Edgar Filing: ANADARKO PETROLEUM CORP

ANADARKO PETROLEUM CORP 3RD QTR 2010 FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2010

[ ] 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, 2010 is shown below:


Title of Class		Number of Shares Outstanding

Common Stock, par value $0.10 per share		495,592,465

TABLE OF CONTENTS


PART I.		Page

Item 1.	Financial Statements

	Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2010 and 2009	3

	Consolidated Balance Sheets as of September 30, 2010, and December 31, 2009	4

	Consolidated Statement of Equity for the Nine Months Ended September 30, 2010	5

	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2010 and 2009	6

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43

	Financial Results	46

	Operating Results	56

	Liquidity and Capital Resources	57

	Regulatory Matters, Environmental and Additional Factors Affecting Business	64

	Critical Accounting Estimates	67

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	68

Item 4.	Controls and Procedures	70

PART II.

Item 1.	Legal Proceedings	71

Item 1A.	Risk Factors	74

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	80

Item 6.	Exhibits	81

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	2010		2009		2010		2009
Revenues and Other
Gas sales	$	809	$	614	$	2,692	$	2,148
Oil and condensate sales		1,298		1,218		4,138		2,768
Natural-gas liquids sales		227		166		736		365
Gathering, processing and marketing sales		182		169		643		531
Gains (losses) on divestitures and other, net		34		50		84		114
Reversal of accrual for DWRRA dispute (Note 12)		—		657		—		657

Total		2,550		2,874		8,293		6,583

Costs and Expenses
Oil and gas operating		207		201		590		660
Oil and gas transportation and other		220		169		607		527
Exploration		296		224		649		813
Gathering, processing and marketing		134		151		466		469
General and administrative		275		223		688		658
Depreciation, depletion and amortization		962		909		2,845		2,648
Other taxes		240		213		809		543
Impairments		20		5		147		79

Total		2,354		2,095		6,801		6,397

Operating Income (Loss)		196		779		1,492		186
Other (Income) Expense
Interest expense		218		121		642		504
(Gains) losses on commodity derivatives, net		(200)		134		(1,052)		503
(Gains) losses on other derivatives, net		221		131		656		(315)
Other (income) expense, net		(129)		(20)		(106)		(23)

Total		110		366		140		669

Income (Loss) Before Income Taxes		86		413		1,352		(483)
Income Tax Expense (Benefit)		94		207		660		(142)

Net Income (Loss)		(8)		206		692		(341)
Net Income Attributable to Noncontrolling Interests		18		6		42		23

Net Income (Loss) Attributable to Common Stockholders	$	(26)	$	200	$	650	$	(364)

Per Common Share:
Net income (loss) attributable to common stockholders - basic	$	(0.05)	$	0.40	$	1.30	$	(0.77)
Net income (loss) attributable to common stockholders - diluted	$	(0.05)	$	0.40	$	1.30	$	(0.77)
Average Number of Common Shares Outstanding - Basic		496		491		495		476

Average Number of Common Shares Outstanding - Diluted		496		493		496		476

Dividends (per Common Share)	$	0.09	$	0.09	$	0.27	$	0.27

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)


millions	September 30, 2010		December 31, 2009
ASSETS
Current Assets
Cash and cash equivalents	$	4,218	$	3,531
Accounts receivable, net of allowance:
Customers		848		1,019
Others		1,221		1,033
Other current assets		793		500

Total		7,080		6,083

Properties and Equipment
Cost		53,710		50,344
Less accumulated depreciation, depletion and amortization		15,999		13,140

Net properties and equipment		37,711		37,204
Other Assets		1,723		1,514
Goodwill and Other Intangible Assets		5,312		5,322

Total Assets	$	51,826	$	50,123

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	2,904	$	2,876
Accrued expenses		1,082		948
Current portion of long-term debt		718		—

Total		4,704		3,824

Long-term Debt		12,753		11,149
Midstream Subsidiary Note Payable to a Related Party		—		1,599
Other Long-term Liabilities
Deferred income taxes		9,820		9,925
Other		3,405		3,211

Total		13,225		13,136

Equity
Stockholders’ Equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 508.6 million and 505.0 million shares issued as of September 30, 2010, and December 31, 2009, respectively)		51		50
Paid-in capital		7,445		7,243
Retained earnings		14,382		13,868
Treasury stock (13.0 million and 12.4 million shares as of September 30, 2010, and December 31, 2009, respectively)		(756)		(721)
Accumulated other comprehensive income (loss)		(493)		(512)

Total Stockholders’ Equity		20,629		19,928
Noncontrolling Interests		515		487

Total Equity		21,144		20,415

Commitments and Contingencies (Note 2, Note 3 and Note 12)

Total Liabilities and Equity	$	51,826	$	50,123

See accompanying notes to consolidated financial statements.

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)		Total Stockholders’ Equity		Noncontrolling Interests		Total Equity
millions
Balance at December 31, 2009	$	50	$	7,243	$	13,868	$	(721)	$	(512)	$	19,928	$	487	$	20,415
Net income (loss)		—		—		650		—		—		650		42		692
Common stock issued		1		202		—		—		—		203		—		203
Dividends		—		—		(136)		—		—		(136)		—		(136)
Repurchase of common stock		—		—		—		(35)		—		(35)		—		(35)
Sale of subsidiary units		—		—		—		—		—		—		97		97
Distributions to noncontrolling interest owners and other, net		—		—		—		—		—		—		(111)		(111)
Previously deferred losses on derivative instruments		—		—		—		—		13		13		—		13
Pension and other postretirement plans adjustments		—		—		—		—		6		6		—		6

Balance at September 30, 2010	$	51	$	7,445	$	14,382	$	(756)	$	(493)	$	20,629	$	515	$	21,144

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
millions	2010		2009		2010		2009
Net Income (Loss)	$	(8)	$	206	$	692	$	(341)

Other Comprehensive Income (Loss), net of taxes
Previously deferred losses on derivative instruments⁽¹⁾		5		5		13		17
Foreign currency translation adjustments		—		1		—		1
Pension and other postretirement plans adjustments:
Net gain (loss) incurred during period⁽²⁾		—		—		(21)		—
Prior service credit (cost) incurred during period⁽³⁾		—		—		(4)		—
Amortization of net actuarial loss and prior service cost to net periodic benefit cost⁽⁴⁾		9		8		31		28


Total		14		14		19		46


Comprehensive Income (Loss)		6		220		711		(295)

Comprehensive Income Attributable to Noncontrolling Interests		18		6		42		23


Comprehensive Income (Loss) Attributable to Common Stockholders	$	(12)	$	214	$	669	$	(318)

⁽¹⁾	Net of income tax benefit (expense) of $(2) million and $(3) million for the three months ended September 30, 2010 and 2009, respectively, and $(7) million and $(9) million for the nine months ended September 30, 2010 and 2009, respectively.

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

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

⁽⁴⁾	Net of income tax benefit (expense) of $(5) million and $(4) million for the three months ended September 30, 2010 and 2009, respectively, and $(17) million and $(16) million for the nine months ended September 30, 2010 and 2009, respectively.

