwater wells (Lucius and Nansen) and one non-operated deepwater well (Vito). The Moratorium was lifted effective October 12, 2010. In July and August 2011, the DOI issued drilling permits to Anadarko for the Heidelberg appraisal well, the Cheyenne East exploration well near the Independence Hub facility, and a development well in the Nansen field. Drilling activity at these locations is expected to begin in late 2011. Anadarko is awaiting additional DOI approvals for other exploration plans and drilling permits.

      As a result of the Moratorium and additional inspection and safety requirements issued by the BOEMRE in May and June 2010, the Company provided notification of force majeure to drilling contractors of four of the Company's contracted deepwater rigs in the Gulf of Mexico. Some of the contracts have provisions that authorize contract termination by either party if force majeure conditions continue for a specified number of consecutive days.

       In June 2010, the Company gave written notice of termination to the drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit in the United States District Court for the Southern District of Houston, Texas (Houston, 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 asserted that Anadarko had breached the drilling contract. If the Company does not prevail in its claim, the Company could be obligated to pay the rig contract rate from the contract-termination date through March 2011, the end of the original contract term. The disputed rental for the contract period is $116 million; however, any potential damages would be reduced by, among other things, amounts resulting from the drilling contractor's ability to mitigate damages by leasing the drilling rig to another third party, as well as cost savingsrealized by the drilling contractor as a result of not operating the drilling rig for the entire original contract period. At September 30, 2011, the Company has not recognized a liability for costs associated with this dispute as management believes payment related to this matter is not probable. The Company intends to vigorously pursue this claim.

       In September 2010, the Company gave written notice of termination to another drilling contractor of a rig that had previously been placed in force majeure, and the Company filed a lawsuit in the Houston, 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 September 18, 2010. The drilling contractor filed a Motion to Dismiss and an Original Answer in October 2010. The Houston, Texas District Court, acting on its discretion, converted the Motion to Dismiss into a Motion for Summary Judgment and entered a scheduling order for submission of briefs during February and March 2011. In May 2011, the Company and the drilling contractor mutually agreed to dismiss all claims related to this dispute. Theresolution of this disputedid not have an impact on Anadarko's consolidated financial position, results of operations, or cash flows.

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Revenues and Other
Natural-gas sales	$ 840		$ 809		$ 2,564		$ 2,692
Oil and condensate sales	1,905		1,298		5,948		4,138
Natural-gas liquids sales	377		227		1,080		736
Gathering, processing, and marketing sales	262		182		750		643
Gains (losses) on divestitures and other, net	(185)		34		(214)		84
Total	3,199		2,550		10,128		8,293
Costs and Expenses
Oil and gas operating	262		207		730		590
Oil and gas transportation and other	217		220		633		607
Exploration	307		296		722		649
Gathering, processing, and marketing	214		134		590		466
General and administrative	293		273		806		686
Depreciation, depletion, and amortization	932		962		2,902		2,845
Other taxes	375		240		1,132		809
Impairments	183		20		287		147
Deepwater Horizon settlement and related costs	4,042	[1]	2	[1]	4,055	[1]	2	[1]
Total	6,825		2,354		11,857		6,801
Operating Income (Loss)	(3,626)		196		(1,729)		1,492
Other (Income) Expense
Interest expense	206		218		642		642
Other (income) expense, net	40		(129)		(2)		(106)
Total	870		110		1,262		140
Income (Loss) Before Income Taxes	(4,496)		86		(2,991)		1,352
Income Tax Expense (Benefit)	(1,468)		94		(762)		660
Net Income (Loss)	(3,028)		(8)		(2,229)		692
Net Income Attributable to Noncontrolling Interests	23		18		62		42
Net Income (Loss) Attributable to Common Stockholders	(3,051)		(26)		(2,291)		650
Per Common Share:
Net income (loss) attributable to common stockholders - basic	$ (6.12)		$ (0.05)		$ (4.60)		$ 1.30
Net income (loss) attributable to common stockholders - diluted	$ (6.12)		$ (0.05)		$ (4.60)		$ 1.30
Average Number of Common Shares Outstanding - Basic	498		496		498		495
Average Number of Common Shares Outstanding - Diluted	498		496		498		496
Dividends (per Common Share)	$ 0.09		$ 0.09		$ 0.27		$ 0.27
Commodity Contract [Member] | (Gains) Losses on Commodity Derivatives, Net [Member]
(Gains) losses on derivative instruments, net	(230)		(200)		(317)		(1,052)
Interest Rate Contract and Other [Member] | (Gains) Losses on Other Derivatives, Net [Member]
(Gains) losses on derivative instruments, net	$ 854		$ 221		$ 939		$ 656

