UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2012

or

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

EXCHANGE ACT OF 1934

For the transition period from        to         

Commission File No. 1-8968

ANADARKO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices)

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

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

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

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

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

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

The number of shares outstanding of the Company’s common stock as of September 30, 2012, is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.10 per share	499,759,225

TABLE OF CONTENTS

PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Nine Months Ended September 30,  2012 and 2011		2
	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September  30, 2012 and 2011		3
	Consolidated Balance Sheets as of September 30, 2012, and December 31, 2011		4
	Consolidated Statement of Equity for the Nine Months Ended September 30, 2012		5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011		6
	Notes to Consolidated Financial Statements		7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
	Financial Results		30
	Operating Results		41
	Liquidity and Capital Resources		43
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		47
Item 4.	Controls and Procedures		48
PART II
Item 1.	Legal Proceedings		49
Item 1A.	Risk Factors		49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		50
Item 6.	Exhibits		51

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended  September 30,						Nine Months Ended   September 30,
millions except per-share amounts	2012			2011			2012			2011
Revenues and Other
Natural-gas sales	$	613		$	840		$	1,682		$	2,564
Oil and condensate sales		2,163			1,905			6,629			5,948
Natural-gas liquids sales		289			377			913			1,080
Gathering, processing, and marketing sales		218			262			671			750
Gains (losses) on divestitures and other, net		49			(185	)		106			(214	)
Total		3,332			3,199			10,001			10,128
Costs and Expenses
Oil and gas operating		241			262			732			730
Oil and gas transportation and other		247			217			710			633
Exploration		297			307			1,662			722
Gathering, processing, and marketing		185			214			552			590
General and administrative		285			293			816			784
Depreciation, depletion, and amortization		979			932			2,936			2,902
Other taxes		267			375			970			1,132
Impairments		4			183			166			287
Algeria exceptional profits tax settlement		7			—			(1,797	)		—
Deepwater Horizon settlement and related costs		4			4,042			15			4,077
Total		2,516			6,825			6,762			11,857
Operating Income (Loss)		816			(3,626	)		3,239			(1,729	)
Other (Income) Expense
Interest expense		185			206			561			642
(Gains) losses on commodity derivatives, net		237			(230	)		(231	)		(317	)
(Gains) losses on other derivatives, net		14			854			154			939
Other (income) expense, net		(10	)		40			(264	)		(2	)
Total		426			870			220			1,262
Income (Loss) Before Income Taxes		390			(4,496	)		3,019			(2,991	)
Income Tax Expense (Benefit)		248			(1,468	)		764			(762	)
Net Income (Loss)		142			(3,028	)		2,255			(2,229	)
Net Income Attributable to Noncontrolling Interests		21			23			67			62
Net Income (Loss) Attributable to Common Stockholders	$	121		$	(3,051	)	$	2,188		$	(2,291	)
Per Common Share
Net income (loss) attributable to common stockholders—basic	$	0.24		$	(6.12	)	$	4.35		$	(4.60	)
Net income (loss) attributable to common stockholders—diluted	$	0.24		$	(6.12	)	$	4.34		$	(4.60	)
Average Number of Common Shares Outstanding—Basic		500			498			499			498
Average Number of Common Shares Outstanding—Diluted		502			498			501			498
Dividends (per Common Share)	$	0.09		$	0.09		$	0.27		$	0.27

See accompanying Notes to Consolidated Financial Statements.

2

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended  September 30,					Nine Months Ended   September 30,
millions	2012		2011			2012		2011
Net Income (Loss)	$	142	$	(3,028	)	$	2,255	$	(2,229	)
Other Comprehensive Income (Loss), net of taxes
Reclassification of previously deferred derivative losses to net income (1)		2		2			6		7
Amortization of net actuarial loss and prior service cost to net periodic benefit cost (2)		15		14			45		41
Total		17		16			51		48
Comprehensive Income (Loss)		159		(3,012	)		2,306		(2,181	)
Comprehensive Income Attributable to Noncontrolling Interests		21		23			67		62
Comprehensive Income (Loss) Attributable to Common Stockholders	$	138	$	(3,035	)	$	2,239	$	(2,243	)

⁽¹⁾  Net of income tax benefit (expense) of $(1) million for the three months ended September 30, 2012 and 2011, and $(3) million and $(4) million for the nine months ended September 30, 2012 and 2011, respectively.

⁽²⁾  Net of income tax benefit (expense) of $(8) million for the three months ended September 30, 2012 and 2011, and $(25) million and $(24) million for the nine months ended September 30, 2012 and 2011, respectively.

See accompanying Notes to Consolidated Financial Statements.

3

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

millions	September 30, 2012			December 31, 2011
ASSETS
Current Assets
Cash and cash equivalents	$	2,532		$	2,697
Accounts receivable, net of allowance:
Customers		1,352			1,269
Others		1,572			1,990
Algeria exceptional profits tax settlement		1,122			—
Other current assets		746			975
Total		7,324			6,931
Properties and Equipment
Cost		62,125			60,081
Less accumulated depreciation, depletion, and amortization		24,149			22,580
Net properties and equipment		37,976			37,501
Other Assets		1,664			1,516
Goodwill and Other Intangible Assets		5,754			5,831
Total Assets	$	52,718		$	51,779
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	2,882		$	3,299
Accrued expenses		903			1,430
Current portion of long-term debt		1,039			170
Total		4,824			4,899
Long-term Debt		13,102			15,060
Other Long-term Liabilities
Deferred income taxes		8,743			8,479
Asset retirement obligations		1,669			1,737
Other		2,949			2,621
Total		13,361			12,837
Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 517.7 million and 516.0 million shares issued as of September 30, 2012, and December 31, 2011, respectively)		51			51
Paid-in capital		8,062			7,851
Retained earnings		13,671			11,619
Treasury stock (18.0 million and 17.6 million shares as of September 30, 2012, and December 31, 2011, respectively)		(830	)		(804	)
Accumulated other comprehensive income (loss)		(561	)		(612	)
Total Stockholders’ Equity		20,393			18,105
Noncontrolling interests		1,038			878
Total Equity		21,431			18,983
Total Liabilities and Equity	$	52,718		$	51,779

See accompanying Notes to Consolidated Financial Statements.

4

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

	Total Stockholders’ Equity
	Common Stock		Paid-in  Capital		Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests			Total  Equity
millions
Balance at December 31, 2011	$	51	$	7,851	$	11,619		$	(804	)	$	(612	)	$	878		$	18,983
Net income (loss)		—		—		2,188			—			—			67			2,255
Common stock issued		—		177		—			—			—			—			177
Dividends—common		—		—		(136	)		—			—			—			(136	)
Repurchase of common stock		—		—		—			(26	)		—			—			(26	)
Subsidiary equity transactions (1)		—		34		—			—			—			160			194
Distributions to noncontrolling interest owners		—		—		—			—			—			(81	)		(81	)
Contributions from noncontrolling interest owners		—		—		—			—			—			14			14
Reclassification of previously deferred derivative losses to net income		—		—		—			—			6			—			6
Adjustments for pension and other postretirement plans		—		—		—			—			45			—			45
Balance at September 30, 2012	$	51	$	8,062	$	13,671		$	(830	)	$	(561	)	$	1,038		$	21,431

⁽¹⁾  The $34 million increase to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders, totaled $2,222 million for the nine months ended September 30, 2012.

See accompanying Notes to Consolidated Financial Statements.

5

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended   September 30,
millions	2012			2011
Cash Flows from Operating Activities
Net income (loss)	$	2,255		$	(2,229	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, and amortization		2,936			2,902
Deferred income taxes		95			(1,195	)
Dry hole expense and impairments of unproved properties		1,389			423
Impairments		166			287
(Gains) losses on divestitures, net		23			243
Unrealized (gains) losses on derivatives, net		539			767
Other		174			151
Changes in assets and liabilities:
Deepwater Horizon settlement and related costs		25			4,020
Algeria exceptional profits tax settlement		(1,183	)		—
Tronox-related contingent loss		(250	)		—
(Increase) decrease in accounts receivable		409			(939	)
Increase (decrease) in accounts payable and accrued expenses		(486	)		250
Other items—net		27			(88	)
Net cash provided by (used in) operating activities		6,119			4,592
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs		(5,448	)		(4,110	)
Acquisition of midstream businesses		—			(802	)
Divestitures of properties and equipment and other assets		440			75
Other—net		(188	)		(52	)
Net cash provided by (used in) investing activities		(5,196	)		(4,889	)
Cash Flows from Financing Activities
Borrowings, net of issuance costs		885			1,051
Repayments of debt		(2,005	)		(1,154	)
Increase (decrease) in accounts payable, banks		12			39
Dividends paid		(136	)		(135	)
Repurchase of common stock		(26	)		(31	)
Issuance of common stock, including tax benefit on stock option exercises		68			57
Sale of subsidiary units		212			328
Distributions to noncontrolling interest owners		(81	)		(57	)
Contributions from noncontrolling interest owners		14			9
Net cash provided by (used in) financing activities		(1,057	)		107
Effect of Exchange Rate Changes on Cash		(31	)		(3	)
Net Increase (Decrease) in Cash and Cash Equivalents		(165	)		(193	)
Cash and Cash Equivalents at Beginning of Period		2,697			3,680
Cash and Cash Equivalents at End of Period	$	2,532		$	3,487

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. The Company also participates in the hard minerals business through its ownership of non-operated joint ventures and royalty arrangements. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

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

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

2.  Acquisitions

The acquisitions of the Platte Valley assets in February 2011 and the Wattenberg Plant in May 2011 constitute business combinations and were accounted for using the acquisition method. Preliminary fair-value measurements of assets acquired and liabilities assumed were finalized in the first quarter of 2012, and were equal to the amounts included on the Company’s Consolidated Balance Sheet as of December 31, 2011.