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
millions	2010		2009
Cash Flow from Operating Activities
Net income (loss)	$	692	$	(341)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		2,845		2,648
Deferred income taxes		(142)		(8)
Dry hole expense and impairments of unproved properties		473		608
Impairments		147		79
(Gains) losses on divestitures, net		(12)		(44)
Unrealized (gains) losses on derivatives		(66)		1,073
Reversal of accrual for DWRRA dispute (Note 12)		—		(657)
Other		145		131
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		15		(139)
Increase (decrease) in accounts payable and accrued expenses		(291)		(180)
Other items - net		126		(344)

Net cash provided by (used in) operating activities		3,932		2,826

Cash Flow from Investing Activities
Additions to properties and equipment and dry hole costs		(3,563)		(2,934)
Divestitures of properties and equipment and other assets		44		113
Other - net		(30)		(107)

Net cash provided by (used in) investing activities		(3,549)		(2,928)

Cash Flow from Financing Activities
Borrowings, net of issuance costs		3,199		1,975
Retirements of debt		(1,173)		(1,470)
Retirement / repayment of midstream subsidiary note payable to a related party		(1,599)		(100)
Increase (decrease) in accounts payable, banks		(70)		(270)
Dividends paid		(136)		(131)
Repurchase of common stock		(35)		(17)
Issuance of common stock, including tax benefit on stock option exercises		90		1,360
Sale of subsidiary units		97		—
Distributions to noncontrolling interest owners		(36)		(22)
Contributions from noncontrolling interest owners		—		3
Other financing activities		(24)		—

Net cash provided by (used in) financing activities		313		1,328

Effect of Exchange Rate Changes on Cash		(9)		—

Net Increase (Decrease) in Cash and Cash Equivalents		687		1,226
Cash and Cash Equivalents at Beginning of Period		3,531		2,360

Cash and Cash Equivalents at End of Period	$	4,218	$	3,586

See accompanying notes to consolidated financial statements.

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). The Company also engages in the gathering, processing and treating of natural gas, and transporting 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. The terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

The accompanying financial statements and notes should be read in conjunction with the Company’s 2009 Annual Report on Form 10-K.

Basis of Presentation The information, as 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, 2010, and December 31, 2009, the Consolidated Statements of Income and Comprehensive Income for the three and nine months ended September 30, 2010 and 2009, the Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009, and the Consolidated Statement of Equity for the nine months ended September 30, 2010. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

In the fourth quarter of 2009, the Company changed the manner in which gains and losses on commodity derivatives, used to economically hedge production, are presented within the Consolidated Statements of Income to provide enhanced transparency into asset operating performance. Prior to this change, all realized and unrealized gains and losses on commodity derivatives were reported in gas sales, oil and condensate sales or NGLs sales. Gains and losses on commodity derivatives are now presented as a separate line item on the Consolidated Statements of Income. Prior periods have been reclassified to conform to this presentation. See Note 9 for disclosures regarding derivative instruments.

In preparing financial statements in accordance with accounting principles generally accepted in the United States, management makes informed judgments and estimates that affect both the reported amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Management reviews its estimates periodically, including those related to the carrying value of properties and equipment, proved reserves, goodwill, intangible assets, asset retirement obligations, litigation reserves, environmental liabilities, pension 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.

Environmental Contingencies Except for environmental contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. See Note 2 and Note 12.

Legal Contingencies The Company is subject to legal proceedings, claims and liabilities that arise in the ordinary course of its business. Except for legal contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with legal claims when such losses are probable and reasonably estimable. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 2, Note 3 and Note 12.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

Changes in Accounting Principles Effective January 1, 2010, the Company adopted revised oil and gas reserve estimation standards. These standards allow the use of reliable technology in determining estimates of proved reserve quantities and require the use of a 12-month first-day-of-the-month average price to estimate proved reserves. Adoption of these new standards did not have a material impact on depreciation, depletion and amortization expense.

The Company also adopted amendments to consolidation guidance applicable to variable interest entities, effective January 1, 2010. The revised guidance did not have an impact on the Company’s consolidated financial statements.

2. Deepwater Horizon Events

Background In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. Response and clean-up efforts are being conducted by BP Exploration & Production Inc. (BP), the operator and 65% owner of the well, and by other parties, all under the direction of the Unified Command of the United States Coast Guard (the Unified Command or USCG). On July 15, 2010, after several attempts to contain the oil spill, BP successfully installed a capping stack that shut in the well and prevented the further release of hydrocarbons. Installation of the capping stack was a temporary solution that was followed by a successful “static kill” cementing operation completed on August 5, 2010. The Macondo well was permanently plugged on September 19, 2010, when BP completed a “bottom kill” cementing operation in connection with the successful interception of the well by a relief well. Investigations by the federal government and other parties into the cause of the well blowout, explosion, and resulting oil spill, as well as other matters arising from or relating to these events, are ongoing.

Based on information provided by BP to the Company, BP has incurred costs of approximately $12.1 billion (including costs associated with USCG invoices totaling $518 million) through September 30, 2010, related to spill response and containment, relief-well drilling, grants to certain Gulf Coast states for clean-up costs, local tourism promotion, monetary damage claims and federal costs. In addition, BP has incurred more than $3.0 billion of costs since September 30, 2010.

BP, Anadarko and other parties, including parties that do not own an interest in the Macondo well, such as the drilling contractor, have been notified by the USCG of their status as a “responsible party or guarantor” (RP) under the Oil Pollution Act of 1990 (OPA). Under OPA, RPs may be held jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims directly related to the spill and spill cleanup. The USCG has directly billed the RPs for reimbursement of spill-related response costs incurred by the USCG and other federal and state agencies. The RPs have each received identical invoices for total costs, without specification or stipulation of any allocation of costs between or among the RPs. To date, as operator, BP has paid all USCG invoices, thereby satisfying the joint and several obligation of the RPs to the USCG for these costs. BP has also publicly indicated its intention to continue to pay 100% of all costs associated with clean-up efforts, claims and reimbursements related to the Deepwater Horizon events.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

The following analysis applies relevant accounting guidance to the Deepwater Horizon events to determine the Company’s liability accrual as of September 30, 2010. The process for quantifying the Company’s Deepwater Horizon event-related liability accrual involves the identification of all potential costs and the grouping of these costs in a manner that enables the Company to apply relevant accounting guidance to each cost based upon the qualitative characteristics of such costs. This is appropriate because satisfaction of liability-recognition criteria may vary depending upon the type of costs being analyzed. For example and as discussed more fully below, contingent contractual liabilities (such as those arising under the JOA) and contingent environmental liabilities (such as those arising under OPA) are subject to substantially similar liability-recognition criteria; however, circumstances under which such criteria are considered satisfied are different.

As discussed and analyzed below, after applying the relevant accounting guidance to the Company’s Deepwater Horizon event-related contingent liabilities, the Company’s aggregate liability accrual for these amounts is zero as of September 30, 2010. The zero accrual is not intended to represent an opinion of the Company that it will not incur any future liability related to the Deepwater Horizon events. Rather, the zero accrual is based on currently available facts and the application of accounting rules to this set of facts where the relevant accounting rules do not allow for loss recognition in situations where a loss is not considered probable or cannot be reasonably estimated.

In quantifying its potential Deepwater Horizon event-related liabilities, the Company has made certain assumptions regarding facts that are the subject of continuing investigations, the duration and extent of ongoing clean-up activities, and current and potential future damage claims. Thus, the Company’s zero liability accrual for the Deepwater Horizon events is subject to change in the future, perhaps materially. Below is a discussion of the Company’s current analysis, under applicable accounting guidance, of its potential liability for (i) amounts invoiced by BP under the JOA, (ii) OPA-related environmental liabilities, and (iii) other contingent liabilities.

JOA Contingent Liabilities JOA contingent liabilities relate to Anadarko’s potential responsibility for a 25% share of costs incurred by BP through September 30, 2010, for which BP has sought reimbursement from Anadarko under the JOA. Accounting standards require the Company to accrue contingent liabilities arising under the terms of the JOA if it is both “probable” that a liability has been incurred and the amount of the liability can be reasonably estimated.

