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 March 31, 2013

or

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

EXCHANGE ACT OF 1934

For the transition period from        to        

Commission File No. 1-8968

ANADARKO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate 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  x    No  ¨

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

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

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

The number of shares outstanding of the Company’s common stock at April 30, 2013, is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.10 per share	501,473,546

TABLE OF CONTENTS

PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three Months Ended March 31, 2013 and 2012		2
	Consolidated Statements of Comprehensive Income for the Three Months Ended March 31,  2013 and 2012		3
	Consolidated Balance Sheets at March 31, 2013, and December 31, 2012		4
	Consolidated Statement of Equity for the Three Months Ended March 31, 2013		5
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012		6
	Notes to Consolidated Financial Statements		7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
	Financial Results		27
	Operating Results		36
	Liquidity and Capital Resources		38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		41
Item 4.	Controls and Procedures		42
PART II
Item 1.	Legal Proceedings		43
Item 1A.	Risk Factors		43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		44
Item 6.	Exhibits		45

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March  31,
millions except per-share amounts	2013			2012
Revenues and Other
Natural-gas sales	$	807		$	573
Oil and condensate sales		2,377			2,244
Natural-gas liquids sales		303			342
Gathering, processing, and marketing sales		231			253
Gains (losses) on divestitures and other, net		175			35
Total		3,893			3,447
Costs and Expenses
Oil and gas operating		247			242
Oil and gas transportation and other		255			240
Exploration		264			244
Gathering, processing, and marketing		199			189
General and administrative		272			269
Depreciation, depletion, and amortization		1,022			930
Other taxes		280			377
Impairments		29			50
Algeria exceptional profits tax settlement		33			(1,804	)
Deepwater Horizon settlement and related costs		3			8
Total		2,604			745
Operating Income (Loss)		1,289			2,702
Other (Income) Expense
Interest expense		164			186
(Gains) losses on derivatives, net		191			(284	)
Other (income) expense, net		(6	)		265
Total		349			167
Income (Loss) Before Income Taxes		940			2,535
Income tax expense (benefit)		456			352
Net Income (Loss)		484			2,183
Net income attributable to noncontrolling interests		24			27
Net Income (Loss) Attributable to Common Stockholders	$	460		$	2,156
Per Common Share
Net income (loss) attributable to common stockholders—basic	$	0.91		$	4.30
Net income (loss) attributable to common stockholders—diluted	$	0.91		$	4.28
Average Number of Common Shares Outstanding—Basic		501			499
Average Number of Common Shares Outstanding—Diluted		503			501
Dividends (per Common Share)	$	0.09		$	0.09

See accompanying Notes to Consolidated Financial Statements.

2

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
millions	2013		2012
Net Income (Loss)	$	484	$	2,183
Other Comprehensive Income (Loss), net of taxes
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net (1)		2		2
Amortization of net actuarial (gain) loss to general and administrative expense (2)		19		15
Total		21		17
Comprehensive Income (Loss)		505		2,200
Comprehensive income attributable to noncontrolling interests		24		27
Comprehensive Income (Loss) Attributable to Common Stockholders	$	481	$	2,173

⁽¹⁾  Net of income tax benefit (expense) of $(1) million for the three months ended March 31, 2013 and 2012.

⁽²⁾  Net of income tax benefit (expense) of $(10) million for the three months ended March 31, 2013, and $(8) million for the three months ended March 31, 2012.

See accompanying Notes to Consolidated Financial Statements.

3

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
millions	2013			2012
ASSETS
Current Assets
Cash and cash equivalents	$	3,735		$	2,471
Accounts receivable (net of allowance of $5 million and $7 million)
Customers		1,511			1,473
Others		1,249			1,274
Algeria exceptional profits tax settlement		280			730
Other current assets		535			847
Total		7,310			6,795
Properties and Equipment
Cost		65,160			63,598
Less accumulated depreciation, depletion, and amortization		26,190			25,200
Net properties and equipment		38,970			38,398
Other Assets		1,630			1,716
Goodwill and Other Intangible Assets		5,678			5,680
Total Assets	$	53,588		$	52,589
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	2,909		$	2,989
Current asset retirement obligations		387			298
Accrued expenses		776			707
Total		4,072			3,994
Long-term Debt		13,663			13,269
Other Long-term Liabilities
Deferred income taxes		8,964			8,759
Asset retirement obligations		1,519			1,587
Other		3,040			3,098
Total		13,523			13,444
Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 519.9 million and 518.6 million shares issued)		52			51
Paid-in capital		8,282			8,230
Retained earnings		14,243			13,829
Treasury stock (18.5 million and 18.1 million shares)		(868	)		(841	)
Accumulated other comprehensive income (loss)		(619	)		(640	)
Total Stockholders’ Equity		21,090			20,629
Noncontrolling interests		1,240			1,253
Total Equity		22,330			21,882
Total Liabilities and Equity	$	53,588		$	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)		—		—		460			—			—			24			484
Common stock issued		1		50		—			—			—			—			51
Dividends—common		—		—		(46	)		—			—			—			(46	)
Repurchase of common stock		—		—		—			(27	)		—			—			(27	)
Subsidiary equity transactions (1)		—		2		—			—			—			(5	)		(3	)
Distributions to noncontrolling interest owners		—		—		—			—			—			(33	)		(33	)
Contributions from noncontrolling interest owners		—		—		—			—			—			1			1
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net		—		—		—			—			2			—			2
Adjustments for pension and other postretirement plans		—		—		—			—			19			—			19
Balance at March 31, 2013	$	52	$	8,282	$	14,243		$	(868	)	$	(619	)	$	1,240		$	22,330

⁽¹⁾  The $2 million increase to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders, totaled $462 million for the three months ended March 31, 2013.

See accompanying Notes to Consolidated Financial Statements.

5

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
millions	2013			2012
Cash Flows from Operating Activities
Net income (loss)	$	484		$	2,183
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, and amortization		1,022			930
Deferred income taxes		162			210
Dry hole expense and impairments of unproved properties		177			149
Impairments		29			50
(Gains) losses on divestitures, net		(144	)		17
Unrealized (gains) losses on derivatives, net		246			(142	)
Other		44			46
Changes in assets and liabilities
Deepwater Horizon settlement and related costs		—			30
Algeria exceptional profits tax settlement		450			(1,804	)
Tronox-related contingent loss		—			275
(Increase) decrease in accounts receivable		40			(27	)
Increase (decrease) in accounts payable and accrued expenses		(125	)		(258	)
Other items—net		118			232
Net cash provided by (used in) operating activities		2,503			1,891
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs		(1,710	)		(1,703	)
Acquisition of midstream business		(135	)		—
Divestitures of properties and equipment and other assets		361			47
Other—net		(133	)		(42	)
Net cash provided by (used in) investing activities		(1,617	)		(1,698	)
Cash Flows from Financing Activities
Borrowings, net of issuance costs		385			319
Repayments of debt		—			(171	)
Increase (decrease) in accounts payable, banks		86			(19	)
Dividends paid		(46	)		(45	)
Repurchase of common stock		(27	)		(22	)
Issuance of common stock, including tax benefit on stock option exercises		18			35
Sale of subsidiary units		(1	)		—
Distributions to noncontrolling interest owners		(33	)		(25	)
Contributions from noncontrolling interest owners		1			5
Net cash provided by (used in) financing activities		383			77
Effect of Exchange Rate Changes on Cash		(5	)		(10	)
Net Increase (Decrease) in Cash and Cash Equivalents		1,264			260
Cash and Cash Equivalents at Beginning of Period		2,471			2,697
Cash and Cash Equivalents at End of Period	$	3,735		$	2,957

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 March 31, 2013, and December 31, 2012, the Consolidated Statements of Income, Comprehensive Income, and Cash Flows for the three months ended March 31, 2013 and 2012, and the Consolidated Statement of Equity for the three months ended March 31, 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:

	March 31,		December 31,
millions	2013		2012
Crude oil	$	58	$	91
Natural gas		16		48
NGLs		44		37
Total	$	118	$	176

3.    Acquisitions and Divestitures

Acquisitions    In March 2013, Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, acquired a 33.75% interest in gas-gathering systems located in the Marcellus shale in north-central Pennsylvania from a third party for $135 million.

Divestitures    In the first quarter of 2013, proceeds from divestitures of $361 million and net gains on divestitures of $144 million were primarily related to the Company’s divestiture of its interests in a soda ash joint venture.

7

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4. Impairments

The following summarizes impairments by segment:

	Three Months Ended March 31,
millions	2013		2012
Oil and gas exploration and production
Long-lived assets held for use
Gulf of Mexico properties	$	—	$	50
Midstream
Long-lived assets held for use		29		—
Impairments	$	29	$	50

During the first quarter of 2013, a midstream property was impaired due to a reduction in estimated future cash flows. During the first quarter of 2012, 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 aggregate fair values to which the above-described assets were impaired, by major 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	$	—	$	—	$	22	$	22
2012
Long-lived assets held for use	$	—	$	—	$	37	$	37

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

5. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $1.9 billion at March 31, 2013, and $2.1 billion at December 31, 2012. The decrease in suspended exploratory well costs during 2013 primarily resulted from costs charged to dry hole expense in Sierra Leone, reclassification of costs to proved properties in the Marcellus and Utica shales in the Southern and Appalachia Region, and the sale of the Company’s interest in Indonesian subsidiaries, partially offset by the capitalization of costs associated with exploration drilling in Brazil. During the three months ended March 31, 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.

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.

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 March 31, 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. At March 31, 2013, WGP’s ownership interest in WES consisted of a 46.0% limited partner interest, the entire 2.0% general partner interest, and all WES incentive distribution rights. 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 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 March 31, 2013:

	2013			2014
	Settlement			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)		200
Average price per MMBtu
Ceiling sold price (call)	$	—		$	5.00
Floor purchased price (put)	$	—		$	3.75
Floor sold price (put)	$	—		$	2.75
Fixed-Price Contracts (thousand MMBtu/d)		1,185			—
Average price per MMBtu	$	4.00		$	—
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)		108			—
Average price per barrel	$	102.50		$	—

⁽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.

Marketing and Trading Derivative Activities    In addition to the positions in the above table, the Company also engages in marketing and trading activities. These activities include physical product sales and related derivative transactions used to manage commodity-price risk. At March 31, 2013, the Company had fixed-price physical transactions related to natural gas totaling 4 billion cubic feet (Bcf), offset by derivative transactions totaling 4 Bcf. At December 31, 2012, the Company had fixed-price physical transactions related to natural gas totaling 10 Bcf, offset by derivative transactions totaling 10 Bcf.

10

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Derivative Instruments (Continued)

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 March 31, 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				Gross
	Derivative Assets				Derivative Liabilities
millions Balance Sheet Classification	March 31,     2013		December 31, 2012		March 31,     2013			December 31, 2012
Commodity derivatives
Other current assets	$	43	$	475	$	(20	)	$	(197	)
Other assets		22		24		(7	)		(7	)
Accrued expenses		153		6		(245	)		(14	)
Other liabilities		—		1		(4	)		(7	)
		218		506		(276	)		(225	)
Interest-rate and other derivatives
Other liabilities		—		—		(1,101	)		(1,194	)
Total derivatives	$	218	$	506	$	(1,377	)	$	(1,419	)

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 or losses related to derivative instruments:

millions
Classification of (Gain) Loss Recognized	Realized			Unrealized			Total
Three Months Ended March 31, 2013
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	4		$	4		$	8
(Gains) losses on derivatives, net		(51	)		334			283
Interest-rate and other derivatives
(Gains) losses on derivatives, net		—			(92	)		(92	)
Total (gains) losses on derivatives, net	$	(47	)	$	246		$	199
Three Months Ended March 31, 2012
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	(2	)	$	5		$	3
(Gains) losses on derivatives, net		(137	)		89			(48	)
Interest-rate and other derivatives
(Gains) losses on derivatives, net		—			(236	)		(236	)
Total (gains) losses on derivatives, net	$	(139	)	$	(142	)	$	(281	)

⁽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 March 31, 2013, $186 million of the Company’s $1.4 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.

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 $92 million (net of collateral) at March 31, 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.