3.  Inventories

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

millions	September 30, 2012		December 31, 2011
Crude oil	$	76	$	103
Natural gas		32		49
NGLs		42		59
Total	$	150	$	211

4.  Properties and Equipment

Suspended Exploratory Well Costs  The Company’s suspended exploratory well costs at September 30, 2012, and December 31, 2011, were $1.9 billion and $1.4 billion, respectively. The increase in suspended exploratory well costs during 2012 primarily relates to the capitalization of costs associated with successful exploration drilling in Mozambique, the Gulf of Mexico, the Marcellus shale in the Southern and Appalachia Region, and Ghana. For the nine months ended September 30, 2012, $41 million of exploratory well costs previously capitalized as suspended exploratory well costs for greater than one year as of December 31, 2011, were charged to dry hole expense.

7

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4.  Properties and Equipment (Continued)

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.

Assets Held for Sale  In 2011, the Company began marketing certain domestic properties from the oil and gas exploration and production reporting segment and the midstream reporting segment in order to redirect operating activities and capital investment to other areas. These assets were remeasured to their fair value, estimated using Level 3 fair-value inputs, with resulting losses of $268 million related to oil and gas exploration and production reporting segment properties and $31 million related to midstream reporting segment properties for the three and nine months ended September 30, 2011. In 2012, the Company recognized losses on assets held for sale of $5 million and $35 million for the three and nine months ended September 30, 2012, respectively, primarily related to certain oil and gas exploration and production reporting segment properties. Gains and losses related to assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. At September 30, 2012, the remaining balances of assets and liabilities associated with assets held for sale were not material.

5.  Impairments

The following summarizes impairment expense by segment:

	Three Months Ended     September 30,				Nine Months Ended          September 30,
millions	2012		2011		2012		2011
Oil and Gas Exploration & Production
Long-lived assets held for use
U.S. onshore properties	$	2	$	—	$	81	$	100
Gulf of Mexico properties		—		93		67		93
Cost-method investment		1		87		12		91
Midstream
Long-lived assets held for use		1		3		6		3
Total impairment expense	$	4	$	183	$	166	$	287

In 2012, U.S. onshore and midstream properties were impaired due to lower natural-gas prices, and Gulf of Mexico properties were impaired as a result of downward reserves revisions for a property that was near the end of its economic life. In 2011, U.S. onshore properties were impaired due to a change in projected cash flows resulting from the Company’s intent to divest of the properties, and Gulf of Mexico properties were impaired due to declines in estimated recoverable reserves. Impairments of the Company’s Venezuelan cost-method investment were due to declines in estimated recoverable reserves in 2012 and 2011, and lower crude oil prices in 2012.

8

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5.  Impairments (Continued)

The following summarizes the aggregate fair values of the above-described assets, by major category and input level within the fair-value hierarchy, at the respective dates of impairment:

millions 2012	Level 1		Level 2		Level 3 (1)		Total
Long-lived assets held for use	$	—	$	—	$	38	$	38
Cost-method investment		—		—		34		34
2011
Long-lived assets held for use	$	—	$	—	$	395	$	395
Cost-method investment		—		—		38		38

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

Impairments of Unproved Properties  Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. In the second quarter of 2012, the Company recognized a $720 million impairment of unproved Powder River coalbed methane properties primarily resulting from lower natural-gas prices. Also in the second quarter of 2012, the Company recognized a $124 million impairment of an unproved Gulf of Mexico natural-gas property that the Company does not plan to pursue under the forecasted natural-gas price environment.

6.  Noncontrolling Interests

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

7.  Derivative Instruments

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

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

9

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7.  Derivative Instruments (Continued)

The Company does not apply hedge accounting to any of its derivative instruments. As a result, both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings. Accumulated other comprehensive loss balances of $100 million ($64 million after tax) and $109 million ($70 million after tax) at September 30, 2012, and December 31, 2011, respectively, relate to interest-rate derivatives that were previously subject to hedge accounting.

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

	2012			2013
Natural Gas
Three-Way Collars (thousand MMBtu/d)		—	(1)		—	(1)
Fixed-Price Contracts (thousand MMBtu/d)		1,000			900
Average price per MMBtu	$	4.69		$	4.00
Crude Oil
Three-Way Collars (MBbls/d)		62			26
Average price per barrel
Ceiling sold price (call)	$	122.30		$	125.15
Floor purchased price (put)	$	101.22		$	105.00
Floor sold price (put)	$	81.34		$	85.00
Fixed-Price Contracts (MBbls/d)		60			34
Average price per barrel	$	107.19		$	110.04

⁽¹⁾  The Company has entered into offsetting purchased and sold natural-gas three-way collars of 500,000 MMBtu/d and 450,000 MMBtu/d for 2012 and 2013, respectively.

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

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

Marketing and Trading Derivative Activities  In addition to the positions in the above tables, the Company also engages in marketing and trading activities, which include physical product sales and related derivative transactions used to manage commodity-price risk. At September 30, 2012, and December 31, 2011, the Company had fixed-price physical transactions related to natural gas totaling 12 billion cubic feet (Bcf) and 22 Bcf, respectively, offset by derivative transactions for 11 Bcf and 21 Bcf, respectively, for a net position of 1 Bcf at these dates.

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 LIBOR. The swap instruments include a provision that requires both the termination of the swaps and cash settlement in full at the start of the reference period. During the third quarter of 2012, the Company extended the swap maturity dates for interest-rate swaps with an aggregate notional principal amount of $800 million from October 2012 to September 2016. In connection with these extensions, the swap interest rates were also adjusted.

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

millions except percentages	Reference Period		Weighted-Average
Notional Principal Amount	Start	End	Interest Rate
$                     200	October 2012	October 2022	5.07 %
$                     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 fair value of the Company’s derivative instruments is presented below.

	Gross Derivative Assets				Gross Derivative Liabilities
millions	September 30,		December 31,		September 30,			December 31,
Balance Sheet Classification	2012		2011		2012			2011
Commodity derivatives
Other current assets	$	485	$	924	$	(228	)	$	(353	)
Other assets		76		150		(34	)		(15	)
Accrued expenses		7		5		(22	)		(33	)
Other liabilities		11		1		(20	)		(17	)
		579		1,080		(304	)		(418	)
Interest-rate and other derivatives
Accrued expenses		—		—		(67	)		(391	)
Other liabilities		—		—		(1,284	)		(808	)
		—		—		(1,351	)		(1,199	)
Total derivatives	$	579	$	1,080	$	(1,655	)	$	(1,617	)

11

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7.  Derivative Instruments (Continued)

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

millions	Three Months Ended September 30, 2012									Nine Months Ended September 30, 2012
Classification of (Gain) Loss Recognized	Realized			Unrealized			Total			Realized			Unrealized			Total
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	3		$	5		$	8		$	—		$	18		$	18
(Gains) losses on commodity derivatives, net		(200	)		437			237			(600	)		369			(231	)
Interest-rate and other derivatives
(Gains) losses on other derivatives, net		—			14			14			2			152			154
Derivative (gain) loss, net	$	(197	)	$	456		$	259		$	(598	)	$	539		$	(59	)
millions	Three Months Ended September 30, 2011									Nine Months Ended September 30, 2011
Classification of (Gain) Loss Recognized	Realized			Unrealized			Total			Realized			Unrealized			Total
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	1		$	(3	)	$	(2	)	$	17		$	(8	)	$	9
(Gains) losses on commodity derivatives, net		(71	)		(159	)		(230	)		(155	)		(162	)		(317	)
Interest-rate and other derivatives
(Gains) losses on other derivatives, net		—			854			854			2			937			939
Derivative (gain) loss, net	$	(70	)	$	692		$	622		$	(136	)	$	767		$	631

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

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

In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across all derivative types. At September 30, 2012, $422 million of the Company’s $1.7 billion gross derivative liability balance, and at December 31, 2011, $749 million of the Company’s $1.6 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types.

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

At September 30, 2012, and December 31, 2011, the aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed was $158 million (net of collateral) and $2 million (net of collateral), respectively, included in accrued expenses on the Company’s Consolidated Balance Sheets.

