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, 2013

or

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

EXCHANGE ACT OF 1934

For the transition period fromto

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  ý    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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  ý    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  ý    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  ý

The number of shares outstanding of the Company’s common stock at October 31, 2013, is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.10 per share	503,266,938

TABLE OF CONTENTS

PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2013 and 2012	2
	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2013 and 2012	3
	Consolidated Balance Sheets at September 30, 2013, and December 31, 2012	4
	Consolidated Statement of Equity for the Nine Months Ended September 30, 2013	5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	45
PART II
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 6.	Exhibits	48

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	2013			2012			2013			2012
Revenues and Other
Natural-gas sales	$	805		$	613		$	2,547		$	1,682
Oil and condensate sales	2,389			2,163			6,761			6,629
Natural-gas liquids sales	325			289			889			913
Gathering, processing, and marketing sales	270			218			750			671
Gains (losses) on divestitures and other, net	64			49			296			106
Total	3,853			3,332			11,243			10,001
Costs and Expenses
Oil and gas operating	277			241			769			732
Oil and gas transportation and other	255			247			763			710
Exploration	272			297			714			1,662
Gathering, processing, and marketing	217			185			638			552
General and administrative	255			285			787			816
Depreciation, depletion, and amortization	996			979			2,958			2,936
Other taxes	294			267			819			970
Impairments	593			4			632			166
Algeria exceptional profits tax settlement	—			7			33			(1,797		)
Deepwater Horizon settlement and related costs	5			4			12			15
Total	3,164			2,516			8,125			6,762
Operating Income (Loss)	689			816			3,118			3,239
Other (Income) Expense
Interest expense	177			185			513			561
(Gains) losses on derivatives, net	72			251			(393		)	(77		)
Other (income) expense, net	(23		)	(10		)	69			(264		)
Total	226			426			189			220
Income (Loss) Before Income Taxes	463			390			2,929			3,019
Income tax expense (benefit)	240			248			1,263			764
Net Income (Loss)	223			142			1,666			2,255
Net income attributable to noncontrolling interests	41			21			95			67
Net Income (Loss) Attributable to Common Stockholders	$	182		$	121		$	1,571		$	2,188
Per Common Share
Net income (loss) attributable to common stockholders—basic	$	0.36		$	0.24		$	3.11		$	4.35
Net income (loss) attributable to common stockholders—diluted	$	0.36		$	0.24		$	3.10		$	4.34
Average Number of Common Shares Outstanding—Basic	503			500			502			499
Average Number of Common Shares Outstanding—Diluted	505			502			504			501
Dividends (per Common Share)	$	0.18		$	0.09		$	0.36		$	0.27

See accompanying Notes to Consolidated Financial Statements.

2

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions	2013		2012		2013		2012
Net Income (Loss)	$	223	$	142	$	1,666	$	2,255
Other Comprehensive Income (Loss), net of taxes
Reclassification of previously deferred derivative losses to    (gains) losses on derivatives, net (1)	2		2		5		6
Adjustments for pension and other postretirement plans
Amortization of net actuarial (gain) loss to general and    administrative expense (2)	18		15		56		44
Amortization of net prior service (credit) cost to general and    administrative expense	1		—		1		1
Total adjustments for pension and other postretirement plans	19		15		57		45
Total	21		17		62		51
Comprehensive Income (Loss)	244		159		1,728		2,306
Comprehensive income attributable to noncontrolling interests	41		21		95		67
Comprehensive Income (Loss) Attributable to Common Stockholders	$	203	$	138	$	1,633	$	2,239

 __________________________________________________________________

⁽¹⁾  Net of income tax benefit (expense) of $(1) million for the three months ended September 30, 2013, $(1) million for the three months ended September 30, 2012, $(3) million for the nine months ended September 30, 2013, and $(3) million for the nine months ended September 30, 2012.

⁽²⁾  Net of income tax benefit (expense) of $(11) million for the three months ended September 30, 2013, $(8) million for the three months ended September 30, 2012, $(32) million for the nine months ended September 30, 2013, and $(25) million for the nine months ended September 30, 2012.

See accompanying Notes to Consolidated Financial Statements.

3

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,			December 31,
millions	2013			2012
ASSETS
Current Assets
Cash and cash equivalents	$	3,939		$	2,471
Accounts receivable (net of allowance of $6 million and $7 million)
Customers	1,266			1,473
Others	1,199			1,274
Algeria exceptional profits tax settlement	—			730
Other current assets	736			847
Total	7,140			6,795
Properties and Equipment
Cost	69,167			63,598
Less accumulated depreciation, depletion, and amortization	28,682			25,200
Net properties and equipment	40,485			38,398
Other Assets	2,006			1,716
Goodwill and Other Intangible Assets	5,663			5,680
Total Assets	$	55,294		$	52,589
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	3,070		$	2,989
Current asset retirement obligations	311			298
Accrued expenses	1,357			707
Total	4,738			3,994
Long-term Debt	13,647			13,269
Other Long-term Liabilities
Deferred income taxes	9,372			8,759
Asset retirement obligations	1,673			1,587
Other	1,963			3,098
Total	13,008			13,444
Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 521.7 million and 518.6 million shares issued)	52			51
Paid-in capital	8,521			8,230
Retained earnings	15,218			13,829
Treasury stock (18.5 million and 18.1 million shares)	(871		)	(841		)
Accumulated other comprehensive income (loss)	(578		)	(640		)
Total Stockholders’ Equity	22,342			20,629
Noncontrolling interests	1,559			1,253
Total Equity	23,901			21,882
Total Liabilities and Equity	$	55,294		$	52,589

See accompanying Notes to Consolidated Financial Statements.

4

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

	Total Stockholders’ Equity
	Common Stock		Paid-in Capital		Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests			Total Equity
millions
Balance at December 31, 2012	$	51	$	8,230	$	13,829		$	(841	)	$	(640	)	$	1,253		$	21,882
Net income (loss)	—		—		1,571			—			—			95			1,666
Common stock issued	1		230		—			—			—			—			231
Dividends—common stock	—		—		(182		)	—			—			—			(182		)
Repurchase of common stock	—		—		—			(30		)	—			—			(30		)
Subsidiary equity transactions (1)	—		61		—			—			—			320			381
Distributions to noncontrolling interest owners	—		—		—			—			—			(111		)	(111		)
Contributions from noncontrolling interest owners	—		—		—			—			—			2			2
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—		—			—			5			—			5
Adjustments for pension and other postretirement plans	—		—		—			—			57			—			57
Balance at September 30, 2013	$	52	$	8,521	$	15,218		$	(871	)	$	(578	)	$	1,559		$	23,901

 __________________________________________________________________

⁽¹⁾  The $61 millionincrease to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders totaled $1,632 million for the nine months ended September 30, 2013.

See accompanying Notes to Consolidated Financial Statements.

5

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended   September 30,
millions	2013			2012
Cash Flows from Operating Activities
Net income (loss)	$	1,666		$	2,255
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, and amortization	2,958			2,936
Deferred income taxes	535			95
Dry hole expense and impairments of unproved properties	423			1,389
Impairments	632			166
(Gains) losses on divestitures, net	(165		)	23
Unrealized (gains) losses on derivatives, net	(359		)	539
Other	174			174
Changes in assets and liabilities
Deepwater Horizon settlement and related costs	3			25
Algeria exceptional profits tax settlement	730			(1,183		)
Tronox-related contingent loss	—			(250		)
(Increase) decrease in accounts receivable	246			409
Increase (decrease) in accounts payable and accrued expenses	(37		)	(486		)
Other items—net	(22		)	27
Net cash provided by (used in) operating activities	6,784			6,119
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	(5,327		)	(5,448		)
Acquisition of businesses	(473		)	—
Divestitures of properties and equipment and other assets	451			440
Other—net	(552		)	(188		)
Net cash provided by (used in) investing activities	(5,901		)	(5,196		)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	843			885
Repayments of debt	(495		)	(2,005		)
Increase (decrease) in outstanding checks	63			12
Dividends paid	(182		)	(136		)
Repurchase of common stock	(30		)	(26		)
Issuance of common stock, including tax benefit on share-based compensation awards	123			68
Sale of subsidiary units	418			212
Distributions to noncontrolling interest owners	(111		)	(81		)
Contributions from noncontrolling interest owners	2			14
Net cash provided by (used in) financing activities	631			(1,057		)
Effect of Exchange Rate Changes on Cash	(46		)	(31		)
Net Increase (Decrease) in Cash and Cash Equivalents	1,468			(165		)
Cash and Cash Equivalents at Beginning of Period	2,471			2,697
Cash and Cash Equivalents at End of Period	$	3,939		$	2,532

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, treating, and transporting of natural gas, crude oil, and NGLs. 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 at September 30, 2013, and December 31, 2012, the Consolidated Statements of Income and Comprehensive Income for the three and nine months ended September 30, 2013 and 2012, the Consolidated Statements of Cash Flows for the nine months endedSeptember 30, 2013 and 2012, and the Consolidated Statement of Equity for the nine months ended September 30, 2013. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

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

2. Inventories

       The following summarizes the major classes of inventories included in other current assets:

	September 30,		December 31,
millions	2013		2012
Crude oil	$	102	$	91
Natural gas	41		48
NGLs	66		37
Total	$	209	$	176

3. Acquisitions and Divestitures

Acquisitions    Anadarko and Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, made several unrelated acquisitions during the nine months ended September 30, 2013. In March 2013, WES acquired a 33.75% interest in gas-gathering systems located in the Marcellus shale in north-central Pennsylvania for $135 million. In June 2013, WES acquired a 25% interest in a joint venture formed to design, construct, and own two fractionators located in Mont Belvieu, Texas for $78 million. In August 2013, Anadarko acquired certain oil and gas properties and related assets in the Moxa area of Wyoming for $310 million, including $306 million that represents the fair value of the oil and gas properties acquired. In September 2013, WES acquired an intrastate pipeline in southwestern Wyoming for $28 million.

Divestitures    For the nine months ended September 30, 2013, proceeds from divestitures of $451 million and net gains on divestitures of $165 million were primarily related to the Company’s divestiture of its interests in a soda ash joint venture during the first quarter of 2013. In August 2013, the Company entered into a definitive agreement to sell a 10% working interest in Mozambique’s Offshore Area 1 for $2.64 billion. The transaction is subject to governmental approvals and other customary closing conditions, and is expected to close in late 2013 or early 2014.

7

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4. Impairments

       The following summarizes impairments by segment:

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions	2013		2012		2013		2012
Oil and gas exploration and production
Long-lived assets held for use
U.S. onshore properties	$	—	$	2	$	—	$	81
Gulf of Mexico properties	593		—		593		67
Cost-method investment	—		1		10		12
Midstream
Long-lived assets held for use	—		1		29		6
Impairments	$	593	$	4	$	632	$	166

       During the third quarter of 2013, certain Gulf of Mexico properties were impaired due to a reduction in estimated future net cash flows per barrel and downward revisions of reserves that the Company no longer plans to develop. The Company impaired its Venezuelan cost-method investment in 2013 and 2012 due to declines in estimated recoverable value. In addition, a midstream property was impaired during 2013 due to a reduction in estimated future cash flows. In 2012, certain U.S. onshore and midstream properties were impaired primarily due to lower natural-gas prices and a Gulf of Mexico property was impaired as a result of downward reserves revisions for a property that was near the end of its economic life.

       The following summarizes the post-impairment fair value of the above-described assets, by asset category and input level within the fair-value hierarchy:

millions
2013	Level 1		Level 2		Level 3 (1)		Total
Long-lived assets held for use	$	—	$	—	$	266	$	266
Cost-method investment (2)	—		—		32		32
2012
Long-lived assets held for use	$	—	$	—	$	38	$	38
Cost-method investment (2)	—		—		34		34

 __________________________________________________________________

⁽¹⁾  The income approach was used to measure fair value.

⁽²⁾  This represents the Company’s after-tax net investment.

5. Suspended Exploratory Well Costs

       The Company’s suspended exploratory well costs were $2.2 billion at September 30, 2013, and $2.1 billion at December 31, 2012. The increase in suspended exploratory well costs during 2013 is primarily related to the capitalization of costs associated with successful exploration drilling in the Gulf of Mexico, Brazil, and Mozambique. Management believes projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development and is actively pursuing efforts to assess whether reserves can be attributed to these projects. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time. During the nine months ended September 30, 2013, $95 million of exploratory well costs previously capitalized as suspended exploratory well costs for greater than one year at December 31, 2012, were charged to dry hole expense.

8

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. Noncontrolling Interests

       Western Gas Equity Partners, LP (WGP) is a consolidated subsidiary formed by Anadarko to own partnership interests in WES. At September 30, 2013, Anadarko’s ownership interest in WGP consisted of a 91.0% limited partner interest and the entire general partner interest.

       WES is a limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. During 2013, WES has issued approximately seven million common units to the public, raising net proceeds of $419 million. At September 30, 2013, WGP’s ownership interest in WES consisted of a 43.1% limited partner interest, the entire 2.0% general partner interest, and all WES incentive distribution rights. At September 30, 2013, Anadarko also owned a 0.4% limited partner interest in WES through another subsidiary.

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, Louisiana for natural gas and Cushing, Oklahoma or Sullom Voe, Scotland for oil. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).

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

       The Company does not apply hedge accounting to any of its derivative instruments. As a result, both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings. Net derivative losses attributable to interest-rate 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. See Note 10—Accumulated Other Comprehensive Income (Loss).

9

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities    The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are a combination of NYMEX West Texas Intermediate (WTI) and IntercontinentalExchange, Inc. (ICE) Brent prices. The following is a summary of the Company’s derivative instruments related to its Oil and Natural-Gas Production/Processing Derivative Activities at September 30, 2013:

	2013 Settlement			2014 Settlement
Natural Gas
Two-Way Collars (thousand MMBtu/d)	600		(1)	—
Average price per MMBtu
Ceiling sold price (call)	$	4.00		$	—
Floor purchased price (put)	$	3.18		$	—
Three-Way Collars (thousand MMBtu/d)	—		(2)	600
Average price per MMBtu
Ceiling sold price (call)	$	—		$	5.01
Floor purchased price (put)	$	—		$	3.75
Floor sold price (put)	$	—		$	2.75
Fixed-Price Contracts (thousand MMBtu/d)	1,185			600
Average price per MMBtu	$	4.00		$	4.26
Crude Oil
Three-Way Collars (MBbls/d)	26			—
Average price per barrel
Ceiling sold price (call)	$	125.15		$	—
Floor purchased price (put)	$	105.00		$	—
Floor sold price (put)	$	85.00		$	—
Fixed-Price Contracts (MBbls/d)	167			—
Average price per barrel	$	102.74		$	—

__________________________________________________________________

⁽¹⁾  The two-way collars have a contract term of April 2013 to October 2013.

⁽²⁾  The Company entered into offsetting purchased and sold natural-gas three-way collars of 450,000 MMBtu/d for 2013 settlement.

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

       A two-way collar is a combination of two options: a sold call and a purchased 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.

       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.

10

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Derivative Instruments (Continued)

Marketing and Trading Derivative Activities    In addition to the positions in the previous table, the Company also engages in marketing and trading activities. These activities include physical product sales and related fixed-to-floating derivative transactions used to manage commodity-price risk. At September 30, 2013, and December 31, 2012, the Company had fixed-price physical transactions related to natural gas totaling 10 billion cubic feet (Bcf), offset by fixed-to-floating derivative transactions totaling 10 Bcf.

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

       The Company had the following outstanding interest-rate swaps at September 30, 2013:

millions except percentages		Reference Period		Weighted-Average
Notional Principal Amount		Start	End	Interest Rate
$	750	June 2014	June 2024	6.00%
$	1,100	June 2014	June 2044	5.57%
$	50	September 2016	September 2026	5.91%
$	750	September 2016	September 2046	5.86%

Effect of Derivative Instruments—Balance Sheet    The following summarizes the fair value of the Company’s derivative instruments:

	Gross Derivative Assets				Gross Derivative Liabilities
millions	September 30,		December 31,		September 30,			December 31,
Balance Sheet Classification	2013		2012		2013			2012
Commodity derivatives
Other current assets	$	359	$	475	$	(170	)	$	(197	)
Other assets	50		24		(13		)	(7		)
Accrued expenses	48		6		(61		)	(14		)
Other liabilities	—		1		(2		)	(7		)
	457		506		(246		)	(225		)
Interest-rate and other derivatives
Accrued expenses (1)	—		—		(550		)	—
Other liabilities (1)	—		—		(215		)	(1,194		)
	—		—		(765		)	(1,194		)
Total derivatives	$	457	$	506	$	(1,011	)	$	(1,419	)

 __________________________________________________________________

⁽¹⁾ Interest-rate swaps with June 2014 maturity dates were reclassified from other liabilities to accrued expenses during the second quarter of 2013.

11

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Derivative Instruments (Continued)

Effect of Derivative Instruments—Statement of Income    The following summarizes realized and unrealized gains and losses related to derivative instruments:

millions	Three Months Ended   September 30, 2013									Nine Months Ended   September 30, 2013
Classification of (Gain) Loss Recognized	Realized			Unrealized			Total			Realized			Unrealized			Total
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	2		$	(10	)	$	(8	)	$	9		$	(12	)	$	(3	)
(Gains) losses on derivatives, net	26			120			146			(46		)	81			35
Interest-rate and other derivatives
(Gains) losses on derivatives, net	—			(74		)	(74		)	—			(428		)	(428		)
Total (gains) losses on derivatives, net	$	28		$	36		$	64		$	(37	)	$	(359	)	$	(396	)
	Three Months Ended   September 30, 2012									Nine Months Ended   September 30, 2012
Classification of (Gain) Loss Recognized	Realized			Unrealized			Total			Realized			Unrealized			Total
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	3		$	5		$	8		$	—		$	18		$	18
(Gains) losses on derivatives, net	(200		)	437			237			(600		)	369			(231		)
Interest-rate and other derivatives
(Gains) losses on derivatives, net	—			14			14			2			152			154
Total (gains) losses on derivatives, net	$	(197	)	$	456		$	259		$	(598	)	$	539		$	(59	)

__________________________________________________________________

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

Credit-Risk Considerations    The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on fair value of its counterparties’ creditworthiness. 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 derivative types. At September 30, 2013, $305 million of the Company’s $1.0 billion gross derivative liability balance, and at December 31, 2012, $339 million of the Company’s $1.4 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types.

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

12

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Derivative Instruments (Continued)

       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 from major credit rating agencies declining to a level below investment grade. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $52 million (net of collateral) at September 30, 2013, and $94 million (net of collateral) at December 31, 2012. The current portion of these amounts was included in accrued expenses and the long-term portion of these amounts was included in other long-term liabilities—other 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 summarizes the fair value of the Company’s derivative assets and liabilities, by input level within the fair-value hierarchy:

millions
September 30, 2013	Level 1			Level 2			Level 3		Netting (1)			Collateral			Total
Assets
Commodity derivatives
Financial institutions	$	4		$	379		$	—	$	(226	)	$	(1	)	$	156
Other counterparties	—			74			—		(6		)	—			68
Total derivative assets	$	4		$	453		$	—	$	(232	)	$	(1	)	$	224
Liabilities
Commodity derivatives
Financial institutions	$	(4	)	$	(232	)	$	—	$	226		$	1		$	(9	)
Other counterparties	—			(10		)	—		6			—			(4		)
Interest-rate and other derivatives	—			(765		)	—		—			—			(765		)
Total derivative liabilities	$	(4	)	$	(1,007	)	$	—	$	232		$	1		$	(778	)
December 31, 2012
Assets
Commodity derivatives
Financial institutions	$	6		$	453		$	—	$	(206	)	$	—		$	253
Other counterparties	—			47			—		(5		)	—			42
Total derivative assets	$	6		$	500		$	—	$	(211	)	$	—		$	295
Liabilities
Commodity derivatives
Financial institutions	$	(6	)	$	(202	)	$	—	$	206		$	1		$	(1	)
Other counterparties	—			(17		)	—		5			—			(12		)
Interest-rate and other derivatives	—			(1,194		)	—		—			—			(1,194		)
Total derivative liabilities	$	(6	)	$	(1,413	)	$	—	$	211		$	1		$	(1,207	)

 __________________________________________________________________

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

13

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Debt and Interest Expense

Debt    The Company’s outstanding debt is senior unsecured, except for borrowings, if any, under the $5.0 billion Facility. The following summarizes the Company’s outstanding debt:

	September 30,			December 31,
millions	2013			2012
Total debt at face value	$	15,302		$	14,952
Net unamortized discounts and premiums (1)	(1,655		)	(1,683		)
Total long-term debt	$	13,647		$	13,269

__________________________________________________________________

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

       Anadarko’s $500 million aggregate principal amount of 7.625% Senior Notes due March 2014 and $275 million aggregate principal amount of 5.750% Senior Notes due June 2014 are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance these obligations using long-term debt. The Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, which would cause the Company to repay up to the then-accreted value of the outstanding Zero Coupons. None of the Zero Coupons (accreted value of $718 million) were put to the Company in October 2013.

Fair Value    The Company uses a market approach to determine fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $15.8 billion at September 30, 2013, and $16.2 billion at December 31, 2012.

Debt Activity    The following summarizes the Company’s debt activity during the nine months ended September 30,2013:

	Carrying
millions	Value			Description
Balance at December 31, 2012	$	13,269
Borrowings	385			WES revolving credit facility
Other, net	9			Amortization of debt discounts and premiums
Balance at March 31, 2013	$	13,663
Borrowings	110			WES revolving credit facility
Repayments	(245		)	WES revolving credit facility
Other, net	10			Amortization of debt discounts and premiums
Balance at June 30, 2013	$	13,538
Issuance	250			WES 2.600% Senior Notes due 2018
Borrowings	100			WES revolving credit facility
Repayments	(250		)	WES revolving credit facility
Other, net	9			Amortization of debt discounts and premiums
Balance at September 30, 2013	$	13,647

WES Borrowings    During the third quarter of 2013, WES repaid $250 million of outstanding borrowings under its five-year, $800 million senior unsecured revolving credit facility maturing in March 2016 (RCF) with net proceeds from its public offering of $250 million aggregate principal amount of 2.600% Senior Notes due 2018. At September 30, 2013, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $100 million at an interest rate of 1.68%, and had available borrowing capacity of $687 million ($800 million maximum capacity, less $100 million of outstanding borrowings and $13 million of outstanding letters of credit).