With respect to the operator’s duties and liabilities, the JOA provides the following:

•

BP, as operator, owes duties to the non-operating parties (including Anadarko) to perform the drilling of the well in a good and workmanlike manner and to comply with all applicable laws and regulations;

•

BP, as operator, is not liable to non-operating parties for losses sustained or liabilities incurred, except for losses resulting from the operator’s gross negligence or willful misconduct; and

•

Liability for losses, damages, costs, expenses, or claims involving activities or operations shall be borne by each party in proportion to its participating interest, except that when liability results from the gross negligence or willful misconduct of a party, that party shall be solely responsible for liability resulting from its gross negligence or willful misconduct.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

The Company believes publicly available evidence indicates that the blowout of the well, the explosion on the Deepwater Horizon drilling rig, and the subsequent release of hydrocarbons were preventable and the direct result of BP’s decisions, omissions and actions, and likely constitute gross negligence or willful misconduct by BP. BP has issued a public statement indicating that it disagrees with this assessment. Under the JOA, liabilities arising as a result of gross negligence or willful misconduct by BP are the sole responsibility of BP and are not chargeable to other JOA parties, including Anadarko.

In light of the above, Anadarko does not consider JOA contingent liabilities for Deepwater Horizon event-related costs billed by BP to the Company to satisfy the standard of “probable” required for loss recognition. Accordingly, as of September 30, 2010, pursuant to applicable accounting guidance, the Company has not recognized a liability in its Consolidated Balance Sheets for amounts invoiced by BP under the JOA. In the future, the Company may recognize a liability for amounts invoiced by BP under the JOA if new information arising from the legal discovery process, hearings, other investigations, expert analysis, or testing alters the Company’s current assessment as to the likelihood of the Company incurring a liability for its existing JOA contingent obligations.

OPA-related Environmental Liabilities Under OPA, Anadarko may be held jointly and severally liable with all RPs for OPA-related costs associated with the Deepwater Horizon events. Anadarko’s designation by the USCG as an RP arises as a result of Anadarko’s status as a co-lessee in the lease block in which the Macondo well is located.

Applicable accounting guidance requires the Company to accrue an environmental liability if it is both “probable” that a liability has been incurred and the amount of the liability can be reasonably estimated. Under accounting guidance applicable to environmental liabilities, a liability is presumed “probable” if the entity is both identified as an RP and associated with the environmental event. The Company’s co-lessee status in the Macondo well lease block and the subsequent designation of the Company as an RP satisfies these standards and therefore establishes the presumption that the Company’s potential environmental liabilities related to the Deepwater Horizon events are “probable.” Given that such liabilities are probable, applicable accounting guidance requires the Company to (i) estimate, on a gross basis for all RPs, a range of total potential OPA-related environmental liabilities for the Deepwater Horizon events, and (ii) separately assess and estimate the Company’s allocable share of the gross estimated costs.

OPA-related environmental costs that have been paid by BP and subsequently invoiced to the non-operating working interest owners are accounted for as JOA contingent liabilities (discussed above) rather than OPA-related environmental liabilities (discussed herein). Payment by BP satisfied these liabilities for all RPs, including Anadarko, and resulted in BP seeking reimbursement from Anadarko through the JOA, which created a JOA contingent liability. The Company assumes that all OPA-related environmental costs incurred by BP and reported to the Company have been paid by BP, thereby satisfying those joint and several OPA-related environmental liabilities for all RPs.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

Gross OPA-related Environmental Cost-range Estimate The Company estimates the range of gross OPA-related environmental liabilities for all RPs to be $6.0 billion to $9.0 billion, excluding (i) $12.1 billion of costs incurred by BP as of September 30, 2010, which are considered and analyzed as JOA contingent liabilities, and (ii) amounts the Company currently cannot reasonably estimate, which, as discussed below, include OPA damage claims that may be made subsequent to the end of 2010, potential costs associated with penalties and fines, natural resource damages (NRD) and future NRD assessments, and civil litigation damages. The costs that the Company currently cannot reasonably estimate may be significant.

Anadarko’s gross OPA-related environmental cost-range estimate is comprised of spill-response costs and OPA damage claims. This cost-range estimate is based on information received from BP to date, certain assumptions discussed below, and publicly available information from the Gulf Coast Claims Facility (GCCF). The GCCF is an independent claims facility that was established in June 2010, as part of an agreement between the federal government and BP, to assist claimants in the submission and resolution of claims for costs and damages incurred as a result of the Deepwater Horizon events. As a non-operator, the Company is limited to formulating its estimates of spill response costs and OPA damages based upon information provided by BP, publicly available information, and management’s assumptions regarding a number of variables associated with the Deepwater Horizon events that remain uncertain or unknown. Although the Macondo well has been permanently plugged, the scope and extent of damages and clean-up activities continue to evolve, resulting in significant uncertainty as to the spill’s ultimate impacts and associated costs. Accordingly, the Company believes that actual gross OPA-related environmental costs may vary, perhaps materially, from the Company’s estimate.

Spill-Response Costs and Assumptions These costs include costs associated with the following:

•

relief-well drilling;

•

source containment and well control; and

•

spill mitigation and removal costs.

Estimated spill-response costs are based on cost information received from BP, which was used to estimate activity-based run-rates for various spill-response activities, which, in turn, were projected forward according to the Company’s estimates of the potential duration and extent of the spill response and clean up.

Relief-well drilling costs include materials, manpower and day rates for two drilling rigs. BP permanently plugged the Macondo well on September 19, 2010, with a “bottom kill” cementing operation that was conducted subsequent to the successful interception of the Macondo well by a relief well. The September 19, 2010, plugging date is approximately thirty days later than the Company’s previous best-case plugging-date estimate and thirty days earlier than the Company’s previous worst-case plugging-date estimate. The Company’s current cost-range estimate includes a one-week well plug-and-abandon period subsequent to the successful “bottom kill” operation. In addition, the Company’s current cost-range estimate includes a demobilization and decontamination period of six weeks for the low-end cost-range estimate and eleven weeks for the high-end cost-range estimate.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

Source-containment and well-control costs primarily include amounts related to the following:

•

the operation of remote-operated vehicles (ROVs) observing the well’s status and working to shut in the well;

•

the containment and subsea collection efforts; and

•

the operation and decontamination of numerous vessels deployed to support operations and collect and/or flare hydrocarbons.

The Company’s previous estimate of source-containment and well-control costs assumed that much of the source-containment activities and equipment would no longer be required after the well was permanently plugged. However, based on information provided to the Company by BP, source-containment and well-control expenses have continued at a cost rate equal to or greater than the cost rate in effect while the spill was ongoing due to resource demobilization occurring more slowly than originally anticipated. Demobilization delays are largely attributable to a prolonged decontamination period for well-site equipment and vessels. The Company has adjusted its previous cost estimate to reflect this information.

Spill mitigation and removal costs primarily include amounts related to the following:

•

labor;

•

materials and equipment associated with dispersant application;

•

containment and boom acquisition and deployment;

•

operation and decontamination of support vessels deployed for marine/open water clean up;

•

operation of aircraft;

•

shoreline clean up; and

•

costs related to federal, state and local efforts to coordinate the response and to control the spill.

The Company’s previous estimate for spill mitigation and removal costs was based on the assumption that offshore resources would begin to demobilize once the well was permanently plugged and oil stopped flowing; however, these costs have continued as a result of resource-demobilization timing. Accordingly, the Company has adjusted its previous cost estimate to reflect actual costs incurred by BP and the assumption that marine/open water clean-up and vessel demobilization and decontamination activities will continue for sixty to ninety days subsequent to the permanent plugging of the Macondo well.

The Company’s assumption that marine/open water clean-up activities will cease within sixty to ninety days subsequent to the permanent plugging of the Macondo well is based on the view that hydrocarbons spilled into open water would have been collected, evaporated, dispersed, or degraded within this sixty- to ninety-day period. Based on publicly available reports by BP and the Unified Command that oil reached the most distant beaches within a sixty- to ninety-day period from the onset of the spill, and that no hydrocarbons were released from the Macondo well subsequent to July 15, 2010, the Company’s high-end and low-end cost-range estimates for marine/open water clean-up costs consider delays in executing complete demobilization and decontamination of support vessels.