12

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

millions September 30, 2012	Level 1			Level 2			Level 3		Netting (1)			Collateral			Total
Assets
Commodity derivatives
Financial institutions	$	2		$	517		$	—	$	(272	)	$	(10	)	$	237
Other counterparties		—			60			—		(8	)		—			52
Total derivative assets	$	2		$	577		$	—	$	(280	)	$	(10	)	$	289
Liabilities
Commodity derivatives
Financial institutions	$	(2	)	$	(278	)	$	—	$	272		$	10		$	2
Other counterparties		—			(24	)		—		8			—			(16	)
Interest-rate and other derivatives		—			(1,351	)		—		—			—			(1,351	)
Total derivative liabilities	$	(2	)	$	(1,653	)	$	—	$	280		$	10		$	(1,365	)
December 31, 2011
Assets
Commodity derivatives
Financial institutions	$	3		$	947		$	—	$	(361	)	$	(52	)	$	537
Other counterparties		—			130			—		(13	)		—			117
Total derivative assets	$	3		$	1,077		$	—	$	(374	)	$	(52	)	$	654
Liabilities
Commodity derivatives
Financial institutions	$	(4	)	$	(375	)	$	—	$	361		$	7		$	(11	)
Other counterparties		—			(39	)		—		13			—			(26	)
Interest-rate and other derivatives		—			(1,199	)		—		—			130			(1,069	)
Total derivative liabilities	$	(4	)	$	(1,613	)	$	—	$	374		$	137		$	(1,106	)

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

13

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8.  Debt and Interest Expense

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

millions	September 30, 2012			December 31,   2011
Long-term notes and debentures	$	14,821		$	16,452
WES borrowings		1,020			500
Total debt at face value	$	15,841		$	16,952
Net unamortized discounts and premiums (1)		(1,700	)		(1,722	)
Total borrowings	$	14,141		$	15,230
Less: Current portion of long-term debt		1,039			170
Total long-term debt	$	13,102		$	15,060

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

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

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

millions	Carrying         Value			Description
Balance at December 31, 2011	$	15,230
Borrowings		319		WES revolving credit facility
Repayments		(131	)	6.125% Senior Notes due 2012
		(40	)	WES revolving credit facility
Other, net		8		Changes in debt premium or discount
Balance at March 31, 2012	$	15,386
Issuance		516		WES 4.00% Senior Notes due 2022
Borrowings		55		WES revolving credit facility
Repayments		(800	)	$5.0 billion Facility
		(334	)	WES revolving credit facility
Other, net		9		Changes in debt premium or discount
Balance at June 30, 2012	$	14,832
Repayments		(700	)	$5.0 billion Facility
Other, net		9		Changes in debt premium or discount
Balance at September 30, 2012	$	14,141

Anadarko Revolving Credit Facility and Letter of Credit Facility  At September 30, 2012, the Company was in compliance with all applicable covenants contained in the $5.0 billion Facility, had outstanding borrowings of $1.0 billion at an interest rate of 1.72%, and had available borrowing capacity of $4.0 billion ($5.0 billion maximum capacity less $1.0 billion of outstanding borrowings). The Company intends to repay the outstanding borrowings under the $5.0 billion Facility within the next year with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute and has classified these borrowings as current portion of long-term debt on the Company’s Consolidated Balance Sheet at September 30, 2012.

In 2011, the Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit (LOC Facility). In the third quarter of 2012, the Company terminated the LOC Facility.

14

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8.  Debt and Interest Expense (Continued)

WES Borrowings  During the second quarter of 2012, WES repaid all outstanding borrowings under its five-year $800 million senior unsecured revolving credit facility (RCF) with net proceeds from its public offering of $520 million aggregate principal amount of 4.00% Senior Notes due 2022. At September 30, 2012, WES was in compliance with all covenants contained in the RCF. In October 2012, WES issued an additional $150 million of 4.00% Senior Notes due 2022.

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

	Three Months Ended     September 30,						Nine Months Ended          September 30,
millions	2012			2011			2012			2011
Current debt, long-term debt, and other	$	238		$	245		$	724		$	743
Capitalized interest		(53	)		(39	)		(163	)		(101	)
Total interest expense	$	185		$	206		$	561		$	642

9.  Stockholders’ Equity

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

	Three Months Ended     September 30,					Nine Months Ended          September 30,
millions except per-share amounts	2012		2011			2012		2011
Net income (loss)
Net income (loss) attributable to common stockholders	$	121	$	(3,051	)	$	2,188	$	(2,291	)
Less: Distributions on participating securities		—		—			1		—
Less: Undistributed income allocated to participating securities		1		—			13		—
Basic	$	120	$	(3,051	)	$	2,174	$	(2,291	)
Diluted	$	120	$	(3,051	)	$	2,174	$	(2,291	)
Shares
Average number of common shares outstanding—basic		500		498			499		498
Dilutive effect of stock options and performance-based stock awards		2		—			2		—
Average number of common shares outstanding—diluted		502		498			501		498
Excluded (1)		6		12			6		12
Net income (loss) per common share
Basic	$	0.24	$	(6.12	)	$	4.35	$	(4.60	)
Diluted	$	0.24	$	(6.12	)	$	4.34	$	(4.60	)
Dividends per common share	$	0.09	$	0.09		$	0.27	$	0.27

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

15

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10.  Commitments

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

Other Commitments  In 2012, the Company entered into contractual agreements for processing, transportation, and storage of natural gas, crude oil, and NGLs. These obligations total approximately $2.0 billion, with aggregate future payments of $17 million in 2012, $173 million in 2013, $228 million in 2014, $227 million in 2015, $225 million in 2016, and $1.1 billion thereafter.

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, oil-field contamination claims, and environmental claims, including claims involving assets owned by acquired companies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

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

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

16

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11.  Contingencies (Continued)

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

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

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

17

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11.  Contingencies (Continued)

The Louisiana District Court plans to hold a trial in Transocean’s Limitation of Liability case in the MDL. In March 2012, BP and the Plaintiffs’ Steering Committee (PSC) entered into a tentative settlement agreement to resolve the substantial majority of economic loss and medical claims stemming from the Deepwater Horizon events. In light of this settlement agreement, the Louisiana District Court postponed the start of the trial until a future date and requested that the parties submit separate briefs that explain the parties’ opinions as to the impact of the tentative settlement on the Louisiana District Court’s previously issued trial plan. BP and the PSC jointly filed the proposed settlement agreement with the Louisiana District Court in April 2012. In May 2012, the Louisiana District Court issued its revised case management order (CMO) ruling that the first phase of the trial will commence in February 2013 (Phase I). Phase I is expected to last for six to twelve weeks. BP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean will participate in Phase I of the trial. The CMO provides that the Stipulated Order excusing Anadarko from participation in Phase I of the trial remains in effect. The issues to be 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 estimated to start in June 2013 (Phase II) and may take six to eight weeks to complete. The issues to be tried in Phase II will 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 (Exchange Act) for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. In March 2012, the New York District Court granted the Lead Plaintiff’s motion to transfer venue to the U.S. District Court for the Southern District of Texas – Houston Division (Texas District Court). In May 2012, the Texas District Court granted the defendants’ motion to transfer the consolidated action within the district to Judge Keith P. Ellis.

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

Given the various stages of these 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 any and all indemnities provided by BP against civil damages.

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

18

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11.  Contingencies (Continued)

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

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

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

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

In February 2012, the Company filed a motion for partial summary judgment seeking dismissal of several claims, including all actual and constructive fraudulent transfer claims protected by Section 546(e) of the U.S. Bankruptcy Code. The court has not yet ruled on that issue. Trial began in May 2012 and in September 2012, the evidence closed and both sides rested. Closing arguments are scheduled for December 2012.

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

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

19

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11.  Contingencies (Continued)

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

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

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

Other Litigation  In December 2008, Anadarko sold its interest in the Peregrino heavy-oil field offshore Brazil. The Company is currently litigating a dispute with the Brazilian tax authorities regarding the tax rate applicable to the transaction. Currently, $168 million, the amount of tax in dispute, resides in a judicially controlled Brazilian bank account, pending final resolution of the matter and is included in other assets on the Company’s Consolidated Balance Sheet as of September 30, 2012.

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

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

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

20

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11.  Contingencies (Continued)

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

In March 2012, the Company reached an agreement with Sonatrach to resolve the exceptional profits tax dispute. The agreement was approved by the Algerian government and provides for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period that began in June 2012. At September 30, 2012, a receivable of $1.1 billion on the Company’s Consolidated Balance Sheet was included in the oil and gas exploration and production reporting segment. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for the nine months ended September 30, 2012, to reflect the effect of this agreement on previously recorded expenses. Additionally, the parties agreed to an amendment to the existing Production Sharing Agreement (PSA) that provides the Company increased sales volumes and a lower effective exceptional profits tax rate in future periods. The amendment also confirms the duration for each exploitation license granted under the PSA will be 25 years from the date the license was awarded.

12.  Income Taxes

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

	Three Months Ended September 30,					Nine Months Ended September 30,
millions except percentages	2012		2011			2012		2011
Income tax expense (benefit)	$	248	$	(1,468	)	$	764	$	(762	)
Effective tax rate		64%		33%			25%		25%

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

The Company reported a loss before income taxes for the three and nine months ended September 30, 2011. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2011, was primarily attributable to Algerian exceptional profits taxes, U.S. tax on foreign income inclusions and distributions, and foreign tax rate differentials and valuation allowances. The decrease from the 35% U.S. federal statutory rate for the nine months ended September 30, 2011, was also attributable to items resulting from business acquisitions. These items were partially offset by the U.S. tax impact from losses and restructuring of foreign operations, state income taxes, and other items.