12

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Derivative Instruments (Continued)

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

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

millions
March 31, 2013	Level 1			Level 2			Level 3		Netting (1)			Collateral			Total
Assets
Commodity derivatives
Financial institutions	$	3		$	189		$	—	$	(178	)	$	(1	)	$	13
Other counterparties		—			26			—		(2	)		—			24
Total derivative assets	$	3		$	215		$	—	$	(180	)	$	(1	)	$	37
Liabilities
Commodity derivatives
Financial institutions	$	(3	)	$	(250	)	$	—	$	178		$	4		$	(71	)
Other counterparties		—			(23	)		—		2			—			(21	)
Interest-rate and other derivatives		—			(1,101	)		—		—			—			(1,101	)
Total derivative liabilities	$	(3	)	$	(1,374	)	$	—	$	180		$	4		$	(1,193	)
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:

	March 31,			December 31,
millions	2013			2012
Total debt at face value	$	15,337		$	14,952
Net unamortized discounts and premiums (1)		(1,674	)		(1,683	)
Total long-term debt	$	13,663		$	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 Zero-Coupon Senior Notes due 2036, which can be put to the Company in October 2013 for the then-accreted value, are classified as long-term debt on the Company’s Consolidated Balance Sheets. The Company has the ability and intent to refinance the obligations using long-term debt.

Fair Value    The Company uses a market approach to determine fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $16.5 billion at March 31, 2013, and $16.2 billion at December 31, 2012.

Debt Activity    The following summarizes the Company’s debt activity during the three months ended March 31, 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

WES Borrowings    At March 31, 2013, WES was in compliance with all covenants contained in its five-year, $800 million senior unsecured revolving credit facility maturing in March 2016, had outstanding borrowings of $385 million at an interest rate of 1.70%, and had available borrowing capacity of $402 million ($800 million maximum capacity, less $385 million of outstanding borrowings and $13 million of outstanding letters of credit).

Interest Expense    The following summarizes interest expense:

	Three Months Ended March 31,
millions	2013			2012
Current debt, long-term debt, and other	$	232		$	250
Capitalized interest		(68	)		(64	)
Interest expense	$	164		$	186

14

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Stockholders’ Equity

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

	Three Months Ended March  31,
millions except per-share amounts	2013		2012
Net income (loss)
Net income (loss) attributable to common stockholders	$	460	$	2,156
Less undistributed income allocated to participating securities		3		12
Basic	$	457	$	2,144
Diluted	$	457	$	2,144
Shares
Average number of common shares outstanding—basic		501		499
Dilutive effect of stock options		2		2
Average number of common shares outstanding—diluted		503		501
Excluded (1)		4		4
Net income (loss) per common share
Basic	$	0.91	$	4.30
Diluted	$	0.91	$	4.28
Dividends per common share	$	0.09	$	0.09

⁽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):

	Interest-rate
	Derivatives			Pension and
	Previously			Other
	Subject to Hedge			Postretirement
millions	Accounting			Plans			Total
Balance at December 31, 2012	$	(61	)	$	(579	)	$	(640	)
Reclassifications from accumulated other comprehensive income (loss)		2			19			21
Balance at March 31, 2013	$	(59	)	$	(560	)	$	(619	)

15

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. 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 discussion of the Company’s contingencies includes material developments with respect to matters previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012. No new material matters have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

Deepwater Horizon Events    In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% non-operated interest. In October 2011, the Company and BP entered into a settlement agreement 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.

16

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. 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 non-operating 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 confirmed by the Louisiana District Court, and the subjective criteria of the CWA, the Company believes that its exposure to CWA penalties will not materially impact the Company’s consolidated financial position, results of operations, or cash flows.

Civil Litigation Damage Claims    Numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court. 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 Transocean’s Limitation of Liability case in the MDL 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 are scheduled to be fully submitted by July 2013. BP, BP p.l.c., the United States, state and local governments, 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 include 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 wish to prove to the court that their respective company was not at fault. The second phase of trial is expected to start in September 2013 (Phase II). The issues to be tried in Phase II are expected to include 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 will participate in Phase II of the trial.

17

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. 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 March 2012, the New York District Court granted the Lead Plaintiff’s motion to transfer venue to the U.S. District Court for the Southern District of Texas – Houston Division (Texas District Court). In May 2012, the Texas District Court granted the defendants’ motion to transfer the consolidated action within the district to Judge Keith P. Ellis. In July 2012, the plaintiffs filed their First Amended Consolidated Class Action Complaint. The defendants filed a renewed motion to dismiss in the Southern District Court of Texas in September 2012. In April 2013, Judge Ellis heard oral arguments on the motion to dismiss, but has not yet issued a ruling.

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)

11. 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. 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.

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 as of March 31, 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.  Income Taxes

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

	Three Months Ended March 31,
millions except percentages	2013		2012
Income tax expense (benefit)	$	456	$	352
Effective tax rate		49%		14%

The increase from the 35% U.S. federal statutory rate for the three months ended March 31, 2013, 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 three months ended March 31, 2012, was primarily attributable to the non-taxable resolution of the Algeria exceptional profits tax dispute. This amount was partially offset by the tax impact from foreign operations and Algerian exceptional profits taxes.

13.  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:

	Three Months Ended March 31,
millions	2013		2012
Cash paid (received)
Interest	$	251	$	265
Income taxes	$	28	$	(70	)
Non-cash investing activities
Fair value of properties and equipment received in non-cash exchange transactions	$	13	$	—

20

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14.  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.

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; interest expense; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; Deepwater Horizon settlement and related costs; Algeria exceptional profits tax settlement; Tronox-related contingent loss; unrealized (gains) losses on derivatives, net; and realized (gains) losses on interest-rate and other derivatives, net, less net income attributable to noncontrolling interests. The Company’s definition of Adjusted EBITDAX excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Adjusted EBITDAX also excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Anadarko’s definition of Adjusted EBITDAX excludes Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, and Tronox-related contingent loss, as these costs are outside the normal operations of the Company. See Note 11—Contingencies. 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       March 31,
millions	2013		2012
Income (loss) before income taxes	$	940	$	2,535
Exploration expense		264		244
DD&A		1,022		930
Impairments		29		50
Deepwater Horizon settlement and related costs		3		8
Algeria exceptional profits tax settlement		33		(1,804	)
Tronox-related contingent loss		—		275
Interest expense		164		186
Unrealized (gains) losses on derivatives, net		246		(142	)
Less net income attributable to noncontrolling interests		24		27
Consolidated Adjusted EBITDAX	$	2,677	$	2,255

21

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14.  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 March 31, 2013
Sales revenues	$	1,541		$	84		$	2,093		$	—		$	3,718
Intersegment revenues		1,862			253			(1,966	)		(149	)		—
Gains (losses) on divestitures and other, net		4			—			—			171			175
Total revenues and other		3,407			337			127			22			3,893
Operating costs and expenses (1)		881			188			164			20			1,253
Realized (gains) losses on commodity derivatives, net		—			—			—			(51	)		(51	)
Other (income) expense, net (2)		—			—			—			(6	)		(6	)
Net income attributable to noncontrolling interests		—			24			—			—			24
Total expenses and other		881			212			164			(37	)		1,220
Unrealized (gains) losses on derivatives, net included in marketing revenue		—			—			4			—			4
Adjusted EBITDAX	$	2,526		$	125		$	(33	)	$	59		$	2,677
Three Months Ended March 31, 2012
Sales revenues	$	1,899		$	87		$	1,426		$	—		$	3,412
Intersegment revenues		1,174			249			(1,295	)		(128	)		—
Gains (losses) on divestitures and other, net		(17	)		(1	)		—			53			35
Total revenues and other		3,056			335			131			(75	)		3,447
Operating costs and expenses (1)		926			189			154			48			1,317
Realized (gains) losses on commodity derivatives, net		—			—			—			(137	)		(137	)
Other (income) expense, net (2)		—			—			—			(10	)		(10	)
Net income attributable to noncontrolling interests		—			27			—			—			27
Total expenses and other		926			216			154			(99	)		1,197
Unrealized (gains) losses on derivatives, net included in marketing revenue		—			—			5			—			5
Adjusted EBITDAX	$	2,130		$	119		$	(18	)	$	24		$	2,255

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

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

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15.  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.

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

	Pension Benefits						Other Benefits
millions	2013			2012			2013		2012
Three Months Ended March 31
Service cost	$	21		$	19		$	2	$	2
Interest cost		20			21			4		4
Expected return on plan assets		(23	)		(23	)		—		—
Amortization of net actuarial loss (gain)		29			23			—		—
Net periodic benefit cost	$	47		$	40		$	6	$	6

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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 the energy market

• 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

• 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

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• 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

• 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

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

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

• civil or political unrest 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, Kenya, Côte d’Ivoire, Liberia, Sierra Leone, Brazil, New Zealand, and other countries.

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

Overall

• Anadarko’s first-quarter sales volumes totaled 793 thousand barrels of oil equivalent per day (MBOE/d), representing a 13% increase over the first quarter of 2012.

• Anadarko’s first-quarter liquids sales volumes were 345 thousand barrels per day (MBbls/d), representing a 14% increase over the first quarter of 2012.

U.S. Onshore

• The Rocky Mountains Region (Rockies) first-quarter sales volumes were 328 MBOE/d, representing a 5% increase over the first quarter of 2012, primarily due to increased sales volumes from the Wattenberg field.

• The Southern and Appalachia Region first-quarter sales volumes were 237 MBOE/d, representing a 36% increase over the first quarter of 2012, primarily due to increased sales volumes from the Marcellus, Eagleford, and Haynesville shales.

Gulf of Mexico

• Gulf of Mexico first-quarter sales volumes were 118 MBOE/d, representing a 1% decrease from the first quarter of 2012, primarily due to natural production declines, partially offset by production at Caesar/Tonga, which began in March 2012.

• The Company signed a definitive agreement to enter into a carried-interest arrangement that requires a third-party partner to fund $860 million of Anadarko’s future capital costs to earn a 12.75% working interest in the Heidelberg development. The carried-interest arrangement closed in April 2013.

• The Company successfully drilled the Shenandoah-2 appraisal well (30% working interest) in Walker Ridge Block 51, encountering more than 1,000 net feet of oil pay.

• The Company participated in the successful drilling of the Coronado exploration well (15% working interest) in Walker Ridge Block 98, encountering more than 400 net feet of oil pay.

International

• International first-quarter sales volumes were 98 MBOE/d, representing an 18% increase from the first quarter of 2012, primarily due to increased sales volumes in Ghana.

• The Company achieved first production at the El Merk project in Algeria.

• The Company participated in the successful drillstem test on the Itaipu discovery well (33% working interest) in the Campos basin in Brazil, achieving flow rates of up to 5,600 barrels of oil per day.

Financial

• Anadarko’s net income attributable to common stockholders for the first quarter of 2013 totaled $460 million.

• The Company generated approximately $2.5 billion of cash flows from operations and ended the quarter with $3.7 billion of cash on hand.

• Anadarko collected $450 million associated with the Algeria exceptional profits tax receivable.

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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 March 31, 2013,” refer to the comparison of the three months ended March 31, 2013, to the three months ended March 31, 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

Selected Data

	Three Months Ended March 31,
millions except per-share amounts	2013		2012
Financial Results
Revenues and other	$	3,893	$	3,447
Costs and expenses		2,604		745
Other (income) expense		349		167
Income tax expense (benefit)		456		352
Net income (loss) attributable to common stockholders	$	460	$	2,156
Net income (loss) per common share attributable to common stockholders—diluted	$	0.91	$	4.28
Average number of common shares outstanding—diluted		503		501
Operating Results
Adjusted EBITDAX (1)	$	2,677	$	2,255
Sales volumes (MMBOE)		71		64

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

Net Income (Loss) Attributable to Common Stockholders    For the three months ended March 31, 2013, Anadarko’s net income attributable to common stockholders totaled $460 million, or $0.91 per share (diluted), compared to net income attributable to common stockholders of $2.2 billion, or $4.28 per share (diluted), for the three months ended March 31, 2012. Anadarko’s net income for the three months ended March 31, 2012, included $1.8 billion related to the favorable resolution of the Algeria exceptional profits tax dispute.