14

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Debt and Interest Expense (Continued)

Interest Expense    The following summarizes interest expense:

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions	2013			2012			2013			2012
Current debt, long-term debt, and other	$	240		$	238		$	710		$	724
Capitalized interest	(63		)	(53		)	(197		)	(163		)
Interest expense	$	177		$	185		$	513		$	561

9. Stockholders’ Equity

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

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions except per-share amounts	2013		2012		2013		2012
Net income (loss)
Net income (loss) attributable to common stockholders	$	182	$	121	$	1,571	$	2,188
Less distributions on participating securities	—		—		1		1
Less undistributed income allocated to participating securities	1		1		9		13
Basic	$	181	$	120	$	1,561	$	2,174
Diluted	$	181	$	120	$	1,561	$	2,174
Shares
Average number of common shares outstanding—basic	503		500		502		499
Dilutive effect of stock options	2		2		2		2
Average number of common shares outstanding—diluted	505		502		504		501
Excluded (1)	3		6		4		6
Net income (loss) per common share
Basic	$	0.36	$	0.24	$	3.11	$	4.35
Diluted	$	0.36	$	0.24	$	3.10	$	4.34
Dividends per common share	$	0.18	$	0.09	$	0.36	$	0.27

 __________________________________________________________________

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

10. Accumulated Other Comprehensive Income (Loss)

       The following summarizes the after-tax changes in the balances of each component of accumulated other comprehensive income (loss):

millions	Interest-rate Derivatives Previously Subject to Hedge Accounting			Pension and Other Postretirement Plans			Total
Balance at December 31, 2012	$	(61	)	$	(579	)	$	(640	)
Reclassifications to Consolidated Statement of Income	5			57			62
Balance at September 30, 2013	$	(56	)	$	(522	)	$	(578	)

15

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Commitments

       In June 2013, the Company entered into a three-year operating lease agreement for a deepwater drillship expected to be delivered in late 2014. The lease obligation totals $464 million, with aggregate future annual minimum lease payments of $33 million in 2014, $154 million in 2015, $155 million in 2016, and $122 million in 2017.

12. Contingencies

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

       The following is a discussion of the material developments with respect to the contingencies previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012, and material matters that have arisen since the filing of such report.

Deepwater Horizon Events    In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% nonoperated interest. In October 2011, the Company and BP entered into a settlement agreement relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against claims and damages arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and other potential damages. This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-upon amount, BP p.l.c. has agreed to become the sole guarantor. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder derivative or securities laws claims, or certain other claims. The Company has not recorded a liability for any costs that are subject to indemnification by BP. For additional disclosure of the Deepwater Horizon events, the Company’s Settlement Agreement with BP, environmental claims under OPA, NRD claims, potential penalties and fines, and civil litigation, see Note 17—Contingencies—Deepwater Horizon Events in the Notes to the Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

Penalties and Fines    In December 2010, the U.S. Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the U.S. District Court in New Orleans, Louisiana (Louisiana District Court) against several parties, including Anadarko, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. In February 2012, the Louisiana District Court entered a declaratory judgment that, as a partial owner of the Macondo well, Anadarko is liable for civil penalties under Section 311 of the CWA. The declaratory judgment addresses liability only, and does not address the amount of any civil penalty. The assessment of a civil penalty against Anadarko has been reserved until a later proceeding to be scheduled by the Louisiana District Court. In August 2012, Anadarko filed a notice of appeal in the U.S. Court of Appeals for the Fifth Circuit concerning that portion of the February 2012 declaratory judgment finding Anadarko liable for civil penalties under the CWA. The appeal is pending and oral arguments are set for December 2013.

16

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Contingencies (Continued)

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

       Applicable accounting guidance requires the Company to accrue a liability if it is probable that a liability is incurred and the amount of the liability can be reasonably estimated. The Louisiana District Court’s declaratory judgment in February 2012 satisfies the requirement that a loss, arising from the future assessment of a civil penalty against Anadarko, is probable. Notwithstanding the declaratory judgment, the Company currently cannot estimate the amount of any potential civil penalty. The CWA sets forth subjective criteria, including degree of fault and history of prior violations, which significantly influence the magnitude of CWA penalty assessments. As a result of the subjective nature of CWA penalty assessments, the Company currently cannot estimate the amount of any such penalty nor determine a range of potential loss. Furthermore, neither the February 2012 settlement of Deepwater Horizon-related civil penalties (including those under the CWA) by the other nonoperating partner with the United States and five affected Gulf states (Texas, Louisiana, Mississippi, Alabama, and Florida) nor the January 2013 settlement of CWA civil and criminal penalties by the drilling contractor with the United States affects the Company’s current conclusion regarding its ability to estimate potential fines and penalties. The Company lacks insight into those settlements, retains legal counsel separate from the other parties, and was not involved in any manner with respect to those settlements. Events or factors that could assist the Company in estimating the amount of any potential civil penalty or a range of potential loss related to such penalties include (i) an assessment by the DOJ, (ii) a ruling by a court of competent jurisdiction, or (iii) the initiation of substantive settlement negotiations between the Company and the DOJ.

       Given the Company’s lack of direct operational involvement in the event, as was reconfirmed by the Louisiana District Court in September 2013, and the subjective criteria of the CWA, the Company believes that its exposure to CWA penalties will not materially impact the Company’s consolidated financial position, results of operations, or cash flows.

Civil Litigation Damage Claims    Numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court. In March 2012, BP and the Plaintiffs’ Steering Committee entered into a tentative settlement agreement to resolve the substantial majority of economic loss and medical claims stemming from the Deepwater Horizon events, which the Louisiana District Court approved in orders issued in December 2012 and January 2013. Only OPA claims seeking economic loss damages against the Company remain. In addition, certain state and local governments have appealed, or have provided indication of a likely appeal of, the MDL court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages, irrespective of whether such claims are based on federal (including OPA) or state law.

       The first phase of the trial in the proceeding filed in the MDL by Transocean Ltd. (Transocean) under the Limitation of Liability Act commenced in February 2013 (Phase I). In April 2013, the evidence closed and all parties rested. Findings of fact, post-trial briefs, and responsive briefs were submitted in July 2013. BP, BP p.l.c., the United States, state and local governments, Halliburton Energy Services, Inc. (Halliburton), and Transocean participated in Phase I of the trial. Anadarko was excused from participation in Phase I of the trial. The issues tried in Phase I included the cause of the blow-out and all related events leading up to April 22, 2010, the date the Deepwater Horizon sank, as well as allocation of fault. The allocation of fault remains in the Phase I trial because Halliburton and Transocean have not settled with any of the parties and each wishes to prove to the court that their respective company was not at fault. The second phase of trial began in September 2013 (Phase II) and in October 2013 the evidence closed and all parties rested. The issues tried in Phase II included spill-source control and quantification of the spill for the period from April 22, 2010, until the well was capped. The Company, BP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean participated in Phase II of the trial. The judge entered an order prior to commencement of the Phase II trial excluding any evidence of Anadarko’s culpability or fault during Phase II of the trial.    

17

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Contingencies (Continued)

       Two separate class action complaints were filed in June and August 2010, in the U.S. District Court for the Southern District of New York (New York District Court) on behalf of purported purchasers of the Company’s stock between June 9, 2009, and June 12, 2010, against Anadarko and certain of its officers. The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. In November 2010, the New York District Court consolidated the two cases. In March 2012, the New York District Court granted the plaintiffs’ motion to transfer venue to the U.S. District Court for the Southern District of Texas - Houston Division (Texas District Court). In May 2012, the Texas District Court granted the defendants’ motion to transfer the consolidated action within the district to Judge Keith P. Ellison. In July 2012, the plaintiffs filed their First Amended Consolidated Class Action Complaint. The defendants filed a renewed motion to dismiss in the Texas District Court in September 2012. In July 2013, the Texas District Court dismissed the claims relating to all but one of the alleged misstatements asserted in the plaintiffs’ complaint. The Texas District Court gave the plaintiffs 30 days to amend the complaint to attempt to rehabilitate the claims that were dismissed. The plaintiffs declined to amend the complaint. The Company filed its answer to the complaint in September 2013.

       In September 2010, a purported shareholder made a demand on the Company’s Board of Directors (the Board) to investigate allegations of breaches of duty by members of management related to the Deepwater Horizon events. The Board received a supplemental demand letter from the shareholder in March 2012. The Board considered each of the demand letters in January 2011 and April 2012 and determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letters. In May 2013, a shareholder derivative petition was filed in the 215^th District Court of Harris County, Texas by the shareholder against Anadarko (as a nominal defendant) and certain current and former directors and officers. The petition alleges breach of fiduciary duties, unjust enrichment, abuse of control, and gross mismanagement in connection with the Deepwater Horizon events. The plaintiff seeks an unspecified amount of damages, certain changes to the Company’s governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs.

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

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

       The Company will continue to monitor the MDL and other legal proceedings discussed above as well as federal investigations related to the Deepwater Horizon events. The Company cannot predict the nature of evidence that may be discovered during the course of legal proceedings or the timing of completion of any legal proceedings.

       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.

18

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Contingencies (Continued)

Tronox Litigation    In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York (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 and seeks, among other things, to recover damages, including interest, in excess of $18.9 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. In accordance with Tronox’s Plan of Reorganization, the Adversary Proceeding is being pursued by the Anadarko Litigation Trust. Pursuant to the Anadarko Litigation Trust Agreement, the Anadarko Litigation Trust was “deemed substituted” for Tronox in the Adversary Proceeding as the party in such litigation. For purposes of this Form 10-Q, references to “Tronox” after February 2011 refer to the Anadarko Litigation Trust. For additional disclosure related to the Tronox Litigation, see Note 17—Contingencies—Tronox Litigation in the Notes to the Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

       The U.S. government was granted authority to intervene in the Adversary Proceeding, and in May 2009 asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act (FDCPA Complaint). Anadarko and Kerr-McGee moved to dismiss the claims of the U.S. government, but that motion has been stayed by the Bankruptcy Court. In April 2012, Anadarko and Kerr-McGee filed an answer to the FDCPA Complaint.

       In February 2012, the Company filed a motion for partial summary judgment seeking dismissal of several claims, including all actual and constructive fraudulent transfer claims protected by Section 546(e) of the Bankruptcy Code. The court has not yet ruled on that issue. Trial began in May 2012 and in September 2012, the evidence closed and both sides rested. In November 2012, the parties filed post-trial briefs and closing arguments were presented in December 2012. The parties filed final post-trial briefs in January 2013. The matter is pending before the court. To date, we have no information concerning the timing or form of decision that can be expected from the Bankruptcy Court in the Adversary Proceeding. Furthermore, Executive Benefits Insurance Agency v. Arkison, a case pending before the U.S. Supreme Court, raises certain legal issues including, but not limited to, whether affirmative consent is required for a bankruptcy court to have authority to enter a final judgment in a fraudulent transfer case. The Company is unable to determine the impact, if any, of this case on the substance or timing of a decision related to the Adversary Proceeding.

       The Company remains confident in the merits of its position and does not believe a loss resulting from litigating the Adversary Proceeding is probable. Accounting guidance requires that contingent losses be probable in nature for loss recognition to be appropriate. Accordingly, the Company’s Consolidated Balance Sheet at September 30, 2013, does not include a loss-contingency liability related to the litigation of the Adversary Proceeding.

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

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

19

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Contingencies (Continued)

Other    During the nine months ended September 30, 2013, the Company recognized a pretax loss of $131 million, reported in other (income) expense, net in the Consolidated Statement of Income, related to the cost to decommission wells and production facilities previously sold to a third party. In June 2013, as a result of a Chapter 11 bankruptcy declaration by the third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of the facility and related wells. These wells and production facilities are no longer owned by the Company nor are they related to its current operations. Anadarko expects to complete decommissioning of the production facilities in 2014 and the wells in 2015. Decommissioning obligations of $44 million were included in accrued expenses and $85 million were included in other long-term liabilities on the Consolidated Balance Sheet at September 30, 2013. Actual costs may vary from this estimate; however, the Company does not believe that such variation will materially impact its consolidated financial position, results of operations, or cash flows.

13. Income Taxes

       The following summarizes income tax expense (benefit) and effective tax rates:

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except percentages	2013			2012			2013			2012
Income tax expense (benefit)	$	240		$	248		$	1,263		$	764
Effective tax rate	52		%	64		%	43		%	25		%

       The increase from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2013, and the three months ended September 30, 2012, was primarily attributable to the tax impact from foreign operations and Algerian exceptional profits taxes. The decrease from the 35% U.S. federal statutory rate for the nine months ended September 30, 2012, was primarily attributable to the non-taxable resolution of the Algeria exceptional profits tax dispute, partially offset by the tax impact from foreign operations and Algerian exceptional profits taxes.

14. Supplemental Cash Flow Information

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

	Nine Months Ended   September 30,
millions	2013		2012
Cash paid (received)
Interest	$	569	$	613
Income taxes	$	137	$	(13	)
Non-cash investing activities
Fair value of properties and equipment received in non-cash exchange transactions	$	13	$	65

15. Segment Information

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

20

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information (Continued)

       To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; interest expense; unrealized (gains) losses on derivatives, net; realized (gains) losses on interest-rate and other derivatives, net; and certain items not related to the Company’s normal operations, less net income attributable to noncontrolling interests. During the periods presented, these items included Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Finally, unrealized (gains) losses on derivatives, net and realized (gains) losses on interest-rate and other derivatives, net are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance.

       Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders. Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income or cash flows from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:

	Three Months Ended   September 30,					Nine Months Ended   September 30,
millions	2013			2012		2013			2012
Income (loss) before income taxes	$	463		$	390	$	2,929		$	3,019
Exploration expense	272			297		714			1,662
DD&A	996			979		2,958			2,936
Impairments	593			4		632			166
Interest expense	177			185		513			561
Unrealized (gains) losses on derivatives, net	36			456		(359		)	539
Realized (gains) losses on interest-rate and other derivatives, net	—			—		—			2
Deepwater Horizon settlement and related costs	5			4		12			15
Algeria exceptional profits tax settlement	—			7		33			(1,797		)
Tronox-related contingent loss	—			—		—			(250		)
Certain other nonoperating items	(10		)	—		75			—
Less net income attributable to noncontrolling interests	41			21		95			67
Consolidated Adjusted EBITDAX	$	2,491		$	2,301	$	7,412		$	6,786

21

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information (Continued)

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

millions	Oil and Gas Exploration & Production		Midstream			Marketing			Other and Intersegment Eliminations			Total
Three Months Ended September 30, 2013
Sales revenues	$	1,916	$	95		$	1,778		$	—		$	3,789
Intersegment revenues	1,516		287			(1,629		)	(174		)	—
Gains (losses) on divestitures and other, net	7		—			—			57			64
Total revenues and other	3,439		382			149			(117		)	3,853
Operating costs and expenses (1)	930		216			164			(12		)	1,298
Realized (gains) losses on commodity    derivatives, net	—		—			—			26			26
Other (income) expense, net (2)	—		—			—			(13		)	(13		)
Net income attributable to noncontrolling interests	—		41			—			—			41
Total expenses and other	930		257			164			1			1,352
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—		—			(10		)	—			(10		)
Adjusted EBITDAX	$	2,509	$	125		$	(25	)	$	(118	)	$	2,491
Three Months Ended September 30, 2012
Sales revenues	$	1,393	$	80		$	1,810		$	—		$	3,283
Intersegment revenues	1,587		232			(1,682		)	(137		)	—
Gains (losses) on divestitures and other, net	12		(6		)	—			43			49
Total revenues and other	2,992		306			128			(94		)	3,332
Operating costs and expenses (1)	840		182			152			51			1,225
Realized (gains) losses on commodity    derivatives, net	—		—			—			(200		)	(200		)
Other (income) expense, net (2)	—		—			—			(10		)	(10		)
Net income attributable to noncontrolling interests	—		21			—			—			21
Total expenses and other	840		203			152			(159		)	1,036
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—		—			5			—			5
Adjusted EBITDAX	$	2,152	$	103		$	(19	)	$	65		$	2,301

 __________________________________________________________________

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

⁽²⁾   Other (income) expense, net excludes Tronox-related contingent loss and certain other nonoperating items since these expenses are excluded from Adjusted EBITDAX.

22

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information (Continued)

millions	Oil and Gas Exploration & Production			Midstream			Marketing			Other and Intersegment Eliminations			Total
Nine Months Ended September 30, 2013
Sales revenues	$	5,044		$	267		$	5,636		$	—		$	10,947
Intersegment revenues	4,904			805			(5,234		)	(475		)	—
Gains (losses) on divestitures and other, net	12			—			—			284			296
Total revenues and other	9,960			1,072			402			(191		)	11,243
Operating costs and expenses (1)	2,656			613			492			15			3,776
Realized (gains) losses on commodity    derivatives, net	—			—			—			(46		)	(46		)
Other (income) expense, net (2)	—			—			—			(6		)	(6		)
Net income attributable to noncontrolling interests	—			95			—			—			95
Total expenses and other	2,656			708			492			(37		)	3,819
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—			—			(12		)	—			(12		)
Adjusted EBITDAX	$	7,304		$	364		$	(102	)	$	(154	)	$	7,412
Nine Months Ended September 30, 2012
Sales revenues	$	5,180		$	248		$	4,467		$	—		$	9,895
Intersegment revenues	3,796			701			(4,101		)	(396		)	—
Gains (losses) on divestitures and other, net	(17		)	(8		)	—			131			106
Total revenues and other	8,959			941			366			(265		)	10,001
Operating costs and expenses (1)	2,639			545			464			132			3,780
Realized (gains) losses on commodity    derivatives, net	—			—			—			(600		)	(600		)
Other (income) expense, net (2)	—			—			—			(14		)	(14		)
Net income attributable to noncontrolling interests	—			67			—			—			67
Total expenses and other	2,639			612			464			(482		)	3,233
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—			—			18			—			18
Adjusted EBITDAX	$	6,320		$	329		$	(80	)	$	217		$	6,786

 __________________________________________________________________

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

⁽²⁾   Other (income) expense, net excludes Tronox-related contingent loss and certain other nonoperating items since these expenses are excluded from Adjusted EBITDAX.

23

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

16. Pension Plans and Other Postretirement Benefits

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

       During the nine months ended September 30, 2013, the Company made contributions of $122 million to its funded pension plans, $6 million to its unfunded pension plans, and $11 million to its unfunded other postretirement benefit plans. During the fourth quarter of 2013, the Company expects to contribute $2 million to its funded pension plans, $30 million to its unfunded pension plans, and $5 million to its unfunded other postretirement benefit plans.

       The following summarizes the Company’s pension and other postretirement benefit cost:

	Pension Benefits						Other Benefits
millions	2013			2012			2013		2012
Three Months Ended September 30
Service cost	$	21		$	19		$	2	$	2
Interest cost	19			21			3		4
Expected return on plan assets	(22		)	(23		)	—		—
Amortization of net actuarial loss (gain)	29			23			—		—
Amortization of net prior service cost (credit)	—			—			1		—
Net periodic benefit cost	$	47		$	40		$	6	$	6
Nine Months Ended September 30
Service cost	$	64		$	57		$	7	$	7
Interest cost	58			64			10		12
Expected return on plan assets	(68		)	(68		)	—		—
Amortization of net actuarial loss (gain)	88			69			—		—
Amortization of net prior service cost (credit)	—			—			1		1
Net periodic benefit cost	$	142		$	122		$	18	$	20

24

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

       Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company has made in this report, and may from time to time 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,” “would,” “will,” “potential,” “continue,” “forecast,” “future,” “likely,” “outlook,” 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 be realized. 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 energy markets

• production levels

• reserves levels

• operating results

• competitive conditions

• technology

• availability of capital resources, levels of capital expenditures, and other contractual obligations

• 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

• weather

• inflation

• availability of goods and services, including unexpected changes in costs

• 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

• the Company’s inability to timely obtain or maintain permits, including those necessary for drilling and/or development projects

• 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

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

25

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

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

• civil or political unrest or acts of terrorism in a region or country

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

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

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

• disruptions in international crude oil cargo shipping activities

• physical, digital, internal, and external security breaches

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

• 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 2012 Annual Report on Form 10-K, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management

       The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this report in Part I, Item 1; the information set forth in Risk Factors under Part II, Item 1A; the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the 2012 Annual Report on Form 10-K; and the information set forth in the Risk Factors under Part I, Item 1A of the 2012 Annual Report on Form 10-K.

OVERVIEW

       Anadarko is among the world’s largest independent exploration and production companies. Anadarko is engaged in the exploration, development, production, and marketing of natural gas, crude oil, condensate, and NGLs. The Company also engages in the gathering, processing, treating, and transporting of natural gas, crude oil, and NGLs. The Company has production and exploration activities worldwide, including activities in the United States, Algeria, Mozambique, Ghana, China, Brazil, Kenya, Côte d’Ivoire, Liberia, Sierra Leone, New Zealand, and other countries.

26

Significant operating and financial activities during the third quarter of 2013 include the following:

Overall

• Anadarko’s third-quarter sales volumes totaled 775 thousand barrels of oil equivalent per day (MBOE/d), representing a 5%increase over the third quarter of 2012.

• Anadarko’s third-quarter liquids sales volumes were 337 thousand barrels per day (MBbls/d), representing an increase of 4% over the third quarter of 2012, primarily due to increased sales volumes in the Wattenberg field, the Eagleford shale, and the East Texas horizontal development.

U.S. Onshore

• U.S. onshore third-quarter sales volumes were 590 MBOE/d, representing an 11%increase from the third quarter of 2012, primarily due to increased sales volumes from the Wattenberg field, the Marcellus and Eagleford shales, and the East Texas horizontal development, partially offset by a natural production decline in the Powder River basin.

• Anadarko acquired certain oil and gas properties and related assets in the Moxa area of Wyoming for $310 million.

Gulf of Mexico

• Gulf of Mexico third-quarter sales volumes were 82 MBOE/d, representing a 23%decrease from the third quarter of 2012, primarily due to natural production declines.