21

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

13.  Supplemental Cash Flow Information

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

	Nine Months Ended       September 30,
millions	2012			2011
Cash paid (received)
Interest	$	613		$	708
Income taxes	$	(13	)	$	238
Non-cash investing activities
Fair value of properties and equipment received in non-cash exchange transactions	$	65		$	4
Gain related to the fair-value remeasurement of Anadarko’s pre-acquisition 7% equity interest in the Wattenberg Plant	$	—		$	21

14.  Segment Information

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

To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes 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 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 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.

22

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14.  Segment Information (Continued)

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

	Three Months Ended       September 30,					Nine Months Ended       September 30,
millions	2012		2011			2012			2011
Income (loss) before income taxes	$	390	$	(4,496	)	$	3,019		$	(2,991	)
Exploration expense		297		307			1,662			722
DD&A		979		932			2,936			2,902
Impairments		4		183			166			287
Deepwater Horizon settlement and related costs		4		4,042			15			4,077
Algeria exceptional profits tax settlement (1)		7		—			(1,797	)		—
Tronox-related contingent loss (1)		—		—			(250	)		—
Interest expense		185		206			561			642
Unrealized (gains) losses on derivatives, net		456		692			539			767
Realized (gains) losses on other derivatives, net (1)		—		—			2			2
Less: Net income attributable to noncontrolling interests		21		23			67			62
Consolidated Adjusted EBITDAX	$	2,301	$	1,843		$	6,786		$	6,346

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

23

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14.  Segment Information (Continued)

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

millions	Oil and Gas Exploration & Production			Midstream			Marketing			Other and  Intersegment  Eliminations			Total
Three Months Ended September 30, 2012
Sales revenues	$	1,393		$	80		$	1,810		$	—		$	3,283
Intersegment revenues		1,587			232			(1,682	)		(137	)		—
Gains (losses) on divestitures and other, net		12			(6	)		—			43			49
Total revenues and other		2,992			306			128			(94	)		3,332
Operating costs and expenses (1)		840			182			152			51			1,225
Realized (gains) losses on commodity derivatives, net		—			—			—			(200	)		(200	)
Other (income) expense, net (2)		—			—			—			(10	)		(10	)
Net income attributable to noncontrolling interests		—			21			—			—			21
Total expenses and other		840			203			152			(159	)		1,036
Unrealized (gains) losses on derivatives, net included in marketing revenue		—			—			5			—			5
Adjusted EBITDAX	$	2,152		$	103		$	(19	)	$	65		$	2,301
Three Months Ended September 30, 2011
Sales revenues	$	1,801		$	76		$	1,507		$	—		$	3,384
Intersegment revenues		1,244			251			(1,386	)		(109	)		—
Gains (losses) on divestitures and other, net		(193	)		(31	)		—			39			(185	)
Total revenues and other		2,852			296			121			(70	)		3,199
Operating costs and expenses (1)		955			210			143			53			1,361
Realized (gains) losses on commodity derivatives, net		—			—			—			(71	)		(71	)
Other (income) expense, net (2)		—			—			—			40			40
Net income attributable to noncontrolling interests		—			23			—			—			23
Total expenses and other		955			233			143			22			1,353
Unrealized (gains) losses on derivatives, net included in marketing revenue		—			—			(3	)		—			(3	)
Adjusted EBITDAX	$	1,897		$	63		$	(25	)	$	(92	)	$	1,843

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

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

24

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14.  Segment Information (Continued)

millions	Oil and Gas Exploration & Production			Midstream			Marketing			Other and  Intersegment  Eliminations			Total
Nine Months Ended September 30, 2012
Sales revenues	$	5,180		$	248		$	4,467		$	—		$	9,895
Intersegment revenues		3,796			701			(4,101	)		(396	)		—
Gains (losses) on divestitures and other, net		(17	)		(8	)		—			131			106
Total revenues and other		8,959			941			366			(265	)		10,001
Operating costs and expenses (1)		2,639			545			464			132			3,780
Realized (gains) losses on commodity derivatives, net		—			—			—			(600	)		(600	)
Other (income) expense, net (2)		—			—			—			(14	)		(14	)
Net income attributable to noncontrolling interests		—			67			—			—			67
Total expenses and other		2,639			612			464			(482	)		3,233
Unrealized (gains) losses on derivatives, net included in marketing revenue		—			—			18			—			18
Adjusted EBITDAX	$	6,320		$	329		$	(80	)	$	217		$	6,786
Nine Months Ended September 30, 2011
Sales revenues	$	5,668		$	238		$	4,436		$	—		$	10,342
Intersegment revenues		3,699			684			(4,066	)		(317	)		—
Gains (losses) on divestitures and other, net		(307	)		(11	)		—			104			(214	)
Total revenues and other		9,060			911			370			(213	)		10,128
Operating costs and expenses (1)		2,717			575			414			163			3,869
Realized (gains) losses on commodity derivatives, net		—			—			—			(155	)		(155	)
Other (income) expense, net (2)		—			—			—			(2	)		(2	)
Net income attributable to noncontrolling interests		—			62			—			—			62
Total expenses and other		2,717			637			414			6			3,774
Unrealized (gains) losses on derivatives, net included in marketing revenue		—			—			(8	)		—			(8	)
Adjusted EBITDAX	$	6,343		$	274		$	(52	)	$	(219	)	$	6,346

⁽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.

25

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15.  Pension Plans and Other Postretirement Benefits

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

During the nine months ended September 30, 2012, the Company made contributions of $99 million to its funded pension plans, $4 million to its unfunded pension plans, and $14 million to its unfunded other postretirement benefit plans. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. During the remainder of 2012, the Company does not expect to make significant contributions to its funded pension plans, unfunded pension plans, or unfunded other postretirement benefit plans.

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

	Pension Benefits						Other Benefits
millions	2012			2011			2012		2011
Three Months Ended September 30
Service cost	$	19		$	20		$	2	$	3
Interest cost		21			21			4		4
Expected return on plan assets		(23	)		(21	)		—		—
Amortization of net actuarial loss (gain)		23			22			—		—
Net periodic benefit cost	$	40		$	42		$	6	$	7
Nine Months Ended September 30
Service cost	$	57		$	59		$	7	$	7
Interest cost		64			64			12		12
Expected return on plan assets		(68	)		(64	)		—		—
Amortization of net actuarial loss (gain)		69			64			—		—
Amortization of net prior service cost (credit)		—			1			1		—
Net periodic benefit cost	$	122		$	124		$	20	$	19

26

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 otherwise make in other public filings, press releases, and management discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by, or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events, or otherwise.

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

• the Company’s assumptions about the energy market;

• production levels;

• reserve levels;

• operating results;

• competitive conditions;

• technology;

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

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

• volatility in the commodity-futures market;

• the weather;

• inflation;

• the availability of goods and services;

• drilling risks;

• future processing volumes and pipeline throughput;

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

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

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

27

• the 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;

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

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

• civil or political unrest in a region or country;

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

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

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

• disruptions in international crude oil cargo shipping activities;

• electronic, cyber, and physical security breaches;

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

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

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this report in Part I, Item 1, the information set forth in Risk Factors under Part II, Item 1A as well as the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the 2011 Annual Report on Form 10-K, and the information set forth in the Risk Factors under Part I, Item 1A of the 2011 Annual Report on Form 10-K.

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, Indonesia, South Africa, and New Zealand.

28

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

Overall

• Anadarko’s third-quarter sales volumes totaled 739 thousand barrels of oil equivalent per day (MBOE/d), representing a 12% increase over the third quarter of 2011.

• The Company achieved third-quarter liquids sales volumes of 322 thousand barrels per day (MBbls/d), representing a 15% increase over the third quarter of 2011.

United States Onshore

• The Rocky Mountains Region (Rockies) achieved third-quarter sales volumes of 325 MBOE/d, representing a 7% increase over the third quarter of 2011, primarily due to increased sales volumes from the Wattenberg field and the Greater Natural Buttes area.

• The Southern and Appalachia Region achieved third-quarter sales volumes of 207 MBOE/d, representing a 44% increase over the third quarter of 2011, primarily due to increased sales volumes from the Marcellus, Eagleford, and Haynesville shales.

Gulf of Mexico

• Gulf of Mexico third-quarter sales volumes were 106 MBOE/d, representing a 12% decrease from the third quarter of 2011, primarily due to natural production declines and weather-related shut-ins.

• The Company closed a carried-interest arrangement that requires a third-party partner to fund approximately $556 million of Anadarko’s capital costs to earn a 7.2% working interest in the Lucius development.

International

• International third-quarter sales volumes were 91 MBOE/d, representing a 17% increase from the third quarter of 2011, primarily related to timing of cargo liftings in Ghana.

• Offshore Ghana, the Company successfully drilled the Wawa exploration well (18% working interest), encountering approximately 43 net feet of oil pay and 65 net feet of gas-condensate pay.

Financial

• The Company generated approximately $2.2 billion of cash flows from operations and ended the quarter with $2.5 billion of cash on hand.

• Anadarko’s net income attributable to common stockholders for the third quarter of 2012 totaled $121 million.

• The Company repaid $700 million of borrowings under its senior secured revolving credit facility ($5.0 billion Facility).