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Sales Revenues and Volumes

	Three Months Ended March  31,
millions except percentages	2013		Inc/(Dec) vs. 2012	2012
Sales Revenues
Natural-gas sales	$	807	41%	$	573
Oil and condensate sales		2,377	6		2,244
Natural-gas liquids sales		303	(11)		342
Total	$	3,487	10	$	3,159

Anadarko’s total sales revenues increased for the three months ended March 31, 2013, primarily due to higher sales volumes for all products and higher average natural-gas prices. This increase was partially offset by lower average crude-oil and NGLs prices for the three months ended March 31, 2013.

	Three Months Ended March 31,
millions	Natural Gas		Oil and Condensate			NGLs			Total
2012 sales revenues	$	573	$	2,244		$	342		$	3,159
Changes associated with sales volumes		57		320			32			409
Changes associated with prices		177		(187	)		(71	)		(81	)
2013 sales revenues	$	807	$	2,377		$	303		$	3,487

	Three Months Ended March 31,
Sales Volumes	2013		Inc/(Dec) vs. 2012	2012
Barrels of Oil Equivalent (MMBOE except percentages)
United States		62	11%		56
International		9	16		8
Total		71	11		64
Barrels of Oil Equivalent per Day (MBOE/d except percentages)
United States		695	12%		621
International		98	18		83
Total		793	13		704

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.

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Natural-Gas Sales Volumes, Average Prices, and Revenues

	Three Months Ended March 31,
	2013		Inc/(Dec) vs. 2012		2012
United States
Sales volumes—Bcf		242		10%		220
MMcf/d		2,689		11		2,416
Price per Mcf	$	3.33		28	$	2.60
Natural-gas sales revenues (millions)	$	807		41	$	573

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

Mcf—thousand cubic feet

The Company’s natural-gas sales volumes increased 273 MMcf/d for the three months ended March 31, 2013, primarily due to higher sales volumes of 270 MMcf/d in the Southern and Appalachia Region. This increase was a result of infrastructure expansions in 2012 allowing the Company to bring wells online in the Eagleford and Marcellus shales, as well as new wells drilled in the liquids-rich Haynesville shale.

The average natural-gas price Anadarko received increased for the three months ended March 31, 2013, due to increased U.S. residential and commercial demand as a result of cooler winter temperatures. This resulted in lower U.S. end-of-winter storage levels and brought overall U.S. storage levels in line with the 5-year average.

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

	Three Months Ended March 31,
	2013		Inc/(Dec) vs. 2012		2012
United States
Sales volumes—MMBbls		14		13%		12
MBbls/d		159		15		138
Price per barrel	$	97.32		(8)	$	105.75
International
Sales volumes—MMBbls		9		16%		8
MBbls/d		98		18		83
Price per barrel	$	112.18		(7)	$	120.00
Total
Sales volumes—MMBbls		23		14%		20
MBbls/d		257		16		221
Price per barrel	$	102.97		(7)	$	111.07
Oil and condensate sales revenues (millions)	$	2,377		6	$	2,244

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s crude-oil and condensate sales volumes increased 36 MBbls/d for the three months ended March 31, 2013. Increased horizontal drilling in the Wattenberg field led to 18 MBbls/d in higher volumes in the Rockies, while horizontal drilling and infrastructure expansions in the Eagleford shale and Bone Spring/Avalon formations contributed to an 8 MBbls/d improvement in the Southern and Appalachia Region. International sales volumes increased 15 MBbls/d primarily due to one additional cargo lifting in Ghana as a result of enhanced production due to successful acid stimulations in 2012 and additional Phase 1A Jubilee wells brought online. Sales volumes decreased by 3 MBbls/d in the Gulf of Mexico due to natural production declines, partially offset by production at Caesar/Tonga, which began in March 2012. The Company achieved first production at the El Merk project in Algeria in March 2013, and the Company’s first delivery of crude-oil sales volumes is expected to occur in the second quarter of 2013.

Anadarko’s average crude-oil price received decreased for the three months ended March 31, 2013, due to renewed economic growth concerns in Europe and China, which outweighed continuing supply disruption concerns associated with political and civil unrest in the Middle East and North Africa.

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

	Three Months Ended March 31,
	2013		Inc/(Dec) vs. 2012	2012
United States
Sales volumes—MMBbls		8	9%		7
MBbls/d		88	10		80
Price per barrel	$	38.17	(19)	$	47.09
Natural-gas liquids sales revenues (millions)	$	303	(11)	$	342

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 8 MBbls/d for the three months ended March 31, 2013, as a result of infrastructure expansion during 2012 and continued drilling in liquids-rich areas, primarily in the Eagleford and Haynesville shales in the Southern and Appalachia Region.

Anadarko’s average NGLs price received decreased for the three months ended March 31, 2013, primarily due to lower market prices for ethane and propane due to higher inventory levels. Ethane production capacity remains elevated relative to demand, resulting in ethane rejection to balance the market.

Gathering, Processing, and Marketing Margin

	Three Months Ended March 31,
millions except percentages	2013		Inc/(Dec) vs. 2012		2012
Gathering, processing, and marketing sales	$	231		(9)%	$	253
Gathering, processing, and marketing expenses		199		5		189
Margin	$	32		(50)	$	64

For the three months ended March 31, 2013, the gathering, processing, and marketing margin decreased by $32 million primarily due to reduced natural-gas processing margins as a result of lower NGLs prices, partially offset by increased natural-gas residue sales due to higher natural-gas prices. Also, for the three months ended March 31, 2013, gathering, processing, and marketing margin decreased due to higher transportation expenses.

Gains (Losses) on Divestitures and Other, net

For the three months ended March 31, 2013, gains (losses) on divestitures and other, net increased by $140 million primarily due to a gain associated with the Company’s divestiture of its interests in a soda ash joint venture. The Company divested its interests for $310 million and potential additional consideration based on future revenue. The Company retained its royalty interest in minerals, such as natural soda ash, mined from the Company’s Land Grant.

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Costs and Expenses

	Three Months Ended March 31,
	2013		Inc/(Dec) vs. 2012		2012
Oil and gas operating (millions)	$	247		2%	$	242
Oil and gas operating—per BOE		3.46		(8)		3.78
Oil and gas transportation and other (millions)		255		6		240
Oil and gas transportation and other—per BOE		3.58		(4)		3.74

For the three months ended March 31, 2013, oil and gas operating expenses increased by $5 million primarily due to $7 million related to timing of cargo liftings in China and $5 million related to 2013 acid stimulations in Ghana, partially offset by lower surface maintenance costs of $7 million primarily in the Rockies and the Gulf of Mexico. For the three months ended March 31, 2013, oil and gas operating expenses per barrel of oil equivalent (BOE) decreased by $0.32 primarily as a result of increased sales volumes, while production costs remained flat.

For the three months ended March 31, 2013, oil and gas transportation and other expenses increased by $15 million 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. For the three months ended March 31, 2013, oil and gas transportation and other expenses per BOE decreased by $0.16 primarily due to increased sales volumes.

	Three Months Ended March 31,
millions	2013		2012
Exploration Expense
Dry hole expense	$	158	$	89
Impairments of unproved properties		19		60
Geological and geophysical expenses		37		35
Exploration overhead and other		50		60
Total exploration expense	$	264	$	244

Dry hole expense for the three months ended March 31, 2013, included $110 million associated with two wells in Sierra Leone and $27 million associated with a well in Kenya. Dry hole expense for the three months ended March 31, 2012, included $37 million related to a well in Côte d’Ivoire and $24 million related to a well in Sierra Leone. Unproved property impairments for the three months ended March 31, 2013, decreased primarily as a result of a change in the Company’s estimated success rate associated with unproved Gulf of Mexico properties. Exploration overhead decreased due to less 2013 exploration spending related to U.S. properties and lower delay rentals associated with U.S. onshore properties.

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	Three Months Ended March 31,
millions except percentages	2013		Inc/(Dec) vs. 2012	2012
General and administrative	$	272	1%	$	269
Depreciation, depletion, and amortization		1,022	10		930
Other taxes		280	(26)		377
Impairments		29	(42)		50

For the three months ended March 31, 2013, general and administrative (G&A) expense increased by $3 million due to $27 million of higher employee-related expenses as a result of operational expansions and increased employee-benefit-related expenses, partially offset by lower legal and consulting fees of $19 million and other G&A expenses.

For the three months ended March 31, 2013, depreciation, depletion, and amortization (DD&A) expense increased by $92 million primarily due to higher sales volumes.

For the three months ended March 31, 2013, other taxes decreased by $97 million primarily related to lower Algerian exceptional profits taxes of $72 million due to a lower Algeria effective tax rate resulting from the resolution of the Algeria exceptional profits tax dispute, as well as lower crude-oil prices. U.S. production and severance taxes decreased $26 million primarily due to lower profit in Alaska as a result of decreased sales volumes and lower crude-oil prices.

Impairment expense for the three months ended March 31, 2013, included $29 million related to a midstream property that was impaired due to a reduction in estimated future cash flows. Impairment expense for the three months ended March 31, 2012, included $50 million related to a downward reserves revision for a Gulf of Mexico property that was near the end of its economic life.

	Three Months Ended March 31,
millions	2013		2012
Algeria exceptional profits tax settlement	$	33	$	(1,804	)
Deepwater Horizon settlement and related costs		3		8

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 the Company’s previously recorded and unpaid transportation charges. The crude oil is being delivered to the Company over a 12-month period that began in June 2012. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for the three months ended March 31, 2012, to reflect the effect of this agreement for previously recorded expenses. At March 31, 2013, the Company had collected approximately $1.5 billion associated with the Algeria exceptional profits tax receivable. The Company expects to collect the balance of the Algeria exceptional profits tax receivable during the second quarter of 2013. In March 2013, the Company revised its estimate related to the Algerian taxation of the prior-period 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.

In October 2011, the Company and BP entered into a settlement agreement relating to the Deepwater Horizon events. For the three months ended March 31, 2013 and 2012, Deepwater Horizon settlement and related costs included legal expenses and related costs associated with the Deepwater Horizon events. See Note 11—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.

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Other (Income) Expense

	Three Months Ended March 31,
millions except percentages	2013			Inc/(Dec) vs. 2012		2012
Interest Expense
Current debt, long-term debt, and other	$	232			(7)%	$	250
Capitalized interest		(68	)		(6)		(64	)
Interest expense	$	164			(12)	$	186

For the three months ended March 31, 2013, interest expense decreased by $22 million. The decrease is primarily due to 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), and a $4 million increase in capitalized interest related to higher construction-in-progress balances for long-term capital projects. For additional information regarding the Company’s financing activities, see Liquidity and Capital Resources.

	Three Months Ended March 31,
millions	2013			2012
(Gains) Losses on Derivatives, net
Commodity derivatives
Realized (gains) losses
Natural gas	$	(67	)	$	(170	)
Oil and condensate		18			33
Natural gas liquids		(2	)		—
Total realized (gains) losses		(51	)		(137	)
Unrealized (gains) losses
Natural gas		269			(86	)
Oil and condensate		60			173
Natural gas liquids		5			2
Total unrealized (gains) losses		334			89
Total (gains) losses on commodity derivatives, net		283			(48	)
Interest-rate and other derivatives
Unrealized (gains) losses		(92	)		(236	)
Total (gains) losses on derivatives, net	$	191		$	(284	)

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 March 31 of each year. For additional information on (gains) losses on commodity derivatives, see Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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.

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	Three Months Ended March 31,
millions except percentages	2013			Inc/(Dec) vs. 2012		2012
Other (Income) Expense, net
Interest income	$	(2	)		—%	$	(2	)
Other		(4	)		101		267
Total other (income) expense, net	$	(6	)		102	$	265

For the three months ended March 31, 2013, total other income increased by $271 million primarily due to a $275 million Tronox-related contingent loss that was recognized during the first quarter of 2012, and subsequently reversed in the second quarter of 2012. See Note 11—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Income Tax Expense

	Three Months  Ended March 31,
millions except percentages	2013		2012
Income tax expense (benefit)	$	456	$	352
Effective tax rate		49%		14%

The increase from the 35% U.S. federal statutory rate for the three months ended March 31, 2013, was primarily attributable to the following:

• tax impact from foreign operations

• Algerian exceptional profits taxes

The decrease from the 35% U.S. federal statutory rate for the three months ended March 31, 2012, was primarily attributable to the non-taxable resolution of the Algeria exceptional profits tax dispute. This amount was partially offset by the following:

• tax impact from foreign operations

• Algerian exceptional profits taxes

Net Income Attributable to Noncontrolling Interests

For the three months ended March 31, 2013, the Company’s net income attributable to noncontrolling interests of $24 million primarily related to the public ownership interests of 51.6% in Western Gas Partners, LP (WES) and 9.0% in Western Gas Equity Partners, LP (WGP) at March 31, 2013. In December 2012, Anadarko completed the initial public offering of WGP, consisting of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit. For the three months ended March 31, 2012, the Company’s net income attributable to noncontrolling interests of $27 million primarily related to a 54.4% public ownership interest in WES at March 31, 2012.