• Anadarko’s 80 MBOE/d Lucius spar was installed on location in the deepwater Gulf of Mexico and well-completion activities were initiated.

International

• International third-quarter sales volumes were 93 MBOE/d, which were consistent with third-quarter 2012 sales volumes.

• Anadarko entered into a definitive agreement to sell a 10% working interest in Mozambique’s Offshore Area 1 for $2.64 billion. The transaction is subject to governmental approvals and other customary closing conditions, and is expected to close in late 2013 or early 2014.

• Anadarko and its partners achieved initial oil production from the second train at the El Merk project in Algeria and continued to advance the third facility.

• Anadarko successfully drilled two appraisal wells in Offshore Area 1 in Mozambique, encountering natural-gas pay of approximately 330 net feet at Golfinho-5 and approximately 240 net feet at Golfinho-6.

Financial

• Anadarko’s net income attributable to common stockholders totaled $182 million, which included a $593 million pretax expense for impairments of certain Gulf of Mexico properties.

• The Company generated $1.8 billion of cash flow from operations and ended the quarter with $3.9 billion of cash on hand.

• Anadarko increased the quarterly dividend paid to common stockholders from nine cents per share to eighteen cents per share.

• Western Gas Partners, LP (WES), a consolidated subsidiary of Anadarko, completed a public offering of $250 million aggregate principal amount of 2.600% Senior Notes due 2018, with net proceeds from the offering used to repay borrowings under its five-year, $800 million senior unsecured revolving credit facility maturing in March 2016 (RCF).

27

       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, 2013,” refer to the comparison of the three months ended September 30, 2013, to the three months ended September 30, 2012, and any increases or decreases “for the nine months ended September 30, 2013,” refer to the comparison of the nine months ended September 30, 2013, to the nine months ended September 30, 2012. The primary factors that affect the Company’s results of operations include commodity prices for natural gas, crude oil, and NGLs; sales volumes; the Company’s ability to discover additional oil and natural-gas reserves; the cost of finding such reserves; and operating costs.

RESULTS OF OPERATIONS

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions except per-share amounts	2013		2012		2013		2012
Financial Results
Revenues and other	$	3,853	$	3,332	$	11,243	$	10,001
Costs and expenses	3,164		2,516		8,125		6,762
Other (income) expense	226		426		189		220
Income tax expense (benefit)	240		248		1,263		764
Net income (loss) attributable to common stockholders	$	182	$	121	$	1,571	$	2,188
Net income (loss) per common share attributable to common    stockholders—diluted	$	0.36	$	0.24	$	3.10	$	4.34
Average number of common shares outstanding—diluted	505		502		504		501
Operating Results
Adjusted EBITDAX (1)	$	2,491	$	2,301	$	7,412	$	6,786
Sales volumes (MMBOE)	71		68		211		200

 ________________________________________________________________________________________________________

MMBOE—million 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 for a reconciliation of Adjusted EBITDAX to income (loss) before income taxes, which is presented in accordance with GAAP.

FINANCIAL RESULTS

Sales Revenues and Volumes

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except percentages	2013		Inc/(Dec) vs. 2012		2012		2013		Inc/(Dec) vs. 2012		2012
Sales Revenues
Natural-gas sales	$	805	31	%	$	613	$	2,547	51	%	$	1,682
Oil and condensate sales	2,389		10		2,163		6,761		2		6,629
Natural-gas liquids sales	325		12		289		889		(3	)	913
Total	$	3,519	15		$	3,065	$	10,197	11		$	9,224

       Anadarko’s total sales revenues increased for the three months ended September 30, 2013, due to higher sales volumes and higher average commodity prices for all products. Anadarko’s total sales revenues increased for the nine months ended September 30, 2013, primarily due to higher sales volumes for all products and higher average natural-gas prices, partially offset by lower average crude-oil and NGLs prices.

28

	Three Months Ended September 30,
millions	Natural Gas		Oil and Condensate		NGLs		Total
2012 sales revenues	$	613	$	2,163	$	289	$	3,065
Changes associated with sales volumes	32		88		14		134
Changes associated with prices	160		138		22		320
2013 sales revenues	$	805	$	2,389	$	325	$	3,519

	Nine Months Ended September 30,
millions	Natural Gas		Oil and Condensate			NGLs			Total
2012 sales revenues	$	1,682	$	6,629		$	913		$	9,224
Changes associated with sales volumes	108		242			70			420
Changes associated with prices	757		(110		)	(94		)	553
2013 sales revenues	$	2,547	$	6,761		$	889		$	10,197

	Three Months Ended   September 30,				Nine Months Ended   September 30,
Sales Volumes	2013	Inc/(Dec) vs. 2012		2012	2013	Inc/(Dec) vs. 2012		2012
Barrels of Oil Equivalent    (MMBOE except percentages)
United States	63	5	%	60	187	6	%	176
International	8	1		8	24	—		24
Total	71	5		68	211	6		200
Barrels of Oil Equivalent per Day    (MBOE/d except percentages)
United States	682	5	%	648	686	6	%	642
International	93	1		91	87	—		87
Total	775	5		739	773	6		729

       Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q and Other (Income) Expense—(Gains) Losses on Derivatives, net. Production of natural gas, crude oil, and NGLs is usually not affected by seasonal swings in demand.

       Near the end of the third quarter of 2013, the Company shut in approximately 675 operated vertical wells in the Greater Wattenberg area in preparation for and during the flooding in Colorado. Due to the damaged roads, bridges, and railways, and other issues that impact the ability to move heavy equipment such as rigs and compression units, the Company has experienced disruptions to its drilling, completions, and construction activities in the area, which have resulted in temporary delays to capacity expansion efforts in the field. These delays are expected to reduce the Company’s total 2013 sales volumes by approximately 2.5 MMBOE.

29

Natural-Gas Sales Volumes, Average Prices, and Revenues

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2013		Inc/(Dec) vs. 2012		2012		2013		Inc/(Dec) vs. 2012		2012
United States
Sales volumes—Bcf	242		5	%	231		725		6	%	681
MMcf/d	2,629		5		2,499		2,655		6		2,487
Price per Mcf	$	3.33	25		$	2.67	$	3.51	42		$	2.47
Natural-gas sales revenues (millions)	$	805	31		$	613	$	2,547	51		$	1,682

 _______________________________________________________________________________

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

Mcf—thousand cubic feet

       The Company’s natural-gas sales volumes increased 130 MMcf/d for the three months ended September 30, 2013, and 168 MMcf/d for the nine months ended September 30, 2013. Sales volumes for the Southern and Appalachia Region increased240 MMcf/d for the three months ended September 30, 2013, and 259 MMcf/d for the nine months ended September 30, 2013, primarily due to infrastructure expansions that allowed the Company to bring wells online in the Eagleford and Marcellus shales, as well as new wells drilled in the liquids-rich East Texas horizontal development. These increases were partially offset by lower sales volumes in the Gulf of Mexico of 70 MMcf/d for the three months ended September 30, 2013, and 49 MMcf/d for the nine months ended September 30, 2013, primarily due to natural production declines. Also, sales volumes for the Rockies decreased 40 MMcf/d for the three months ended September 30, 2013, and 42 MMcf/d for the nine months ended September 30, 2013, primarily due to a natural production decline in the Powder River basin.

       The average natural-gas price Anadarko received increased for the three and nine months ended September 30, 2013, due to increased U.S. residential and commercial demand. This contributed to a reduction in overall U.S. storage levels, which are in line with the five-year average.

30

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2013		Inc/(Dec) vs. 2012		2012		2013		Inc/(Dec) vs. 2012		2012
United States
Sales volumes—MMBbls	14		6	%	13		42		6	%	40
MBbls/d	152		6		143		155		6		146
Price per barrel	$	103.15	10		$	94.19	$	98.48	(1	)	$	99.26
International
Sales volumes—MMBbls	8		1	%	8		24		—	%	24
MBbls/d	93		1		91		87		—		87
Price per barrel	$	110.82	2		$	108.94	$	108.94	(3	)	$	111.75
Total
Sales volumes—MMBbls	22		4	%	21		66		4	%	64
MBbls/d	245		4		234		242		4		233
Price per barrel	$	106.05	6		$	99.93	$	102.23	(2	)	$	103.90
Oil and condensate sales revenues (millions)	$	2,389	10		$	2,163	$	6,761	2		$	6,629

 _______________________________________________________________________________

MMBbls—million barrels

MBbls/d—thousand barrels per day

       Anadarko’s total crude-oil and condensate sales volumes increased 11 MBbls/d for the three months ended September 30, 2013, and 9 MBbls/d for the nine months ended September 30, 2013. Sales volumes in the Rockies increased13 MBbls/d for the three months ended September 30, 2013, and 14 MBbls/d for the nine months ended September 30, 2013, primarily due to increased horizontal drilling in the Wattenberg field. Southern and Appalachia Region sales volumes increased4 MBbls/d for the three months ended September 30, 2013, and 6 MBbls/d for the nine months ended September 30, 2013, as a result of horizontal drilling and infrastructure expansions in the Eagleford shale. Sales volumes in the Gulf of Mexico decreased8 MBbls/d for the three months ended September 30, 2013, primarily due to natural production declines and 10 MBbls/d for the nine months ended September 30, 2013, primarily due to scheduled downtime for maintenance, well work, and natural production declines.

       Anadarko’s average crude-oil price received increased for the three months ended September 30, 2013, primarily due to increased U.S. pipeline capacity causing reduced Cushing inventories and increased West Texas Intermediate prices. Anadarko’s average crude-oil price received decreased slightly for the nine months ended September 30, 2013, due to modestly lower concerns over supply disruptions from the Middle East and North Africa.

31

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2013		Inc/(Dec) vs. 2012		2012		2013		Inc/(Dec) vs. 2012		2012
United States
Sales volumes—MMBbls	9		5	%	8		24		8	%	22
MBbls/d	92		5		88		88		8		81
Price per barrel	$	38.49	7		$	35.93	$	37.07	(9	)	$	40.96
Natural-gas liquids sales revenues (millions)	$	325	12		$	289	$	889	(3	)	$	913

       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 4 MBbls/d for the three months ended September 30, 2013, and 7 MBbls/d for the nine months ended September 30, 2013. Sales volumes for the Southern and Appalachia Region increased by 8 MBbls/d for the three months ended September 30, 2013, and 11 MBbls/d for the nine months ended September 30, 2013, as a result of continued horizontal drilling and infrastructure expansion in the Eagleford shale, and drilling in the liquids-rich East Texas horizontal development. Sales volumes for the Gulf of Mexico decreased by 4 MBbls/d for the three months ended September 30, 2013, and 2 MBbls/d for the nine months ended September 30, 2013, primarily due to natural production declines. Sales volumes for the Rockies decreased by 2 MBbls/d for the nine months ended September 30, 2013, primarily due to ethane rejection in 2013.

       Anadarko’s average NGLs price received increased for the three months ended September 30, 2013, primarily due to higher U.S. propane prices as a result of increased propane exports. However, Anadarko’s average price received for NGLs decreased for the nine months ended September 30, 2013, primarily due to lower market prices for ethane and butanes as a result of higher U.S. inventory and production levels.

Gathering, Processing, and Marketing Margin

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except percentages	2013		Inc/(Dec) vs. 2012		2012		2013		Inc/(Dec) vs. 2012		2012
Gathering, processing, and marketing sales	$	270	24	%	$	218	$	750	12	%	$	671
Gathering, processing, and marketing expense	217		17		185		638		16		552
Gathering, processing, and marketing margin	$	53	61		$	33	$	112	(6	)	$	119

       The gathering, processing, and marketing margin increased by $20 million for the three months ended September 30, 2013. This increase is primarily due to higher gathering revenue as a result of increased throughput across several of Anadarko’s systems and higher marketing margins, partially offset by increased transportation expenses.

       The gathering, processing, and marketing margin decreased by $7 million for the nine months ended September 30, 2013, primarily due to reduced natural-gas processing margins and higher transportation expenses, partially offset by increased gathering revenue and higher marketing margins.

Gains (Losses) on Divestitures and Other, net

       Gains (losses) on divestitures and other, net increased by $190 million for the nine months ended September 30, 2013, primarily due to a $140 million gain associated with the Company’s divestiture of its interests in a soda ash joint venture during the first quarter of 2013. The Company divested its interests in the soda ash joint venture for $310 million and potential additional consideration based on future revenue of the joint venture. The Company retained its royalty interest in soda ash mined from the Company’s Land Grant by the joint venture.

32

Costs and Expenses

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2013		Inc/(Dec) vs. 2012		2012		2013		Inc/(Dec) vs. 2012		2012
Oil and gas operating (millions)	$	277	15	%	$	241	$	769	5	%	$	732
Oil and gas operating—per BOE	3.88		9		3.55		3.65		(1	)	3.67
Oil and gas transportation and other (millions)	255		3		247		763		7		710
Oil and gas transportation and other—per BOE	3.58		(2	)	3.64		3.62		2		3.56

       Oil and gas operating expense increased by $36 million for the three months ended September 30, 2013, and $37 million for the nine months ended September 30, 2013, due to higher expenses in Algeria associated with the start of El Merk production in 2013 and increased workovers in the Gulf of Mexico. The related per barrel of oil equivalent (BOE) costs increased by $0.33 for the three months ended September 30, 2013, primarily due to the higher costs discussed above, partially offset by increased sales volumes. The related per-BOE costs decreased by $0.02 for the nine months ended September 30, 2013, primarily due to increased sales volumes, partially offset by the higher costs discussed above.

       Oil and gas transportation and other expense increased by $8 million for the three months ended September 30, 2013, and $53 million for the nine months ended September 30, 2013, primarily due to higher gas-gathering and transportation costs attributable to higher volumes and increased costs related to growth in the Company’s U.S. onshore asset base. In addition, for the nine months ended September 30, 2013, oil and gas transportation and other expense increased $25 million due to a reversal in the second quarter of 2012 of previously accrued rig termination fees for a deepwater drilling rig in the Gulf of Mexico. This expense reversal resulted from a dispute settlement with the drilling contractor. Oil and gas transportation and other expense per BOE decreased$0.06 for the three months ended September 30, 2013, primarily due to increased sales volumes, partially offset by the higher costs discussed above. Oil and gas transportation and other expense per BOE increased$0.06 for the nine months ended September 30, 2013, primarily due to the higher costs discussed above, partially offset by increased sales volumes.

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions	2013		2012		2013		2012
Exploration Expense
Dry hole expense	$	77	$	142	$	301	$	346
Impairments of unproved properties	83		60		122		1,043
Geological and geophysical expense	51		40		111		89
Exploration overhead and other	61		55		180		184
Total exploration expense	$	272	$	297	$	714	$	1,662

       For the three months ended September 30, 2013, dry hole expense decreased by $65 million primarily associated with 2012 dry hole expense for wells in Brazil and Ghana, partially offset by 2013 dry hole expense for wells in Kenya. For the three months ended September 30, 2013, unproved property impairments increased $23 million primarily due to a $53 million impairment of a domestic property as a result of changes to the Company’s drilling plans. This impairment was partially offset by a decrease of $36 million as a result of a 2013 increase in the Company’s estimated success rate associated with certain unproved Gulf of Mexico properties. For the three months ended September 30, 2013, geological and geophysical expense increased $11 million due to increased seismic purchases primarily in Colombia.

33

       For the nine months ended September 30, 2013, dry hole expense decreased by $45 million primarily due to 2012 dry hole expense for wells in Brazil, Sierra Leone, Ghana, Alaska, and the Gulf of Mexico, partially offset by 2013 dry hole expense for wells in Sierra Leone, Kenya, and Mozambique. For the nine months ended September 30, 2013, unproved property impairments decreased by $921 million. During the second quarter of 2012, the Company recognized a $720 million unproved property impairment attributable to Powder River coalbed methane properties in the Rockies primarily due to lower natural-gas prices and a $124 million unproved property impairment associated with a Gulf of Mexico natural-gas property that the Company does not plan to develop under the forecasted natural-gas price environment. In addition, unproved property impairments decreased by $108 million as a result of a 2013 increase in the Company’s estimated success rate associated with certain unproved Gulf of Mexico properties. The decrease for unproved property impairments was partially offset by the $53 million third-quarter 2013 domestic property impairment discussed previously. For the nine months ended September 30, 2013, geological and geophysical expense increased $22 million due to increased seismic purchases primarily in Colombia.

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except percentages	2013		Inc/(Dec) vs. 2012		2012		2013		Inc/(Dec) vs. 2012		2012
General and administrative	$	255	(11	)%	$	285	$	787	(4	)%	$	816
Depreciation, depletion, and amortization	996		2		979		2,958		1		2,936
Other taxes	294		10		267		819		(16	)	970
Impairments	593		NM		4		632		NM		166

_________________________________________________________________________

NM—not meaningful

       For the three months ended September 30, 2013, general and administrative (G&A) expense decreased by $30 million primarily due to lower legal and consulting fees. For the nine months ended September 30, 2013, G&A expense decreased by $29 million due to lower legal and consulting fees of $80 million, partially offset by higher employee-related expenses of $50 million related to operational expansion and increased employee-benefit-related expenses.

       Depreciation, depletion, and amortization (DD&A) expense increased by $17 million for the three months ended September 30, 2013, and $22 million for the nine months ended September 30, 2013, primarily due to higher sales volumes in 2013, partially offset by the 2012 accelerated depletion of certain fields in the Gulf of Mexico.

For the three months ended September 30, 2013, other taxes increased by $27 million primarily due to higher ad valorem taxes of $21 million and higher U.S. production and severance taxes of $11 million as a result of higher sales volumes and commodity prices for U.S. onshore properties. For the nine months ended September 30, 2013, other taxes decreased by $151 million primarily related to lower Algerian exceptional profits taxes of $128 million due to a lower effective tax rate resulting from the resolution of the Algeria exceptional profits tax dispute, and decreased sales volumes and crude-oil prices in Algeria. In addition, lower crude-oil prices and lower sales volumes in China and Alaska resulted in a $29 million decrease in Chinese windfall profits taxes and a $19 million decrease in U.S. production and severance taxes. These decreases were partially offset by increased ad valorem taxes of $33 million discussed above.

       Impairment expense for the three and nine months ended September 30, 2013, included $593 million for certain Gulf of Mexico properties due to a reduction in estimated future net cash flows per barrel and downward revisions of reserves that the Company no longer plans to develop. Impairment expense for the nine months ended September 30, 2013, also included $29 million related to a midstream property that was impaired due to a reduction in estimated future cash flows and $10 million related to the Company’s Venezuelan cost-method investment due to declines in estimated recoverable value. Impairment expense for the nine months ended September 30, 2012, included $81 million related to certain onshore domestic oil and gas exploration and production properties and $6 million related to midstream properties due to lower natural-gas prices, $67 million related to downward reserves revisions for a Gulf of Mexico property that was near the end of its economic life, and $12 million related to the Company’s Venezuelan cost-method investment due to declines in estimated recoverable value.

34

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions	2013		2012		2013		2012
Algeria exceptional profits tax settlement	$	—	$	7	$	33	$	(1,797	)
Deepwater Horizon settlement and related costs	5		4		12		15

       In March 2012, Anadarko and Sonatrach resolved the exceptional profits tax dispute. The resolution provided for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of previously recorded and unpaid transportation charges. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for the three months ended March 31, 2012, to reflect the effect of this agreement on previously recorded expenses. During the third quarter of 2013, the Company collected the remaining balance of the Algeria exceptional profits tax settlement. In March 2013, the Company revised its estimate of income tax expense related to the elimination of previously recorded and unpaid transportation charges and recognized a $33 million unfavorable adjustment to the settlement, which was offset by an equivalent income tax benefit also recognized in March 2013.

       For the three and nine months ended September 30, 2013 and 2012, Deepwater Horizon settlement and related costs included legal expenses and related costs associated with the Deepwater Horizon events. See Note 12—Contingencies—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

	Three Months Ended   September 30,								Nine Months Ended   September 30,
millions except percentages	2013			Inc/(Dec) vs. 2012		2012			2013			Inc/(Dec) vs. 2012		2012
Interest Expense
Current debt, long-term debt, and other	$	240		1	%	$	238		$	710		(2	)%	$	724
Capitalized interest	(63		)	(19	)	(53		)	(197		)	(21	)	(163		)
Interest expense	$	177		(4	)	$	185		$	513		(9	)	$	561

       Interest expense decreased by $8 million for the three months ended September 30, 2013, due to an increase in capitalized interest related to higher construction-in-progress balances for long-term capital projects. Interest expense decreased by $48 million for the nine months ended September 30, 2013, due to an increase in capitalized interest of $34 million related to higher construction-in-progress balances for long-term capital projects and a decrease of $28 million in interest expense resulting from the repayment of outstanding borrowings during 2012 associated with the five-year, $5.0 billion senior secured revolving credit facility maturing in September 2015 ($5.0 billion Facility). The decrease for the nine months ended September 30, 2013, was partially offset by $17 million of 2013 interest expense for outstanding borrowings primarily related to WES’s 4.000% Senior Notes due 2022. For additional information regarding the Company’s financing activities, see Liquidity and Capital Resources.

35

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions	2013			2012			2013			2012
(Gains) Losses on Derivatives, net
Commodity derivatives
Realized (gains) losses
Natural gas	$	(40	)	$	(170	)	$	(91	)	$	(564	)
Oil and condensate	68			(27		)	52			(30		)
Natural gas liquids	(2		)	(3		)	(7		)	(6		)
Total realized (gains) losses	26			(200		)	(46		)	(600		)
Unrealized (gains) losses
Natural gas	(6		)	262			5			464
Oil and condensate	119			164			69			(77		)
Natural gas liquids	7			11			7			(18		)
Total unrealized (gains) losses	120			437			81			369
Total (gains) losses on commodity derivatives, net	146			237			35			(231		)
Interest-rate and other derivatives
Realized (gains) losses	—			—			—			2
Unrealized (gains) losses	(74		)	14			(428		)	152
Total (gains) losses on interest-rate and other derivatives, net	(74		)	14			(428		)	154
Total (gains) losses on derivatives, net	$	72		$	251		$	(393	)	$	(77	)

       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 derivatives entered into or settled within each period and price changes related to positions open at September 30 of both years. For additional information 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.