Based on additional cost information received from BP during the quarter ended September 30, 2010, the Company’s estimate of shoreline clean-up costs has significantly increased. The Company expects shoreline clean-up activities to continue through the end of 2010 and likely longer in some limited areas. For example, where contamination occurs in areas that require prolonged and/or labor-intensive clean up, such as in wetland areas, clean-up activities could extend well beyond the end of 2010, resulting in significantly higher clean-up costs than if the contamination were confined to beach areas. The Company’s cost estimate assumes shoreline clean-up activities will continue through the end of 2010. The Company believes it will be better positioned to reasonably estimate additional shoreline clean-up costs once the scope and extent of required clean-up activities becomes known.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

OPA Damage Claims OPA damages (other than NRD, discussed below) include costs associated with increased public-service expenses, damages to real or personal property, damages to subsistence users of natural resources, lost revenues, and lost profits and earning capacity. These damages are assessed pursuant to OPA and are limited, in general, to $75 million. However, the $75 million limit has not been applied for purposes of formulating the Company’s cost-range estimate and may not be applicable where there is a finding of gross negligence, willful misconduct, or a violation of an applicable federal safety, construction, or operating regulation by an RP, an agent or employee of an RP, or a person acting pursuant to a contractual relationship with an RP.

The Company’s estimate includes potential OPA damage claims and costs to administer those claims based on data received from BP and publicly available information from the GCCF. This claims information has been used to formulate estimates of the number of claims to be paid, the average expected per-claim payout, and costs to administer claims and operate claims offices projected through the end of 2010. During the third quarter of 2010, BP transitioned claims administration for most OPA damage claims to the GCCF, which is administered by an independent third party. Since this transition, both the number of claims paid and the average per-claim payout have increased, resulting in a significant increase to the Company’s previous estimate of potential OPA damage claims. According to public statements made by BP, BP is continuing to administer OPA damage claims made by federal and state governments.

The Company believes that claims will continue beyond the end of 2010, but is currently unable to reasonably estimate the amount and extent of future claims or related administrative costs that may be incurred by BP or others. The Company lacks visibility into, among other things, the processes associated with OPA damage claim approvals and claims administration, which significantly hinders the Company’s ability to formulate a long-term estimate of potential OPA damage claims. Accordingly, the Company’s estimates do not include amounts attributable to damage claims that will likely be made subsequent to the end of 2010.

Allocable Share of Gross OPA-related Environmental Costs As discussed above, under applicable accounting guidance, the Company is required to estimate its allocable share of gross OPA-related environmental liabilities based on the Company’s estimate of the allocation method and percentage that may ultimately apply. No agreed-upon or stipulated allocation of gross OPA-related environmental liabilities currently exists. As a result, the Company considered the following factors for purposes of estimating a range of its allocable share of these liabilities:

•

BP’s payment to date of Deepwater Horizon event-related costs – To date, BP has paid all Deepwater Horizon event-related costs and has repeatedly stated publicly and in congressional testimony that it will continue to pay all of these costs. The Company knows of no reason that BP will not continue to pay these costs as they arise. The obligation of the RPs for amounts payable under OPA is satisfied as such amounts are paid. Accordingly, the Company currently estimates its minimum allocable share of gross OPA-related environmental liabilities to be zero, recognizing that once amounts are paid by BP, these liabilities become JOA contingent liabilities (which are discussed above).

•

Anadarko’s co-lessee interest in the Macondo well lease block – If BP ceases paying any of these costs, the federal government could seek payment from all RPs (including BP and Anadarko) under the joint and several liability provisions of OPA. Under this scenario, the Company estimates its maximum allocation of gross OPA-related environmental liabilities could be 25%, which is equivalent to Anadarko’s working interest in the Macondo well. This maximum allocation assumes no allocation of costs to non-lessee RPs.

•

Allocation to non-lessee RPs – In addition to the three co-lessees of the lease block in which the Macondo well is located (including the Company), two other federal government-designated RPs have been identified for the Deepwater Horizon events (non-lessee RPs). The allocation of costs to all RPs, including the non-lessee RPs, would reduce Anadarko’s potential allocable share of gross OPA-related environmental liabilities to an amount less than Anadarko’s 25% working interest in the Macondo well.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

Based on the above, the Company has concluded that a range of 0-25% is appropriate for its potential allocable share of gross OPA-related environmental liabilities. Furthermore, due to the potential for BP, despite its statements to the contrary, to cease paying 100% of these costs, and the potential allocation to non-lessee RPs, Anadarko is currently unable to determine that any single allocation percentage within the 0-25% range is more likely to result than another. Accordingly, applicable accounting guidance requires the Company to accrue the liability for its share of allocable gross OPA-related environmental liabilities at the low end of the estimated range, in this case 0%, resulting in zero accrual at September 30, 2010, for potential OPA-related environmental obligations related to the Deepwater Horizon events.

Other Contingencies

Penalties and Fines These costs include amounts that may be assessed as a result of potential civil and/or criminal penalties under various federal, state and/or local statutes and/or regulations as a result of the Deepwater Horizon events, including, for example, Section 311 of the Clean Water Act (CWA), the Outer Continental Shelf Lands Act, the Migratory Bird Treaty Act, and possibly other federal, state and local laws. The foregoing does not represent an exhaustive list of statutes and regulations that potentially could trigger a penalty or fine assessment against the Company. Currently, the Company cannot reasonably estimate the amount of any federal, state or local penalties that could be assessed or the extent to which such penalties could be material to the Company’s financial statements. To date, no penalties or fines have been assessed against the Company or, to the Company’s knowledge, any other party.

Under the CWA, penalties include civil penalties that apply to events such as the Deepwater Horizon events. Applicable CWA penalties may be assessed in an amount not more than $37,500 per day or $1,100 per barrel of oil discharged. In cases of gross negligence or willful misconduct, such civil penalties may be increased to not less than $140,000 per day and not more than $4,300 per barrel of oil discharged, although several factors (as described below) impact this assessment. At this time, and as discussed more fully below, the Company is unable to determine whether it will be subject to a CWA penalty assessment, and if a CWA penalty were to be individually assessed against the Company, the amount of such penalty.

The CWA states that penalties may be assessed against the “owner, operator or person in charge.” Under the CWA, it is not clear that the Company, as a non-operating interest holder, would, as a matter of law, be assessed penalties based upon the actions of the operator. Accordingly, the Company, as a non-operating working interest owner, does not consider its exposure to potential liability for penalties arising under the CWA to be “probable” at this time.

Notwithstanding the above, the Company has nevertheless considered its potential exposure to a directly assessed CWA penalty, and has concluded that a reasonable estimate of such penalty cannot be made at this time. If assessed, a CWA penalty would likely take into account the total volume of oil spilled. Over the course of the spill, there have been several widely varying estimates of the flow rate from the well by various groups. On August 2, 2010, the federal government published its spill-volume estimate of 4.9 million barrels, which was based on several assumptions and acknowledges variability of the flow rate over time, inherent imprecision in the federal government’s ability to accurately estimate the flow rate, and uncertainty in evaporation and dispersion rates. Notwithstanding these variables, for the purpose of calculating any potential CWA assessment, the Company has assumed this spill-volume estimate will be utilized, unless a revised or restated spill-volume estimate is released at a later date.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

Although a spill-volume estimate has been issued, there is significant uncertainty as to the amount of any potential CWA penalty assessment. This uncertainty stems from historic assessments and subsequent settlements of CWA penalties, which generally vary greatly from a simple per-barrel penalty assessment due to the following subjective factors that are routinely taken into account when ultimately determining a CWA penalty:

•

the degree of culpability involved;

•

the seriousness of the violation;

•

the economic benefit to the violator;

•

any other penalties assessed for the same incident;

•

the history of prior violations; and

•

any mitigation efforts undertaken and the success of those efforts.