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OPERATING RESULTS

Segment Analysis—Adjusted EBITDAX    To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes, interest expense, exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, Tronox-related contingent loss, unrealized (gains) losses on derivatives, net, and realized (gains) losses on interest-rate and other derivatives, net, less net income attributable to noncontrolling interests. The Company’s definition of Adjusted EBITDAX, which is not a GAAP measure, excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Adjusted EBITDAX also excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Anadarko’s definition of Adjusted EBITDAX excludes Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, and Tronox-related contingent loss, as these costs are outside the normal operations of the Company. See Note 11—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for discussion of these events. Finally, unrealized (gains) losses on derivatives, net and realized (gains) losses on 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.

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Adjusted EBITDAX

	Three Months Ended March 31,
millions except percentages	2013			Inc/(Dec) vs. 2012		2012
Income (loss) before income taxes	$	940			(63)%	$	2,535
Exploration expense		264			8		244
DD&A		1,022			10		930
Impairments		29			(42)		50
Deepwater Horizon settlement and related costs		3			(63)		8
Algeria exceptional profits tax settlement		33			102		(1,804	)
Tronox-related contingent loss		—			(100)		275
Interest expense		164			(12)		186
Unrealized (gains) losses on derivatives, net		246			NM		(142	)
Less net income attributable to noncontrolling interests		24			(11)		27
Consolidated Adjusted EBITDAX	$	2,677			19	$	2,255
Adjusted EBITDAX by reporting segment
Oil and gas exploration and production	$	2,526			19%	$	2,130
Midstream		125			5		119
Marketing		(33	)		(83)		(18	)
Other and intersegment eliminations		59			146		24

NM—not meaningful

Oil and Gas Exploration and Production    Adjusted EBITDAX for the three months ended March 31, 2013, increased primarily due to higher sales volumes, higher natural-gas prices, and lower other taxes primarily from a lower Algerian effective tax rate and lower U.S. production and severance taxes primarily in Alaska. These increases to Adjusted EBITDAX were partially offset by lower crude-oil and NGLs prices.

Midstream    The increase in Adjusted EBITDAX for the three months ended March 31, 2013, is primarily due to increased throughput across several of Anadarko’s systems, which increased gathering revenue. This increase was partially offset by lower natural-gas processing margins.

Marketing    Marketing earnings primarily represent the margin earned on sales of natural gas, oil, and NGLs purchased from third parties. For the three months ended March 31, 2013, Adjusted EBITDAX decreased primarily due to higher transportation expenses.

Other and Intersegment Eliminations    Other and intersegment eliminations consist primarily of corporate costs, realized gains and losses on commodity derivatives, and income from hard minerals investments and royalties. The increase in Adjusted EBITDAX for the three months ended March 31, 2013, was primarily due to a $140 million gain associated with the Company’s divestiture of its interest in a soda ash joint venture, partially offset by lower realized gains on commodity derivatives in 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 three months ended March 31, 2013, cash flows from operating activities were the primary source of capital investment funding. In addition, the Company collected $450 million associated with the Algeria exceptional profits tax receivable during the three months ended March 31, 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 March 31, 2013, Anadarko had no scheduled debt maturities in 2013 and $775 million of scheduled debt maturities in 2014. Anadarko’s $500 million aggregate principal amount of 7.625% Senior Notes due March 2014 and Zero-Coupon Senior Notes due 2036, which can be put to the Company in October 2013 for the then-accreted value of $718 million, are classified as long-term debt on the Company’s Consolidated Balance Sheets. The Company has the ability and intent to refinance the obligations using long-term debt. 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 March 31, 2013, the Company had no outstanding borrowings and there were no restrictions on its ability to utilize the $5.0 billion Facility. The Company was in compliance with all applicable covenants contained in the $5.0 billion Facility.

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 five-year, $800 million senior unsecured revolving credit facility maturing in March 2016 (RCF).

At March 31, 2013, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings of $385 million at an interest rate of 1.70%, and had available borrowing capacity of $402 million ($800 million maximum capacity, less $385 million of outstanding borrowings and $13 million of outstanding letters of credit). See Financing Activities below.

Sources of Cash

Operating Activities    Anadarko’s cash flows from operating activities during the three months ended March 31, 2013, was $2.5 billion, compared to $1.9 billion for the same period of 2012. Cash flows for 2013 increased primarily due to higher sales volumes, higher average natural-gas prices, and cash collected associated with the Algeria exceptional profits tax receivable, but were partially offset by lower average NGLs and crude-oil prices.

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

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Investing Activities    During the three months ended March 31, 2013, Anadarko received pretax proceeds of $361 million related to several property divestiture transactions, including the divestiture of its interests in a soda ash joint venture.

Financing Activities    During the three months ended March 31, 2013, Anadarko’s consolidated subsidiary, WES, borrowed $385 million under its RCF primarily to fund the acquisition of a 33.75% interest in certain gas-gathering systems, located in the Marcellus shale in north-central Pennsylvania, in separate transactions with Anadarko and a third party.

Uses of Cash

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

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

	Three Months Ended March 31,
millions	2013		2012
Property acquisition—exploration	$	7	$	56
Exploration		319		385
Development		894		1,007
Capitalized interest		62		56
Total oil and gas capital expenditures		1,282		1,504
Gathering, processing, and marketing and other (1)		465		286
Total capital expenditures (2)	$	1,747	$	1,790

⁽¹⁾  Includes WES capital expenditures of $299 million for three months ended March 31, 2013, and $98 million for three months ended March 31, 2012.

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

The Company’s capital spending decreased 2% for the three months ended March 31, 2013, due to lower exploration property acquisition costs onshore United States, decreased exploration drilling in East and West Africa, and lower construction costs to Anadarko related to the development of the Lucius project located in the Gulf of Mexico as a result of the carried-interest arrangement discussed below. These decreases were partially offset by higher expenditures for domestic onshore plants and gathering systems. In March 2013, WES acquired a 33.75% interest in gas-gathering systems located in the Marcellus shale in north-central Pennsylvania from a third party for $135 million.

In the first quarter of 2013, the Company signed a definitive agreement to enter 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 carried-interest arrangement closed during the second quarter of 2013 and is effective as of April 1, 2013. The third-party funding is expected to cover nearly all of Anadarko’s future capital costs through first production, which is expected to occur by mid-2016.

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 year-end 2014. At March 31, 2013, $231 million of the total $556 million obligation had been funded.

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In the first quarter of 2011, the Company entered into a carried-interest arrangement that requires a third-party partner to fund approximately $1.6 billion of Anadarko’s future capital costs in the Eagleford shale, located in South Texas, to earn a one-third interest in Anadarko’s Eagleford shale assets. The third-party funding is expected to cover 90% of Anadarko’s future capital costs in the basin until the carry is fully funded, which is expected to occur by year-end 2013. At March 31, 2013, $1.4 billion of the total $1.6 billion obligation had been funded.

Pension and Other Postretirement Contributions    During the three months ended March 31, 2013, the Company made contributions of $1 million to its funded pension plans, $1 million to its unfunded pension plans, and $3 million to its unfunded other postretirement benefit plans. During the remainder of 2013, the Company expects to contribute approximately $95 million to its funded pension plans, approximately $44 million to its unfunded pension plans, and approximately $13 million to its unfunded other postretirement benefit plans.

Common Stock Dividends and Distributions to Noncontrolling Interest Owners    Anadarko paid dividends to its common stockholders of $46 million during the three months ended March 31, 2013, and $45 million during the three months ended March 31, 2012 (nine cents per share in each quarterly period). Anadarko has paid a dividend to its common stockholders on a quarterly basis since becoming an independent public company in 1986. The amount of future dividends paid to Anadarko common stockholders will be determined by the Board of Directors on a quarterly basis and will depend on 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 its subsidiary WGP, an aggregate of $29 million during the three months ended March 31, 2013, and $22 million during the three months ended March 31, 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 $0.54 per common unit for the first quarter of 2013 (to be paid in May 2013).

WGP distributed to its unitholders other than Anadarko an aggregate of $1 million during the three months ended March 31, 2013. WGP has declared a cash distribution of $0.17875 per unit for the first quarter of 2013 (to be paid in May 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 $7.8 billion to $8.2 billion. This amount includes $550 million to $600 million for 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 65% of its remaining 2013 anticipated natural-gas sales volumes and 50% 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.

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. In addition, foreign-currency exchange-rate risk exists due to anticipated foreign-currency denominated payments and receipts. These risks can affect revenues and cash flow from operating, investing, and financing activities. The Company’s risk-management policies provide for the use of derivative instruments to manage these risks. The types of commodity derivative instruments utilized by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. Both exchange and over-the-counter traded commodity derivative instruments may be subject to margin deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties in order to satisfy these margin requirements. For additional information related to the Company’s derivative and financial instruments, see Note 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 and unpredictable. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of the Company’s oil and gas properties or goodwill may be required if commodity prices experience a significant decline. Below is a sensitivity analysis for the Company’s commodity-price-related derivative instruments.

Derivative Instruments Held for Non-Trading Purposes    The Company had derivative instruments in place to reduce the price risk associated with future production of 527 Bcf of natural gas and 37 MMBbls of crude oil at March 31, 2013, with a net derivative liability position of $64 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $512 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $512 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 March 31, 2013, the Company had a net derivative asset position of $7 million (unrealized gains of $25 million and unrealized losses of $18 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 March 31, 2013, the Company had a net derivative liability position of $1.1 billion 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 $121 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 or borrowings under the $5.0 billion Facility. 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, and Mozambican meticais. 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 March 31, 2013, cash of $168 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 March 31, 2013.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the first 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.

See Note 11—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference, for material developments with respect to matters previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

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 11—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 first 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
January 1-31		21,147	$	76.30		—
February 1-28		2,510	$	81.93		—
March 1-31		317,276	$	80.55		—
First-Quarter 2013		340,933	$	80.30		—	$	—

⁽¹⁾  During the first 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; 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)
May 6, 2013	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Senior 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.

May 6, 2013

/s/ R. A. WALKER

R. A. Walker

President and Chief Executive Officer

EX-31.(II)

EXHIBIT 31(ii)

CERTIFICATIONS

I, Robert G. Gwin, certify that:

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

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

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

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

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

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

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

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

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

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

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

May 6, 2013

/s/ ROBERT G. GWIN

Robert G. Gwin

Senior Vice President, Finance and Chief Financial Officer                

EX-32

EXHIBIT 32

SECTION 1350 CERTIFICATION OF PERIODIC REPORT

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

(1) the Quarterly Report on Form 10-Q of the Company for the period ending March 31, 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.