       Anadarko enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to unfavorable interest-rate changes. The fair value of the Company’s interest-rate swap portfolio increases (decreases) when interest rates increase (decrease). 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.

	Three Months Ended   September 30,								Nine Months Ended   September 30,
millions except percentages	2013			Inc/(Dec) vs. 2012		2012			2013			Inc/(Dec) vs. 2012		2012
Other (Income) Expense, net
Interest income	$	(4	)	60	%	$	(10	)	$	(8	)	43	%	$	(14	)
Other	(19		)	NM		—			77			131		(250		)
Total other (income) expense, net	$	(23	)	(130	)	$	(10	)	$	69		126		$	(264	)

       For the three months ended September 30, 2013, total other income increased by $13 million primarily due to a $10 million reduction to the estimated cost to decommission wells and production facilities. During the nine months ended September 30, 2013, the Company recognized a pretax loss of $131 million related to the cost to decommission wells and production facilities previously sold to a third party. In June 2013, as a result of a Chapter 11 bankruptcy declaration by the third party, theU.S. Department of the Interior ordered Anadarko to perform the decommissioning of the facility and related wells. These wells and production facilities are no longer owned by the Company nor are they related to its current operations. Anadarko expects to complete decommissioning of the production facilities in 2014 and the wells in 2015. In addition, other income for the three months ended September 30, 2013, increased $4 million due to changes in foreign-currency gains/losses. These gains/losses reflected the impact of exchange-rate changes primarily applicable to foreign currency held in escrow pending final determination of the Company’s Brazilian tax liability attributable to the 2008 divestiture of the Peregrino field offshore Brazil.

36

       Total other income decreased by $333 million for the nine months ended September 30, 2013, primarily due to the reversal of a $250 million Tronox-related contingent loss in 2012. See Note 12—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. In addition, during the nine months ended September 30, 2013, the Company recognized a pretax loss of $131 million related to the cost to decommission wells and production facilities as discussed above. The decrease for the nine months ended September 30, 2013, was partially offset by the second-quarter 2013 reversal of the $56 million tax indemnification liability associated with the 2006 sale of the Company’s Canadian subsidiary. The indemnity was reversed as a result of certain Canadian tax legislative changes.

Income Tax Expense

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except percentages	2013			2012			2013			2012
Income tax expense (benefit)	$	240		$	248		$	1,263		$	764
Effective tax rate	52		%	64		%	43		%	25		%

       The increase from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2013, and the three months ended September 30, 2012, was primarily attributable to the tax impact from foreign operations and Algerian exceptional profits taxes. The decrease from the 35% U.S. federal statutory rate for the nine months ended September 30, 2012, was primarily attributable to the non-taxable resolution of the Algeria exceptional profits tax dispute, partially offset by the tax impact from foreign operations and Algerian exceptional profits taxes.

Net Income Attributable to Noncontrolling Interests

       The Company’s net income attributable to noncontrolling interests of $41 million for the three months ended September 30, 2013, and $95 million for the nine months ended September 30, 2013, related to the public ownership at September 30, 2013, of a 54.5% limited partner interest in Western Gas Partners, LP (WES) and a 9.0% limited partner interest in Western Gas Equity Partners, LP (WGP). The Company’s net income attributable to noncontrolling interests of $21 million for the three months ended September 30, 2012, and $67 million for the nine months ended September 30, 2012, primarily related to the public ownership of a 56.6% limited partner interest in WES at September 30, 2012.

37

OPERATING RESULTS

Segment Analysis—Adjusted EBITDAX    To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes, exploration expense, DD&A, impairments, interest expense, unrealized (gains) losses on derivatives, net, realized (gains) losses on interest-rate and other derivatives, net, and certain items not related to the Company’s normal operations, less net income attributable to noncontrolling interests. During the periods presented, these items included Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX, which is not a GAAP measure, excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Finally, unrealized (gains) losses on derivatives, net and realized (gains) losses on interest-rate and other derivatives, net are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance.

       Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders. Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies. 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.

38

Adjusted EBITDAX

	Three Months Ended   September 30,								Nine Months Ended   September 30,
millions except percentages	2013			Inc/(Dec) vs. 2012		2012			2013			Inc/(Dec) vs. 2012		2012
Income (loss) before income taxes	$	463		19	%	$	390		$	2,929		(3	)%	$	3,019
Exploration expense	272			(8	)	297			714			(57	)	1,662
DD&A	996			2		979			2,958			1		2,936
Impairments	593			NM		4			632			NM		166
Interest expense	177			(4	)	185			513			(9	)	561
Unrealized (gains) losses on derivatives, net	36			(92	)	456			(359		)	(167	)	539
Realized (gains) losses on interest-rate and    other derivatives, net	—			NM		—			—			(100	)	2
Deepwater Horizon settlement and    related costs	5			25		4			12			(20	)	15
Algeria exceptional profits tax settlement	—			(100	)	7			33			102		(1,797		)
Tronox-related contingent loss	—			NM		—			—			100		(250		)
Certain other nonoperating items	(10		)	NM		—			75			NM		—
Less net income attributable to    noncontrolling interests	41			95		21			95			42		67
Consolidated Adjusted EBITDAX	$	2,491		8		$	2,301		$	7,412		9		$	6,786
Adjusted EBITDAX by reporting segment
Oil and gas exploration and production	$	2,509		17	%	$	2,152		$	7,304		16	%	$	6,320
Midstream	125			21		103			364			11		329
Marketing	(25		)	(32	)	(19		)	(102		)	(28	)	(80		)
Other and intersegment eliminations	(118		)	NM		65			(154		)	(171	)	217

Oil and Gas Exploration and Production    Adjusted EBITDAX for the three months ended September 30, 2013, increased primarily due to higher sales volumes for all products and higher commodity prices. Adjusted EBITDAX for the nine months ended September 30, 2013, increased primarily due to higher sales volumes for all products and higher natural-gas prices, partially offset by lower crude-oil and NGLs prices.

MidstreamThe increase in Adjusted EBITDAX for the three and nine months ended September 30, 2013, was primarily due to higher gathering revenue as a result of increased throughput across several of Anadarko’s systems. This increase was partially offset by lower natural-gas processing margins for the nine months ended September 30, 2013.

MarketingMarketing earnings primarily represent the margin earned on sales of natural gas, oil, and NGLs purchased from third parties. For the three and nine months ended September 30, 2013, Adjusted EBITDAX decreased primarily due to higher transportation expenses, partially offset by higher margins primarily associated with natural-gas and NGLs sales.

Other and Intersegment EliminationsOther and intersegment eliminations consists primarily of corporate costs, realized gains and losses on commodity derivatives, and income from hard-minerals royalties. The decrease in Adjusted EBITDAX for the three and nine months ended September 30, 2013, was primarily due to lower realized gains on commodity derivatives in 2013. The decrease for the nine months ended September 30, 2013, was partially offset by a $140 million gain associated with the Company’s divestiture of its interest in a soda ash joint venture during the first quarter of 2013. See Other (Income) Expense.

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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 expenditure requirements.

       Consistent with this approach, during the nine months ended September 30, 2013, cash flows from operating activities were the primary source of capital investment funding. In addition, the Company collected the remaining $730 million of the Algeria exceptional profits tax settlement during the nine months ended September 30, 2013. The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule, and evaluates available funding alternatives in light of current and expected conditions.

       At September 30, 2013, Anadarko had no scheduled debt maturities for the remainder of 2013. Anadarko’s $500 million aggregate principal amount of 7.625% Senior Notes due March 2014 and $275 million aggregate principal amount of 5.750% Senior Notes due June 2014 are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance these obligations using long-term debt. The Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, which would cause the Company to repay up to the then-accreted value of the outstanding Zero Coupons. None of the Zero Coupons (accreted value of $718 million) were put to the Company in October 2013. The Zero Coupons can be put to the Company in October 2014 for up to the then-accreted value of $756 million. The Company has a variety of funding sources available, including cash on hand, an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through divestitures and joint-venture arrangements, and the Company’s $5.0 billion Facility. Management believes that the Company’s liquidity position, asset portfolio, and continued strong operating and financial performance provide the necessary financial flexibility to fund the Company’s current and long-term operations.

Revolving Credit Facility    Obligations incurred under the $5.0 billion Facility, as well as obligations Anadarko has to lenders or their affiliates pursuant to certain derivative instruments as discussed in Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, are guaranteed by certain of the Company’s wholly owned domestic subsidiaries, and are secured by a perfected first-priority security interest in certain exploration and production assets located in the United States and 65% of the capital stock of certain wholly owned foreign subsidiaries. At September 30, 2013, the Company had no outstanding borrowings under the $5.0 billion Facility, there were no restrictions on its ability to utilize this borrowing capacity, and the Company was in compliance with all applicable covenants.

WES Funding Sources    Anadarko’s consolidated subsidiary, WES, uses cash flows from operations to fund ongoing operations (including capital investments in the ordinary course of business), service its debt, and make distributions to its equity holders. As needed, WES supplements cash generated from its operating activities with proceeds from debt or equity issuances or borrowings under its RCF. At September 30, 2013, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $100 million at an interest rate of 1.68%, and had available borrowing capacity of $687 million ($800 million maximum capacity, less $100 million of outstanding borrowings and $13 million of outstanding letters of credit). See Financing Activities below.

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Insurance Coverage and Other Indemnities    Anadarko maintains property and casualty insurance that includes coverage for physical damage to the Company’s properties, blowout/control of a well, restoration and redrill, sudden and accidental pollution, third-party liability, workers’ compensation and employers’ liability, and other risks. Anadarko’s insurance coverage includes deductibles that must be met prior to recovery. Additionally, the Company’s insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect the Company against liability or loss from all potential consequences and damages.

       The Company’s current insurance coverage includes (a) $300 million per occurrence from Oil Insurance Limited (OIL) for physical damage to Anadarko’s properties on a replacement cost basis, blowout/control of well, redrill, and sudden and accidental pollution; (b) $700 million per occurrence from the commercial markets for the items described in item (a) above, which is in excess of the OIL coverage and which follows the form of OIL coverage with certain exceptions; (c) $400 million from the commercial markets, which scales to Anadarko’s working interest, for third-party liabilities including sudden and accidental pollution and aviation liability; and (d) $275 million for aircraft liability (in addition to the third-party liability limits described in item (c) above). Anadarko does not carry significant coverage for loss of production income from any of the Company’s facilities or for any losses that result from the effects of a named windstorm.

       Anadarko’s property and casualty insurance policies renew in June of each year. At the next renewal date scheduled for June 2014, the Company may not be able to secure similar coverage for the same costs, if at all. Future insurance coverage costs for the oil and gas industry could increase and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that the Company considers economically acceptable.

       The Company’s service agreements, including drilling contracts, generally indemnify Anadarko for injuries and death to employees of the service provider and subcontractors hired by the service provider as well as for property damage suffered by the service provider and its contractors. Also, these service agreements generally indemnify Anadarko for pollution originating from the equipment of any contractors or subcontractors hired by the service provider.

Sources of Cash

Operating ActivitiesAnadarko’s cash flows from operating activities during the nine months ended September 30, 2013, was $6.8 billion, compared to $6.1 billion for the same period of 2012. Operating cash flows for 2013 increased primarily due to higher sales volumes, higher average natural-gas prices, the favorable impact of changes in working capital items, and an increase in cash collected in 2013 associated with the Algeria exceptional profits tax settlement, but were partially offset by lower average crude-oil and NGLs prices.

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

Investing ActivitiesDuring the nine months ended September 30, 2013, Anadarko received pretax proceeds of $451 million primarily related to the divestiture of its interests in a soda ash joint venture.

Financing ActivitiesDuring the nine months ended September 30, 2013, Anadarko’s consolidated subsidiary, WES, borrowed $595 million under its RCF primarily to fund the March 2013 acquisition of an interest in certain gas-gathering systems located in the Marcellus shale in north-central Pennsylvania, the September 2013 acquisition of an intrastate pipeline in southwestern Wyoming, and for other general partnership purposes, including the funding of capital expenditures. During 2013, WES has issued approximately seven million common units to the public, raising net proceeds of $419 million, which were used to repay a portion of outstanding RCF borrowings and for other general partnership purposes, including the funding of WES’s capital expenditures. In August 2013, WES completed a public offering of $250 million aggregate principal amount of 2.600% Senior Notes due 2018, with net proceeds from the offering used to repay outstanding borrowings under its RCF.

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Uses of Cash

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

Capital ExpendituresThe following presents the Company’s capital expenditures by category:

	Nine Months Ended   September 30,
millions	2013		2012
Property acquisitions
Exploration	$	236	$	138
Development	320		14
Exploration	1,071		1,193
Development	2,929		2,821
Capitalized interest	170		149
Total oil and gas capital expenditures	4,726		4,315
Gathering, processing, and marketing and other (1)	1,185		1,063
Total capital expenditures (2)	$	5,911	$	5,378

 ________________________________________________________________________________________

⁽¹⁾  Includes WES capital expenditures of $622 million for the nine months ended September 30, 2013, and $360 million for the nine months ended September 30, 2012.

⁽²⁾  Capital expenditures in this table 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 by $533 million for the nine months ended September 30, 2013, due to acquisitions of development properties and domestic onshore plants and gathering systems. In August 2013, Anadarko acquired certain oil and gas properties and related assets in the Moxa area of Wyoming for $310 million, including $306 million in the table above that represents the fair value of the oil and gas properties acquired. In March 2013, WES acquired a 33.75% interest in gas-gathering systems located in the Marcellus shale in north-central Pennsylvania for $135 million. In September 2013, WES acquired an intrastate pipeline in southwestern Wyoming for $28 million. These increases were offset by lower costs resulting from decreased exploration drilling in East and West Africa and onshore United States and lower costs to Anadarko related to development projects as a result of the carried-interest arrangements discussed below.

       In the second quarter of 2013, the Company entered into a carried-interest arrangement that requires a third-party partner to fund $860 million of Anadarko’s capital costs to earn a 12.75% working interest in the Heidelberg development, located in the Gulf of Mexico. The third-party funding is expected to cover nearly all of Anadarko’s expected future capital costs through first production, which is expected to occur by mid-2016. At September 30, 2013, $78 million of the total $860 million obligation had been funded.

       In the third quarter of 2012, the Company entered into a carried-interest arrangement that requires a third-party partner to fund $556 million of Anadarko’s capital costs to earn a 7.2% working interest in the Lucius development, located in the Gulf of Mexico. The amount of the carry obligation represents 100% of the Company’s expected capital costs through first production. The funding obligation is expected to be complete by mid-2014. At September 30, 2013, $353 million of the total $556 million obligation had been funded.

       In the first quarter of 2011, the Company entered into a carried-interest arrangement that required a third-party partner to fund approximately $1.6 billion of Anadarko’s capital costs in the Eagleford shale, located in South Texas, to earn a one-third interest in Anadarko’s Eagleford shale assets. The carry was fully funded in June 2013.

Investments    During the nine months ended September 30, 2013, the Company made capital contributions of $345 million to equity subsidiaries, which are included in Other—net under Investing Activities in the Consolidated Statements of Cash Flows. These contributions were primarily associated with joint ventures to build the Front Range Pipeline, the Texas Express Pipeline, and two fractionation trains in Mont Belvieu.

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Debt Retirements and Repayments    During the nine months ended September 30, 2013, WES repaid $495 million of borrowings under its RCF with proceeds from its public offering of common units and its debt offering, as discussed in Sources of Cash.

Common Stock Dividends and Distributions to Noncontrolling Interest Owners    Anadarko paid dividends to its common stockholders of $182 million during the nine months ended September 30, 2013, and $136 million during the nine months ended September 30, 2012. During the third quarter of 2013, Anadarko increased the quarterly dividend paid to common stockholders from nine cents per share to eighteen cents per share. Anadarko has paid a dividend to its common stockholders on a quarterly basis since becoming a 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 earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors.

       WES distributed to its unitholders, other than Anadarko and WGP, an aggregate of $94 million during thenine months ended September 30, 2013,and $72 million during thenine months ended September 30, 2012. 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 $0.58 per common unit for the thirdquarter of2013 (to be paid in November 2013).

       WGP distributed to its unitholders, other than Anadarko, an aggregate of $8 million during the nine months ended September 30, 2013. WGP declared a cash distribution of $0.21375 per unit for thethirdquarter of2013(to be paid in November 2013).

Outlook

       The Company is committed to the execution of its worldwide exploration, appraisal, and development programs. The Company estimates a 2013 capital spending range of $8.1 billion to $8.3 billion. This amount includes $670 million to $740 million of WES capital expenditures, excluding WES acquisitions. The Company plans to allocate approximately 70% of its 2013 capital spending to development activities, 20% to exploration activities, and 10% to gas-gathering and processing activities and other business activities. The Company expects its 2013 capital spending by area to be approximately 60% for the U.S. onshore area and Alaska, 15% for the Gulf of Mexico, 15% for International, and 10% for midstream and other.

       Anadarko believes that its cash on hand and expected level of operating cash flows will be sufficient to fund the Company’s projected operational and capital programs for 2013 and continue to meet its other obligations. The Company’s cash on hand is available for use and could be supplemented, as needed, with available borrowing capacity under the $5.0 billion Facility. The Company currently does not consider European sovereign debt events to pose significant risk to the Company’s ability to access available borrowing capacity under the $5.0 billion Facility. The Company may also enter into carried-interest arrangements with third parties to fund certain capital expenditures and execute asset divestitures to supplement cash flow.

       The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule, and evaluates available funding alternatives in light of current and expected conditions. In order to reduce commodity-price risk and increase the predictability of 2013 cash flows, Anadarko entered into strategic derivative positions, which cover approximately 55% of its remaining 2013 anticipated natural-gas sales volumes and 74% of its remaining 2013 anticipated crude-oil sales volumes. In addition, the Company has derivative positions in place for 2014. See Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

       In August 2013, the Company entered into a definitive agreement to sell a 10% working interest in Mozambique’s Offshore Area 1 for $2.64 billion. Anadarko will remain the operator with a working interest of 26.5%. The transaction is subject to governmental approvals and other customary closing conditions, and is expected to close in late 2013 or early 2014. Anadarko expects to use a portion of the net proceeds in 2014 to further accelerate the short- and intermediate-term oil and NGLs opportunities in its U.S. portfolio.      

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Obligations and Commitments

       In June 2013, the Company entered into a three-year operating lease agreement for a deepwater drillship expected to be delivered in late 2014. The lease obligation totals $464 million, with aggregate future annual minimum lease payments of $33 million in 2014, $154 million in 2015, $155 million in 2016, and $122 million in 2017.

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 used by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. Both exchange and over-the-counter traded commodity derivative instruments may be subject to margin deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties in order to satisfy these margin requirements. For additional information related to the Company’s derivative and financial instruments, see Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

COMMODITY-PRICE RISK    The Company’s most significant market risk relates to prices for natural gas, crude oil, and NGLs. Management expects energy prices to remain volatile. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of the Company’s oil and gas properties or goodwill may be required if commodity prices experience a significant decline. Below is a sensitivity analysis for the Company’s commodity-price-related derivative instruments.

Derivative Instruments Held for Non-Trading Purposes    At September 30, 2013, the Company had derivative instruments in place to reduce the price risk associated with future production of 566 Bcf of natural gas and 18 MMBbls of crude oil, with a net derivative asset position of $167 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $325 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $334 million. However, any realized derivative gain or loss would be substantially offset by the realized sales value of production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes    At September 30, 2013, the Company had a net derivative asset position of $44 million (unrealized gains of $49 million and unrealized losses of $5 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    Any borrowings under the $5.0 billion Facility and the WES RCF are subject to variable interest rates. The balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheet is subject to fixed interest rates. The Company’s $2.9 billion of London Interbank Offered Rate (LIBOR) based obligations, which are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two non-controlled entities, give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. A 10% increase in LIBOR would not materially impact the Company’s interest cost on outstanding debt, but would affect fair value of outstanding debt.

       At September 30, 2013, the Company had a net derivative liability position of $765 million related to interest-rate swaps. A 10% increase or decrease in interest rates would increase or decrease the aggregate fair value of outstanding interest-rate swap agreements by approximately $139 million. However, any change in the interest-rate derivative gain or loss would be substantially offset by borrowing costs associated with any 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 primarily realized in U.S. dollars, and the predominant portion of Anadarko’s capital and operating expenditures are U.S.-dollar-denominated. Exposure to foreign-currency risk generally arises in connection with project-specific contractual arrangements and other commitments. Near-term foreign-currency-denominated expenditures are primarily in euros, Brazilian reais, British pounds sterling, Mozambican meticais, and Colombian pesos. Management periodically enters into various risk-management transactions to mitigate a portion of its exposure to foreign-currency exchange-rate risk.

       The Company has risk related to exchange-rate changes applicable to cash held in escrow pending final determination of the Company’s Brazilian tax liability for its 2008 divestiture of the Peregrino field offshore Brazil. At September 30, 2013, cash of $153 million was held in escrow. 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 the Company in reports that it files 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, 2013.

Changes in Internal Control over Financial Reporting

       There were no changes in Anadarko’s internal control over financial reporting during the third quarter of 2013 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

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

       In July 2013, Kerr-McGee Gathering LLC, one of the Company’s consolidated subsidiaries, entered into a consent order with the Colorado Department of Public Health and Environment relating to the failure to comply with certain terms of permits at its Frederick compression station and agreed to pay a penalty of approximately $125,000.

       See Note 12—Contingenciesin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference, for material developments with respect to matters previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012, and material matters that have arisen since the filing of such report.

Item 1A.  Risk Factors

       Consider carefully the risk factor included below, as well as those under the caption “Risk Factors” under Part I, Item 1A in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012, 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, 2012; and in the Company’s other public filings, press releases, and public discussions with Company management.

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

       In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance. Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee and seeks, among other things, to recover damages, including interest, in excess of $18.9 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. For a description of the updates to this litigation since the description thereof included in Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements included in Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2012, see Note 12—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. An adverse resolution of any proceedings related to Tronox could subject us to significant monetary damages and other penalties, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

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

       The following sets forth information with respect to repurchases by the Company of its shares of common stock during the third quarter of 2013.