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

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Deepwater Horizon Events - Liability Accrual, OA Liabilities, and OPA-Related Environmental Costs (Detail) (USD $)	Sep. 30, 2011	Sep. 30, 2011 Deepwater Horizon [Member] Oil Pollution Act of 1990 [Member]	Oct. 25, 2011 Deepwater Horizon [Member] Oil Pollution Act of 1990 [Member] BP Exploration and Production Inc. [Member]	Sep. 30, 2011 Deepwater Horizon [Member] BP Settlement Agreement [Member]	Sep. 30, 2011 Deepwater Horizon [Member] BP Settlement Agreement [Member] BP indemnification liability [Member]
Loss Contingencies [Line Items]
Deepwater Horizon settlement and related costs	$ 4,017,000,000			$ 4,000,000,000
Loss contingency accrual at carrying value		0			0
Gross OPA-related environmental costs, minimum, excluding amounts BP has already funded, amounts that cannot reasonably be estimated by BP, and non-OPA-related fines and penalties			7,000,000,000
Gross OPA-related environmental costs, maximum, excluding amounts BP has already funded, amounts that cannot reasonably be estimated by BP, and non-OPA-related fines and penalties			$ 11,000,000,000
Allocable percentage share of gross OPA-related environmental costs		0.00%

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Effect of Derivative Instruments - Statement of Income Table (Detail) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Derivative [Line Items]
Unrealized (gains) losses on derivatives, net					$ 767		$ (66)
Commodity Contract [Member] | (Gains) Losses on Commodity Derivatives, Net [Member] | Nondesignated [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	(71)		(157)		(155)		(339)
Unrealized (gains) losses on derivatives, net	(159)		(43)		(162)		(713)
Derivative (Gain) Loss, net	(230)		(200)		(317)		(1,052)
Commodity Contract [Member] | Nondesignated [Member] | Gathering, Processing, and Marketing Sales [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	1	[1]			17	[1]	1	[1]
Unrealized (gains) losses on derivatives, net	(3)	[1]	(4)	[1]	(8)	[1]	(9)	[1]
Derivative (Gain) Loss, net	(2)	[1]	(4)	[1]	9	[1]	(8)	[1]
Interest Rate Contract and Other [Member] | (Gains) Losses on Other Derivatives, Net [Member] | Nondesignated [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net					2
Unrealized (gains) losses on derivatives, net	854		221		937		656
Derivative (Gain) Loss, net	854		221		939		656
Nondesignated [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	(70)		(157)		(136)		(338)
Unrealized (gains) losses on derivatives, net	692	[2]	174	[2]	767	[2]	(66)	[2]
Derivative (Gain) Loss, net	622		17		631		(404)
Commodity Contract [Member] | (Gains) Losses on Commodity Derivatives, Net [Member]
Derivative [Line Items]
Derivative (Gain) Loss, net	(230)		(200)		(317)		(1,052)
Interest Rate Contract and Other [Member] | (Gains) Losses on Other Derivatives, Net [Member]
Derivative [Line Items]
Derivative (Gain) Loss, net	$ 854		$ 221		$ 939		$ 656

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

[2] In the fourth quarter of 2010, the Company revised the definition of Adjusted EBITDAX to exclude the impact of unrealized (gains) losses on derivative instruments, net. The prior periods have been adjusted to reflect this change.

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Commitments - Additional Information (Detail) (USD $)	9 Months Ended	18 Months Ended	11 Months Ended
	Sep. 30, 2011 Drilling rigs commitment [Member]	Oct. 16, 2011 Deepwater Horizon [Member] Operating Agreement [Member] BP Exploration and Production Inc. [Member]	Nov. 30, 2011 Deepwater Horizon [Member] BP Settlement Agreement [Member]
Operating Leased Assets [Line Items]
Operating leases, period	5 years
Operating lease obligations	$ 1,200,000,000
Operating leases, future minimum payment, due in 2013	30,000,000
Operating leases, future minimum payment, due in 2014	209,000,000
Operating leases, future minimum payment, due in 2015	238,000,000
Operating leases, future minimum payments, due thereafter	715,000,000
Loss Contingencies [Line Items]
Payments for Deepwater Horizon settlement costs			4,000,000,000
Amounts invoiced to Anadarko by BP for costs related to the Deepwater Horizon incident		$ 6,100,000,000

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Pension and Other Postretirement Benefit Costs Table (Detail) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Pension Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	$ 20	$ 17	$ 59	$ 52
Interest cost	21	21	64	63
Expected return on plan assets	(21)	(21)	(64)	(62)
Amortization of net actuarial loss (gain)	22	14	64	49
Amortization of net prior service cost (credit)		1	1	2
Net periodic benefit cost	42	32	124	104
Other Postretirement Benefit Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	3	3	7	7
Interest cost	4	4	12	12
Amortization of net actuarial loss (gain)		(1)		(2)
Amortization of net prior service cost (credit)				(1)
Net periodic benefit cost	$ 7	$ 6	$ 19	$ 16