May 6, 2013
	/s/ R. A. WALKER
	R. A. Walker
	President and Chief Executive Officer
May 6, 2013
	/s/ ROBERT G. GWIN
	Robert G. Gwin
	Senior Vice President, Finance and Chief Financial Officer

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

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Impairments - Impairments by Segment Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Impaired Long Lived Assets Held and Used [Line Items]
Impairments	$ 29	$ 50
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		50
Midstream Reporting Segment [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Long-lived assets held for use	$ 29

XML

Debt and Interest Expense - Interest Expense Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Interest Expense [Abstract]
Current debt, long-term debt, and other	$ 232	$ 250
Capitalized interest	(68)	(64)
Interest expense	$ 164	$ 186

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Derivative Instruments - Effect of Derivative Instruments - Statement of Income Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Derivative [Line Items]
Unrealized (gains) losses on derivatives, net	$ 246	$ (142)
Total (gains) losses on derivatives, net	191	(284)
Gathering, Processing, and Marketing Sales and Gains (Losses) on Derivatives, Net [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	(47)	(139)
Unrealized (gains) losses on derivatives, net	246	(142)
Total (gains) losses on derivatives, net	199	(281)
Commodity Derivatives [Member] | Gathering, Processing, and Marketing Sales [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	4	(2)
Unrealized (gains) losses on derivatives, net	4	5
Total (gains) losses on derivatives, net	8	3
Commodity Derivatives [Member] | (Gains) Losses on Derivatives, net [Member]
Derivative [Line Items]
Realized (gains) losses on derivatives, net	(51)	(137)
Unrealized (gains) losses on derivatives, net	334	89
Total (gains) losses on derivatives, net	283	(48)
Interest-Rate and Other Derivatives [Member] | (Gains) Losses on Derivatives, net [Member]
Derivative [Line Items]
Unrealized (gains) losses on derivatives, net	(92)	(236)
Total (gains) losses on derivatives, net	$ (92)	$ (236)

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Stockholders' Equity (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Net income (loss)
Net income (loss) attributable to common stockholders	$ 460		$ 2,156
Less undistributed income allocated to participating securities	3		12
Basic	457		2,144
Diluted	$ 457		$ 2,144
Shares
Average number of common shares outstanding - basic	501		499
Dilutive effect of stock options	2		2
Average number of common shares outstanding - diluted	503		501
Excluded	4	[1]	4	[1]
Net income (loss) per common share
Basic	$ 0.91		$ 4.30
Diluted	$ 0.91		$ 4.28
Dividends per common share	$ 0.09		$ 0.09

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

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Derivative Instruments - Interest-Rate Derivatives Table (Detail) (USD $)	3 Months Ended
	Mar. 31, 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

XML

Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2013

Table Text Block [Abstract]

Supplemental Cash Flow Table

		Three Months Ended
		March 31,
millions		2013		2012
Cash paid (received)
	Interest	$	251	$	265
	Income taxes	$	28	$	(70)
Non-cash investing activities
	Fair value of properties and equipment received in non-cash exchange transactions	$	13	$	—

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Contingencies - Deepwater Horizon Events (Detail) (USD $)	Sep. 30, 2011 Macondo Exploration Well [Member]	Mar. 31, 2013 Deepwater Horizon [Member] BP indemnification liability [Member]
Loss Contingencies [Line Items]
Anadarko's non-operated interest	25.00%
Loss contingency accrual at carrying value		$ 0

XML

Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2013

Policy Text Block [Abstract]

Use of Estimates

Use of EstimatesThe 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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Debt and Interest Expense - Outstanding Debt Table (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Debt Disclosure [Abstract]
Total debt at face value	$ 15,337		$ 14,952
Net unamortized discounts and premiums	(1,674)	[1]	(1,683)	[1]
Total long-term debt	$ 13,663		$ 13,269

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

XML

Noncontrolling Interests (Detail)	Mar. 31, 2013
Western Gas Equity Partners Limited Partnership [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	91.00%
Western Gas Partners Limited Partnership [Member] | Limited Partner [Member] | Western Gas Equity Partners Limited Partnership, Ownership Interest [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	46.00%
Western Gas Partners Limited Partnership [Member] | Limited Partner [Member] | Other Anadarko Subsidiary, Ownership Interest [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	0.40%
Western Gas Partners Limited Partnership [Member] | General Partner [Member] | Western Gas Equity Partners Limited Partnership, Ownership Interest [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	2.00%

XML

Acquisitions and Divestitures - Acquisitions (Detail) (Western Gas Partners Limited Partnership [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Western Gas Partners Limited Partnership [Member]
Business Acquisition [Line Items]
Date of acquisition agreement	Mar. 31, 2013
Ownership interest purchased	33.75%
Purchase price	$ 135

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Debt and Interest Expense - Debt Activity Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Debt Disclosure [Abstract]
Carrying value, beginning balance	$ 13,269
Debt Instrument [Line Items]
Other, net	9
Carrying value, ending balance	13,663
Western Gas Partners Limited Partnership [Member] | Borrowings [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Borrowings	$ 385

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Supplemental Cash Flow Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Cash paid (received)
Interest	$ 251	$ 265
Income taxes	28	(70)
Non-cash investing activities
Fair value of properties and equipment received in non-cash exchange transactions	$ 13

XML

Derivative Instruments - Effect of Derivative Instruments - Balance Sheet Table (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Derivatives Fair Value [Line Items]
Gross derivative assets	$ 218	$ 506
Gross derivative liabilities	(1,377)	(1,419)
Commodity Derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	218	506
Gross derivative liabilities	(276)	(225)
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	43	475
Gross derivative liabilities	(20)	(197)
Commodity Derivatives [Member] | Other Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	22	24
Gross derivative liabilities	(7)	(7)
Commodity Derivatives [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	153	6
Gross derivative liabilities	(245)	(14)
Commodity Derivatives [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets		1
Gross derivative liabilities	(4)	(7)
Interest-Rate and Other Derivatives [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative liabilities	$ (1,101)	$ (1,194)

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Cash Flows from Operating Activities
Net income (loss)	$ 484	$ 2,183
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, and amortization	1,022	930
Deferred income taxes	162	210
Dry hole expense and impairments of unproved properties	177	149
Impairments	29	50
(Gains) losses on divestitures, net	(144)	17
Unrealized (gains) losses on derivatives, net	246	(142)
Other	44	46
Changes in assets and liabilities
Deepwater Horizon settlement and related costs		30
Algeria exceptional profits tax settlement	450	(1,804)
Tronox-related contingent loss		275
(Increase) decrease in accounts receivable	40	(27)
Increase (decrease) in accounts payable and accrued expenses	(125)	(258)
Other items - net	118	232
Net cash provided by (used in) operating activities	2,503	1,891
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	(1,710)	(1,703)
Acquisition of midstream business	(135)
Divestitures of properties and equipment and other assets	361	47
Other - net	(133)	(42)
Net cash provided by (used in) investing activities	(1,617)	(1,698)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	385	319
Repayments of debt		(171)
Increase (decrease) in accounts payable, banks	86	(19)
Dividends paid	(46)	(45)
Repurchase of common stock	(27)	(22)
Issuance of common stock, including tax benefit on stock option exercises	18	35
Sale of subsidiary units	(1)
Distributions to noncontrolling interest owners	(33)	(25)
Contributions from noncontrolling interest owners	1	5
Net cash provided by (used in) financing activities	383	77
Effect of Exchange Rate Changes on Cash	(5)	(10)
Net Increase (Decrease) in Cash and Cash Equivalents	1,264	260
Cash and Cash Equivalents at Beginning of Period	2,471	2,697
Cash and Cash Equivalents at End of Period	$ 3,735	$ 2,957

XML

Segment Information - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2013 Segment
Segment Reporting Information [Line Items]
Number of reporting segments	3
Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Number of operating segments	2

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Derivative Instruments - Additional Information (Detail) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Gross derivative liability	$ 1,377,000,000	$ 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	92,000,000	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	186,000,000	339,000,000
Marketing and Trading Derivatives [Member] | Natural Gas [Member]
Derivative [Line Items]
Fixed-price physical transactions	4,000,000	10,000,000
Derivative transactions	4,000,000	10,000,000
Securing most derivative counterparties [Member] | Five Billion Dollar Facility [Member]
Derivative [Line Items]
Five billion dollar facility	$ 5,000,000,000

XML

Debt and Interest Expense (Tables)

3 Months Ended

Mar. 31, 2013

Table Text Block [Abstract]

Debt Outstanding and Debt Activity Tables

	March 31,		December 31,
millions	2013		2012
Total debt at face value	$	15,337	$	14,952
Net unamortized discounts and premiums (1)		(1,674)		(1,683)
Total long-term debt	$	13,663	$	13,269

__________________________________________________________________________

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

		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

Interest Expense Table

	Three Months Ended
	March 31,
millions	2013		2012
Current debt, long-term debt, and other	$	232	$	250
Capitalized interest		(68)		(64)
Interest expense	$	164	$	186

XML

Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2013

Table Text Block [Abstract]

Schedule of Derivative Instruments

				2013			2014
				Settlement			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)		200
		Average price per MMBtu
			Ceiling sold price (call)	$	—		$	5.00
			Floor purchased price (put)	$	—		$	3.75
			Floor sold price (put)	$	—		$	2.75
	Fixed-Price Contracts (thousand MMBtu/d)				1,185			—
		Average price per MMBtu		$	4.00		$	—
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)				108			—
		Average price per barrel		$	102.50		$	—

_______________________________________________________

(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/dfor 2013settlement.

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

millions except percentages		Reference Period		Weighted-Average
Notional Principal Amount		Start	End	Interest Rate
$	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

		Gross				Gross
		Derivative Assets				Derivative Liabilities
millions		March 31,		December 31,		March 31,		December 31,
Balance Sheet Classification		2013		2012		2013		2012
Commodity derivatives
	Other current assets	$	43	$	475	$	(20)	$	(197)
	Other assets		22		24		(7)		(7)
	Accrued expenses		153		6		(245)		(14)
	Other liabilities		—		1		(4)		(7)
			218		506		(276)		(225)
Interest-rate and other derivatives
	Other liabilities		—		—		(1,101)		(1,194)
Total derivatives		$	218	$	506	$	(1,377)	$	(1,419)

millions
Classification of (Gain) Loss Recognized		Realized		Unrealized		Total
Three Months Ended March 31, 2013
Commodity derivatives
	Gathering, processing, and marketing sales (1)	$	4	$	4	$	8
	(Gains) losses on derivatives, net		(51)		334		283
Interest-rate and other derivatives
	(Gains) losses on derivatives, net		—		(92)		(92)
Total (gains) losses on derivatives, net		$	(47)	$	246	$	199

Three Months Ended March 31, 2012
Commodity derivatives
	Gathering, processing, and marketing sales (1)	$	(2)	$	5	$	3
	(Gains) losses on derivatives, net		(137)		89		(48)
Interest-rate and other derivatives
	(Gains) losses on derivatives, net		—		(236)		(236)
Total (gains) losses on derivatives, net		$	(139)	$	(142)	$	(281)

_______________________________________________________

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

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

millions
March 31, 2013			Level 1		Level 2		Level 3		Netting (1)		Collateral		Total
Assets
	Commodity derivatives
		Financial institutions	$	3	$	189	$	—	$	(178)	$	(1)	$	13
		Other counterparties		—		26		—		(2)		—		24
Total derivative assets			$	3	$	215	$	—	$	(180)	$	(1)	$	37
Liabilities
	Commodity derivatives
		Financial institutions	$	(3)	$	(250)	$	—	$	178	$	4	$	(71)
		Other counterparties		—		(23)		—		2		—		(21)
	Interest-rate and other derivatives			—		(1,101)		—		—		—		(1,101)
Total derivative liabilities			$	(3)	$	(1,374)	$	—	$	180	$	4	$	(1,193)

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.

XML

Accumulated Other Comprehensive Income (Loss) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at December 31, 2012	$ (640)
Reclassification from accumulated other comprehensive income (loss)	21
Balance at March 31, 2013	(619)
Interest-rate Derivatives Previously Subject to Hedge Accounting [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at December 31, 2012	(61)
Reclassification from accumulated other comprehensive income (loss)	2
Balance at March 31, 2013	(59)
Pension and Other Postretirement Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at December 31, 2012	(579)
Reclassification from accumulated other comprehensive income (loss)	19
Balance at March 31, 2013	$ (560)

XML

Derivative Instruments - Natural Gas Production/Processing Derivative Activities Table (Detail) (Natural Gas [Member])	Mar. 31, 2013
April 2013 to October 2013 Settlement [Member] | Two Way Collars [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments, amount per day	600,000	[1]
April 2013 to October 2013 Settlement [Member] | Two Way Collars [Member] | Call Options Sold [Member]
Average price per MMBtu
Average ceiling price	4.00
April 2013 to October 2013 Settlement [Member] | Two Way Collars [Member] | Put Options Purchased [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]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments, amount per day	0	[2]
2013 Settlement [Member] | Three-Way Collars [Member] | Offsetting Purchased and Sold Positions For Four Hundred Fifty Thousand Million British Thermal Units Per Day [Member] | Call Options Sold [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments, amount per day	450,000
2013 Settlement [Member] | Three-Way Collars [Member] | Offsetting Purchased and Sold Positions For Four Hundred Fifty Thousand Million British Thermal Units Per Day [Member] | Call Options Purchased [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments, amount per day	(450,000)
2013 Settlement [Member] | Fixed-Price Contracts [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments, 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]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments, amount per day	200,000
2014 Settlement [Member] | Three-Way Collars [Member] | Call Options Sold [Member]
Average price per MMBtu
Average ceiling price	5.00
2014 Settlement [Member] | Three-Way Collars [Member] | Put Options Purchased [Member]
Average price per MMBtu
Average floor price	3.75
2014 Settlement [Member] | Three-Way Collars [Member] | Put Options Sold [Member]
Average price per MMBtu
Average floor price	2.75

[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.