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	1,406	$	87.48	—
August 1-31	901	$	90.25	—
September 1-30	851	$	92.02	—
Third-Quarter 2013	3,158	$	89.49	—	$	—

 ____________________________________________________________

⁽¹⁾  During the third quarter of 2013, 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 or double asterisk (**) and are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Exhibit Number			Description	File Number
	3	(i)	Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009, filed as exhibit 3.3 to Form 8-K filed on May 22, 2009	1-8968
		(ii)	By-Laws of Anadarko Petroleum Corporation, amended and restated as of May 15, 2012, filed as exhibit 3.1 to Form 8-K filed on May 15, 2012	1-8968
*	31	(i)	Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer
*	31	(ii)	Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer
**	32		Section 1350 Certifications
*	101	.INS	XBRL Instance Document
*	101	.SCH	XBRL Schema Document
*	101	.CAL	XBRL Calculation Linkbase Document
*	101	.DEF	XBRL Definition Linkbase Document
*	101	.LAB	XBRL Label Linkbase Document
*	101	.PRE	XBRL Presentation 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, thereunto duly authorized.

		ANADARKO PETROLEUM CORPORATION
		(Registrant)
November 4, 2013	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer

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EX-31.(I)

EXHIBIT 31(i)

CERTIFICATIONS

I, R. A. Walker, certify that:

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

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

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

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

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

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

November 4, 2013

/s/ R. A. WALKER

R. A. Walker

Chairman, President and Chief Executive Officer

EX-31.(II)

EXHIBIT 31(ii)

CERTIFICATIONS

I, Robert G. Gwin, certify that:

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

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

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

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

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

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

November 4, 2013

/s/ ROBERT G. GWIN

Robert G. Gwin

Executive Vice President, Finance and Chief Financial Officer

EX-32

EXHIBIT 32

SECTION 1350 CERTIFICATION OF PERIODIC REPORT

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

(1) the Quarterly Report on Form 10-Q of the Company for the period ended September 30, 2013, 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.

November 4, 2013
	/s/ R. A. WALKER
	R. A. Walker
	Chairman, President and Chief Executive Officer
November 4, 2013
	/s/ ROBERT G. GWIN
	Robert G. Gwin
	Executive 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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Debt and Interest Expense

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Debt and Interest Expense

8. Debt and Interest Expense

Debt    The Company’s outstanding debt is senior unsecured, except for borrowings, if any, under the $5.0 billion Facility. The following summarizes the Company’s outstanding debt:

	September 30,			December 31,
millions	2013			2012
Total debt at face value	$	15,302		$	14,952
Net unamortized discounts and premiums (1)	(1,655		)	(1,683		)
Total long-term debt	$	13,647		$	13,269

__________________________________________________________________

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

       Anadarko’s $500 million aggregate principal amount of 7.625% Senior Notes due March 2014 and $275 million aggregate principal amount of 5.750% Senior Notes due June 2014 are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance these obligations using long-term debt. The Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, which would cause the Company to repay up to the then-accreted value of the outstanding Zero Coupons. None of the Zero Coupons (accreted value of $718 million) were put to the Company in October 2013.

Fair Value    The Company uses a market approach to determine fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $15.8 billion at September 30, 2013, and $16.2 billion at December 31, 2012.

Debt Activity    The following summarizes the Company’s debt activity during the nine months ended September 30,2013:

	Carrying
millions	Value			Description
Balance at December 31, 2012	$	13,269
Borrowings	385			WES revolving credit facility
Other, net	9			Amortization of debt discounts and premiums
Balance at March 31, 2013	$	13,663
Borrowings	110			WES revolving credit facility
Repayments	(245		)	WES revolving credit facility
Other, net	10			Amortization of debt discounts and premiums
Balance at June 30, 2013	$	13,538
Issuance	250			WES 2.600% Senior Notes due 2018
Borrowings	100			WES revolving credit facility
Repayments	(250		)	WES revolving credit facility
Other, net	9			Amortization of debt discounts and premiums
Balance at September 30, 2013	$	13,647

WES Borrowings    During the third quarter of 2013, WES repaid $250 million of outstanding borrowings under its five-year, $800 million senior unsecured revolving credit facility maturing in March 2016 (RCF) with net proceeds from its public offering of $250 million aggregate principal amount of 2.600% Senior Notes due 2018. At September 30, 2013, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $100 million at an interest rate of 1.68%, and had available borrowing capacity of $687 million ($800 million maximum capacity, less $100 million of outstanding borrowings and $13 million of outstanding letters of credit).

8. Debt and Interest Expense (Continued)

Interest Expense    The following summarizes interest expense:

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions	2013			2012			2013			2012
Current debt, long-term debt, and other	$	240		$	238		$	710		$	724
Capitalized interest	(63		)	(53		)	(197		)	(163		)
Interest expense	$	177		$	185		$	513		$	561

XML

Debt and Interest Expense - Debt Activity Table (Detail) (USD $)	3 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013
Debt Disclosure [Abstract]
Carrying value, beginning balance	$ 13,538,000,000	$ 13,663,000,000	$ 13,269,000,000
Debt Instrument [Line Items]
Other, net	9,000,000	10,000,000	9,000,000
Carrying value, ending balance	13,647,000,000	13,538,000,000	13,663,000,000
Western Gas Partners, LP [Member] | Senior Notes 3 [Member]
Debt Instrument [Line Items]
Issuance	250,000,000
Western Gas Partners, LP [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Borrowings	100,000,000	110,000,000	385,000,000
Repayments	$ (250,000,000)	$ (245,000,000)

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement of Comprehensive Income [Abstract]
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net, tax effect	$ (1)	$ (1)	$ (3)	$ (3)
Amortization of net actuarial (gain) loss to general and administrative expense, tax effect	$ (11)	$ (8)	$ (32)	$ (25)

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

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, treating, and transporting of natural gas, crude oil, and NGLs. 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 at September 30, 2013, and December 31, 2012, the Consolidated Statements of Income and Comprehensive Income for the three and nine months ended September 30, 2013 and 2012, the Consolidated Statements of Cash Flows for the nine months endedSeptember 30, 2013 and 2012, and the Consolidated Statement of Equity for the nine months ended September 30, 2013. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

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

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Segment Information

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Segment Information

15. Segment Information

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

15. Segment Information (Continued)

       To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; interest expense; unrealized (gains) losses on derivatives, net; realized (gains) losses on interest-rate and other derivatives, net; and certain items not related to the Company’s normal operations, less net income attributable to noncontrolling interests. During the periods presented, these items included Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Finally, unrealized (gains) losses on derivatives, net and realized (gains) losses on interest-rate and other derivatives, net are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance.

       Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders. Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income or cash flows from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:

	Three Months Ended   September 30,					Nine Months Ended   September 30,
millions	2013			2012		2013			2012
Income (loss) before income taxes	$	463		$	390	$	2,929		$	3,019
Exploration expense	272			297		714			1,662
DD&A	996			979		2,958			2,936
Impairments	593			4		632			166
Interest expense	177			185		513			561
Unrealized (gains) losses on derivatives, net	36			456		(359		)	539
Realized (gains) losses on interest-rate and other derivatives, net	—			—		—			2
Deepwater Horizon settlement and related costs	5			4		12			15
Algeria exceptional profits tax settlement	—			7		33			(1,797		)
Tronox-related contingent loss	—			—		—			(250		)
Certain other nonoperating items	(10		)	—		75			—
Less net income attributable to noncontrolling interests	41			21		95			67
Consolidated Adjusted EBITDAX	$	2,491		$	2,301	$	7,412		$	6,786

15. Segment Information (Continued)

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

millions	Oil and Gas Exploration & Production		Midstream			Marketing			Other and Intersegment Eliminations			Total
Three Months Ended September 30, 2013
Sales revenues	$	1,916	$	95		$	1,778		$	—		$	3,789
Intersegment revenues	1,516		287			(1,629		)	(174		)	—
Gains (losses) on divestitures and other, net	7		—			—			57			64
Total revenues and other	3,439		382			149			(117		)	3,853
Operating costs and expenses (1)	930		216			164			(12		)	1,298
Realized (gains) losses on commodity    derivatives, net	—		—			—			26			26
Other (income) expense, net (2)	—		—			—			(13		)	(13		)
Net income attributable to noncontrolling interests	—		41			—			—			41
Total expenses and other	930		257			164			1			1,352
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—		—			(10		)	—			(10		)
Adjusted EBITDAX	$	2,509	$	125		$	(25	)	$	(118	)	$	2,491
Three Months Ended September 30, 2012
Sales revenues	$	1,393	$	80		$	1,810		$	—		$	3,283
Intersegment revenues	1,587		232			(1,682		)	(137		)	—
Gains (losses) on divestitures and other, net	12		(6		)	—			43			49
Total revenues and other	2,992		306			128			(94		)	3,332
Operating costs and expenses (1)	840		182			152			51			1,225
Realized (gains) losses on commodity    derivatives, net	—		—			—			(200		)	(200		)
Other (income) expense, net (2)	—		—			—			(10		)	(10		)
Net income attributable to noncontrolling interests	—		21			—			—			21
Total expenses and other	840		203			152			(159		)	1,036
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—		—			5			—			5
Adjusted EBITDAX	$	2,152	$	103		$	(19	)	$	65		$	2,301

 __________________________________________________________________

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

⁽²⁾   Other (income) expense, net excludes Tronox-related contingent loss and certain other nonoperating items since these expenses are excluded from Adjusted EBITDAX.

15. Segment Information (Continued)

millions	Oil and Gas Exploration & Production			Midstream			Marketing			Other and Intersegment Eliminations			Total
Nine Months Ended September 30, 2013
Sales revenues	$	5,044		$	267		$	5,636		$	—		$	10,947
Intersegment revenues	4,904			805			(5,234		)	(475		)	—
Gains (losses) on divestitures and other, net	12			—			—			284			296
Total revenues and other	9,960			1,072			402			(191		)	11,243
Operating costs and expenses (1)	2,656			613			492			15			3,776
Realized (gains) losses on commodity    derivatives, net	—			—			—			(46		)	(46		)
Other (income) expense, net (2)	—			—			—			(6		)	(6		)
Net income attributable to noncontrolling interests	—			95			—			—			95
Total expenses and other	2,656			708			492			(37		)	3,819
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—			—			(12		)	—			(12		)
Adjusted EBITDAX	$	7,304		$	364		$	(102	)	$	(154	)	$	7,412
Nine Months Ended September 30, 2012
Sales revenues	$	5,180		$	248		$	4,467		$	—		$	9,895
Intersegment revenues	3,796			701			(4,101		)	(396		)	—
Gains (losses) on divestitures and other, net	(17		)	(8		)	—			131			106
Total revenues and other	8,959			941			366			(265		)	10,001
Operating costs and expenses (1)	2,639			545			464			132			3,780
Realized (gains) losses on commodity    derivatives, net	—			—			—			(600		)	(600		)
Other (income) expense, net (2)	—			—			—			(14		)	(14		)
Net income attributable to noncontrolling interests	—			67			—			—			67
Total expenses and other	2,639			612			464			(482		)	3,233
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—			—			18			—			18
Adjusted EBITDAX	$	6,320		$	329		$	(80	)	$	217		$	6,786

 __________________________________________________________________

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

⁽²⁾   Other (income) expense, net excludes Tronox-related contingent loss and certain other nonoperating items since these expenses are excluded from Adjusted EBITDAX.

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Accumulated Other Comprehensive Income (Loss) (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at December 31, 2012	$ (640)
Reclassifications to Consolidated Statement of Income	62
Balance at September 30, 2013	(578)
Interest-rate Derivatives Previously Subject to Hedge Accounting [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at December 31, 2012	(61)
Reclassifications to Consolidated Statement of Income	5
Balance at September 30, 2013	(56)
Pension and Other Postretirement Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at December 31, 2012	(579)
Reclassifications to Consolidated Statement of Income	57
Balance at September 30, 2013	$ (522)

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Stockholders' Equity

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Stockholders' Equity

9. Stockholders’ Equity

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

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions except per-share amounts	2013		2012		2013		2012
Net income (loss)
Net income (loss) attributable to common stockholders	$	182	$	121	$	1,571	$	2,188
Less distributions on participating securities	—		—		1		1
Less undistributed income allocated to participating securities	1		1		9		13
Basic	$	181	$	120	$	1,561	$	2,174
Diluted	$	181	$	120	$	1,561	$	2,174
Shares
Average number of common shares outstanding—basic	503		500		502		499
Dilutive effect of stock options	2		2		2		2
Average number of common shares outstanding—diluted	505		502		504		501
Excluded (1)	3		6		4		6
Net income (loss) per common share
Basic	$	0.36	$	0.24	$	3.11	$	4.35
Diluted	$	0.36	$	0.24	$	3.10	$	4.34
Dividends per common share	$	0.18	$	0.09	$	0.36	$	0.27

 __________________________________________________________________

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

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Derivative Instruments - Effect of Derivative Instruments - Balance Sheet Table (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Derivatives Fair Value [Line Items]
Gross derivative assets	$ 457		$ 506
Gross derivative liabilities	(1,011)		(1,419)
Commodity Derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	457		506
Gross derivative liabilities	(246)		(225)
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	359		475
Gross derivative liabilities	(170)		(197)
Commodity Derivatives [Member] | Other Noncurrent Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	50		24
Gross derivative liabilities	(13)		(7)
Commodity Derivatives [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	48		6
Gross derivative liabilities	(61)		(14)
Commodity Derivatives [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0		1
Gross derivative liabilities	(2)		(7)
Interest-Rate and Other Derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	(765)		(1,194)
Interest-Rate and Other Derivatives [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	(550)	[1]	0
Interest-Rate and Other Derivatives [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	$ (215)	[1]	$ (1,194)	[1]

[1] Interest-rate swaps with June 2014 maturity dates were reclassified from other liabilities to accrued expenses during the second quarter of 2013.

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Commitments (Detail) (Deepwater Drillship [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Deepwater Drillship [Member]
Operating Leased Assets [Line Items]
Operating lease, period	3 years
Total future minimum lease payments	$ 464
Aggregate future annual minimum lease payments in 2014	33
Aggregate future annual minimum lease payments in 2015	154
Aggregate future annual minimum lease payments in 2016	155
Aggregate future annual minimum lease payments in 2017	$ 122

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Acquisitions and Divestitures - Acquisitions (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended		1 Months Ended	9 Months Ended	1 Months Ended	9 Months Ended	1 Months Ended	9 Months Ended	1 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Mar. 31, 2013 Marcellus Interest in Gas Gathering Systems [Member] Western Gas Partners, LP [Member]	Sep. 30, 2013 Marcellus Interest in Gas Gathering Systems [Member] Western Gas Partners, LP [Member]	Jun. 30, 2013 Mont Belvieu Joint Venture [Member] Western Gas Partners, LP [Member]	Sep. 30, 2013 Mont Belvieu Joint Venture [Member] Western Gas Partners, LP [Member]	Aug. 31, 2013 Moxa Oil and Gas Properties [Member]	Sep. 30, 2013 Moxa Oil and Gas Properties [Member]	Sep. 30, 2013 Intrastate Pipeline in Wyoming [Member] Western Gas Partners, LP [Member]	Sep. 30, 2013 Intrastate Pipeline in Wyoming [Member] Western Gas Partners, LP [Member]
Business Acquisition [Line Items]
Date of acquisition agreement				Mar. 31, 2013		Jun. 30, 2013		Aug. 31, 2013		Sep. 30, 2013
Ownership interest purchased			33.75%		25.00%
Purchase price	$ 473	$ 0	$ 135		$ 78		$ 310		$ 28
Fair value, oil and gas properties acquired							$ 306

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Inventories (Tables)

9 Months Ended

Sep. 30, 2013

Table Text Block [Abstract]

Inventory Disclosure Table

The following summarizes the major classes of inventories included in other current assets:

	September 30,		December 31,
millions	2013		2012
Crude oil	$	102	$	91
Natural gas	41		48
NGLs	66		37
Total	$	209	$	176

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2013

Policy Text Block [Abstract]

Use of Estimates

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

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Derivative Instruments - Crude Oil Production/Processing Derivative Activities Table (Detail) (Not Designated as Hedging Instrument [Member], 2013 Settlement [Member], Crude Oil [Member], Price Risk Derivative [Member])	9 Months Ended
	Sep. 30, 2013
Three-Way Collars [Member]
Derivative [Line Items]
Derivative nonmonetary notional amount per day	26
Three-Way Collars [Member] | Call Option [Member] | Short [Member]
Average price per barrel
Average ceiling price	125.15
Three-Way Collars [Member] | Put Option [Member] | Short [Member]
Average price per barrel
Average floor price	85.00
Three-Way Collars [Member] | Put Option [Member] | Long [Member]
Average price per barrel
Average floor price	105.00
Fixed-Price Contracts [Member]
Derivative [Line Items]
Derivative nonmonetary notional amount per day	167
Average price per barrel
Average price per barrel	102.74

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2013

Table Text Block [Abstract]

Supplemental Cash Flow Table

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

	Nine Months Ended   September 30,
millions	2013		2012
Cash paid (received)
Interest	$	569	$	613
Income taxes	$	137	$	(13	)
Non-cash investing activities
Fair value of properties and equipment received in non-cash exchange transactions	$	13	$	65

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Impairments - Impairments by Segment Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Impaired Long Lived Assets Held and Used [Line Items]
Impairments	$ 593	$ 4	$ 632	$ 166
Oil and Gas Exploration and Production Reporting Segment [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Cost-method investment	0	1	10	12
Oil and Gas Exploration and Production Reporting Segment [Member] | U.S. Onshore Properties [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Long-lived assets held for use	0	2	0	81
Oil and Gas Exploration and Production Reporting Segment [Member] | Gulf of Mexico Properties [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Long-lived assets held for use	593	0	593	67
Midstream Reporting Segment [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Long-lived assets held for use	$ 0	$ 1	$ 29	$ 6

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Derivative Instruments - Effect of Derivative Instruments - Statement of Income Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Derivative [Line Items]
Unrealized (gains) losses on derivatives, net					$ (359)		$ 539
Total (gains) losses on derivatives, net	72		251		(393)		(77)
Gathering, Processing, and Marketing Sales and Gains (Losses) on Derivatives, Net [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	28		(197)		(37)		(598)
Unrealized (gains) losses on derivatives, net	36		456		(359)		539
Total (gains) losses on derivatives, net	64		259		(396)		(59)
Commodity Derivatives [Member] | Gathering, Processing, and Marketing Sales [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	2	[1]	3	[1]	9	[1]	0	[1]
Unrealized (gains) losses on derivatives, net	(10)	[1]	5	[1]	(12)	[1]	18	[1]
Total (gains) losses on derivatives, net	(8)	[1]	8	[1]	(3)	[1]	18	[1]
Commodity Derivatives [Member] | (Gains) Losses on Derivatives, net [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	26		(200)		(46)		(600)
Unrealized (gains) losses on derivatives, net	120		437		81		369
Total (gains) losses on derivatives, net	146		237		35		(231)
Interest-Rate and Other Derivatives [Member] | (Gains) Losses on Derivatives, net [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	0		0		0		2
Unrealized (gains) losses on derivatives, net	(74)		14		(428)		152
Total (gains) losses on derivatives, net	$ (74)		$ 14		$ (428)		$ 154

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

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Stockholders' Equity (Tables)

9 Months Ended

Sep. 30, 2013

Table Text Block [Abstract]

Earnings Per Share Table

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

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions except per-share amounts	2013		2012		2013		2012
Net income (loss)
Net income (loss) attributable to common stockholders	$	182	$	121	$	1,571	$	2,188
Less distributions on participating securities	—		—		1		1
Less undistributed income allocated to participating securities	1		1		9		13
Basic	$	181	$	120	$	1,561	$	2,174
Diluted	$	181	$	120	$	1,561	$	2,174
Shares
Average number of common shares outstanding—basic	503		500		502		499
Dilutive effect of stock options	2		2		2		2
Average number of common shares outstanding—diluted	505		502		504		501
Excluded (1)	3		6		4		6
Net income (loss) per common share
Basic	$	0.36	$	0.24	$	3.11	$	4.35
Diluted	$	0.36	$	0.24	$	3.10	$	4.34
Dividends per common share	$	0.18	$	0.09	$	0.36	$	0.27

 __________________________________________________________________

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

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Segment Information - Selected Financial Information for Anadarko's Reporting Segments Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Segment Reporting Information [Line Items]
Revenue	$ 3,789		$ 3,283		$ 10,947		$ 9,895
Gains (losses) on divestitures and other, net	64		49		296		106
Total	3,853		3,332		11,243		10,001
Operating costs and expenses (1)	1,298	[1]	1,225	[1]	3,776	[1]	3,780	[1]
Other (income) expense, net	(23)		(10)		69		(264)
Net income attributable to noncontrolling interests	41		21		95		67
Total expenses and other	1,352		1,036		3,819		3,233
Unrealized (gains) losses on derivatives, net included in marketing revenue					(359)		539
Adjusted EBITDAX	2,491		2,301		7,412		6,786
Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue	(174)		(137)		(475)		(396)
Gains (losses) on divestitures and other, net	57		43		284		131
Total	(117)		(94)		(191)		(265)
Operating costs and expenses (1)	(12)	[1]	51	[1]	15	[1]	132	[1]
Total expenses and other	1		(159)		(37)		(482)
Adjusted EBITDAX	(118)		65		(154)		217
Gathering, Processing, and Marketing Sales [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	2	[2]	3	[2]	9	[2]	0	[2]
Unrealized (gains) losses on derivatives, net included in marketing revenue	(10)	[2]	5	[2]	(12)	[2]	18	[2]
(Gains) Losses on Derivatives, net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	26		(200)		(46)		(600)
Unrealized (gains) losses on derivatives, net included in marketing revenue	120		437		81		369
(Gains) Losses on Derivatives, net [Member] | Commodity Contract [Member] | Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	26		(200)		(46)		(600)
Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	(13)	[3]	(10)	[3]	(6)	[3]	(14)	[3]
Excluding Certain Other Nonoperating Items [Member] | Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	(13)	[3]	(10)	[3]	(6)	[3]	(14)	[3]
Oil and Gas Exploration and Production Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenue	1,916		1,393		5,044		5,180
Gains (losses) on divestitures and other, net	7		12		12		(17)
Oil and Gas Exploration and Production Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total	3,439		2,992		9,960		8,959
Operating costs and expenses (1)	930	[1]	840	[1]	2,656	[1]	2,639	[1]
Total expenses and other	930		840		2,656		2,639
Adjusted EBITDAX	2,509		2,152		7,304		6,320
Oil and Gas Exploration and Production Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	1,516		1,587		4,904		3,796
Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenue	95		80		267		248
Gains (losses) on divestitures and other, net	0		(6)		0		(8)
Midstream Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total	382		306		1,072		941
Operating costs and expenses (1)	216	[1]	182	[1]	613	[1]	545	[1]
Net income attributable to noncontrolling interests	41		21		95		67
Total expenses and other	257		203		708		612
Adjusted EBITDAX	125		103		364		329
Midstream Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	287		232		805		701
Marketing Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenue	1,778		1,810		5,636		4,467
Gains (losses) on divestitures and other, net	0		0		0		0
Marketing Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total	149		128		402		366
Operating costs and expenses (1)	164	[1]	152	[1]	492	[1]	464	[1]
Total expenses and other	164		152		492		464
Adjusted EBITDAX	(25)		(19)		(102)		(80)
Marketing Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	(1,629)		(1,682)		(5,234)		(4,101)
Marketing Reporting Segment [Member] | Gathering, Processing, and Marketing Sales [Member] | Commodity Contract [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net included in marketing revenue	$ (10)		$ 5		$ (12)		$ 18

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

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

[3] Other (income) expense, net excludes Tronox-related contingent loss and certain other nonoperating items since these expenses are excluded from Adjusted EBITDAX.