The above factors, coupled with general uncertainty as to the federal government’s position regarding the direct assessment of CWA penalties to the Company as a non-operator well owner, and the potential for allocation of CWA penalties among other RPs, prevent the Company from reasonably estimating its exposure to CWA penalties at this time. Thus, the Company currently can neither conclude that its exposure to CWA penalties is “probable” nor reasonably estimate the amount of its potential liability, if any, for CWA penalties.

Natural Resource Damages (NRD) This category includes costs to assess damages to natural resources resulting from the spill and/or spill clean-up activities as well as future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of their damage assessments. Natural resources generally include land, fish, water, air, wildlife, or other such resources belonging to, managed by, held in trust by, or otherwise controlled by, the federal, state or local government.

Based on information provided by BP to the Company, costs associated with assessing NRD have been incurred by BP through September 30, 2010. According to prior testimony, these amounts are intended to fund costs associated with the trustees’ pre-assessment activities for establishing baseline conditions prior to assessing potential impacts from the spill and spill clean-up efforts. Assessment-funding amounts may change significantly based on the extent and magnitude of the spill impacts and spill clean-up activities, which will not be fully known until the clean-up activities are substantially complete. Thus, the Company is unable to estimate total NRD assessment costs at this time. The Company also anticipates that federal and/or state natural resource trustee agencies may make NRD damage claims against certain parties; however, the Company is unable to reasonably estimate the magnitude of any potential damage claims until spill-response efforts and the NRD assessment is complete, which may take several years.

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

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

In July 2010, a public hearing of the United States Judicial Panel on Multidistrict Litigation (JPML) was held to consider motions of various plaintiffs and BP to consolidate Deepwater Horizon event-related lawsuits filed in various federal courts into a consolidated Multidistrict Litigation (MDL) in a single venue. In August 2010, the JPML created MDL No. 2179 to administer essentially all litigation filed in federal court involving Deepwater Horizon event-related claims. Federal Judge Carl Barbier will preside over this MDL in the Eastern District of Louisiana in New Orleans, Louisiana. In October 2010, the court appointed four plaintiffs’ attorneys to serve on a Plaintiff Executive Committee (PEC) and also appointed 15 of the plaintiffs’ attorneys to a Plaintiffs’ Steering Committee (PSC). The PEC will coordinate the responsibilities of the PSC, appear at status conferences representing the PSC, and provide any further administrative or logistical functions as the court may order. In October 2010, the court issued a case management order that initially establishes a schedule for procedural matters, discovery and trial of the MDL cases. The case management order sets, for trial beginning in June 2011, one or more cases brought against BP as an RP under OPA to serve as test cases for liability and damage issues. The court has not yet selected the specific cases to be tried. Also, the court scheduled a February 2012 trial date to determine the limitation and liability allocation issues for the parties involved in the Deepwater Horizon events, which will also address whether Transocean Ltd. can limit its liability under admiralty law to the value of the Deepwater Horizon drilling rig. The parties to the MDL are engaged in document discovery.

Lawsuits seeking to place limitations on the Company’s projects in the Gulf of Mexico have also been filed by non-governmental organizations against various governmental agencies.

In June 2010, a class action complaint was filed in the United States District Court for the Southern District of New York on behalf of purported purchasers of the Company’s stock between June 12, 2009, and June 9, 2010, against Anadarko and certain of its officers. The complaint alleges causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs.

Also in June 2010, a shareholder derivative petition was filed in the District Court of Harris County, Texas, by a shareholder of the Company against Anadarko (as a nominal defendant) and certain of its officers and current and certain former directors. The petition alleges breaches of fiduciary duties, unjust enrichment, and waste of corporate assets in connection with the Deepwater Horizon events. The plaintiffs seek certain changes to the Company’s governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs. In August 2010, the defendants moved to dismiss the derivative litigation. In September 2010, a purported shareholder made a demand on the Company’s Board of Directors to investigate allegations of breaches of duty by members of management.

These proceedings are at a very early stage; accordingly, the Company currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the proceedings described above. The Company intends to vigorously defend itself, its officers and its directors in these proceedings.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Deepwater Horizon Events (Continued)

Liability Outlook As discussed above, the Company’s aggregate Deepwater Horizon event-related liability accrual of zero as of September 30, 2010, is not intended to represent an opinion of the Company that it will not incur any future liability related to the Deepwater Horizon events. The Company’s liability assessment is based on the application of relevant accounting guidance to the Company’s understanding of currently available facts surrounding the Deepwater Horizon events. As more facts become known, it is reasonably possible that the Company may be required to recognize a liability related to the Deepwater Horizon events, and that the liability could be material to the Company’s consolidated financial position, results of operations or cash flows. For example, new information arising out of the legal-discovery process could alter the legal assessment as to the likelihood of the Company incurring a liability related to its existing JOA contingent liabilities. Moreover, if BP discontinues payment or is otherwise unable to satisfy its obligations, the Company could be required to recognize an OPA-related environmental liability. Similarly, if other RPs do not satisfy their obligations under OPA, the Company could incur additional liability. If Anadarko is required to recognize and pay additional liabilities, the Company could pursue remedies under the JOA to recover costs from BP or the other working interest owner. In addition, the Company could pursue recovery or contribution from other RPs that are not party to the JOA.

Insurance Recoveries The Company carries insurance to protect against potential financial losses. At the time of the Deepwater Horizon events, the Company’s insurance coverage applied to gross covered costs up to a level of approximately $710 million, less up to $60 million of deductibles. Based on Anadarko’s 25% non-operated interest in the Macondo well, the Company estimates its potential net insurance coverage could total $178 million, less deductibles of $15 million. The Company has not recognized a receivable for any potential recoveries in its Consolidated Balance Sheets. At this time, recovery of these amounts is not considered probable because the Company is not considered to have incurred a probable loss under the JOA or an insurable loss for unpaid liabilities. If the Company’s current legal assessment changes such that the Company becomes liable under the JOA for Deepwater Horizon event-related costs and funds such costs, the Company is positioned to recover the first $163 million of insured costs under its existing insurance policy. The Company also carries directors’ and officers’ insurance to cover certain risks associated with certain of the above-described legal proceedings.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

3. Deepwater Drilling Moratorium and Other Related Matters

In May and July 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), previously known as the Minerals Management Service, an agency of the Department of the Interior (DOI), issued directives requiring lessees and operators of federal oil and gas leases in the Outer Continental Shelf regions of the Gulf of Mexico and Pacific Ocean to cease drilling all new deepwater wells, including wellbore sidetracks and bypasses, through November 30, 2010. These deepwater drilling moratoria (collectively, the Moratorium) prohibited drilling and/or spudding any new wells, and required operators that were in the process of drilling wells to proceed to the next safe opportunity to secure such wells, and to take all necessary steps to cease operations and temporarily abandon the impacted wells. Anadarko ceased all drilling operations in the Gulf of Mexico in accordance with the Moratorium, which resulted in the suspension of operations of two operated deepwater wells (Lucius and Nansen) and one non-operated deepwater well (Vito). The Moratorium was lifted effective October 12, 2010, but the Company is unable to resume drilling operations until the BOEMRE approves new drilling permits.

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

In June 2010, the Company gave written notice of termination to the drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on June 19, 2010. The drilling contractor filed an Original Answer in July 2010 denying the Moratorium constituted a force majeure event and asserted that Anadarko had breached the drilling contract. If the Company does not prevail in its claim, the Company could be obligated to pay the rig contract rate from the contract-termination date through March 2011, the end of the original contract term.