XML

Stockholders' Equity (Tables)

3 Months Ended

Mar. 31, 2013

Table Text Block [Abstract]

Earnings Per Share Table

		Three Months Ended
		March 31,
millions except per-share amounts		2013		2012
Net income (loss)
	Net income (loss) attributable to common stockholders	$	460	$	2,156
	Less undistributed income allocated to participating securities		3		12
	Basic	$	457	$	2,144
	Diluted	$	457	$	2,144
Shares
	Average number of common shares outstanding—basic		501		499
	Dilutive effect of stock options		2		2
	Average number of common shares outstanding—diluted		503		501
	Excluded (1)		4		4
Net income (loss) per common share
	Basic	$	0.91	$	4.30
	Diluted	$	0.91	$	4.28
	Dividends per common share	$	0.09	$	0.09

_________________________________________________________

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

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Accumulated Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2013

Table Text Block [Abstract]

Schedule Of Accumulated Other Comprehensive Income (Loss) Table

			Interest-rate
			Derivatives		Pension and
			Previously		Other
			Subject to Hedge		Postretirement
millions			Accounting		Plans		Total
Balance at December 31, 2012			$	(61)	$	(579)	$	(640)
	Reclassifications from accumulated other
		comprehensive income (loss)		2		19		21
Balance at March 31, 2013			$	(59)	$	(560)	$	(619)

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CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Statement of Stockholders' Equity [Abstract]
Increase to paid-in capital for change in ownership interest upon equity issuance	$ 2
Net income (loss) attributable to common stockholders, including increase to paid-in capital for change in ownership interest upon equity issuance	$ 462

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2013

Table Text Block [Abstract]

Schedule of Income Taxes and Effective Tax Rate

	Three Months Ended
	March 31,
millions except percentages	2013			2012
Income tax expense (benefit)	$	456		$	352
Effective tax rate		49	%		14	%

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Impairments - Fair-Value Measurements Table (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Mar. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets held for use	$ 22		$ 37
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	$ 22	[1]	$ 37	[1]

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

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Debt and Interest Expense - Western Gas Partners, LP Additional Information (Detail) (Revolving Credit Facility [Member], USD $)	3 Months Ended
	Mar. 31, 2013
Line of Credit Facility [Line Items]
Line of credit, maximum capacity	$ 5,000,000,000
Western Gas Partners Limited Partnership [Member]
Line of Credit Facility [Line Items]
Line of credit, maximum capacity	800,000,000
Line of credit, expiration date	Mar. 24, 2016
Line of credit, outstanding borrowings	385,000,000
Line of credit, interest rate	1.70%
Line of credit, available borrowing capacity	402,000,000
Outstanding letters of credit	$ 13,000,000

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Revenues and Other
Natural-gas sales	$ 807	$ 573
Oil and condensate sales	2,377	2,244
Natural-gas liquids sales	303	342
Gathering, processing, and marketing sales	231	253
Gains (losses) on divestitures and other, net	175	35
Total	3,893	3,447
Costs and Expenses
Oil and gas operating	247	242
Oil and gas transportation and other	255	240
Exploration	264	244
Gathering, processing, and marketing	199	189
General and administrative	272	269
Depreciation, depletion, and amortization	1,022	930
Other taxes	280	377
Impairments	29	50
Algeria exceptional profits tax settlement	33	(1,804)
Deepwater Horizon settlement and related costs	3	8
Total	2,604	745
Operating Income (Loss)	1,289	2,702
Other (Income) Expense
Interest expense	164	186
(Gains) losses on derivatives, net	191	(284)
Other (income) expense, net	(6)	265
Total	349	167
Income (Loss) Before Income Taxes	940	2,535
Income tax expense (benefit)	456	352
Net Income (Loss)	484	2,183
Net income attributable to noncontrolling interests	24	27
Net Income (Loss) Attributable to Common Stockholders	$ 460	$ 2,156
Per Common Share
Net income (loss) attributable to common stockholders - basic	$ 0.91	$ 4.30
Net income (loss) attributable to common stockholders - diluted	$ 0.91	$ 4.28
Average Number of Common Shares Outstanding - Basic	501	499
Average Number of Common Shares Outstanding - Diluted	503	501
Dividends (per Common Share)	$ 0.09	$ 0.09

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Derivative Instruments - Crude Oil Production/Processing Derivative Activities Table (Detail) (2013 Settlement [Member], Crude Oil [Member])	Mar. 31, 2013
Three-Way Collars [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments, amount per day	26
Three-Way Collars [Member] | Call Options Sold [Member]
Average price per barrel
Average ceiling price	125.15
Three-Way Collars [Member] | Put Options Purchased [Member]
Average price per barrel
Average floor price	105.00
Three-Way Collars [Member] | Put Options Sold [Member]
Average price per barrel
Average floor price	85.00
Fixed-Price Contracts [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivative instruments not designated as hedging instruments, amount per day	108
Average price per barrel
Average price per barrel	102.50

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.1	$ 0.1
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	519,900,000	518,600,000
Treasury stock, shares	18,500,000	18,100,000

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Income Taxes - Income Tax Expense (Benefit) Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income tax expense (benefit)	$ 456	$ 352
Effective tax rate	49.00%	14.00%

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Pension Plans and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2013

Table Text Block [Abstract]

Components of Net Periodic Benefit Cost Table

	Pension Benefits				Other Benefits
millions	2013		2012		2013		2012
Three Months Ended March 31
Service cost	$	21	$	19	$	2	$	2
Interest cost		20		21		4		4
Expected return on plan assets		(23)		(23)		—		—
Amortization of net actuarial loss (gain)		29		23		—		—
Net periodic benefit cost	$	47	$	40	$	6	$	6

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Pension Plans and Other Postretirement Benefits (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pension Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	$ 21	$ 19
Interest cost	20	21
Expected return on plan assets	(23)	(23)
Amortization of net actuarial loss (gain)	29	23
Net periodic benefit cost	47	40
Other Postretirement Benefit Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	2	2
Interest cost	4	4
Net periodic benefit cost	$ 6	$ 6

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Supplemental Cash Flow Information

13.  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:

		Three Months Ended
		March 31,
millions		2013		2012
Cash paid (received)
	Interest	$	251	$	265
	Income taxes	$	28	$	(70)
Non-cash investing activities
	Fair value of properties and equipment received in non-cash exchange transactions	$	13	$	—

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Inventories (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Energy Related Inventory [Abstract]
Crude oil	$ 58	$ 91
Natural gas	16	48
NGLs	44	37
Total	$ 118	$ 176

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Pension Plans and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Pension Plans and Other Postretirement Benefits

15.  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 lifeinsurance benefits for certain retired employees. Retiree healthcare benefits are funded by contributions from the retiree, and in certain circumstances, contributions from the Company. The Company's retiree lifeinsurance plan is noncontributory.

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

	Pension Benefits				Other Benefits
millions	2013		2012		2013		2012
Three Months Ended March 31
Service cost	$	21	$	19	$	2	$	2
Interest cost		20		21		4		4
Expected return on plan assets		(23)		(23)		—		—
Amortization of net actuarial loss (gain)		29		23		—		—
Net periodic benefit cost	$	47	$	40	$	6	$	6

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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)	484					460			24
Common stock issued	51		1	50
Dividends - common	(46)					(46)
Repurchase of common stock	(27)						(27)
Subsidiary equity transactions	(3)			2	[1]				(5)
Distributions to noncontrolling interest owners	(33)								(33)
Contributions from noncontrolling interest owners	1								1
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	2	[2]						2
Adjustments for pension and other postretirement plans	19							19
Balance at Mar. 31, 2013	$ 22,330		$ 52	$ 8,282		$ 14,243	$ (868)	$ (619)	$ 1,240

[1] The $2 million increase to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders, totaled $462 million for the three months ended March 31, 2013.

[2] Net of income tax benefit (expense) of $(1) million for the three months ended March 31, 2013 and 2012.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 484		$ 2,183
Other Comprehensive Income (Loss), net of taxes
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	2	[1]	2	[1]
Amortization of net actuarial (gain) loss to general and administrative expense	19	[2]	15	[2]
Total	21		17
Comprehensive Income (Loss)	505		2,200
Comprehensive income attributable to noncontrolling interests	24		27
Comprehensive Income (Loss) Attributable to Common Stockholders	$ 481		$ 2,173

[1] Net of income tax benefit (expense) of $(1) million for the three months ended March 31, 2013 and 2012.

[2] Net of income tax benefit (expense) of $(10) million for the three months ended March 31, 2013, and $(8) million for the three months ended March 31, 2012.

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Debt and Interest Expense

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Debt and Interest Expense

8.  Debt and Interest Expense

DebtThe 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:

	March 31,		December 31,
millions	2013		2012
Total debt at face value	$	15,337	$	14,952
Net unamortized discounts and premiums (1)		(1,674)		(1,683)
Total long-term debt	$	13,663	$	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 Zero-Coupon Senior Notes due 2036, which can be put to the Company in October 2013 for the then-accreted value, are classified as long-term debt on the Company's Consolidated Balance Sheets. The Company has the ability and intent to refinance the obligationsusing long-term debt.

Fair ValueThe Company uses a market approach to determine fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company's total borrowings was $16.5 billion at March 31, 2013, and $16.2 billion at December 31, 2012.

Debt ActivityThe following summarizes the Company's debt activity during the three months ended March 31, 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

WES BorrowingsAt March 31, 2013, WES was in compliance with all covenants contained in its five-year, $800 million senior unsecured revolving credit facility maturing in March 2016, had outstanding borrowings of $385 million at an interest rate of 1.70%, and had available borrowing capacity of $402 million ($800 million maximum capacity, less $385 million of outstanding borrowings and $13 million of outstanding letters of credit).

Interest ExpenseThe following summarizes interest expense:

	Three Months Ended
	March 31,
millions	2013		2012
Current debt, long-term debt, and other	$	232	$	250
Capitalized interest		(68)		(64)
Interest expense	$	164	$	186

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Document and Entity Information	3 Months Ended
	Mar. 31, 2013	Apr. 30, 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	Mar. 31, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		501,473,546

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Stockholders' Equity

3 Months Ended

Mar. 31, 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
		March 31,
millions except per-share amounts		2013		2012
Net income (loss)
	Net income (loss) attributable to common stockholders	$	460	$	2,156
	Less undistributed income allocated to participating securities		3		12
	Basic	$	457	$	2,144
	Diluted	$	457	$	2,144
Shares
	Average number of common shares outstanding—basic		501		499
	Dilutive effect of stock options		2		2
	Average number of common shares outstanding—diluted		503		501
	Excluded (1)		4		4
Net income (loss) per common share
	Basic	$	0.91	$	4.30
	Diluted	$	0.91	$	4.28
	Dividends per common share	$	0.09	$	0.09

_________________________________________________________

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

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Statement of Comprehensive Income [Abstract]
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net, tax effect	$ (1)	$ (1)
Amortization of net actuarial (gain) loss to general and administrative expense, tax effect	$ (10)	$ (8)

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Acquisitions and Divestitures

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Acquisitions and Divestitures

3.  Acquisitions and Divestitures

Acquisitions   In March 2013, Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, acquired a 33.75% interest in gas-gathering systems located in the Marcellus shale in north-central Pennsylvania from a third party for $135 million.

DivestituresIn the first quarter of 2013, proceeds from divestitures of $361million and net gains on divestitures of $144million were primarily related to the Company's divestiture of its interests in a soda ash joint venture.