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Segment Information - Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) before Income Taxes Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Reconciliation of Operating Profit (Loss) from Segments to Consolidated [Abstract]
Income (loss) before income taxes	$ 463	$ 390	$ 2,929	$ 3,019
Exploration expense	272	297	714	1,662
DD&A	996	979	2,958	2,936
Impairments	593	4	632	166
Interest expense	177	185	513	561
Deepwater Horizon settlement and related costs	5	4	12	15
Algeria exceptional profits tax settlement	0	7	33	(1,797)
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net			(359)	539
Certain other nonoperating items			0	(250)
Less net income attributable to noncontrolling interests	41	21	95	67
Consolidated Adjusted EBITDAX	2,491	2,301	7,412	6,786
Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Certain other nonoperating items	(10)	0	75	0
Gathering, Processing, and Marketing Sales and Gains (Losses) on Derivatives, Net [Member]
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net	36	456	(359)	539
Realized (gains) losses on interest-rate and other derivatives, net	28	(197)	(37)	(598)
(Gains) Losses on Derivatives, net [Member] | Interest-Rate and Other Derivatives [Member]
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net	(74)	14	(428)	152
Realized (gains) losses on interest-rate and other derivatives, net	0	0	0	2
Tronox Litigation [Member]
Segment Reporting Information [Line Items]
Tronox-related contingent loss	$ 0	$ 0	$ 0	$ (250)

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Noncontrolling Interests (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Noncontrolling Interest [Line Items]
Net proceeds raised from offering by subsidiary	$ 418	$ 212
Western Gas Equity Partners, LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	91.00%
Western Gas Partners, LP [Member]
Noncontrolling Interest [Line Items]
Common units issued to the public	7
Net proceeds raised from offering by subsidiary	$ 419
Western Gas Partners, LP [Member] | Limited Partner [Member] | Western Gas Equity Partners, LP, Ownership Interest [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	43.10%
Western Gas Partners, LP [Member] | Limited Partner [Member] | Other Anadarko Subsidiary, Ownership Interest [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	0.40%
Western Gas Partners, LP [Member] | General Partner [Member] | Western Gas Equity Partners, LP, Ownership Interest [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	2.00%

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Pension Plans and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Pension Plans and Other Postretirement Benefits

16. Pension Plans and Other Postretirement Benefits

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

       During the nine months ended September 30, 2013, the Company made contributions of $122 million to its funded pension plans, $6 million to its unfunded pension plans, and $11 million to its unfunded other postretirement benefit plans. During the fourth quarter of 2013, the Company expects to contribute $2 million to its funded pension plans, $30 million to its unfunded pension plans, and $5 million to its unfunded other postretirement benefit plans.

       The following summarizes the Company’s pension and other postretirement benefit cost:

	Pension Benefits						Other Benefits
millions	2013			2012			2013		2012
Three Months Ended September 30
Service cost	$	21		$	19		$	2	$	2
Interest cost	19			21			3		4
Expected return on plan assets	(22		)	(23		)	—		—
Amortization of net actuarial loss (gain)	29			23			—		—
Amortization of net prior service cost (credit)	—			—			1		—
Net periodic benefit cost	$	47		$	40		$	6	$	6
Nine Months Ended September 30
Service cost	$	64		$	57		$	7	$	7
Interest cost	58			64			10		12
Expected return on plan assets	(68		)	(68		)	—		—
Amortization of net actuarial loss (gain)	88			69			—		—
Amortization of net prior service cost (credit)	—			—			1		1
Net periodic benefit cost	$	142		$	122		$	18	$	20

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 6	$ 7
Common stock, par value	$ 0.1	$ 0.1
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	521,700,000	518,600,000
Treasury stock, shares	18,500,000	18,100,000

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CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Statement of Stockholders' Equity [Abstract]
Increase to paid-in capital for change in ownership interest upon equity issuance	$ 61
Net income (loss) attributable to common stockholders, including increase to paid-in capital for change in ownership interest upon equity issuance	$ 1,632

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Inventories

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Inventories

2. Inventories

       The following summarizes the major classes of inventories included in other current assets:

	September 30,		December 31,
millions	2013		2012
Crude oil	$	102	$	91
Natural gas	41		48
NGLs	66		37
Total	$	209	$	176

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash Flows from Operating Activities
Net income (loss)	$ 1,666	$ 2,255
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, and amortization	2,958	2,936
Deferred income taxes	535	95
Dry hole expense and impairments of unproved properties	423	1,389
Impairments	632	166
(Gains) losses on divestitures, net	(165)	23
Unrealized (gains) losses on derivatives, net	(359)	539
Other	174	174
Changes in assets and liabilities
Deepwater Horizon settlement and related costs	3	25
Algeria exceptional profits tax settlement	730	(1,183)
Tronox-related contingent loss	0	(250)
(Increase) decrease in accounts receivable	246	409
Increase (decrease) in accounts payable and accrued expenses	(37)	(486)
Other items—net	(22)	27
Net cash provided by (used in) operating activities	6,784	6,119
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	(5,327)	(5,448)
Acquisition of businesses	(473)	0
Divestitures of properties and equipment and other assets	451	440
Other—net	(552)	(188)
Net cash provided by (used in) investing activities	(5,901)	(5,196)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	843	885
Repayments of debt	(495)	(2,005)
Increase (decrease) in outstanding checks	63	12
Dividends paid	(182)	(136)
Repurchase of common stock	(30)	(26)
Issuance of common stock, including tax benefit on share-based compensation awards	123	68
Sale of subsidiary units	418	212
Distributions to noncontrolling interest owners	(111)	(81)
Contributions from noncontrolling interest owners	2	14
Net cash provided by (used in) financing activities	631	(1,057)
Effect of Exchange Rate Changes on Cash	(46)	(31)
Net Increase (Decrease) in Cash and Cash Equivalents	1,468	(165)
Cash and Cash Equivalents at Beginning of Period	2,471	2,697
Cash and Cash Equivalents at End of Period	$ 3,939	$ 2,532

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Impairments - Fair-Value Measurements Table (Detail) (Nonrecurring [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets held for use	$ 266		$ 38
Cost-method investment	32	[1]	34	[1]
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets held for use	0		0
Cost-method investment	0		0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets held for use	0		0
Cost-method investment	0		0
Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets held for use	266	[2]	38	[2]
Cost-method investment	$ 32	[1],[2]	$ 34	[1],[2]

[1] This represents the Company’s after-tax net investment.

[2] The income approach was used to measure fair value.

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Impairments (Tables)

9 Months Ended

Sep. 30, 2013

Table Text Block [Abstract]

Schedule of Impairment Expense

       The following summarizes impairments by segment:

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions	2013		2012		2013		2012
Oil and gas exploration and production
Long-lived assets held for use
U.S. onshore properties	$	—	$	2	$	—	$	81
Gulf of Mexico properties	593		—		593		67
Cost-method investment	—		1		10		12
Midstream
Long-lived assets held for use	—		1		29		6
Impairments	$	593	$	4	$	632	$	166

Nonrecurring Fair Value Measurements Table

       The following summarizes the post-impairment fair value of the above-described assets, by asset category and input level within the fair-value hierarchy:

millions
2013	Level 1		Level 2		Level 3 (1)		Total
Long-lived assets held for use	$	—	$	—	$	266	$	266
Cost-method investment (2)	—		—		32		32
2012
Long-lived assets held for use	$	—	$	—	$	38	$	38
Cost-method investment (2)	—		—		34		34

 __________________________________________________________________

⁽¹⁾  The income approach was used to measure fair value.

⁽²⁾  This represents the Company’s after-tax net investment.

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Accumulated Other Comprehensive Income (Loss) (Tables)

9 Months Ended

Sep. 30, 2013

Table Text Block [Abstract]

Schedule Of Accumulated Other Comprehensive Income (Loss) Table

  The following summarizes the after-tax changes in the balances of each component of accumulated other comprehensive income (loss):

millions	Interest-rate Derivatives Previously Subject to Hedge Accounting			Pension and Other Postretirement Plans			Total
Balance at December 31, 2012	$	(61	)	$	(579	)	$	(640	)
Reclassifications to Consolidated Statement of Income	5			57			62
Balance at September 30, 2013	$	(56	)	$	(522	)	$	(578	)

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Inventories (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Energy Related Inventory [Abstract]
Crude oil	$ 102	$ 91
Natural gas	41	48
NGLs	66	37
Total	$ 209	$ 176

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Stockholders' Equity (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Net income (loss)
Net income (loss) attributable to common stockholders	$ 182		$ 121		$ 1,571		$ 2,188
Less distributions on participating securities	0		0		1		1
Less undistributed income allocated to participating securities	1		1		9		13
Basic	181		120		1,561		2,174
Diluted	$ 181		$ 120		$ 1,561		$ 2,174
Shares
Average number of common shares outstanding—basic	503		500		502		499
Dilutive effect of stock options	2		2		2		2
Average number of common shares outstanding—diluted	505		502		504		501
Excluded (1)	3	[1]	6	[1]	4	[1]	6	[1]
Net income (loss) per common share
Basic	$ 0.36		$ 0.24		$ 3.11		$ 4.35
Diluted	$ 0.36		$ 0.24		$ 3.10		$ 4.34
Dividends per common share	$ 0.18		$ 0.09		$ 0.36		$ 0.27

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

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Derivative Instruments - Fair Value Table (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	$ 457		$ 506
Gross derivative liabilities	(1,011)		(1,419)
Derivative assets netting	(232)	[1]	(211)	[1]
Derivative liabilities netting	232	[1]	211	[1]
Cash collateral from counterparties	(1)		0
Cash collateral held by counterparties	1		1
Derivative assets	224		295
Derivative liabilities	(778)		(1,207)
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	457		506
Gross derivative liabilities	(246)		(225)
Interest-Rate and Other Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	(765)		(1,194)
Derivative liabilities netting	0	[1]	0	[1]
Cash collateral held by counterparties	0		0
Derivative liabilities	(765)		(1,194)
Financial Institutions [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	(226)	[1]	(206)	[1]
Derivative liabilities netting	226	[1]	206	[1]
Cash collateral from counterparties	(1)		0
Cash collateral held by counterparties	1		1
Derivative assets	156		253
Derivative liabilities	(9)		(1)
Other Counterparties [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	(6)	[1]	(5)	[1]
Derivative liabilities netting	6	[1]	5	[1]
Cash collateral from counterparties	0		0
Cash collateral held by counterparties	0		0
Derivative assets	68		42
Derivative liabilities	(4)		(12)
Fair Value, Inputs, Level 1 [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	4		6
Gross derivative liabilities	(4)		(6)
Fair Value, Inputs, Level 1 [Member] | Interest-Rate and Other Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 1 [Member] | Financial Institutions [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	4		6
Gross derivative liabilities	(4)		(6)
Fair Value, Inputs, Level 1 [Member] | Other Counterparties [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 2 [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	453		500
Gross derivative liabilities	(1,007)		(1,413)
Fair Value, Inputs, Level 2 [Member] | Interest-Rate and Other Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative liabilities	(765)		(1,194)
Fair Value, Inputs, Level 2 [Member] | Financial Institutions [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	379		453
Gross derivative liabilities	(232)		(202)
Fair Value, Inputs, Level 2 [Member] | Other Counterparties [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	74		47
Gross derivative liabilities	(10)		(17)
Fair Value, Inputs, Level 3 [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 3 [Member] | Interest-Rate and Other Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 3 [Member] | Financial Institutions [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 3 [Member] | Other Counterparties [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	$ 0		$ 0

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

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Derivative Instruments - Natural Gas Production/Processing Derivative Activities Table (Detail) (Price Risk Derivative [Member], Natural Gas [Member], Not Designated as Hedging Instrument [Member])	9 Months Ended
	Sep. 30, 2013
April 2013 to October 2013 Settlement [Member] | Two Way Collars [Member]
Derivative [Line Items]
Derivative nonmonetary notional amount per day	600,000	[1]
April 2013 to October 2013 Settlement [Member] | Two Way Collars [Member] | Call Option [Member] | Short [Member]
Average price per MMBtu
Average ceiling price	4.00
April 2013 to October 2013 Settlement [Member] | Two Way Collars [Member] | Put Option [Member] | Long [Member]
Average price per MMBtu
Average floor price	3.18
2013 Settlement [Member] | Three-Way Collars [Member] | Offsetting Purchased and Sold Positions For Four Hundred Fifty Thousand Million British Thermal Units Per Day [Member]
Derivative [Line Items]
Derivative nonmonetary notional amount per day	0	[2]
2013 Settlement [Member] | Three-Way Collars [Member] | Call Option [Member] | Short [Member] | Offsetting Purchased and Sold Positions For Four Hundred Fifty Thousand Million British Thermal Units Per Day [Member]
Derivative [Line Items]
Derivative nonmonetary notional amount per day	450,000
2013 Settlement [Member] | Three-Way Collars [Member] | Call Option [Member] | Long [Member] | Offsetting Purchased and Sold Positions For Four Hundred Fifty Thousand Million British Thermal Units Per Day [Member]
Derivative [Line Items]
Derivative nonmonetary notional amount per day	(450,000)
2013 Settlement [Member] | Fixed-Price Contracts [Member]
Derivative [Line Items]
Derivative nonmonetary notional amount per day	1,185,000
Average price per MMBtu
Average price per MMBtu	4.00
2014 Settlement [Member] | Three-Way Collars [Member]
Derivative [Line Items]
Derivative nonmonetary notional amount per day	600,000
2014 Settlement [Member] | Three-Way Collars [Member] | Call Option [Member] | Short [Member]
Average price per MMBtu
Average ceiling price	5.01
2014 Settlement [Member] | Three-Way Collars [Member] | Put Option [Member] | Short [Member]
Average price per MMBtu
Average floor price	2.75
2014 Settlement [Member] | Three-Way Collars [Member] | Put Option [Member] | Long [Member]
Average price per MMBtu
Average floor price	3.75
2014 Settlement [Member] | Fixed-Price Contracts [Member]
Derivative [Line Items]
Derivative nonmonetary notional amount per day	600,000
Average price per MMBtu
Average price per MMBtu	4.26

[1] The two-way collars have a contract term of April 2013 to October 2013.

[2] The Company entered into offsetting purchased and sold natural-gas three-way collars of 450,000 MMBtu/d for 2013 settlement.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 223		$ 142		$ 1,666		$ 2,255
Other Comprehensive Income (Loss), net of taxes
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net (1)	2	[1]	2	[1]	5	[1]	6	[1]
Adjustments for pension and other postretirement plans
Amortization of net actuarial (gain) loss to general and administrative expense (2)	18	[2]	15	[2]	56	[2]	44	[2]
Amortization of net prior service (credit) cost to general and administrative expense	1		0		1		1
Total adjustments for pension and other postretirement plans	19		15		57		45
Total	21		17		62		51
Comprehensive Income (Loss)	244		159		1,728		2,306
Comprehensive income attributable to noncontrolling interests	41		21		95		67
Comprehensive Income (Loss) Attributable to Common Stockholders	$ 203		$ 138		$ 1,633		$ 2,239

[1] Net of income tax benefit (expense) of $(1) million for the three months ended September 30, 2013, $(1) million for the three months ended September 30, 2012, $(3) million for the nine months ended September 30, 2013, and $(3) million for the nine months ended September 30, 2012.

[2] Net of income tax benefit (expense) of $(11) million for the three months ended September 30, 2013, $(8) million for the three months ended September 30, 2012, $(32) million for the nine months ended September 30, 2013, and $(25) million for the nine months ended September 30, 2012.

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Suspended Exploratory Well Costs

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Suspended Exploratory Well Costs

5. Suspended Exploratory Well Costs

       The Company’s suspended exploratory well costs were $2.2 billion at September 30, 2013, and $2.1 billion at December 31, 2012. The increase in suspended exploratory well costs during 2013 is primarily related to the capitalization of costs associated with successful exploration drilling in the Gulf of Mexico, Brazil, and Mozambique. Management believes projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development and is actively pursuing efforts to assess whether reserves can be attributed to these projects. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time. During the nine months ended September 30, 2013, $95 million of exploratory well costs previously capitalized as suspended exploratory well costs for greater than one year at December 31, 2012, were charged to dry hole expense.

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CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current Assets
Cash and cash equivalents	$ 3,939	$ 2,471
Accounts receivable (net of allowance of $6 million and $7 million)
Customers	1,266	1,473
Others	1,199	1,274
Algeria exceptional profits tax settlement	0	730
Other current assets	736	847
Total	7,140	6,795
Properties and Equipment
Cost	69,167	63,598
Less accumulated depreciation, depletion, and amortization	28,682	25,200
Net properties and equipment	40,485	38,398
Other Assets	2,006	1,716
Goodwill and Other Intangible Assets	5,663	5,680
Total Assets	55,294	52,589
Current Liabilities
Accounts payable	3,070	2,989
Current asset retirement obligations	311	298
Accrued expenses	1,357	707
Total	4,738	3,994
Long-term Debt	13,647	13,269
Other Long-term Liabilities
Deferred income taxes	9,372	8,759
Asset retirement obligations	1,673	1,587
Other	1,963	3,098
Total	13,008	13,444
Stockholders' equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 521.7 million and 518.6 million shares issued)	52	51
Paid-in capital	8,521	8,230
Retained earnings	15,218	13,829
Treasury stock (18.5 million and 18.1 million shares)	(871)	(841)
Accumulated other comprehensive income (loss)	(578)	(640)
Total Stockholders’ Equity	22,342	20,629
Noncontrolling interests	1,559	1,253
Total Equity	23,901	21,882
Total Liabilities and Equity	$ 55,294	$ 52,589

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Contingencies (Detail) (USD $)	3 Months Ended		9 Months Ended					9 Months Ended
	Sep. 30, 2013 Tronox Litigation [Member]	Sep. 30, 2012 Tronox Litigation [Member]	Sep. 30, 2013 Tronox Litigation [Member]	Sep. 30, 2012 Tronox Litigation [Member]	Sep. 30, 2013 Tronox Litigation [Member] Principal Portion of Maximum Loss Range [Member]	Sep. 30, 2011 Macondo Exploration Well [Member]	Sep. 30, 2013 Deepwater Horizon [Member] BP indemnification liability [Member]	Sep. 30, 2013 Third Party Bankruptcy Assignment [Member]
Loss Contingencies [Line Items]
Anadarko's nonoperated interest						25.00%
Loss contingency accrual at carrying value	$ 0		$ 0				$ 0
Damages sought, including interest, in excess of			18,900,000,000
Range of potential loss, minimum	0		0
Range of potential loss, maximum	1,400,000,000		1,400,000,000		985,000,000
Pretax loss	0	0	0	(250,000,000)				131,000,000
Decommissioning obligations included in accrued expenses								44,000,000
Decommissioning obligations included in other long-term liabilities								$ 85,000,000

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues and Other
Natural-gas sales	$ 805	$ 613	$ 2,547	$ 1,682
Oil and condensate sales	2,389	2,163	6,761	6,629
Natural-gas liquids sales	325	289	889	913
Gathering, processing, and marketing sales	270	218	750	671
Gains (losses) on divestitures and other, net	64	49	296	106
Total	3,853	3,332	11,243	10,001
Costs and Expenses
Oil and gas operating	277	241	769	732
Oil and gas transportation and other	255	247	763	710
Exploration	272	297	714	1,662
Gathering, processing, and marketing	217	185	638	552
General and administrative	255	285	787	816
Depreciation, depletion, and amortization	996	979	2,958	2,936
Other taxes	294	267	819	970
Impairments	593	4	632	166
Algeria exceptional profits tax settlement	0	7	33	(1,797)
Deepwater Horizon settlement and related costs	5	4	12	15
Total	3,164	2,516	8,125	6,762
Operating Income (Loss)	689	816	3,118	3,239
Other (Income) Expense
Interest expense	177	185	513	561
(Gains) losses on derivatives, net	72	251	(393)	(77)
Other (income) expense, net	(23)	(10)	69	(264)
Total	226	426	189	220
Income (Loss) Before Income Taxes	463	390	2,929	3,019
Income tax expense (benefit)	240	248	1,263	764
Net Income (Loss)	223	142	1,666	2,255
Net income attributable to noncontrolling interests	41	21	95	67
Net Income (Loss) Attributable to Common Stockholders	$ 182	$ 121	$ 1,571	$ 2,188
Per Common Share
Net income (loss) attributable to common stockholders—basic	$ 0.36	$ 0.24	$ 3.11	$ 4.35
Net income (loss) attributable to common stockholders—diluted	$ 0.36	$ 0.24	$ 3.10	$ 4.34
Average Number of Common Shares Outstanding—Basic	503	500	502	499
Average Number of Common Shares Outstanding—Diluted	505	502	504	501
Dividends (per Common Share)	$ 0.18	$ 0.09	$ 0.36	$ 0.27

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Debt and Interest Expense - Outstanding Debt Table (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Debt Disclosure [Abstract]
Total debt at face value	$ 15,302		$ 14,952
Net unamortized discounts and premiums (1)	(1,655)	[1]	(1,683)	[1]
Total long-term debt	$ 13,647		$ 13,269

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

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Table Text Block [Abstract]

Schedule of Derivative Instruments

The following is a summary of the Company’s derivative instruments related to its Oil and Natural-Gas Production/Processing Derivative Activities at September 30, 2013:

	2013 Settlement			2014 Settlement
Natural Gas
Two-Way Collars (thousand MMBtu/d)	600		(1)	—
Average price per MMBtu
Ceiling sold price (call)	$	4.00		$	—
Floor purchased price (put)	$	3.18		$	—
Three-Way Collars (thousand MMBtu/d)	—		(2)	600
Average price per MMBtu
Ceiling sold price (call)	$	—		$	5.01
Floor purchased price (put)	$	—		$	3.75
Floor sold price (put)	$	—		$	2.75
Fixed-Price Contracts (thousand MMBtu/d)	1,185			600
Average price per MMBtu	$	4.00		$	4.26
Crude Oil
Three-Way Collars (MBbls/d)	26			—
Average price per barrel
Ceiling sold price (call)	$	125.15		$	—
Floor purchased price (put)	$	105.00		$	—
Floor sold price (put)	$	85.00		$	—
Fixed-Price Contracts (MBbls/d)	167			—
Average price per barrel	$	102.74		$	—

__________________________________________________________________

⁽¹⁾ The two-way collars have a contract term of April 2013 to October 2013.