In September 2010, the Company gave written notice of termination to another drilling contractor of a rig that had been placed in force majeure, and the Company filed a lawsuit against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on September 18, 2010. The drilling contractor filed a Motion to Dismiss and an Original Answer on October 5, 2010. The Company responded to the Motion to Dismiss on October 26, 2010. If the Company does not succeed in its claim, the Company could be obligated to pay the rig contract rate from the contract-termination date through March 2013, the end of the original contract term.

The disputed rentals for the contract periods described above are $90 million and $377 million, respectively, but any potential damages would be reduced by, among other things, any amounts resulting from the drilling contractor’s ability to mitigate damages by leasing the drilling rig to another third party, as well as cost savings incurred by the drilling contractor by not having to operate the drilling rig on a daily basis. As of September 30, 2010, the Company has not recorded a liability for costs associated with these disputes as management believes payment related to these matters is not probable. The Company intends to vigorously pursue each claim.

In September 2010, the BOEMRE issued a Notice to Lessees that requires lessees to plug all wells that have been idle for the past five years and decommission related equipment. Lessees have 120 days from October 15, 2010, to submit a company-wide plan for decommissioning facilities and wells. The Company is currently evaluating the regulations and is not yet able to determine the effect these new requirements may have on existing asset retirement obligations related to affected wells.

The Company has $3.1 billion and $384 million of unproved property acquisition costs and exploratory drilling costs, respectively, included in net properties and equipment on the Consolidated Balance Sheets at September 30, 2010, related to properties in the Gulf of Mexico that were subject to the Moratorium. As of September 30, 2010, no significant impairment of these properties has been recognized and the Company intends to continue exploration and development of these properties.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4. Goodwill

The Company tests goodwill for impairment annually, at October 1, or more often as facts and circumstances warrant. The first step in the goodwill impairment test is to compare the fair value of each reporting unit to which goodwill has been assigned to the carrying amount of net assets, including goodwill, of the respective reporting unit. Anadarko has allocated goodwill to three reporting units: oil and gas exploration and production; gathering and processing; and transportation. During the second quarter of 2010, a decline in the fair value of Anadarko’s oil and gas exploration and production reporting unit was indicated as a result of the Deepwater Horizon events and general uncertainty arising in connection with the Moratorium and uncertain related regulatory impacts. See Note 2 and Note 3. The Company completed an interim goodwill impairment test of the oil and gas exploration and production reporting unit as of June 30, 2010, and the results of the test indicated no impairment.

At September 30, 2010, the Company had $5.3 billion of goodwill allocated to its three reporting units: $5.2 billion to oil and gas exploration and production; $134 million to gathering and processing; and $5 million to transportation. The Company will complete its annual impairment assessment of goodwill during the fourth quarter of 2010.

Uncertainty related to the Deepwater Horizon events, difficulty or potential delays in obtaining drilling permits, significant declines in commodity prices, or other unanticipated events could result in further goodwill impairment tests in the near term, the results of which may have a material adverse impact on the Company’s results of operations.

5. Noncontrolling Interests

In the second quarter of 2010, Western Gas Partners, LP (WES), a consolidated subsidiary, issued approximately five million common units to the public, representing limited partner interests. This offering raised proceeds of $97 million, which were recorded as noncontrolling interests. As of September 30, 2010, the balance of noncontrolling interests on the Consolidated Balance Sheets includes approximately $85 million, net of tax, which will be transferred to paid-in capital if and when the WES subordinated limited partner units convert to common units. As of September 30, 2010, Anadarko’s ownership interest in WES consists of a 52.2% limited partner interest (common and subordinated units), a 2% general partner interest and incentive distribution rights.

6. Inventories

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


millions	September 30, 2010		December 31, 2009
Crude oil and NGLs	$	150	$	142
Natural gas		44		94

Total	$	194	$	236

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Properties and Equipment

Suspended Exploratory Drilling Costs The Company’s capitalized suspended well costs at September 30, 2010, and December 31, 2009, were $955 million and $579 million, respectively. The increase primarily relates to the capitalization of costs associated with successful exploration drilling in Brazil, the Maverick basin in the Company’s Southern and Appalachia Region, and in the Gulf of Mexico. This increase includes $48 million of costs incurred for the drilling of the Macondo well, prior to its blowout on April 20, 2010. See Note 2. For the nine months ended September 30, 2010, $30 million of exploratory well costs previously capitalized as suspended well costs for greater than one year, were charged to dry hole expense, and $87 million of capitalized suspended well costs were reclassified to proved properties.

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

Impairments Impairment expense for the three and nine months ended September 30, 2010, was $20 million and $147 million, respectively, including $114 million recognized in the second quarter 2010 related to a production platform included in the oil and gas exploration and production operating segment that remains idle with no immediate plan for use, and for which a limited market currently exists. The platform was impaired to fair value of $25 million, estimated using inputs characteristic of a Level 3 fair-value measurement.

Impairment expense for the three and nine months ended September 30, 2009, was $5 million and $79 million, respectively, of which $5 million and $74 million, respectively, related to certain transportation contracts included in the marketing operating segment that declined in value as a result of changes in price differentials at specific locations. These assets were impaired to fair value using market-based inputs characteristic of a Level 2 fair-value measurement.

8. Investments

Noncontrolling Mandatorily Redeemable Interests In 2007, Anadarko contributed certain of its oil and gas properties and gathering and processing assets, with an aggregate fair value of $2.9 billion at the time of the contribution, to newly formed unconsolidated entities in exchange for noncontrolling mandatorily redeemable interests in those entities. Subsequent to their formation, the investee entities loaned Anadarko an aggregate of $2.9 billion. The Company accounts for its investment in these entities under the equity method of accounting. At September 30, 2010, the carrying amount of these investments was $2.8 billion, while the carrying amount of notes payable to affiliates was $2.9 billion. Anadarko has legal right of setoff and intends to net-settle its obligations under each of the notes payable to the investees with the distributable value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the Consolidated Balance Sheets with the excess of the notes payable to affiliates over the aggregate investment carrying amounts reported in other long-term liabilities - other for all periods presented.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Investments (Continued)

Interest on the notes issued by Anadarko is variable, based on the London Interbank Offered Rate (LIBOR) plus a spread that fluctuates with Anadarko’s credit rating. The applicable interest rate was 1.29% and 1.25% at September 30, 2010, and December 31, 2009, respectively. Other (income) expense, net for the three and nine months ended September 30, 2010, includes interest expense on the notes payable to the investee entities of $11 million and $29 million, respectively, and equity earnings from Anadarko’s investments in the investee entities of $(10) million and $(28) million, respectively. Other (income) expense, net for the three and nine months ended September 30, 2009, includes interest expense on the notes payable to the investee entities of $12 million and $48 million, respectively, and equity in earnings from Anadarko’s investments in the investee entities of $(11) million and $(34)million, respectively.

Midstream Financing Arrangement In December 2007, Anadarko, and an entity formed by a group of unrelated third-party investors (the Investor), formed Trinity Associates LLC (Trinity), a variable interest entity. Trinity was initially capitalized with a $100 million cash contribution by Anadarko in exchange for Class A member and managing member interests in Trinity, and a $2.2 billion cash contribution by the Investor in exchange for a Class B member cumulative preferred interest. Trinity invested $100 million in a United States Government securities money market fund (the Fund) and loaned $2.2 billion to a wholly owned midstream subsidiary of Anadarko (Midstream Holding). See Note 10 for discussion regarding the midstream financing arrangement (Midstream Subsidiary Note). The remaining outstanding balance on the Midstream Subsidiary Note was repaid in full during the third quarter of 2010.