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Inventories

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Inventories

2.  Inventories

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

	March 31,		December 31,
millions	2013		2012
Crude oil	$	58	$	91
Natural gas		16		48
NGLs		44		37
Total	$	118	$	176

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Segment Information

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Segment Information

14.  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.

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; interest expense; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; Deepwater Horizon settlement and related costs; Algeria exceptional profits tax settlement; Tronox-related contingent loss; unrealized (gains) losses on derivatives, net; and realized (gains) losses on interest-rate and other derivatives, net, less net income attributable to noncontrolling interests. The Company's definition of Adjusted EBITDAX excludes interest expense to allow for assessment of segment operating results without regard to Anadarko's financing methods or capital structure. Adjusted EBITDAX also excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Anadarko's definition of Adjusted EBITDAX excludes Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, and Tronox-related contingent loss, as these costs are outside the normal operations of the Company.See Note 11—Contingencies.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
	March 31,
millions	2013		2012
Income (loss) before income taxes	$	940	$	2,535
Exploration expense		264		244
DD&A		1,022		930
Impairments		29		50
Deepwater Horizon settlement and related costs		3		8
Algeria exceptional profits tax settlement		33		(1,804)
Tronox-related contingent loss		—		275
Interest expense		164		186
Unrealized (gains) losses on derivatives, net		246		(142)
Less net income attributable to noncontrolling interests		24		27
Consolidated Adjusted EBITDAX	$	2,677	$	2,255

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:

		Oil and Gas						Other and
		Exploration						Intersegment
millions		& Production		Midstream		Marketing		Eliminations		Total
Three Months Ended March 31, 2013
Sales revenues		$	1,541	$	84	$	2,093	$	—	$	3,718
Intersegment revenues			1,862		253		(1,966)		(149)		—
Gains (losses) on divestitures and other, net			4		—		—		171		175
	Total revenues and other		3,407		337		127		22		3,893
Operating costs and expenses (1)			881		188		164		20		1,253
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(51)		(51)
Other (income) expense, net (2)			—		—		—		(6)		(6)
Net income attributable to
	noncontrolling interests		—		24		—		—		24
	Total expenses and other		881		212		164		(37)		1,220
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		4		—		4
Adjusted EBITDAX		$	2,526	$	125	$	(33)	$	59	$	2,677
Three Months Ended March 31, 2012
Sales revenues		$	1,899	$	87	$	1,426	$	—	$	3,412
Intersegment revenues			1,174		249		(1,295)		(128)		—
Gains (losses) on divestitures and other, net			(17)		(1)		—		53		35
	Total revenues and other		3,056		335		131		(75)		3,447
Operating costs and expenses (1)			926		189		154		48		1,317
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(137)		(137)
Other (income) expense, net (2)			—		—		—		(10)		(10)
Net income attributable to
	noncontrolling interests		—		27		—		—		27
	Total expenses and other		926		216		154		(99)		1,197
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		5		—		5
Adjusted EBITDAX		$	2,130	$	119	$	(18)	$	24	$	2,255

_________________________________________________________

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

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

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Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 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):

			Interest-rate
			Derivatives		Pension and
			Previously		Other
			Subject to Hedge		Postretirement
millions			Accounting		Plans		Total
Balance at December 31, 2012			$	(61)	$	(579)	$	(640)
	Reclassifications from accumulated other
		comprehensive income (loss)		2		19		21
Balance at March 31, 2013			$	(59)	$	(560)	$	(619)

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Noncontrolling Interests

3 Months Ended

Mar. 31, 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 March 31, 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. At March 31, 2013, WGP's ownership interest in WES consisted of a 46.0% limited partner interest, the entire 2.0% general partner interest, and all WES incentive distribution rights. Anadarko also owned a 0.4% limited partner interest in WES through another subsidiary.

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Income Taxes - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Income Tax Disclosure [Abstract]
U.S. federal statutory rate	35.00%	35.00%

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Impairments

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Impairments

4.Impairments

The following summarizes impairments by segment:

			Three Months Ended
			March 31,
millions			2013		2012
Oil and gas exploration and production
	Long-lived assets held for use
		Gulf of Mexico properties	$	—	$	50
Midstream
	Long-lived assets held for use			29		—
Impairments			$	29	$	50

During the first quarter of 2013, a midstreamproperty was impaired due to a reduction in estimated future cash flows. During the first quarter of 2012, aGulf 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 aggregate fair valuesto which the above-described assets were impaired, by major 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	$	—	$	—	$	22	$	22
2012
Long-lived assets held for use	$	—	$	—	$	37	$	37

____________________________________________________________________

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

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Suspended Exploratory Well Costs

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Suspended Exploratory Well Costs

5.  Suspended Exploratory Well Costs

The Company's suspended exploratory well costs were $1.9billion at March 31, 2013, and $2.1billion at December 31, 2012. The decreasein suspended exploratory well costs during 2013primarily resulted from costs charged to dry hole expense in Sierra Leone, reclassification of costs to proved properties in the Marcellus and Uticashales in the Southern and Appalachia Region, and the sale of the Company's interest inIndonesiansubsidiaries, partially offset by the capitalization of costs associated with exploration drilling in Brazil. During the threemonths ended March 31, 2013, $95million of exploratory well costs previously capitalized as suspended exploratory well costs for greater than one yearat December 31, 2012,were charged to dry hole expense.

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

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Derivative Instruments

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Derivative Instruments

7.  Derivative Instruments

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

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

       The Company does not apply hedge accounting to any of its derivative instruments. As a result, both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings. Net derivative losses attributable to 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).

Oil and Natural-Gas Production/Processing Derivative ActivitiesThe 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 March 31, 2013:

				2013			2014
				Settlement			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)		200
		Average price per MMBtu
			Ceiling sold price (call)	$	—		$	5.00
			Floor purchased price (put)	$	—		$	3.75
			Floor sold price (put)	$	—		$	2.75
	Fixed-Price Contracts (thousand MMBtu/d)				1,185			—
		Average price per MMBtu		$	4.00		$	—
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)				108			—
		Average price per barrel		$	102.50		$	—

_______________________________________________________

(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/dfor 2013settlement.

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.

Marketing and Trading Derivative Activities   In addition to the positions in the above table, the Company also engages in marketing and trading activities. These activities include physical product sales and related derivative transactions used to manage commodity-price risk. At March 31, 2013,the Company had fixed-price physical transactions related to natural gas totaling 4 billion cubic feet (Bcf), offset by derivative transactions totaling 4 Bcf.At December 31, 2012, the Company had fixed-price physical transactions related to natural gas totaling 10Bcf, offset by derivative transactions totaling 10Bcf.

Interest-Rate DerivativesAnadarko 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 March 31, 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 SheetThe following summarizes the fair value of the Company's derivative instruments:

		Gross				Gross
		Derivative Assets				Derivative Liabilities
millions		March 31,		December 31,		March 31,		December 31,
Balance Sheet Classification		2013		2012		2013		2012
Commodity derivatives
	Other current assets	$	43	$	475	$	(20)	$	(197)
	Other assets		22		24		(7)		(7)
	Accrued expenses		153		6		(245)		(14)
	Other liabilities		—		1		(4)		(7)
			218		506		(276)		(225)
Interest-rate and other derivatives
	Other liabilities		—		—		(1,101)		(1,194)
Total derivatives		$	218	$	506	$	(1,377)	$	(1,419)

Effect of Derivative Instruments—Statement of IncomeThe following summarizes realized and unrealized gains or lossesrelated to derivative instruments:

millions
Classification of (Gain) Loss Recognized		Realized		Unrealized		Total
Three Months Ended March 31, 2013
Commodity derivatives
	Gathering, processing, and marketing sales (1)	$	4	$	4	$	8
	(Gains) losses on derivatives, net		(51)		334		283
Interest-rate and other derivatives
	(Gains) losses on derivatives, net		—		(92)		(92)
Total (gains) losses on derivatives, net		$	(47)	$	246	$	199

Three Months Ended March 31, 2012
Commodity derivatives
	Gathering, processing, and marketing sales (1)	$	(2)	$	5	$	3
	(Gains) losses on derivatives, net		(137)		89		(48)
Interest-rate and other derivatives
	(Gains) losses on derivatives, net		—		(236)		(236)
Total (gains) losses on derivatives, net		$	(139)	$	(142)	$	(281)

_______________________________________________________

(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 March 31, 2013, $186million of the Company's $1.4 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.

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 $92 million (net of collateral) at March 31, 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 financial assets and liabilities, by input level within the fair-value hierarchy:

millions
March 31, 2013			Level 1		Level 2		Level 3		Netting (1)		Collateral		Total
Assets
	Commodity derivatives
		Financial institutions	$	3	$	189	$	—	$	(178)	$	(1)	$	13
		Other counterparties		—		26		—		(2)		—		24
Total derivative assets			$	3	$	215	$	—	$	(180)	$	(1)	$	37
Liabilities
	Commodity derivatives
		Financial institutions	$	(3)	$	(250)	$	—	$	178	$	4	$	(71)
		Other counterparties		—		(23)		—		2		—		(21)
	Interest-rate and other derivatives			—		(1,101)		—		—		—		(1,101)
Total derivative liabilities			$	(3)	$	(1,374)	$	—	$	180	$	4	$	(1,193)

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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Segment Information - Selected Financial Information for Anadarko's Reporting Segments Table (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Segment Reporting Information [Line Items]
Sales revenues	$ 3,718		$ 3,412
Gains (losses) on divestitures and other, net	175		35
Total	3,893		3,447
Operating costs and expenses	1,253	[1]	1,317	[1]
Other (income) expense, net	(6)		265
Net income attributable to noncontrolling interests	24		27
Total expenses and other	1,220		1,197
Unrealized (gains) losses on derivatives, net included in marketing revenue	246		(142)
Adjusted EBITDAX	2,677		2,255
Excluding Tronox Related Contingent Loss [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	(6)	[2]	(10)	[2]
Gathering, Processing, and Marketing Sales [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	4		(2)
Unrealized (gains) losses on derivatives, net included in marketing revenue	4		5
(Gains) Losses on Derivatives, net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	(51)		(137)
Unrealized (gains) losses on derivatives, net included in marketing revenue	334		89
Oil and Gas Exploration and Production Reporting Segment [Member]
Segment Reporting Information [Line Items]
Sales revenues	1,541		1,899
Intersegment revenues	1,862		1,174
Gains (losses) on divestitures and other, net	4		(17)
Total	3,407		3,056
Operating costs and expenses	881	[1]	926	[1]
Total expenses and other	881		926
Adjusted EBITDAX	2,526		2,130
Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Sales revenues	84		87
Intersegment revenues	253		249
Gains (losses) on divestitures and other, net			(1)
Total	337		335
Operating costs and expenses	188	[1]	189	[1]
Net income attributable to noncontrolling interests	24		27
Total expenses and other	212		216
Adjusted EBITDAX	125		119
Marketing Reporting Segment [Member]
Segment Reporting Information [Line Items]
Sales revenues	2,093		1,426
Intersegment revenues	(1,966)		(1,295)
Total	127		131
Operating costs and expenses	164	[1]	154	[1]
Total expenses and other	164		154
Adjusted EBITDAX	(33)		(18)
Marketing Reporting Segment [Member] | Gathering, Processing, and Marketing Sales [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net included in marketing revenue	4		5
Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Intersegment revenues	(149)		(128)
Gains (losses) on divestitures and other, net	171		53
Total	22		(75)
Operating costs and expenses	20	[1]	48	[1]
Total expenses and other	(37)		(99)
Adjusted EBITDAX	59		24
Other and Intersegment Eliminations [Member] | Excluding Tronox Related Contingent Loss [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	(6)	[2]	(10)	[2]
Other and Intersegment Eliminations [Member] | (Gains) Losses on Derivatives, net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Realized (gains) losses on derivatives, net	$ (51)		$ (137)

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

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

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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
	Mar. 31, 2013	Mar. 31, 2012
Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) before Income Taxes [Abstract]
Income (loss) before income taxes	$ 940	$ 2,535
Exploration expense	264	244
DD&A	1,022	930
Impairments	29	50
Deepwater Horizon settlement and related costs	3	8
Algeria exceptional profits tax settlement	33	(1,804)
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net	246	(142)
Interest expense	164	186
Less net income attributable to noncontrolling interests	24	27
Consolidated Adjusted EBITDAX	2,677	2,255
Gathering, Processing, and Marketing Sales and Gains (Losses) on Derivatives, Net [Member]
Segment Reporting Information [Line Items]
Unrealized (gains) losses on derivatives, net	246	(142)
Tronox Litigation [Member]
Segment Reporting Information [Line Items]
Tronox-related contingent loss		$ 275