⁽²⁾ The Company entered into offsetting purchased and sold natural-gas three-way collars of 450,000 MMBtu/d for 2013 settlement.

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

The Company had the following outstanding interest-rate swaps at September 30, 2013:

millions except percentages		Reference Period		Weighted-Average
Notional Principal Amount		Start	End	Interest Rate
$	750	June 2014	June 2024	6.00%
$	1,100	June 2014	June 2044	5.57%
$	50	September 2016	September 2026	5.91%
$	750	September 2016	September 2046	5.86%

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

The following summarizes the fair value of the Company’s derivative instruments:

	Gross Derivative Assets				Gross Derivative Liabilities
millions	September 30,		December 31,		September 30,			December 31,
Balance Sheet Classification	2013		2012		2013			2012
Commodity derivatives
Other current assets	$	359	$	475	$	(170	)	$	(197	)
Other assets	50		24		(13		)	(7		)
Accrued expenses	48		6		(61		)	(14		)
Other liabilities	—		1		(2		)	(7		)
	457		506		(246		)	(225		)
Interest-rate and other derivatives
Accrued expenses (1)	—		—		(550		)	—
Other liabilities (1)	—		—		(215		)	(1,194		)
	—		—		(765		)	(1,194		)
Total derivatives	$	457	$	506	$	(1,011	)	$	(1,419	)

 __________________________________________________________________

⁽¹⁾ Interest-rate swaps with June 2014 maturity dates were reclassified from other liabilities to accrued expenses during the second quarter of 2013.

The following summarizes realized and unrealized gains and losses related to derivative instruments:

millions	Three Months Ended   September 30, 2013									Nine Months Ended   September 30, 2013
Classification of (Gain) Loss Recognized	Realized			Unrealized			Total			Realized			Unrealized			Total
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	2		$	(10	)	$	(8	)	$	9		$	(12	)	$	(3	)
(Gains) losses on derivatives, net	26			120			146			(46		)	81			35
Interest-rate and other derivatives
(Gains) losses on derivatives, net	—			(74		)	(74		)	—			(428		)	(428		)
Total (gains) losses on derivatives, net	$	28		$	36		$	64		$	(37	)	$	(359	)	$	(396	)
	Three Months Ended   September 30, 2012									Nine Months Ended   September 30, 2012
Classification of (Gain) Loss Recognized	Realized			Unrealized			Total			Realized			Unrealized			Total
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	3		$	5		$	8		$	—		$	18		$	18
(Gains) losses on derivatives, net	(200		)	437			237			(600		)	369			(231		)
Interest-rate and other derivatives
(Gains) losses on derivatives, net	—			14			14			2			152			154
Total (gains) losses on derivatives, net	$	(197	)	$	456		$	259		$	(598	)	$	539		$	(59	)

__________________________________________________________________

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

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

The following summarizes the fair value of the Company’s derivative assets and liabilities, by input level within the fair-value hierarchy:

millions
September 30, 2013	Level 1			Level 2			Level 3		Netting (1)			Collateral			Total
Assets
Commodity derivatives
Financial institutions	$	4		$	379		$	—	$	(226	)	$	(1	)	$	156
Other counterparties	—			74			—		(6		)	—			68
Total derivative assets	$	4		$	453		$	—	$	(232	)	$	(1	)	$	224
Liabilities
Commodity derivatives
Financial institutions	$	(4	)	$	(232	)	$	—	$	226		$	1		$	(9	)
Other counterparties	—			(10		)	—		6			—			(4		)
Interest-rate and other derivatives	—			(765		)	—		—			—			(765		)
Total derivative liabilities	$	(4	)	$	(1,007	)	$	—	$	232		$	1		$	(778	)
December 31, 2012
Assets
Commodity derivatives
Financial institutions	$	6		$	453		$	—	$	(206	)	$	—		$	253
Other counterparties	—			47			—		(5		)	—			42
Total derivative assets	$	6		$	500		$	—	$	(211	)	$	—		$	295
Liabilities
Commodity derivatives
Financial institutions	$	(6	)	$	(202	)	$	—	$	206		$	1		$	(1	)
Other counterparties	—			(17		)	—		5			—			(12		)
Interest-rate and other derivatives	—			(1,194		)	—		—			—			(1,194		)
Total derivative liabilities	$	(6	)	$	(1,413	)	$	—	$	211		$	1		$	(1,207	)

 __________________________________________________________________

⁽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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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Supplemental Cash Flow Information

14. Supplemental Cash Flow Information

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

	Nine Months Ended   September 30,
millions	2013		2012
Cash paid (received)
Interest	$	569	$	613
Income taxes	$	137	$	(13	)
Non-cash investing activities
Fair value of properties and equipment received in non-cash exchange transactions	$	13	$	65

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Derivative Instruments - Additional Information (Detail) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2013 Mcf	Dec. 31, 2012 Mcf
Derivative [Line Items]
Gross derivative liability	$ 1,011,000,000	$ 1,419,000,000
Aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed, net of collateral	52,000,000	94,000,000
Five Billion Dollar Facility [Member]
Derivative [Line Items]
Five billion dollar facility	5,000,000,000
Permitted to Offset Gross Derivative Asset with Financial Institutions [Member]
Derivative [Line Items]
Gross derivative liability	305,000,000	339,000,000
Securing most derivative counterparties [Member] | Five Billion Dollar Facility [Member]
Derivative [Line Items]
Five billion dollar facility	$ 5,000,000,000
Commodity [Member] | Natural Gas [Member]
Derivative [Line Items]
Fixed-price physical transactions	10,000,000	10,000,000
Fixed-to-floating derivative transaction	10,000,000	10,000,000

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Debt and Interest Expense - Interest Expense Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Interest Expense [Abstract]
Current debt, long-term debt, and other	$ 240	$ 238	$ 710	$ 724
Capitalized interest	(63)	(53)	(197)	(163)
Interest expense	$ 177	$ 185	$ 513	$ 561

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Pension Plans and Other Postretirement Benefits (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Pension Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	$ 21	$ 19	$ 64	$ 57
Interest cost	19	21	58	64
Expected return on plan assets	(22)	(23)	(68)	(68)
Amortization of net actuarial loss (gain)	29	23	88	69
Amortization of net prior service cost (credit)	0	0	0	0
Net periodic benefit cost	47	40	142	122
Other Postretirement Benefit Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	2	2	7	7
Interest cost	3	4	10	12
Expected return on plan assets	0	0	0	0
Amortization of net actuarial loss (gain)	0	0	0	0
Amortization of net prior service cost (credit)	1	0	1	1
Net periodic benefit cost	$ 6	$ 6	$ 18	$ 20

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Acquisitions and Divestitures - Divestitures (Detail) (USD $)	9 Months Ended		3 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Mozambique Offshore Area 1 [Member]
Gain (Loss) on Disposition of Assets [Abstract]
Proceeds from divestitures	$ 451,000,000	$ 440,000,000
Net gains on divestitures	165,000,000	(23,000,000)
Property, Plant and Equipment [Line Items]
Expected working interest sold			10.00%
Expected proceeds from divestiture			$ 2,640,000,000

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

Table Text Block [Abstract]

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

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	2013			2012		2013			2012
Income (loss) before income taxes	$	463		$	390	$	2,929		$	3,019
Exploration expense	272			297		714			1,662
DD&A	996			979		2,958			2,936
Impairments	593			4		632			166
Interest expense	177			185		513			561
Unrealized (gains) losses on derivatives, net	36			456		(359		)	539
Realized (gains) losses on interest-rate and other derivatives, net	—			—		—			2
Deepwater Horizon settlement and related costs	5			4		12			15
Algeria exceptional profits tax settlement	—			7		33			(1,797		)
Tronox-related contingent loss	—			—		—			(250		)
Certain other nonoperating items	(10		)	—		75			—
Less net income attributable to noncontrolling interests	41			21		95			67
Consolidated Adjusted EBITDAX	$	2,491		$	2,301	$	7,412		$	6,786

Schedule of Segment Reporting Information, by Segment

The following summarizes selected financial information for Anadarko’s reporting segments:

	Oil and Gas								Other and
	Exploration								Intersegment
millions	& Production		Midstream			Marketing			Eliminations			Total
Three Months Ended September 30, 2013
Sales revenues	$	1,916	$	95		$	1,778		$	—		$	3,789
Intersegment revenues	1,516		287			(1,629		)	(174		)	—
Gains (losses) on divestitures and other, net	7		—			—			57			64
Total revenues and other	3,439		382			149			(117		)	3,853
Operating costs and expenses (1)	930		216			164			(12		)	1,298
Realized (gains) losses on commodity    derivatives, net	—		—			—			26			26
Other (income) expense, net (2)	—		—			—			(13		)	(13		)
Net income attributable to noncontrolling interests	—		41			—			—			41
Total expenses and other	930		257			164			1			1,352
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—		—			(10		)	—			(10		)
Adjusted EBITDAX	$	2,509	$	125		$	(25	)	$	(118	)	$	2,491
Three Months Ended September 30, 2012
Sales revenues	$	1,393	$	80		$	1,810		$	—		$	3,283
Intersegment revenues	1,587		232			(1,682		)	(137		)	—
Gains (losses) on divestitures and other, net	12		(6		)	—			43			49
Total revenues and other	2,992		306			128			(94		)	3,332
Operating costs and expenses (1)	840		182			152			51			1,225
Realized (gains) losses on commodity    derivatives, net	—		—			—			(200		)	(200		)
Other (income) expense, net (2)	—		—			—			(10		)	(10		)
Net income attributable to noncontrolling interests	—		21			—			—			21
Total expenses and other	840		203			152			(159		)	1,036
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—		—			5			—			5
Adjusted EBITDAX	$	2,152	$	103		$	(19	)	$	65		$	2,301

	Oil and Gas									Other and
	Exploration									Intersegment
millions	& Production			Midstream			Marketing			Eliminations			Total
Nine Months Ended September 30, 2013
Sales revenues	$	5,044		$	267		$	5,636		$	—		$	10,947
Intersegment revenues	4,904			805			(5,234		)	(475		)	—
Gains (losses) on divestitures and other, net	12			—			—			284			296
Total revenues and other	9,960			1,072			402			(191		)	11,243
Operating costs and expenses (1)	2,656			613			492			15			3,776
Realized (gains) losses on commodity    derivatives, net	—			—			—			(46		)	(46		)
Other (income) expense, net (2)	—			—			—			(6		)	(6		)
Net income attributable to noncontrolling interests	—			95			—			—			95
Total expenses and other	2,656			708			492			(37		)	3,819
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—			—			(12		)	—			(12		)
Adjusted EBITDAX	$	7,304		$	364		$	(102	)	$	(154	)	$	7,412
Nine Months Ended September 30, 2012
Sales revenues	$	5,180		$	248		$	4,467		$	—		$	9,895
Intersegment revenues	3,796			701			(4,101		)	(396		)	—
Gains (losses) on divestitures and other, net	(17		)	(8		)	—			131			106
Total revenues and other	8,959			941			366			(265		)	10,001
Operating costs and expenses (1)	2,639			545			464			132			3,780
Realized (gains) losses on commodity    derivatives, net	—			—			—			(600		)	(600		)
Other (income) expense, net (2)	—			—			—			(14		)	(14		)
Net income attributable to noncontrolling interests	—			67			—			—			67
Total expenses and other	2,639			612			464			(482		)	3,233
Unrealized (gains) losses on derivatives, net    included in marketing revenue	—			—			18			—			18
Adjusted EBITDAX	$	6,320		$	329		$	(80	)	$	217		$	6,786

 __________________________________________________________________

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

⁽²⁾   Other (income) expense, net excludes Tronox-related contingent loss and certain other nonoperating items since these expenses are excluded from Adjusted EBITDAX.

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Pension Plans and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2013

Table Text Block [Abstract]

Components of Net Periodic Benefit Cost Table

The following summarizes the Company’s pension and other postretirement benefit cost:

	Pension Benefits						Other Benefits
millions	2013			2012			2013		2012
Three Months Ended September 30
Service cost	$	21		$	19		$	2	$	2
Interest cost	19			21			3		4
Expected return on plan assets	(22		)	(23		)	—		—
Amortization of net actuarial loss (gain)	29			23			—		—
Amortization of net prior service cost (credit)	—			—			1		—
Net periodic benefit cost	$	47		$	40		$	6	$	6
Nine Months Ended September 30
Service cost	$	64		$	57		$	7	$	7
Interest cost	58			64			10		12
Expected return on plan assets	(68		)	(68		)	—		—
Amortization of net actuarial loss (gain)	88			69			—		—
Amortization of net prior service cost (credit)	—			—			1		1
Net periodic benefit cost	$	142		$	122		$	18	$	20

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Impairments

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Impairments

4. Impairments

       The following summarizes impairments by segment:

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions	2013		2012		2013		2012
Oil and gas exploration and production
Long-lived assets held for use
U.S. onshore properties	$	—	$	2	$	—	$	81
Gulf of Mexico properties	593		—		593		67
Cost-method investment	—		1		10		12
Midstream
Long-lived assets held for use	—		1		29		6
Impairments	$	593	$	4	$	632	$	166

       During the third quarter of 2013, certain Gulf of Mexico properties were impaired due to a reduction in estimated future net cash flows per barrel and downward revisions of reserves that the Company no longer plans to develop. The Company impaired its Venezuelan cost-method investment in 2013 and 2012 due to declines in estimated recoverable value. In addition, a midstream property was impaired during 2013 due to a reduction in estimated future cash flows. In 2012, certain U.S. onshore and midstream properties were impaired primarily due to lower natural-gas prices and a Gulf of Mexico property was impaired as a result of downward reserves revisions for a property that was near the end of its economic life.

       The following summarizes the post-impairment fair value of the above-described assets, by asset category and input level within the fair-value hierarchy:

millions
2013	Level 1		Level 2		Level 3 (1)		Total
Long-lived assets held for use	$	—	$	—	$	266	$	266
Cost-method investment (2)	—		—		32		32
2012
Long-lived assets held for use	$	—	$	—	$	38	$	38
Cost-method investment (2)	—		—		34		34

 __________________________________________________________________

⁽¹⁾  The income approach was used to measure fair value.

⁽²⁾  This represents the Company’s after-tax net investment.

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Segment Information - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2013 Segment
Segment Reporting [Abstract]
Number of reporting segments	3
Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Number of operating segments	2

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Debt and Interest Expense (Tables)

9 Months Ended

Sep. 30, 2013

Table Text Block [Abstract]

Debt Outstanding and Debt Activity Tables

The following summarizes the Company’s outstanding debt:

	September 30,			December 31,
millions	2013			2012
Total debt at face value	$	15,302		$	14,952
Net unamortized discounts and premiums (1)	(1,655		)	(1,683		)
Total long-term debt	$	13,647		$	13,269

__________________________________________________________________

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

The following summarizes the Company’s debt activity during the nine months ended September 30,2013:

	Carrying
millions	Value			Description
Balance at December 31, 2012	$	13,269
Borrowings	385			WES revolving credit facility
Other, net	9			Amortization of debt discounts and premiums
Balance at March 31, 2013	$	13,663
Borrowings	110			WES revolving credit facility
Repayments	(245		)	WES revolving credit facility
Other, net	10			Amortization of debt discounts and premiums
Balance at June 30, 2013	$	13,538
Issuance	250			WES 2.600% Senior Notes due 2018
Borrowings	100			WES revolving credit facility
Repayments	(250		)	WES revolving credit facility
Other, net	9			Amortization of debt discounts and premiums
Balance at September 30, 2013	$	13,647

Interest Expense Table

The following summarizes interest expense:

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions	2013			2012			2013			2012
Current debt, long-term debt, and other	$	240		$	238		$	710		$	724
Capitalized interest	(63		)	(53		)	(197		)	(163		)
Interest expense	$	177		$	185		$	513		$	561

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Suspended Exploratory Well Costs (Detail) (USD $)			9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Greater Than One Year [Member]
Capitalized Exploratory Well Costs [Abstract]
Suspended exploratory well costs	$ 2,200,000,000	$ 2,100,000,000
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs previously capitalized as suspended exploratory well costs for greater than one year at December 31, 2012, charged to dry hole expense			$ 95,000,000

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Derivative Instruments

9 Months Ended

Sep. 30, 2013

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, Louisiana for natural gas and Cushing, Oklahoma or Sullom Voe, Scotland for oil. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).

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

       The Company does not apply hedge accounting to any of its derivative instruments. As a result, both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings. Net derivative losses attributable to interest-rate 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. See Note 10—Accumulated Other Comprehensive Income (Loss).

7. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities    The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are a combination of NYMEX West Texas Intermediate (WTI) and IntercontinentalExchange, Inc. (ICE) Brent prices. The following is a summary of the Company’s derivative instruments related to its Oil and Natural-Gas Production/Processing Derivative Activities at September 30, 2013:

	2013 Settlement			2014 Settlement
Natural Gas
Two-Way Collars (thousand MMBtu/d)	600		(1)	—
Average price per MMBtu
Ceiling sold price (call)	$	4.00		$	—
Floor purchased price (put)	$	3.18		$	—
Three-Way Collars (thousand MMBtu/d)	—		(2)	600
Average price per MMBtu
Ceiling sold price (call)	$	—		$	5.01
Floor purchased price (put)	$	—		$	3.75
Floor sold price (put)	$	—		$	2.75
Fixed-Price Contracts (thousand MMBtu/d)	1,185			600
Average price per MMBtu	$	4.00		$	4.26
Crude Oil
Three-Way Collars (MBbls/d)	26			—
Average price per barrel
Ceiling sold price (call)	$	125.15		$	—
Floor purchased price (put)	$	105.00		$	—
Floor sold price (put)	$	85.00		$	—
Fixed-Price Contracts (MBbls/d)	167			—
Average price per barrel	$	102.74		$	—

__________________________________________________________________

⁽¹⁾  The two-way collars have a contract term of April 2013 to October 2013.

⁽²⁾  The Company entered into offsetting purchased and sold natural-gas three-way collars of 450,000 MMBtu/d for 2013 settlement.

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

       A two-way collar is a combination of two options: a sold call and a purchased 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.

       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.

7. Derivative Instruments (Continued)

Marketing and Trading Derivative Activities    In addition to the positions in the previous table, the Company also engages in marketing and trading activities. These activities include physical product sales and related fixed-to-floating derivative transactions used to manage commodity-price risk. At September 30, 2013, and December 31, 2012, the Company had fixed-price physical transactions related to natural gas totaling 10 billion cubic feet (Bcf), offset by fixed-to-floating derivative transactions totaling 10 Bcf.

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

       The Company had the following outstanding interest-rate swaps at September 30, 2013:

millions except percentages		Reference Period		Weighted-Average
Notional Principal Amount		Start	End	Interest Rate
$	750	June 2014	June 2024	6.00%
$	1,100	June 2014	June 2044	5.57%
$	50	September 2016	September 2026	5.91%
$	750	September 2016	September 2046	5.86%

Effect of Derivative Instruments—Balance Sheet    The following summarizes the fair value of the Company’s derivative instruments:

	Gross Derivative Assets				Gross Derivative Liabilities
millions	September 30,		December 31,		September 30,			December 31,
Balance Sheet Classification	2013		2012		2013			2012
Commodity derivatives
Other current assets	$	359	$	475	$	(170	)	$	(197	)
Other assets	50		24		(13		)	(7		)
Accrued expenses	48		6		(61		)	(14		)
Other liabilities	—		1		(2		)	(7		)
	457		506		(246		)	(225		)
Interest-rate and other derivatives
Accrued expenses (1)	—		—		(550		)	—
Other liabilities (1)	—		—		(215		)	(1,194		)
	—		—		(765		)	(1,194		)
Total derivatives	$	457	$	506	$	(1,011	)	$	(1,419	)

 __________________________________________________________________

⁽¹⁾ Interest-rate swaps with June 2014 maturity dates were reclassified from other liabilities to accrued expenses during the second quarter of 2013.