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Derivative Instruments Related to Natural Gas Production and Processing Activities Table (Detail) (Natural Gas [Member])	Sep. 30, 2011
Contracted Commodities in 2011 [Member] | Three-Way Collars [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments	480
Contracted Commodities in 2011 [Member] | Three-Way Collars [Member] | Call Options Sold [Member]
Average price per MMBtu
Average ceiling price	8.29
Contracted Commodities in 2011 [Member] | Three-Way Collars [Member] | Put Options Purchased [Member]
Average price per MMBtu
Average floor price	6.50
Contracted Commodities in 2011 [Member] | Three-Way Collars [Member] | Put Options Sold [Member]
Average price per MMBtu
Average floor price	5.00
Contracted Commodities in 2011 [Member] | Fixed-Price Contracts [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments	90
Average price per MMBtu
Average price per MMBtu	6.17
Contracted Commodities in 2011 [Member] | Basis Swaps [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments	45
Average price per MMBtu
Average price per MMBtu	(1.74)
Contracted Commodities in 2012 [Member] | Three-Way Collars [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments	500
Contracted Commodities in 2012 [Member] | Three-Way Collars [Member] | Call Options Sold [Member]
Average price per MMBtu
Average ceiling price	9.03
Contracted Commodities in 2012 [Member] | Three-Way Collars [Member] | Put Options Purchased [Member]
Average price per MMBtu
Average floor price	6.50
Contracted Commodities in 2012 [Member] | Three-Way Collars [Member] | Put Options Sold [Member]
Average price per MMBtu
Average floor price	5.00
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

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Derivative Instruments Related to Crude Oil Production and Processing Activities Table (Detail) (Three-Way Collars [Member], Crude Oil [Member])	Sep. 30, 2011
Contracted Commodities in 2011 [Member] | Call Options Sold [Member]
Average price per barrel
Average ceiling price	99.95
Contracted Commodities in 2011 [Member] | Put Options Purchased [Member]
Average price per barrel
Average floor price	79.29
Contracted Commodities in 2011 [Member] | Put Options Sold [Member]
Average price per barrel
Average floor price	64.29
Contracted Commodities in 2011 [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments	126
Contracted Commodities in 2012 [Member] | Call Options Sold [Member]
Average price per barrel
Average ceiling price	92.50
Contracted Commodities in 2012 [Member] | Put Options Purchased [Member]
Average price per barrel
Average floor price	50.00
Contracted Commodities in 2012 [Member] | Put Options Sold [Member]
Average price per barrel
Average floor price	35.00
Contracted Commodities in 2012 [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments	2

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Debt and Interest Expense - Western Gas Partners, LP (Detail) (USD $) Share data in Millions	9 Months Ended		1 Months Ended		3 Months Ended	1 Months Ended		1 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 Western Gas Partners Limited Partnership [Member]	Mar. 31, 2011 Western Gas Partners Limited Partnership [Member]	Mar. 31, 2011 Western Gas Partners Limited Partnership [Member] Four Hundred Fifty Million Dollar Revolving Credit Facility [Member]	Mar. 31, 2011 Western Gas Partners Limited Partnership [Member] Eight Hundred Million Dollar Revolving Credit Facility [Member]	Sep. 30, 2011 Western Gas Partners Limited Partnership [Member] Eight Hundred Million Dollar Revolving Credit Facility [Member]	Mar. 31, 2011 Western Gas Partners Limited Partnership [Member] Eight Hundred Million Dollar Revolving Credit Facility [Member] Repayment of Term Loan [Member]
Line of Credit Facility [Line Items]
Line of credit, additional borrowings					$ 310,000,000			$ 250,000,000
Line of credit facility, period						5 years
Line of credit, maximum borrowing capacity					450,000,000		800,000,000
Line of credit facility, repayment					139,000,000
Common units issued to the public			6	4
Proceeds raised from offering by subsidiary	328,000,000	97,000,000	198,000,000	130,000,000
Line of credit, outstanding borrowings							0
Line of credit, remaining borrowing capacity							$ 800,000,000

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Deepwater Horizon Events - Other Contingencies (Detail) (Deepwater Horizon [Member], USD $)	Oct. 31, 2011	Sep. 30, 2011 Clean Water Act [Member]
Loss Contingencies [Line Items]
Penalties or fines assessed against the Company	$ 0
Loss contingency accrual at carrying value		$ 0