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2013

Table Text Block [Abstract]

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

	Three Months Ended
	March 31,
millions	2013		2012
Income (loss) before income taxes	$	940	$	2,535
Exploration expense		264		244
DD&A		1,022		930
Impairments		29		50
Deepwater Horizon settlement and related costs		3		8
Algeria exceptional profits tax settlement		33		(1,804)
Tronox-related contingent loss		—		275
Interest expense		164		186
Unrealized (gains) losses on derivatives, net		246		(142)
Less net income attributable to noncontrolling interests		24		27
Consolidated Adjusted EBITDAX	$	2,677	$	2,255

Schedule of Segment Reporting Information, by Segment

		Oil and Gas						Other and
		Exploration						Intersegment
millions		& Production		Midstream		Marketing		Eliminations		Total
Three Months Ended March 31, 2013
Sales revenues		$	1,541	$	84	$	2,093	$	—	$	3,718
Intersegment revenues			1,862		253		(1,966)		(149)		—
Gains (losses) on divestitures and other, net			4		—		—		171		175
	Total revenues and other		3,407		337		127		22		3,893
Operating costs and expenses (1)			881		188		164		20		1,253
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(51)		(51)
Other (income) expense, net (2)			—		—		—		(6)		(6)
Net income attributable to
	noncontrolling interests		—		24		—		—		24
	Total expenses and other		881		212		164		(37)		1,220
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		4		—		4
Adjusted EBITDAX		$	2,526	$	125	$	(33)	$	59	$	2,677
Three Months Ended March 31, 2012
Sales revenues		$	1,899	$	87	$	1,426	$	—	$	3,412
Intersegment revenues			1,174		249		(1,295)		(128)		—
Gains (losses) on divestitures and other, net			(17)		(1)		—		53		35
	Total revenues and other		3,056		335		131		(75)		3,447
Operating costs and expenses (1)			926		189		154		48		1,317
Realized (gains) losses on commodity
	derivatives, net		—		—		—		(137)		(137)
Other (income) expense, net (2)			—		—		—		(10)		(10)
Net income attributable to
	noncontrolling interests		—		27		—		—		27
	Total expenses and other		926		216		154		(99)		1,197
Unrealized (gains) losses on derivatives, net
	included in marketing revenue		—		—		5		—		5
Adjusted EBITDAX		$	2,130	$	119	$	(18)	$	24	$	2,255

_________________________________________________________

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

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

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Debt and Interest Expense - Anadarko Additional Information (Detail) (USD $)						3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 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]	Mar. 31, 2013 Five Billion Dollar Facility [Member]	Mar. 31, 2013 Senior Notes, 7 Point 625 Percent, Due 2014 [Member]	Mar. 31, 2013 Senior Notes, Zero Coupon due 2036 [Member]	Mar. 31, 2013 Senior Notes, Zero Coupon due 2036, Accreted Value [Member]
Debt Instrument [Line Items]
Five billion dollar facility					$ 5,000,000,000
Debt instrument, principal amount	15,337,000,000	14,952,000,000				500,000,000
Debt instrument, stated interest rate						7.625%
Debt instrument, maturity date						Mar. 15, 2014	Oct. 10, 2036
Debt instrument, earliest call date								Oct. 10, 2013
Total borrowings, fair value			$ 16,500,000,000	$ 16,200,000,000

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Income Taxes

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Income Taxes

12.  Income Taxes

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

	Three Months Ended
	March 31,
millions except percentages	2013			2012
Income tax expense (benefit)	$	456		$	352
Effective tax rate		49	%		14	%

The increase from the 35% U.S. federal statutory rate for thethree months ended March 31, 2013, 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 thethree months ended March 31, 2012, was primarily attributable to the non-taxable resolution of the Algeria exceptional profits tax dispute. This amount was partially offset by the tax impact from foreign operationsand Algerian exceptional profits taxes.

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Inventories (Tables)

3 Months Ended

Mar. 31, 2013

Table Text Block [Abstract]

Inventory Disclosure Table

	March 31,		December 31,
millions	2013		2012
Crude oil	$	58	$	91
Natural gas		16		48
NGLs		44		37
Total	$	118	$	176

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Derivative Instruments - Fair Value Table (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	$ 218		$ 506
Gross derivative liabilities	(1,377)		(1,419)
Derivative assets netting	(180)	[1]	(211)	[1]
Derivative liabilities netting	180	[1]	211	[1]
Cash collateral from counterparties	(1)
Cash collateral held by counterparties	4		1
Derivative financial assets	37		295
Derivative financial liabilities	(1,193)		(1,207)
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	218		506
Gross derivative liabilities	(276)		(225)
Interest-Rate and Other Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial liabilities	(1,101)		(1,194)
Financial Institutions [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	(178)	[1]	(206)	[1]
Derivative liabilities netting	178	[1]	206	[1]
Cash collateral from counterparties	(1)
Cash collateral held by counterparties	4		1
Derivative financial assets	13		253
Derivative financial liabilities	(71)		(1)
Other Counterparties [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	(2)	[1]	(5)	[1]
Derivative liabilities netting	2	[1]	5	[1]
Derivative financial assets	24		42
Derivative financial liabilities	(21)		(12)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	3		6
Gross derivative liabilities	(3)		(6)
Fair Value, Inputs, Level 1 [Member] | Financial Institutions [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	3		6
Gross derivative liabilities	(3)		(6)
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	215		500
Gross derivative liabilities	(1,374)		(1,413)
Fair Value, Inputs, Level 2 [Member] | Interest-Rate and Other Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative liabilities	(1,101)		(1,194)
Fair Value, Inputs, Level 2 [Member] | Financial Institutions [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	189		453
Gross derivative liabilities	(250)		(202)
Fair Value, Inputs, Level 2 [Member] | Other Counterparties [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	26		47
Gross derivative liabilities	$ (23)		$ (17)

[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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Suspended Exploratory Well Costs (Detail) (USD $)	3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Capitalized Exploratory Well Costs [Abstract]
Suspended exploratory well costs	$ 1,900,000,000	$ 2,100,000,000
Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year [Abstract]
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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CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Current Assets
Cash and cash equivalents	$ 3,735	$ 2,471
Accounts receivable (net of allowance of $5 million and $7 million)
Customers	1,511	1,473
Others	1,249	1,274
Algeria exceptional profits tax settlement	280	730
Other current assets	535	847
Total	7,310	6,795
Properties and Equipment
Cost	65,160	63,598
Less accumulated depreciation, depletion, and amortization	26,190	25,200
Net properties and equipment	38,970	38,398
Other Assets	1,630	1,716
Goodwill and Other Intangible Assets	5,678	5,680
Total Assets	53,588	52,589
Current Liabilities
Accounts payable	2,909	2,989
Current asset retirement obligations	387	298
Accrued expenses	776	707
Total	4,072	3,994
Long-term Debt	13,663	13,269
Other Long-term Liabilities
Deferred income taxes	8,964	8,759
Asset retirement obligations	1,519	1,587
Other	3,040	3,098
Total	13,523	13,444
Stockholders' equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 519.9 million and 518.6 million shares issued)	52	51
Paid-in capital	8,282	8,230
Retained earnings	14,243	13,829
Treasury stock (18.5 million and 18.1 million shares)	(868)	(841)
Accumulated other comprehensive income (loss)	(619)	(640)
Total Stockholders' Equity	21,090	20,629
Noncontrolling interests	1,240	1,253
Total Equity	22,330	21,882
Total Liabilities and Equity	$ 53,588	$ 52,589

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Summary of Significant Accounting Policies

1.  Summary of Significant Accounting Policies

GeneralAnadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of natural gas, crude oil, condensate, and natural gas liquids (NGLs). In addition, the Company engages in the gathering, processing, 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 PresentationThe information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company's Consolidated Balance Sheets atMarch 31, 2013, and December 31, 2012, the Consolidated Statements of Income,Comprehensive Income, and Cash Flowsfor the three months ended March 31, 2013 and 2012, and the Consolidated Statement of Equity for the threemonths ended March 31, 2013. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

Use of EstimatesThe 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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Contingencies - Tronox Litigation (Detail) (Tronox Litigation [Member], USD $)	3 Months Ended
	Mar. 31, 2013
Loss Contingencies [Line Items]
Loss contingency accrual at carrying value	$ 0
Range of potential loss, minimum	0
Range of potential loss, maximum	1,400,000,000
Principal Portion of Maximum Loss Range [Member]
Loss Contingencies [Line Items]
Range of potential loss, maximum	985,000,000
Minimum [Member]
Loss Contingencies [Line Items]
Damages sought, including interest	$ 18,900,000,000

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Impairments (Tables)

3 Months Ended

Mar. 31, 2013

Table Text Block [Abstract]

Schedule of Impairment Expense

			Three Months Ended
			March 31,
millions			2013		2012
Oil and gas exploration and production
	Long-lived assets held for use
		Gulf of Mexico properties	$	—	$	50
Midstream
	Long-lived assets held for use			29		—
Impairments			$	29	$	50

Nonrecurring Fair Value Measurements Table

millions
2013	Level 1		Level 2		Level 3 (1)		Total
Long-lived assets held for use	$	—	$	—	$	22	$	22
2012
Long-lived assets held for use	$	—	$	—	$	37	$	37

____________________________________________________________________

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

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Acquisitions and Divestitures - Divestitures (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Gain (Loss) on Sale of Property [Abstract]
Proceeds from divestitures	$ 361	$ 47
Net gains (losses) on divestitures	$ 144	$ (17)

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Contingencies

3 Months Ended

Mar. 31, 2013

Disclosure Text Block [Abstract]

Contingencies

11.Contingencies

GeneralThe Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims;title disputes;tax disputes;royalty claims; contract claims; 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 discussion of the Company's contingencies includes material developments with respect to matters previously reported in the Company's Annual Report on Form 10-K for the year ended December 31, 2012. No new materialmatters have arisen sincethe filing of the Company's Annual Report on Form 10-K for the year ended December 31, 2012.

Deepwater Horizon EventsIn April 2010, the Macondo well in the Gulf of Mexicoblew out and an explosion occurred on the Deepwater Horizon drilling rig. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% non-operated interest.In October 2011, the Company and BPentered into a settlement agreement 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 Eventsin the Notes to the Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 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.

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 non-operating 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 confirmed by the Louisiana District Court, and the subjective criteria of the CWA, the Company believes that its exposure to CWA penalties will not materially impact the Company's consolidated financial position, results of operations, or cash flows.

Civil Litigation Damage ClaimsNumerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court. 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 Transocean's Limitation of Liability case in the MDL 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 are scheduled to be fully submitted by July 2013. BP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean participated in Phase I of the trial. Anadarkowas excused from participation in Phase I of the trial. The issues tried in Phase I include 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 wish to prove to the court that their respective company was not at fault. The second phase of trial is expected to start in September 2013 (Phase II). The issues to be tried in Phase II are expected to include 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 will participate in Phase II of the trial.

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 March 2012, the New York District Court granted the Lead Plaintiff's motion to transfer venue to the U.S. District Court for the Southern District of Texas – Houston Division (Texas District Court). In May 2012, the Texas District Court granted the defendants' motion to transfer the consolidated action within the district to Judge Keith P. Ellis. In July 2012, the plaintiffs filed their First Amended Consolidated Class Action Complaint. The defendants filed a renewed motion to dismiss in the Southern District Court of Texas in September 2012. In April 2013, Judge Ellis heard oral arguments on the motion to dismiss, but has not yet issued a ruling.

       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 OutlookIt 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.

Tronox LitigationIn January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox's subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee and seeks, among other things, to recover damages, including interest, in excess of $18.9billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. In accordance with Tronox's Plan of Reorganization, the Adversary Proceeding is being 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 TronoxLitigation, 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 December2012. The parties filed final post-trial briefs in January 2013. The matter is pending before the court.

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 as of March 31, 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.