• Anadarko collected $501 million associated with the Algeria exceptional profits tax receivable.

29

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

RESULTS OF OPERATIONS

Selected Data

	Three Months Ended September 30,					Nine Months Ended September 30,
millions except per-share amounts	2012		2011			2012		2011
Financial Results
Revenues and other	$	3,332	$	3,199		$	10,001	$	10,128
Costs and expenses		2,516		6,825			6,762		11,857
Other (income) expense		426		870			220		1,262
Income tax expense (benefit)		248		(1,468	)		764		(762	)
Net income (loss) attributable to common stockholders	$	121	$	(3,051	)	$	2,188	$	(2,291	)
Net income (loss) per common share attributable to common stockholders—diluted	$	0.24	$	(6.12	)	$	4.34	$	(4.60	)
Average number of common shares outstanding—diluted		502		498			501		498
Operating Results
Adjusted EBITDAX (1)	$	2,301	$	1,843		$	6,786	$	6,346
Sales volumes (MMBOE)		68		61			200		185

MMBOE—millions of barrels of oil equivalent

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

FINANCIAL RESULTS

Net Income (Loss) Attributable to Common Stockholders    For the three months ended September 30, 2012, Anadarko’s net income attributable to common stockholders totaled $121 million, or $0.24 per share (diluted), compared to a net loss attributable to common stockholders of $3.1 billion, or $6.12 per share (diluted), for the three months ended September 30, 2011. For the nine months ended September 30, 2012, Anadarko’s net income attributable to common stockholders totaled $2.2 billion, or $4.34 per share (diluted), compared to a net loss attributable to common stockholders of $2.3 billion, or $4.60 per share (diluted), for the same period of 2011. As discussed more fully below, Anadarko’s net income for the nine months ended September 30, 2012, included $1.8 billion related to the favorable resolution of the Algeria exceptional profits tax dispute and $844 million of unproved property impairments. Anadarko’s net income for the three and nine months ended September 30, 2011, included the effects of the $4.0 billion settlement agreement, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement). 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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Sales Revenues and Volumes

	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
Sales Revenues
Natural-gas sales	$	613		(27)%	$	840	$	1,682		(34)%	$	2,564
Oil and condensate sales		2,163		14		1,905		6,629		11		5,948
Natural-gas liquids sales		289		(23)		377		913		(15)		1,080
Total	$	3,065		(2)	$	3,122	$	9,224		(4)	$	9,592

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

	Three Months Ended September 30,
millions	Natural Gas			Oil and Condensate		NGLs			Total
2011 sales revenues	$	840		$	1,905	$	377		$	3,122
Changes associated with sales volumes		84			258		69			411
Changes associated with prices		(311	)		—		(157	)		(468	)
2012 sales revenues	$	613		$	2,163	$	289		$	3,065
	Nine Months Ended September 30,
	Natural Gas			Oil and Condensate		NGLs			Total
2011 sales revenues	$	2,564		$	5,948	$	1,080		$	9,592
Changes associated with sales volumes		175			518		112			805
Changes associated with prices		(1,057	)		163		(279	)		(1,173	)
2012 sales revenues	$	1,682		$	6,629	$	913		$	9,224

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	Three Months Ended September 30,						Nine Months Ended September 30,
Sales Volumes	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
Barrels of Oil Equivalent
(MMBOE except percentages)
United States		60		11%		53		176		8%		162
International		8		17		8		24		4		23
Total		68		12		61		200		8		185
Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States		648		11%		582		642		8%		595
International		91		17		78		87		4		83
Total		739		12		660		729		8		678

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 Commodity Derivatives, net. Production of natural gas, crude oil, and NGLs usually is not affected by seasonal swings in demand.

Natural-Gas Sales Volumes, Average Prices, and Revenues

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
United States
Sales volumes—Bcf		231		10%		209		681		7%		638
MMcf/d		2,499		10		2,271		2,487		7		2,336
Price per Mcf	$	2.67		(34)	$	4.02	$	2.47		(39)	$	4.02
Natural-gas sales revenues (millions)	$	613		(27)	$	840	$	1,682		(34)	$	2,564

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

Mcf—thousand cubic feet

The Company’s natural-gas sales volumes increased 228 MMcf/d and 151 MMcf/d for the three and nine months ended September 30, 2012, respectively. These increases were due to higher sales volumes in the Southern and Appalachia Region of 253 MMcf/d and 200 MMcf/d, respectively, primarily as a result of drilling in the Marcellus, Eagleford, and Haynesville shales, and higher sales volumes in the Rockies of 85 MMcf/d and 72 MMcf/d, respectively, associated with drilling in the Greater Natural Buttes area and the Wattenberg field. These increases were partially offset by reduced sales volumes for the three and nine months ended September 30, 2012, in the Gulf of Mexico of 110 MMcf/d and 121 MMcf/d, respectively, primarily due to natural production declines and weather-related shut-ins.

The average natural-gas price Anadarko received decreased for the three and nine months ended September 30, 2012, as a result of above-average U.S. natural-gas storage levels during 2012.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
United States
Sales volumes—MMBbls		13		11%		12		40		12%		36
MBbls/d		143		11		129		146		12		132
Price per barrel	$	94.19		—	$	94.02	$	99.26		2	$	96.84
International
Sales volumes—MMBbls		8		17%		8		24		4%		23
MBbls/d		91		17		78		87		4		83
Price per barrel	$	108.94		(1)	$	109.69	$	111.75		3	$	108.47
Total
Sales volumes—MMBbls		21		13%		20		64		9%		59
MBbls/d		234		13		207		233		9		215
Price per barrel	$	99.93		—	$	99.92	$	103.90		3	$	101.35
Oil and condensate sales revenues (millions)	$	2,163		14	$	1,905	$	6,629		11	$	5,948

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s crude-oil and condensate sales volumes increased 27 MBbls/d and 18 MBbls/d for the three and nine months ended September 30, 2012, respectively. Increased horizontal drilling in the Wattenberg field led to sales-volume improvements in the Rockies of 8 MBbls/d and 7 MBbls/d for the three and nine months ended September 30, 2012, respectively. Horizontal drilling in the Eagleford shale and Bone Spring/Avalon formations also contributed to increased sales volumes in the Southern and Appalachia Region of 9 MBbls/d and 8 MBbls/d, for the three and nine months ended September 30, 2012, respectively. International sales volumes for the three and nine months ended September 30, 2012, increased 13 MBbls/d and 4 MBbls/d, respectively, primarily related to timing of cargo liftings in Ghana.

Anadarko’s average crude-oil price received for the three months ended September 30, 2012, was flat compared to 2011 prices. Anadarko’s average crude-oil price received increased slightly for the nine months ended September 30, 2012, primarily due to supply disruption concerns associated with political and civil unrest in the Middle East and Africa, which offset downward price pressure caused by macroeconomic concerns in Europe and China.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		Inc/(Dec)   vs. 2011	2011		2012		Inc/(Dec)   vs. 2011	2011
United States
Sales volumes—MMBbls		8	19%		7		22	10%		20
MBbls/d		88	19		74		81	10		74
Price per barrel	$	35.93	(35)	$	55.47	$	40.96	(23)	$	53.48
Natural-gas liquids sales revenues (millions)	$	289	(23)	$	377	$	913	(15)	$	1,080

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. For the three and nine months ended September 30, 2012, the Company’s NGLs sales volumes increased by 14 MBbls/d and 7 MBbls/d, respectively, as a result of drilling in liquids-rich areas, primarily in the Eagleford and Haynesville shales in the Southern and Appalachia Region.

The average NGLs price decreased for the three and nine months ended September 30, 2012, primarily due to lower market prices for ethane and propane. Ethane demand was reduced by down-time for maintenance and conversion upgrades at third-party facilities. Also, mild winter temperatures across much of the United States in 2011 reduced demand for propane and contributed to above-average levels of propane stockpiles. Lastly, increased production from continued liquids-rich development has created further downward pricing pressures for NGLs.

Gathering, Processing, and Marketing Margin

	Three Months Ended September 30,					Nine Months Ended September 30,
millions except percentages	2012		Inc/(Dec)   vs. 2011	2011		2012		Inc/(Dec)   vs. 2011	2011
Gathering, processing, and marketing sales	$	218	(17)%	$	262	$	671	(11)%	$	750
Gathering, processing, and marketing expenses		185	(14)		214		552	(6)		590
Margin	$	33	(31)	$	48	$	119	(26)	$	160

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

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Gains (Losses) on Divestitures and Other, net

For the three and nine months ended September 30, 2012, gains (losses) on divestitures and other, net increased $234 million and $320 million, respectively, primarily due to losses of $299 million recognized in the third quarter of 2011 associated with assets held for sale. These losses related to properties in the oil and gas exploration and production reporting segment and the other midstream reporting segment. Partially offsetting these losses were gains on divestitures for the three and nine months ended September 30, 2011, of $73 million and $76 million, respectively, related to oil and gas exploration and production reporting segment properties located in various international locations. Also, for the nine months ended September 30, 2011, gains (losses) on divestitures and other, net includes a $76 million loss recorded in the second quarter of 2011, which occurred in connection with the Company’s purchase of the Wattenberg Plant. This loss was associated with the effective elimination, for purposes of consolidated financial reporting, of a pre-existing third-party relationship between the Company and the previous owner of the plant related to natural-gas processing contracts. The loss represents the aggregate amount by which the Company’s contracts with the previous owner of the Wattenberg Plant were unfavorable as compared to current market transactions for the same or similar services at the date of the Company’s acquisition of the plant. This loss was partially offset by the recognition of a $21 million gain from the acquisition-date fair-value remeasurement of the Company’s pre-acquisition equity interest in the Wattenberg Plant.