Immediately preceding the repayment of the Midstream Subsidiary Note, Trinity’s assets consisted of $100 million invested in the Fund and the $1.3 billion note receivable from Midstream Holding. Proceeds from repayment of the Midstream Subsidiary Note were distributed to the Investor. Proceeds from Trinity’s liquidation of its investment in the Fund were distributed to Anadarko. Anadarko accounted for its investment in Trinity under the equity method of accounting, and the $100 million distribution received reduced the carrying amount of that investment to zero.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Derivative Instruments

Objective and Strategy The Company utilizes derivative instruments to manage its exposure to cash-flow variability resulting 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 gas production and gas-processing operations (Oil and Gas Production/Processing Derivative Activities). Futures contracts and commodity price swap agreements are used to fix the price of expected future oil and gas sales at major industry trading locations, such as Henry Hub, Louisiana for gas and Cushing, Oklahoma 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 and a ceiling price (collar) for expected future oil and gas sales. Derivative instruments are also used to manage commodity price risk inherent in customer pricing 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 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 economic transactions to which the derivatives relate are recorded to earnings.

Accumulated other comprehensive loss balances of $131 million ($83 million after tax) and $151 million ($96 million after tax), at September 30, 2010, and December 31, 2009, respectively, primarily relate to interest-rate derivatives that were previously designated as cash-flow hedges.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Derivative Instruments (Continued)

Oil and Gas Production/Processing Derivative Activities Below is a summary of the Company’s derivative instruments related to its oil and gas production as of September 30, 2010. The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below reflect a combination of NYMEX Cushing and London Brent Dated prices.


	2010		2011		2012
Natural Gas
Three-Way Collars (thousand MMBtu/d)		1,630		480		500
Average price per MMBtu
Ceiling sold price (call)	$	8.23	$	8.29	$	9.03
Floor purchased price (put)	$	5.59	$	6.50	$	6.50
Floor sold price (put)	$	4.22	$	5.00	$	5.00

Fixed-Price Contracts (thousand MMBtu/d)		90		90		—
Average price per MMBtu	$	6.10	$	6.17	$	—

Basis Swaps (thousand MMBtu/d)		620		45		—
Average price per MMBtu	$	(0.98)	$	(1.74)	$	—
MMBtu - million British thermal units
MMBtu/d - million British thermal units per day

	2010		2011		2012
Crude Oil
Three-Way Collars (MBbls/d)		129		126		2
Average price per barrel
Ceiling sold price (call)	$	90.73	$	99.95	$	92.50
Floor purchased price (put)	$	64.34	$	79.29	$	50.00
Floor sold price (put)	$	49.34	$	64.29	$	35.00
MBbls/d - thousand barrels per day

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

Marketing and Trading Derivative Activities In addition to the positions in the above tables, the Company also engages in marketing and trading activities, which include physical product sales and derivative transactions used to manage commodity price risk. At September 30, 2010, and December 31, 2009, the Company had outstanding physical transactions related to natural gas for 35 billion cubic feet (Bcf) and 46 Bcf, respectively, offset by derivative transactions for 22 Bcf and 17 Bcf, respectively, for net positions of 13 Bcf and 29 Bcf, respectively.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Derivative Instruments (Continued)

Interest-Rate Derivatives In 2008 and 2009, Anadarko entered into interest-rate swap agreements to mitigate the risk of rising interest rates on up to $3.0 billion of debt originally expected to be refinanced in 2011 and 2012, over a reference term of either 10 years or 30 years. 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.

Unrealized (gains) losses of $231 million and $655 million on these swap agreements are reported in (gains) losses on other derivatives, net for the three and nine months ended September 30, 2010, respectively. During the second quarter of 2009, the Company realized $552 million in cash after revising the contractual terms of this swap portfolio, increasing the weighted-average interest rate from approximately 3.25% to approximately 4.80%. The realized gains were partially offset by unrealized losses on these agreements of $130 million and $220 million for the three and nine months ended September 30, 2009, respectively.

A summary of the swaps outstanding as of September 30, 2010, including the outstanding notional principal amounts and the associated reference periods, is presented below.


millions except percentages	Reference Period		Weighted-Average
Notional Principal Amount:	Start	End	Interest Rate
$ 750	October 2011	October 2021	4.72 %
$ 1,250	October 2011	October 2041	4.83 %
$ 250	October 2012	October 2022	4.91 %
$ 750	October 2012	October 2042	4.80 %

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Derivative Instruments (Continued)

Effect of Derivative Instruments - Balance Sheet The fair value of all derivative instruments is included in the table below.


		Gross Derivative Assets				Gross Derivative Liabilities
millions Derivatives	Balance Sheet Classification	September 30, 2010		December 31, 2009		September 30, 2010		December 31, 2009
Commodity
	Other Current Assets	$	663	$	140	$	(247)	$	(63)
	Other Assets		266		82		(38)		(6)
	Accrued Expenses		38		195		(44)		(417)
	Other Liabilities		26		25		(31)		(52)

			993		442		(360)		(538)

Interest Rate and Other
	Other Assets		—		53		—		—
	Accrued Expenses		—		—		(404)		—
	Other Liabilities		—		—		(202)		(3)

			—		53		(606)		(3)

Total Derivatives		$	993	$	495	$	(966)	$	(541)

Effect of Derivative Instruments - Statement of Income The unrealized and realized gain or loss amounts and classification related to derivative instruments are as follows:


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

Derivative (Gain) Loss, Net		$	(157)	$	174	$	17	$	(338)	$	(66)	$	(404)

*Represents the effect of marketing and trading derivative activities.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Derivative Instruments (Continued)


		(Gain) Loss
millions	Classification of (Gain)	Three Months Ended September 30, 2009						Nine Months Ended September 30, 2009
Derivatives	Loss Recognized	Realized		Unrealized		Total		Realized		Unrealized		Total
Commodity	Gathering, Processing and Marketing Sales*	$	7	$	13	$	20	$	(7)	$	46	$	39
	(Gains) Losses on Commodity Derivatives, net		(93)		227		134		(314)		817		503
Interest Rate	(Gains) Losses on Other Derivatives, net		5		126		131		(525)		210		(315)

Derivative (Gain) Loss, Net		$	(81)	$	366	$	285	$	(846)	$	1,073	$	227

*Represents the effect of marketing and trading derivative activities.

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

The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities. In addition, the Company has setoff agreements with certain financial institutions that are triggered in the event of default and provide for contract termination and net settlement across all derivative types. As of September 30, 2010, $528 million of the Company’s $966 million gross derivative liability balance would be available, in the event of default, for setoff against the Company’s gross derivative asset balance with financial institutions. Other than in the event of default, the Company does not net settle across commodity and interest-rate derivatives, as the timing of settlement differs.

Most of the Company’s derivative instruments are subject to provisions that can require collateralization of the Company’s obligations. In the event of a credit-rating downgrade to a level below investment grade by major credit rating agencies, the Company’s counterparties may require immediate settlement or full collateralization. In June 2010, the Company’s credit rating was downgraded from “Baa3” to “Ba1” by Moody’s Investors Service (Moody’s), which triggered credit-risk-related features with certain derivative counterparties, resulting in the Company posting additional collateral under its derivative instruments. No counterparties have requested termination or full settlement of derivative positions. As of September 30, 2010, the aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed was $181 million (net of collateral) and is included in accrued expenses on the Company’s Consolidated Balance Sheet.