7. Derivative Instruments (Continued)

Effect of Derivative Instruments—Statement of Income    The following summarizes realized and unrealized gains and losses related to derivative instruments:

millions	Three Months Ended   September 30, 2013									Nine Months Ended   September 30, 2013
Classification of (Gain) Loss Recognized	Realized			Unrealized			Total			Realized			Unrealized			Total
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	2		$	(10	)	$	(8	)	$	9		$	(12	)	$	(3	)
(Gains) losses on derivatives, net	26			120			146			(46		)	81			35
Interest-rate and other derivatives
(Gains) losses on derivatives, net	—			(74		)	(74		)	—			(428		)	(428		)
Total (gains) losses on derivatives, net	$	28		$	36		$	64		$	(37	)	$	(359	)	$	(396	)
	Three Months Ended   September 30, 2012									Nine Months Ended   September 30, 2012
Classification of (Gain) Loss Recognized	Realized			Unrealized			Total			Realized			Unrealized			Total
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	3		$	5		$	8		$	—		$	18		$	18
(Gains) losses on derivatives, net	(200		)	437			237			(600		)	369			(231		)
Interest-rate and other derivatives
(Gains) losses on derivatives, net	—			14			14			2			152			154
Total (gains) losses on derivatives, net	$	(197	)	$	456		$	259		$	(598	)	$	539		$	(59	)

__________________________________________________________________

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

Credit-Risk Considerations    The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on fair value of its counterparties’ creditworthiness. 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 derivative types. At September 30, 2013, $305 million of the Company’s $1.0 billion gross derivative liability balance, and at December 31, 2012, $339 million of the Company’s $1.4 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types.

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

7. Derivative Instruments (Continued)

       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 from major credit rating agencies declining to a level below investment grade. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $52 million (net of collateral) at September 30, 2013, and $94 million (net of collateral) at December 31, 2012. The current portion of these amounts was included in accrued expenses and the long-term portion of these amounts was included in other long-term liabilities—other 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 summarizes the fair value of the Company’s derivative assets and liabilities, by input level within the fair-value hierarchy:

millions
September 30, 2013	Level 1			Level 2			Level 3		Netting (1)			Collateral			Total
Assets
Commodity derivatives
Financial institutions	$	4		$	379		$	—	$	(226	)	$	(1	)	$	156
Other counterparties	—			74			—		(6		)	—			68
Total derivative assets	$	4		$	453		$	—	$	(232	)	$	(1	)	$	224
Liabilities
Commodity derivatives
Financial institutions	$	(4	)	$	(232	)	$	—	$	226		$	1		$	(9	)
Other counterparties	—			(10		)	—		6			—			(4		)
Interest-rate and other derivatives	—			(765		)	—		—			—			(765		)
Total derivative liabilities	$	(4	)	$	(1,007	)	$	—	$	232		$	1		$	(778	)
December 31, 2012
Assets
Commodity derivatives
Financial institutions	$	6		$	453		$	—	$	(206	)	$	—		$	253
Other counterparties	—			47			—		(5		)	—			42
Total derivative assets	$	6		$	500		$	—	$	(211	)	$	—		$	295
Liabilities
Commodity derivatives
Financial institutions	$	(6	)	$	(202	)	$	—	$	206		$	1		$	(1	)
Other counterparties	—			(17		)	—		5			—			(12		)
Interest-rate and other derivatives	—			(1,194		)	—		—			—			(1,194		)
Total derivative liabilities	$	(6	)	$	(1,413	)	$	—	$	211		$	1		$	(1,207	)

 __________________________________________________________________

⁽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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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Acquisitions and Divestitures

3. Acquisitions and Divestitures

Acquisitions    Anadarko and Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, made several unrelated acquisitions during the nine months ended September 30, 2013. In March 2013, WES acquired a 33.75% interest in gas-gathering systems located in the Marcellus shale in north-central Pennsylvania for $135 million. In June 2013, WES acquired a 25% interest in a joint venture formed to design, construct, and own two fractionators located in Mont Belvieu, Texas for $78 million. In August 2013, Anadarko acquired certain oil and gas properties and related assets in the Moxa area of Wyoming for $310 million, including $306 million that represents the fair value of the oil and gas properties acquired. In September 2013, WES acquired an intrastate pipeline in southwestern Wyoming for $28 million.

Divestitures    For the nine months ended September 30, 2013, proceeds from divestitures of $451 million and net gains on divestitures of $165 million were primarily related to the Company’s divestiture of its interests in a soda ash joint venture during the first quarter of 2013. In August 2013, the Company entered into a definitive agreement to sell a 10% working interest in Mozambique’s Offshore Area 1 for $2.64 billion. The transaction is subject to governmental approvals and other customary closing conditions, and is expected to close in late 2013 or early 2014.

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CONSOLIDATED STATEMENTS 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, 2012	$ 21,882		$ 51	$ 8,230		$ 13,829	$ (841)	$ (640)	$ 1,253
Net income (loss)	1,666					1,571			95
Common stock issued	231		1	230
Dividends—common stock	(182)					(182)
Repurchase of common stock	(30)						(30)
Subsidiary equity transactions (1)	381			61	[1]				320
Distributions to noncontrolling interest owners	(111)								(111)
Contributions from noncontrolling interest owners	2								2
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	5	[2]						5
Adjustments for pension and other postretirement plans	57							57
Balance at Sep. 30, 2013	$ 23,901		$ 52	$ 8,521		$ 15,218	$ (871)	$ (578)	$ 1,559

[1] The $61 million increase to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders totaled $1,632 million for the nine months ended September 30, 2013.

[2] Net of income tax benefit (expense) of $(1) million for the three months ended September 30, 2013, $(1) million for the three months ended September 30, 2012, $(3) million for the nine months ended September 30, 2013, and $(3) million for the nine months ended September 30, 2012.

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Debt and Interest Expense - Additional Information (Detail) (USD $)							9 Months Ended				9 Months Ended		9 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2013 Fair Value Inputs Level 1 and Level 2 [Member] Market Approach Valuation Technique [Member]	Dec. 31, 2012 Fair Value Inputs Level 1 and Level 2 [Member] Market Approach Valuation Technique [Member]	Sep. 30, 2013 Senior Notes 1 [Member]	Sep. 30, 2013 Senior Notes 2 [Member]	Sep. 30, 2013 Senior Notes Zero Coupon [Member]	Oct. 10, 2013 Senior Notes Zero Coupon [Member]	Sep. 30, 2013 Senior Notes 3 [Member] Western Gas Partners, LP [Member]	Sep. 30, 2013 Revolving Credit Facility [Member]	Sep. 30, 2013 Revolving Credit Facility [Member] Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity												$ 5,000,000,000	$ 800,000,000
Debt instrument, principal amount	15,302,000,000			14,952,000,000			500,000,000	275,000,000			250,000,000
Debt instrument, stated interest rate							7.625%	5.75%			2.60%
Debt instrument, maturity date							Mar. 15, 2014	Jun. 15, 2014	Oct. 10, 2036		Aug. 15, 2018
Debt instrument, accreted value	13,647,000,000	13,538,000,000	13,663,000,000	13,269,000,000						718,000,000
Debt Instrument, earliest call date									Oct. 10, 2013
Estimated fair value of total borrowings					15,800,000,000	16,200,000,000
Line of credit, expiration date													Mar. 24, 2016
Line of credit, outstanding borrowings													100,000,000
Line of credit, interest rate													1.68%
Line of credit, available borrowing capacity													687,000,000
Outstanding letters of credit													$ 13,000,000

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Derivative Instruments - Interest-Rate Derivatives Table (Detail) (Not Designated as Hedging Instrument [Member], USD $)	9 Months Ended
	Sep. 30, 2013
Interest-Rate Swap 1 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 750,000,000
Weighted-average interest rate for interest-rate swap	6.00%
Interest-Rate Swap 1 [Member] | Minimum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	Jun. 01, 2014
Interest-Rate Swap 1 [Member] | Maximum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	Jun. 01, 2024
Interest-Rate Swap 2 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	1,100,000,000
Weighted-average interest rate for interest-rate swap	5.57%
Interest-Rate Swap 2 [Member] | Minimum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	Jun. 01, 2014
Interest-Rate Swap 2 [Member] | Maximum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	Jun. 01, 2044
Interest-Rate Swap 3 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	50,000,000
Weighted-average interest rate for interest-rate swap	5.91%
Interest-Rate Swap 3 [Member] | Minimum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	Sep. 01, 2016
Interest-Rate Swap 3 [Member] | Maximum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	Sep. 01, 2026
Interest-Rate Swap 4 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 750,000,000
Weighted-average interest rate for interest-rate swap	5.86%
Interest-Rate Swap 4 [Member] | Minimum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	Sep. 01, 2016
Interest-Rate Swap 4 [Member] | Maximum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	Sep. 01, 2046

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2013

Table Text Block [Abstract]

Schedule of Income Taxes and Effective Tax Rate

 The following summarizes income tax expense (benefit) and effective tax rates:

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except percentages	2013			2012			2013			2012
Income tax expense (benefit)	$	240		$	248		$	1,263		$	764
Effective tax rate	52		%	64		%	43		%	25		%

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Pension Plans and Other Postretirement Benefits Pension Plans and Other Postretirement Benefits - Additional Information (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Pension Plans, Defined Benefit [Member] | Funded Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	$ 122
Expected employer contributions during the remainder of the current fiscal year	2
Pension Plans, Defined Benefit [Member] | Unfunded Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	6
Expected employer contributions during the remainder of the current fiscal year	30
Other Postretirement Benefit Plans, Defined Benefit [Member] | Unfunded Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	11
Expected employer contributions during the remainder of the current fiscal year	$ 5

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Income Taxes - Income Tax Expense (Benefit) Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax expense (benefit)	$ 240	$ 248	$ 1,263	$ 764
Effective tax rate	52.00%	64.00%	43.00%	25.00%

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Accumulated Other Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Accumulated Other Comprehensive Income (Loss)

10. Accumulated Other Comprehensive Income (Loss)

       The following summarizes the after-tax changes in the balances of each component of accumulated other comprehensive income (loss):

millions	Interest-rate Derivatives Previously Subject to Hedge Accounting			Pension and Other Postretirement Plans			Total
Balance at December 31, 2012	$	(61	)	$	(579	)	$	(640	)
Reclassifications to Consolidated Statement of Income	5			57			62
Balance at September 30, 2013	$	(56	)	$	(522	)	$	(578	)

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Noncontrolling Interests

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Noncontrolling Interests

6. Noncontrolling Interests

       Western Gas Equity Partners, LP (WGP) is a consolidated subsidiary formed by Anadarko to own partnership interests in WES. At September 30, 2013, Anadarko’s ownership interest in WGP consisted of a 91.0% limited partner interest and the entire general partner interest.

       WES is a limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. During 2013, WES has issued approximately seven million common units to the public, raising net proceeds of $419 million. At September 30, 2013, WGP’s ownership interest in WES consisted of a 43.1% limited partner interest, the entire 2.0% general partner interest, and all WES incentive distribution rights. At September 30, 2013, Anadarko also owned a 0.4% limited partner interest in WES through another subsidiary.

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Income Taxes

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Income Taxes

13. Income Taxes

       The following summarizes income tax expense (benefit) and effective tax rates:

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except percentages	2013			2012			2013			2012
Income tax expense (benefit)	$	240		$	248		$	1,263		$	764
Effective tax rate	52		%	64		%	43		%	25		%

       The increase from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2013, and the three months ended September 30, 2012, was primarily attributable to the tax impact from foreign operations and Algerian exceptional profits taxes. The decrease from the 35% U.S. federal statutory rate for the nine months ended September 30, 2012, was primarily attributable to the non-taxable resolution of the Algeria exceptional profits tax dispute, partially offset by the tax impact from foreign operations and Algerian exceptional profits taxes.

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Commitments

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Commitments

11. Commitments

       In June 2013, the Company entered into a three-year operating lease agreement for a deepwater drillship expected to be delivered in late 2014. The lease obligation totals $464 million, with aggregate future annual minimum lease payments of $33 million in 2014, $154 million in 2015, $155 million in 2016, and $122 million in 2017.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 31, 2013
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, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		503,266,938

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Contingencies

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Contingencies

12. Contingencies

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

       The following is a discussion of the material developments with respect to the contingencies previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012, and material matters that have arisen since the filing of such report.

Deepwater Horizon Events    In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% nonoperated interest. In October 2011, the Company and BP entered into a settlement agreement relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against claims and damages arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and other potential damages. This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-upon amount, BP p.l.c. has agreed to become the sole guarantor. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder derivative or securities laws claims, or certain other claims. The Company has not recorded a liability for any costs that are subject to indemnification by BP. For additional disclosure of the Deepwater Horizon events, the Company’s Settlement Agreement with BP, environmental claims under OPA, NRD claims, potential penalties and fines, and civil litigation, see Note 17—Contingencies—Deepwater Horizon Events in the Notes to the Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

Penalties and Fines    In December 2010, the U.S. Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the U.S. District Court in New Orleans, Louisiana (Louisiana District Court) against several parties, including Anadarko, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. In February 2012, the Louisiana District Court entered a declaratory judgment that, as a partial owner of the Macondo well, Anadarko is liable for civil penalties under Section 311 of the CWA. The declaratory judgment addresses liability only, and does not address the amount of any civil penalty. The assessment of a civil penalty against Anadarko has been reserved until a later proceeding to be scheduled by the Louisiana District Court. In August 2012, Anadarko filed a notice of appeal in the U.S. Court of Appeals for the Fifth Circuit concerning that portion of the February 2012 declaratory judgment finding Anadarko liable for civil penalties under the CWA. The appeal is pending and oral arguments are set for December 2013.

12. Contingencies (Continued)

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

       Applicable accounting guidance requires the Company to accrue a liability if it is probable that a liability is incurred and the amount of the liability can be reasonably estimated. The Louisiana District Court’s declaratory judgment in February 2012 satisfies the requirement that a loss, arising from the future assessment of a civil penalty against Anadarko, is probable. Notwithstanding the declaratory judgment, the Company currently cannot estimate the amount of any potential civil penalty. The CWA sets forth subjective criteria, including degree of fault and history of prior violations, which significantly influence the magnitude of CWA penalty assessments. As a result of the subjective nature of CWA penalty assessments, the Company currently cannot estimate the amount of any such penalty nor determine a range of potential loss. Furthermore, neither the February 2012 settlement of Deepwater Horizon-related civil penalties (including those under the CWA) by the other nonoperating partner with the United States and five affected Gulf states (Texas, Louisiana, Mississippi, Alabama, and Florida) nor the January 2013 settlement of CWA civil and criminal penalties by the drilling contractor with the United States affects the Company’s current conclusion regarding its ability to estimate potential fines and penalties. The Company lacks insight into those settlements, retains legal counsel separate from the other parties, and was not involved in any manner with respect to those settlements. Events or factors that could assist the Company in estimating the amount of any potential civil penalty or a range of potential loss related to such penalties include (i) an assessment by the DOJ, (ii) a ruling by a court of competent jurisdiction, or (iii) the initiation of substantive settlement negotiations between the Company and the DOJ.

       Given the Company’s lack of direct operational involvement in the event, as was reconfirmed by the Louisiana District Court in September 2013, and the subjective criteria of the CWA, the Company believes that its exposure to CWA penalties will not materially impact the Company’s consolidated financial position, results of operations, or cash flows.

Civil Litigation Damage Claims    Numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court. In March 2012, BP and the Plaintiffs’ Steering Committee entered into a tentative settlement agreement to resolve the substantial majority of economic loss and medical claims stemming from the Deepwater Horizon events, which the Louisiana District Court approved in orders issued in December 2012 and January 2013. Only OPA claims seeking economic loss damages against the Company remain. In addition, certain state and local governments have appealed, or have provided indication of a likely appeal of, the MDL court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages, irrespective of whether such claims are based on federal (including OPA) or state law.

       The first phase of the trial in the proceeding filed in the MDL by Transocean Ltd. (Transocean) under the Limitation of Liability Act commenced in February 2013 (Phase I). In April 2013, the evidence closed and all parties rested. Findings of fact, post-trial briefs, and responsive briefs were submitted in July 2013. BP, BP p.l.c., the United States, state and local governments, Halliburton Energy Services, Inc. (Halliburton), and Transocean participated in Phase I of the trial. Anadarko was excused from participation in Phase I of the trial. The issues tried in Phase I included the cause of the blow-out and all related events leading up to April 22, 2010, the date the Deepwater Horizon sank, as well as allocation of fault. The allocation of fault remains in the Phase I trial because Halliburton and Transocean have not settled with any of the parties and each wishes to prove to the court that their respective company was not at fault. The second phase of trial began in September 2013 (Phase II) and in October 2013 the evidence closed and all parties rested. The issues tried in Phase II included spill-source control and quantification of the spill for the period from April 22, 2010, until the well was capped. The Company, BP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean participated in Phase II of the trial. The judge entered an order prior to commencement of the Phase II trial excluding any evidence of Anadarko’s culpability or fault during Phase II of the trial.    

12. Contingencies (Continued)

       Two separate class action complaints were filed in June and August 2010, in the U.S. District Court for the Southern District of New York (New York District Court) on behalf of purported purchasers of the Company’s stock between June 9, 2009, and June 12, 2010, against Anadarko and certain of its officers. The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. In November 2010, the New York District Court consolidated the two cases. In March 2012, the New York District Court granted the plaintiffs’ motion to transfer venue to the U.S. District Court for the Southern District of Texas - Houston Division (Texas District Court). In May 2012, the Texas District Court granted the defendants’ motion to transfer the consolidated action within the district to Judge Keith P. Ellison. In July 2012, the plaintiffs filed their First Amended Consolidated Class Action Complaint. The defendants filed a renewed motion to dismiss in the Texas District Court in September 2012. In July 2013, the Texas District Court dismissed the claims relating to all but one of the alleged misstatements asserted in the plaintiffs’ complaint. The Texas District Court gave the plaintiffs 30 days to amend the complaint to attempt to rehabilitate the claims that were dismissed. The plaintiffs declined to amend the complaint. The Company filed its answer to the complaint in September 2013.

       In September 2010, a purported shareholder made a demand on the Company’s Board of Directors (the Board) to investigate allegations of breaches of duty by members of management related to the Deepwater Horizon events. The Board received a supplemental demand letter from the shareholder in March 2012. The Board considered each of the demand letters in January 2011 and April 2012 and determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letters. In May 2013, a shareholder derivative petition was filed in the 215^th District Court of Harris County, Texas by the shareholder against Anadarko (as a nominal defendant) and certain current and former directors and officers. The petition alleges breach of fiduciary duties, unjust enrichment, abuse of control, and gross mismanagement in connection with the Deepwater Horizon events. The plaintiff seeks an unspecified amount of damages, certain changes to the Company’s governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs.

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

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

       The Company will continue to monitor the MDL and other legal proceedings discussed above as well as federal investigations related to the Deepwater Horizon events. The Company cannot predict the nature of evidence that may be discovered during the course of legal proceedings or the timing of completion of any legal proceedings.

       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.

12. Contingencies (Continued)

Tronox Litigation    In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York (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 and seeks, among other things, to recover damages, including interest, in excess of $18.9 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. In accordance with Tronox’s Plan of Reorganization, the Adversary Proceeding is being pursued by the Anadarko Litigation Trust. Pursuant to the Anadarko Litigation Trust Agreement, the Anadarko Litigation Trust was “deemed substituted” for Tronox in the Adversary Proceeding as the party in such litigation. For purposes of this Form 10-Q, references to “Tronox” after February 2011 refer to the Anadarko Litigation Trust. For additional disclosure related to the Tronox Litigation, see Note 17—Contingencies—Tronox Litigation in the Notes to the Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

       The U.S. government was granted authority to intervene in the Adversary Proceeding, and in May 2009 asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act (FDCPA Complaint). Anadarko and Kerr-McGee moved to dismiss the claims of the U.S. government, but that motion has been stayed by the Bankruptcy Court. In April 2012, Anadarko and Kerr-McGee filed an answer to the FDCPA Complaint.

       In February 2012, the Company filed a motion for partial summary judgment seeking dismissal of several claims, including all actual and constructive fraudulent transfer claims protected by Section 546(e) of the Bankruptcy Code. The court has not yet ruled on that issue. Trial began in May 2012 and in September 2012, the evidence closed and both sides rested. In November 2012, the parties filed post-trial briefs and closing arguments were presented in December 2012. The parties filed final post-trial briefs in January 2013. The matter is pending before the court. To date, we have no information concerning the timing or form of decision that can be expected from the Bankruptcy Court in the Adversary Proceeding. Furthermore, Executive Benefits Insurance Agency v. Arkison, a case pending before the U.S. Supreme Court, raises certain legal issues including, but not limited to, whether affirmative consent is required for a bankruptcy court to have authority to enter a final judgment in a fraudulent transfer case. The Company is unable to determine the impact, if any, of this case on the substance or timing of a decision related to the Adversary Proceeding.

       The Company remains confident in the merits of its position and does not believe a loss resulting from litigating the Adversary Proceeding is probable. Accounting guidance requires that contingent losses be probable in nature for loss recognition to be appropriate. Accordingly, the Company’s Consolidated Balance Sheet at September 30, 2013, does not include a loss-contingency liability related to the litigation of the Adversary Proceeding.

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

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

12. Contingencies (Continued)

Other    During the nine months ended September 30, 2013, the Company recognized a pretax loss of $131 million, reported in other (income) expense, net in the Consolidated Statement of Income, related to the cost to decommission wells and production facilities previously sold to a third party. In June 2013, as a result of a Chapter 11 bankruptcy declaration by the third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of the facility and related wells. These wells and production facilities are no longer owned by the Company nor are they related to its current operations. Anadarko expects to complete decommissioning of the production facilities in 2014 and the wells in 2015. Decommissioning obligations of $44 million were included in accrued expenses and $85 million were included in other long-term liabilities on the Consolidated Balance Sheet at September 30, 2013. Actual costs may vary from this estimate; however, the Company does not believe that such variation will materially impact its consolidated financial position, results of operations, or cash flows.

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Supplemental Cash Flow Information (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash paid (received)
Interest	$ 569	$ 613
Income taxes	137	(13)
Non-cash investing activities
Fair value of properties and equipment received in non-cash exchange transactions	$ 13	$ 65

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Income Taxes - Additional Information (Detail)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Tax Disclosure [Abstract]
U.S. federal statutory rate	35.00%	35.00%	35.00%	35.00%