Costs and Expenses

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
Oil and gas operating (millions)	$	241		(8)%	$	262	$	732		—%	$	730
Oil and gas operating—per BOE		3.55		(18)		4.32		3.67		(7)		3.94
Oil and gas transportation and other (millions)		247		14		217		710		12		633
Oil and gas transportation and other—per BOE		3.64		2		3.57		3.56		4		3.42

For the three months ended September 30, 2012, oil and gas operating expenses decreased by $21 million primarily due to lower expenses associated with workovers in the Gulf of Mexico and the Rockies. For the three months ended September 30, 2012, oil and gas operating expenses per barrel of oil equivalent (BOE) decreased by $0.77 primarily due to lower workover expenses discussed above, increased operating efficiencies, and increased sales volumes. For the nine months ended September 30, 2012, oil and gas operating expenses per BOE decreased by $0.27 primarily due to increased operating efficiencies and increased sales volumes.

For the three and nine months ended September 30, 2012, oil and gas transportation and other expenses increased by $30 million and $77 million, respectively, primarily due to higher gas gathering and transportation costs attributable to higher volumes and increased costs attributable to growth in the Company’s U.S. onshore asset base. The increase for the nine months ended September 30, 2012, was partially offset by a $25 million reversal of previously accrued rig termination fees for a deepwater drilling rig in the Gulf of Mexico. This expense reversal resulted from a dispute settlement with the drilling contractor. See Note 11—Contingencies—Deepwater Drilling Moratorium and Other Related Matters in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information. For the three and nine months ended September 30, 2012, oil and gas transportation and other expenses per BOE increased by $0.07 and $0.14, respectively, primarily due to the higher costs discussed above, partially offset by increased sales volumes.

35

	Three Months Ended September 30,				Nine Months Ended September 30,
millions	2012		2011		2012		2011
Exploration Expense
Dry hole expense	$	142	$	17	$	346	$	75
Impairments of unproved properties		60		179		1,043		348
Geological and geophysical expenses		40		52		89		152
Exploration overhead and other		55		59		184		147
Total exploration expense	$	297	$	307	$	1,662	$	722

Exploration expense decreased by $10 million for the three months ended September 30, 2012, primarily due to impairments of $129 million recognized during the third quarter of 2011 for unproved Gulf of Mexico properties. Exploration expense also decreased due to lower geological and geophysical expense of $12 million primarily due to 2011 seismic purchases in Kenya. These decreases for the three months ended September 30, 2012, were partially offset by higher dry hole expense of $125 million primarily in Brazil and Ghana.

Exploration expense increased by $940 million for the nine months ended September 30, 2012. During the second quarter of 2012, the Company recognized $844 million of impairments of certain unproved properties in the Rockies and the Gulf of Mexico, approximately $720 million of which was associated with Powder River coalbed methane properties in the Rockies primarily resulting from lower natural-gas prices, and the remaining $124 million was related to a Gulf of Mexico natural-gas property that the Company does not plan to pursue under the forecasted natural-gas price environment. During the third quarter of 2011, the Company recognized impairments of $129 million related to Gulf of Mexico properties. The remaining increase in exploration expense for the nine months ended September 30, 2012, was primarily due to higher dry hole expense of $271 million primarily in Brazil, Sierra Leone, Côte d’Ivoire, and the Gulf of Mexico, partially offset by lower geological and geophysical expense of $63 million primarily due to fewer seismic purchases in Kenya, Liberia, and Mozambique.

	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2012		Inc/(Dec) vs. 2011		2011		2012		Inc/(Dec) vs. 2011		2011
General and administrative	$	285		(3)%	$	293	$	816		4%	$	784
Depreciation, depletion, and amortization		979		5		932		2,936		1		2,902
Other taxes		267		(29)		375		970		(14)		1,132
Impairments		4		(98)		183		166		(42)		287

For the three months ended September 30, 2012, general and administrative (G&A) expense decreased by $8 million primarily due to lower consulting fees. For the nine months ended September 30, 2012, G&A expense increased $32 million primarily due to legal-related expenses of $66 million, partially offset by lower consulting fees of $21 million, which included $16 million incurred during the second quarter of 2011 related to the Maverick basin joint venture, and lower insurance costs of $14 million due to reduced premiums for directors and officers insurance in 2012.

For the three and nine months ended September 30, 2012, depreciation, depletion, and amortization (DD&A) expense increased by $47 million and $34 million, respectively, due to higher sales volumes, accelerated expense in 2012 associated with the depletion of fields in the Gulf of Mexico, and the start of production at Caesar/Tonga in March 2012, partially offset by lower per-barrel DD&A rates resulting from asset impairments recorded in the fourth quarter of 2011 and 2012 Eagleford shale reserves additions.

36

For the three and nine months ended September 30, 2012, other taxes decreased by $108 million and $162 million, respectively, primarily related to lower Algeria exceptional profits taxes of $45 million and $90 million, respectively, due to a lower Algeria effective tax rate resulting from the resolution of the Algeria exceptional profits tax dispute. Other taxes were also lower for the three and nine months ended September 30, 2012, due to decreased U.S. production and severance taxes of $39 million and $50 million, respectively, resulting from lower commodity prices, and lower Chinese windfall profits tax of $17 million and $18 million, respectively.

Impairment expense for the three and nine months ended September 30, 2012, was $4 million and $166 million, respectively. In the second quarter of 2012, due to lower natural-gas prices, the Company recognized impairments of $79 million related to certain U.S. onshore oil and gas exploration and production reporting segment properties and $4 million related to midstream reporting segment properties. The Company also recognized impairments of $50 million and $17 million during the first and second quarter of 2012, respectively, related to downward reserves revisions for a Gulf of Mexico property that was near the end of its economic life. Also in the second quarter of 2012, the Company recognized impairment expense of $11 million related to the Company’s Venezuelan cost-method investment due to declines in estimated recoverable reserves and lower crude-oil prices.

Impairment expense for the three and nine months ended September 30, 2011, was $183 million and $287 million, respectively. During the third quarter of 2011, the Company recognized impairments of $93 million related to Gulf of Mexico properties and $87 million related to the Company’s Venezuelan cost-method investment due to declines in estimated recoverable reserves in these areas. During the second quarter of 2011, the Company recognized impairments of $100 million related to U.S. onshore oil and gas exploration and production reporting segment properties due to a change in projected cash flows resulting from the Company’s intent to divest of the properties.

	Three Months Ended September 30,				Nine Months Ended September 30,
millions	2012		2011		2012			2011
Algeria exceptional profits tax settlement	$	7	$	—	$	(1,797	)	$	—
Deepwater Horizon settlement and related costs		4		4,042		15			4,077

In March 2012, the Company reached an agreement with Sonatrach to resolve the exceptional profits tax dispute. The agreement was approved by the Algerian government and provides for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period that began in June 2012. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income in the first quarter of 2012 to reflect the effect of this agreement on previously recorded expenses. During the nine months ended September 30, 2012, the Company collected $614 million associated with the Algeria exceptional profits tax receivable. The Company expects to collect approximately $400 million during the fourth quarter of 2012 and the balance of the Algeria exceptional profits tax receivable during the first half of 2013. Additionally, the parties agreed to an amendment to the existing Production Sharing Agreement (PSA) that provides the Company increased sales volumes and a lower effective exceptional profits tax rate in future periods. The amendment also confirms the duration for each exploitation license granted under the PSA will be 25 years from the date the license was awarded.

In October 2011, the Company and BP entered into the Settlement Agreement, pursuant to which the Company agreed to pay $4.0 billion in cash and transfer its interest in the Macondo well and the Mississippi Canyon Block 252 lease to BP, and BP agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices and to forgo reimbursement for all future costs arising from the Deepwater Horizon events, including future costs under the operating agreement. The Company recorded a $4.0 billion expense for the settlement during the third quarter of 2011. 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          September 30,								Nine Months Ended       September 30,
millions except percentages	2012			Inc/(Dec) vs. 2011		2011			2012			Inc/(Dec) vs. 2011		2011
Interest Expense
Current debt, long-term debt, and other	$	238			(3)%	$	245		$	724			(3)%	$	743
Capitalized interest		(53	)		(36)		(39	)		(163	)		(61)		(101	)
Total interest expense	$	185			(10)	$	206		$	561			(13)	$	642

For the three and nine months ended September 30, 2012, interest expense decreased by $21 million and $81 million, respectively. This decrease was primarily due to an increase in capitalized interest of $14 million and $62 million, respectively, related to higher construction-in-progress balances for long-term capital projects. Additionally, interest expense for the three and nine months ended September 30, 2012, decreased $9 million and $26 million, respectively, as a result of interest incurred during 2011 related to the Company’s capital lease obligation for a floating production, storage, and offloading vessel for the Jubilee field operations in Ghana. In December 2011, the Company and its partners in the Jubilee project purchased the vessel, resulting in cancellation of the capital lease obligation. Interest expense for the three and nine months ended September 30, 2012, also decreased $4 million and $19 million, respectively, due to lower fees on issued letters of credit and lower commitment fees related to the $5.0 billion Facility. These items were partially offset by interest expense of $7 million and $28 million related to borrowings under the $5.0 billion Facility for the three and nine months ended September 30, 2012, respectively. For additional information regarding the Company’s financing activities, see Liquidity and Capital Resources.

	Three Months Ended September 30,						Nine Months Ended September 30,
millions	2012			2011			2012			2011
(Gains) Losses on Commodity Derivatives, net
Realized (gains) losses
Natural gas	$	(170	)	$	(72	)	$	(564	)	$	(215	)
Oil and condensate		(27	)		—			(30	)		59
Natural gas liquids		(3	)		1			(6	)		1
Total realized (gains) losses		(200	)		(71	)		(600	)		(155	)
Unrealized (gains) losses
Natural gas		262			(7)			464			54
Oil and condensate		164			(133)			(77	)		(197	)
Natural gas liquids		11			(19)			(18	)		(19	)
Total unrealized (gains) losses		437			(159)			369			(162	)
Total (gains) losses on commodity derivatives, net	$	237		$	(230)		$	(231	)	$	(317	)

The Company enters into commodity derivatives to manage the risk of a decrease in the market prices for its anticipated sales of production. The change in (gains) losses on commodity derivatives, net includes the impact of changes in fair value of open positions at September 30 of each year and changes in fair value of derivatives entered into or settled within each period. For additional information on (gains) losses on commodity derivatives, see Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

38

	Three Months Ended September 30,				Nine Months Ended September 30,
millions	2012		2011		2012		2011
(Gains) Losses on Other Derivatives, net
Realized (gains) losses—interest-rate derivatives and other	$	—	$	—	$	2	$	2
Unrealized (gains) losses—interest-rate derivatives and other		14		854		152		937
Total (gains) losses on other derivatives, net	$	14	$	854	$	154	$	939

Anadarko enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to interest-rate changes. The fair value of the Company’s interest-rate swap portfolio increases (decreases) when interest rates increase (decrease). During the third quarter of 2012, the Company extended the swap maturity dates for interest-rate swaps with an aggregate notional principal amount of $800 million from October 2012 to September 2016. In connection with these extensions, the swap interest rates were also adjusted. In October 2012, the Company settled interest rate swaps with a notional amount of $200 million, which will result in a realized fourth-quarter loss of $64 million. For additional information, see Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

	Three Months Ended September 30,								Nine Months Ended September 30,
millions except percentages	2012			Inc/(Dec) vs. 2011		2011			2012			Inc/(Dec) vs. 2011		2011
Other (Income) Expense, net
Interest income	$	(10	)		150%	$	(4	)	$	(14	)		(13)%	$	(16	)
Other		—			100		44			(250	)		NM		14
Total other (income) expense, net	$	(10	)		125	$	40		$	(264	)		NM	$	(2	)

NM—percentage change does not provide

meaningful information

For the three months ended September 30, 2012, total other income increased by $50 million primarily due to changes in foreign currency gains/losses of $43 million. These gains/losses reflect the impact of exchange-rate changes primarily applicable to foreign currency purchased in anticipation of funding future capital expenditures on major international development projects, as well as foreign currency held in escrow pending final determination of the Company’s Brazilian tax liability attributable to the 2008 divestiture of the Peregrino field offshore Brazil. For the nine months ended September 30, 2012, total other income increased by $262 million, primarily due to the reversal of the Tronox-related contingent loss (see Note 11—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q) and $4 million related to changes in foreign currency gains/losses.

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Income Tax Expense

	Three Months  Ended September 30,					Nine Months Ended September 30,
millions except percentages	2012		2011			2012		2011
Income tax expense (benefit)	$	248	$	(1,468	)	$	764	$	(762	)
Effective tax rate		64%		33%			25%		25%

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

• foreign tax rate differentials and valuation allowances;

• Algerian exceptional profits taxes; and

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

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

• foreign tax rate differentials and valuation allowances;

• Algerian exceptional profits taxes; and

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

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

• Algerian exceptional profits taxes;

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

• foreign tax rate differentials and valuation allowances.

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

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

Net Income Attributable to Noncontrolling Interests

For the three and nine months ended September 30, 2012, the Company’s net income attributable to noncontrolling interests of $21 million and $67 million, respectively, primarily related to a 56.6% public ownership interest in Western Gas Partners, LP (WES) at September 30, 2012. For the three and nine months ended September 30, 2011, the Company’s net income attributable to noncontrolling interests of $23 million and $62 million, respectively, primarily related to a 54.7% public ownership interest in WES at September 30, 2011.

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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 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 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 September 30,								Nine Months Ended September 30,
millions except percentages	2012			Inc/(Dec) vs. 2011		2011			2012			Inc/(Dec) vs. 2011		2011
Income (loss) before income taxes	$	390			109 %	$	(4,496	)	$	3,019			NM	$	(2,991	)
Exploration expense		297			(3)		307			1,662			130%		722
DD&A		979			5		932			2,936			1		2,902
Impairments		4			(98)		183			166			(42)		287
Deepwater Horizon settlement and related costs		4			(100)		4,042			15			(100)		4,077
Algeria exceptional profits tax settlement (1)		7			NM		—			(1,797	)		NM		—
Tronox-related contingent loss (1)		—			—		—			(250	)		NM		—
Interest expense		185			(10)		206			561			(13)		642
Unrealized (gains) losses on derivatives, net		456			(34)		692			539			(30)		767
Realized (gains) losses on other derivatives, net (1)		—			—		—			2			—		2
Less: Net income attributable to noncontrolling interests		21			(9)		23			67			8		62
Consolidated Adjusted EBITDAX	$	2,301			25	$	1,843		$	6,786			7	$	6,346
Adjusted EBITDAX by reporting segment
Oil and gas exploration and production	$	2,152			13%	$	1,897		$	6,320			—%	$	6,343
Midstream		103			63		63			329			20		274
Marketing		(19	)		24		(25	)		(80	)		(54)		(52	)
Other and intersegment eliminations		65			171		(92	)		217			199		(219	)

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

Oil and Gas Exploration and Production  Adjusted EBITDAX for the three months ended September 30, 2012, increased primarily due to higher sales volumes, lower other taxes that decreased as a result of lower natural-gas and NGLs prices, and losses incurred in the third quarter of 2011 related to oil and gas assets held for sale. These increases were partially offset by lower natural-gas and NGLs prices. Adjusted EBITDAX for the nine months ended September 30, 2012, decreased primarily due to lower NGLs and natural-gas prices, partially offset by higher sales volumes, higher crude-oil prices, losses incurred in the third quarter of 2011 related to oil and gas assets held for sale, and a $76 million loss recorded in the second quarter of 2011, which occurred in connection with the Company’s purchase of the Wattenberg Plant. This loss was associated with the effective elimination, for purposes of consolidated financial reporting, of a pre-existing third-party relationship between the Company and the previous owner of the plant related to natural-gas processing contracts.

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

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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 September 30, 2012, Adjusted EBITDAX increased primarily due to higher marketing margins on sales from inventory as a result of higher volumes. For the nine months ended September 30, 2012, Adjusted EBITDAX decreased primarily due to lower marketing margins on sales from inventory as a result of lower prices and volumes.

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

LIQUIDITY AND CAPITAL RESOURCES

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

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

During 2012, Moody’s Investors Service returned the Company’s senior unsecured rating to investment grade. As a result, the Company was able to terminate the LOC Facility (discussed below) and all cash that secured financial trades has been returned to the Company.

During the nine months ended September 30, 2012, the Company repaid $1.5 billion of borrowings under the Company’s $5.0 billion Facility with cash on hand. At September 30, 2012, the Company had outstanding borrowings of $1.0 billion at an interest rate of 1.72% under the $5.0 billion Facility. These borrowings were used to fund a portion of the Company’s 2011 Settlement Agreement with BP. The Company intends to repay these borrowings with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute.

At September 30, 2012, Anadarko’s remaining 2012 debt maturities were $39 million. This amount was repaid in October 2012, with no scheduled debt maturities for 2013. The Company intends to repay the $1.0 billion of outstanding borrowings under the $5.0 billion Facility within the next year. These borrowings have been classified, along with the scheduled debt maturities, as current portion of long-term debt on the Company’s Consolidated Balance Sheet at September 30, 2012. The holder of the Zero-Coupon Senior Notes due 2036 (Zero Coupons) has the right to cause the Company to repay up to the then-accreted value of outstanding Zero Coupons in October of each year. The holder did not elect to put any of the accreted balance of the Zero Coupons to the Company in October 2012. The accreted value of the Zero Coupons was $665 million at September 30, 2012, and will be $718 million at October 2013 (the next potential put date).

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

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Revolving Credit Facility and Letter of Credit Facility  Obligations incurred under the $5.0 billion Facility, as well as obligations Anadarko has to lenders or their affiliates pursuant to certain derivative instruments that are supported by the $5.0 billion Facility, as discussed in Note 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. The Company was in compliance with all applicable covenants contained in the $5.0 billion Facility and had available borrowing capacity of $4.0 billion at September 30, 2012 ($5.0 billion maximum capacity less $1.0 billion of outstanding borrowings).

In 2011, the Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit (LOC Facility). In the third quarter of 2012, the Company terminated the LOC Facility.

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

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

Sources of Cash

Operating Activities  Anadarko’s cash flows from operating activities during the nine months ended September 30, 2012, was $6.1 billion, compared to $4.6 billion for the same period of 2011. Cash flows for 2012 increased primarily due to higher average crude-oil prices, higher sales volumes, and cash collected associated with the Algeria exceptional profits tax receivable, but were partially offset by lower average NGLs and natural-gas prices.

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

Investing Activities  During the nine months ended September 30, 2012, Anadarko received pretax proceeds of $440 million related to several property divestiture transactions.

Financing Activities  During the nine months ended September 30, 2012, Anadarko’s consolidated subsidiary, WES, borrowed $374 million under its RCF, primarily to fund the acquisition of certain midstream assets from Anadarko. In June 2012, WES completed a public offering of $520 million aggregate principal amount of 4.00% Senior Notes due 2022. Also in June 2012, WES issued five million common units to the public, raising net proceeds of $212 million. Proceeds from these public offerings were used to repay outstanding RCF borrowings and for other general partnership purposes, including the funding of capital expenditures. In October 2012, WES issued an additional $150 million of 4.00% Senior Notes due 2022. Net proceeds from the offering are expected to be used for general partnership purposes.

Uses of Cash

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

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

	Nine Months Ended September 30,
millions	2012		2011
Property acquisition—exploration	$	138	$	387
Exploration		1,193		581
Development		2,835		2,284
Capitalized interest		163		101
Total oil and gas capital expenditures		4,329		3,353
Gathering, processing, and marketing and other (1)		1,049		1,258
Total capital expenditures (2)	$	5,378	$	4,611

⁽¹⁾  Includes WES capital expenditures of $360 million and $383 million for the nine months ended September 30, 2012 and 2011, respectively.

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

The Company’s capital spending increased 17% for the nine months ended September 30, 2012, primarily due to increased exploration drilling onshore and offshore United States, and in East and West Africa; increased development drilling onshore United States; construction costs related to the development of the Lucius project located in the Gulf of Mexico; and higher expenditures for domestic onshore plants and gathering systems. These increases were partially offset by lower property acquisition costs, primarily onshore United States, and midstream asset acquisitions in 2011. In May 2011, Anadarko increased its ownership interest in the Wattenberg Plant to 100% by acquiring an additional 93% interest for $576 million. Also, during the first quarter of 2011, WES acquired a third-party processing plant and related gathering systems located in the Rocky Mountains area for $302 million.

Pension Contributions  During the nine months ended September 30, 2012, the Company made contributions of $99 million to its funded pension plans, $4 million to its unfunded pension plans, and $14 million to its unfunded other postretirement benefit plans. During the remainder of 2012, the Company does not expect to make significant contributions to its funded pension plans, unfunded pension plans, or unfunded other postretirement benefit plans.

Debt Retirements and Repayments  During the nine months ended September 30, 2012, the Company used cash on hand to repay $1.5 billion of borrowings under its $5.0 billion Facility and retire $131 million of 6.125% Senior Notes that matured in March 2012. In addition, WES repaid $374 million of borrowings under its RCF.

Common Stock Dividends and Distributions to WES Noncontrolling Interest Owners  During the nine months ended September 30, 2012 and 2011, Anadarko paid $136 million in dividends to its common stockholders (nine cents per share in each quarterly period). Anadarko has paid a dividend to its common stockholders on a quarterly basis since becoming an independent public company in 1986. The amount of future dividends paid to Anadarko common stockholders will be determined by the Board of Directors on a quarterly basis and will depend on the Company’s earnings, financial condition, capital requirements, the effect a dividend payment would have on its compliance with its financial covenants, and other factors.

WES distributed to its unitholders, other than Anadarko, an aggregate of $72 million and $51 million during the nine months ended September 30, 2012 and 2011, respectively. WES has made quarterly distributions to its unitholders since its initial public offering in the second quarter of 2008, and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.50 per common unit for the third quarter of 2012 (to be paid in November 2012).

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Outlook

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

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

The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule, and evaluates available funding alternatives in light of current and expected conditions. In order to reduce commodity-price risk and increase the predictability of 2012 cash flows, Anadarko entered into strategic derivative positions, which cover approximately 42% and 53% of its remaining 2012 anticipated natural-gas and crude-oil sales volumes, respectively. In addition, the Company has derivative positions in place for 2013. See Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

In the third quarter of 2012, the Company entered into a carried-interest arrangement that requires a third-party partner to fund approximately $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 third party will fund 100% of Anadarko’s future capital costs in the development until the carry balance is fully funded, which is expected to occur by year-end 2014. At September 30, 2012, $112 million of the total $556 million obligation had been funded.

In the first quarter of 2011, the Company entered into a carried-interest arrangement that requires a third-party partner to fund approximately $1.6 billion of Anadarko’s future capital costs in the Eagleford shale, located in southwest Texas, to earn a one-third interest in Anadarko’s Eagleford shale assets. The third party will fund 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 September 30, 2012, $1.0 billion of the total $1.6 billion obligation had been funded.

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

Obligations and Commitments

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

Midstream and Marketing Activities  In 2012, the Company entered into contractual agreements for processing, transportation, and storage of natural gas, crude oil, and NGLs. These obligations total approximately $2.0 billion, with aggregate future payments of $17 million in 2012, $173 million in 2013, $228 million in 2014, $227 million in 2015, $225 million in 2016, and $1.1 billion thereafter.

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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 421 Bcf of natural gas and 33 MMBbls of crude oil at September 30, 2012, with a net derivative asset position of $259 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $426 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $428 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of crude-oil and natural-gas production volumes.

Derivative Instruments Held for Trading Purposes  The Company had a net derivative asset position of $16 million (unrealized gains of $39 million and unrealized losses of $23 million) on derivative instruments entered into for trading purposes at September 30, 2012. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would not materially impact the Company’s gains or losses on these derivative instruments.

Algerian Settlement Volumes  Volumes received by Anadarko in connection with the resolution of the Algeria exceptional profits tax dispute will be valued at month-average dated Brent price plus a Saharan Blend quality differential. See Note 11—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information. Generally, the market in this region is priced over a five-day period related to the bill of lading date. To the extent the Company’s realized sales price is greater than or less than the settlement value, the Company records a gain or a loss in the period of sale, which is included in gains (losses) on divestitures and other, net on the Consolidated Statements of Income.

INTEREST-RATE RISK  The Company’s $1.0 billion of borrowings under its $5.0 billion Facility are subject to variable interest rates. The balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheet is subject to fixed interest rates. The Company’s $2.9 billion of LIBOR-based obligations, which are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two non-controlled entities, give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. A 10% increase in LIBOR would not materially impact the Company’s interest cost on outstanding debt, but would affect fair value of outstanding debt.

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At September 30, 2012, the Company had a net derivative liability position of $1.4 billion related to interest-rate swaps. A 10% increase or decrease in interest rates would increase or decrease, respectively, the aggregate fair value of outstanding interest-rate swap agreements by approximately $109 million. However, any change in the interest-rate derivative gain or loss would be substantially offset by an increase or decrease, respectively, in borrowing costs associated with any future debt issuances. For a summary of the Company’s open interest-rate derivative positions, see Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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

With respect to international oil and gas development projects, Anadarko is a party to contracts with commitments extending through November 2012 that are impacted by euro-to-U.S. dollar exchange rates. The Company also has exposure related to exchange-rate changes applicable to cash held in escrow of $168 million as of September 30, 2012, pending final determination of the Company’s Brazilian tax liability attributable to its 2008 divestiture of the Peregrino field offshore Brazil.

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

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PART II.    OTHER INFORMATION

Item 1.  Legal Proceedings

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

See Note 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, 2011.

Item 1A.  Risk Factors

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

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

In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance. Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee and seeks, among other things, to recover damages, including interest, in excess of $18.9 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. For a description of the updates to this litigation since the description thereof included in Note 16—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements included in Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, see Note 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 third quarter of 2012.

Period	Total number of shares  purchased(1)		Average   price paid   per share		Total number  of shares purchased   as part of publicly   announced plans or programs		Approximate dollar value of shares that may yet be   purchased under the   plans or programs
July 1-31		1,064	$	65.89		—
August 1-31		39,831	$	69.26		—
September 1-30		650	$	70.50		—
Third-Quarter 2012		41,545	$	69.19		—	$	—

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

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Item 6.  Exhibits

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

Exhibit         Number	Description	Original Filed         Exhibit	File   Number
3 (i)	Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 22, 2009	3.3 to Form 8-K filed on May 22, 2009	1-8968
(ii)	By-Laws of Anadarko Petroleum Corporation, amended and restated as of May 15, 2012	3.1 to Form 8-K filed on May 15, 2012	1-8968
*   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
October 29, 2012	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Senior Vice President, Finance and Chief Financial Officer

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