As discussed in Note 10, in September 2010, the Company closed a $5.0 billion senior secured revolving credit facility (the $5.0 billion Facility), which permits certain of the Company’s derivative counterparties (those extending commitments under the $5.0 billion Facility) to receive security interests in specified assets of the Company, thereby reducing the Company’s requirements to post cash collateral for net derivative liability positions. The Company is actively negotiating the execution of security-interest amendments to the International Swaps and Derivatives Association, Inc. (ISDA) agreements with these counterparties. As these amendments are executed, the Company’s cash collateral requirements will decrease.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Derivative Instruments (Continued)

Fair Value Fair value of futures contracts is based on inputs that represent quoted prices in active markets for identical assets or liabilities, resulting in Level 1 categorization of such measurements. 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 in the Company’s derivative valuations include market-price curves, contract terms and prices, credit-risk adjustments, and, for Black-Scholes option valuations, implied market volatility and discount factors. Because substantially all of the assumptions and inputs for industry-standard models are observable in active markets throughout the full term of the instruments, the Company categorizes each of these measurements as Level 2.

The following tables set forth, by level within the fair-value hierarchy, the fair value of the Company’s derivative financial assets and liabilities.



September 30, 2010
millions	Level 1		Level 2		Level 3		Netting⁽¹⁾		Collateral⁽²⁾		Total
Assets:
Commodity derivatives
Financial institutions	$	6	$	744	$	—	$	(269)	$	(20)	$	461
Other counterparties		—		243		—		(80)		—		163
Interest-rate and other derivatives		—		—		—		—		—		—

Total derivative assets	$	6	$	987	$	—	$	(349)	$	(20)	$	624

Liabilities:
Commodity derivatives
Financial institutions	$	(3)	$	(272)	$	—	$	269	$	—	$	(6)
Other counterparties		—		(85)		—		80		—		(5)
Interest-rate and other derivatives		—		(606)		—		—		222		(384)

Total derivative liabilities	$	(3)	$	(963)	$	—	$	349	$	222	$	(395)

⁽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.

⁽²⁾	Cash collateral held by counterparties from Anadarko was $229 million at September 30, 2010, including $7 million for which no net liability position existed at September 30, 2010. Anadarko held $20 million of cash collateral from counterparties at September 30, 2010.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Derivative Instruments (Continued)


December 31, 2009
millions	Level 1		Level 2		Level 3		Netting⁽¹⁾		Collateral⁽²⁾		Total
Assets:
Commodity derivatives
Financial institutions	$	4	$	385	$	—	$	(284)	$	—	$	105
Other counterparties		—		53		—		(5)		—		48
Interest-rate derivatives		—		53		—		—		—		53

Total derivative assets	$	4	$	491	$	—	$	(289)	$	—	$	206

Liabilities:
Commodity derivatives
Financial institutions	$	(6)	$	(520)	$	—	$	284	$	44	$	(198)
Other counterparties		—		(12)		—		5		—		(7)
Interest-rate derivatives		—		(3)		—		—		—		(3)

Total derivative liabilities	$	(6)	$	(535)	$	—	$	289	$	44	$	(208)

⁽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.

⁽²⁾	Cash collateral held by counterparties from Anadarko was $105 million at December 31, 2009, including $61 million for which no net liability position existed at December 31, 2009. Anadarko held no cash collateral from counterparties at December 31, 2009.

10. Debt and Interest Expense

Debt The following table presents the Company’s outstanding debt as of September 30, 2010, and December 31, 2009. See Note 8 for disclosure regarding Anadarko’s notes payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not included in the Company’s reported debt balance and do not affect consolidated interest expense.


	September 30, 2010						December 31, 2009
millions	Principal		Carrying Value		Fair Value		Principal		Carrying Value		Fair Value
Long-term notes and debentures	$	14,659	$	12,901	$	13,832	$	12,909	$	11,149	$	12,133
Midstream subsidiary note payable to a related party		—		—		—		1,599		1,599		1,599
WES borrowings		570		570		570		—		—		—

Total debt	$	15,229	$	13,471	$	14,402	$	14,508	$	12,748	$	13,732
Less: Current portion of long-term debt		717		718		741		—		—		—

Total long-term debt	$	14,512	$	12,753	$	13,661	$	14,508	$	12,748	$	13,732

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. Debt and Interest Expense (Continued)

In a 2006 private offering, Anadarko received $500 million of loan proceeds upon issuing Zero-Coupon Senior Notes (the Zero Coupons) maturing October 2036. The Zero Coupons have an aggregate principal amount due at maturity of $2.4 billion, reflecting a yield to maturity of 5.24%. The holder had an option to put 82% of the then-accreted value of the Zero Coupons to Anadarko in October 2010 by providing a notice of exercise in September 2010. The holder did not exercise this put right and does not hold a similar put right for 2011; therefore, the full accreted value of the Zero Coupons is reported in long-term debt at September 30, 2010. The holder has the right to cause the Company to repay up to 100% of the then-accreted value of the Zero Coupons in October of each year starting in 2012.

Debt Activity In March and April 2010, Anadarko completed the repurchase of $1.0 billion aggregate principal amount of its 6.750% and 6.875% Notes due 2011 and 6.125% and 5.000% Notes due 2012 (together, the Notes due 2011 and 2012). The following table presents the debt activity of the Company for the nine months ended September 30, 2010.


millions	Activity	Principal		Carrying Value		Description
Balance as of December 31, 2009		$	14,508	$	12,748
First Quarter 2010
	Issuance		750		745	6.200% Senior Notes due 2040
	WES borrowing		210		210	WES credit facility
	Retirements		(528)		(522)	6.750% Notes due 2011
	Repayment		(250)		(250)	Midstream Subsidiary Note
	Other, net		—		6	Changes in debt premium or discount
Second Quarter 2010
	Retirements		(472)		(479)	Notes due 2011 and 2012
	WES repayment		(100)		(100)	WES credit facility
	Other, net		—		(7)	Changes in debt premium or discount
Third Quarter 2010
	Issuance		2,000		2,000	6.375% Senior Notes due 2017
	WES borrowings		460		460	WES credit facility and term loan
	Retirements		(1,349)		(1,349)	Midstream Subsidiary Note
	Other, net		—		9	Changes in debt premium or discount

Balance as of September 30, 2010		$	15,229	$	13,471

In August 2010, Anadarko issued $2.0 billion principal amount of 6.375% Senior Notes due 2017 (the $2.0 billion Senior Notes) and used $1.3 billion of the proceeds to fully retire the Midstream Subsidiary Note. As a result of issuing the $2.0 billion Senior Notes, Anadarko did not enter into a previously contemplated term-loan facility. In October 2010, the Company redeemed the $422 million outstanding principal balance of 6.750% Senior Notes due in May 2011 for $435 million, including a make-whole redemption premium.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. Debt and Interest Expense (Continued)

Midstream Subsidiary Note Payable to a Related Party The principal balance owed by Midstream Holding to Trinity is described in the accompanying Consolidated Balance Sheets as Midstream Subsidiary Note Payable to a Related Party (Midstream Subsidiary Note). The Midstream Subsidiary Note, which had an initial maturity date of December 27, 2012, was retired during the quarter ended September 30, 2010. See Note 8 for additional information regarding the Company’s investment in Trinity.

Anadarko Revolving Credit Facility As discussed in Note 9, in September 2010, the Company entered into the $5.0 billion Facility, and terminated its $1.3 billion revolving credit agreement, scheduled to mature in 2013. At September 30, 2010, the $5.0 billion Facility was undrawn with available capacity of $4.6 billion ($5.0 billion undrawn capacity less $399 million in outstanding letters of credit supported by the $5.0 billion Facility).

Borrowings under the $5.0 billion Facility will bear interest, at the Company’s election, at (i) LIBOR plus a margin ranging from 2.75% to 3.75%, based on the Company’s credit rating, or (ii) the greatest of (a) the JPMorgan Chase Bank prime rate, (b) the federal funds rate plus 0.50%, and (c) one-month LIBOR plus 1%, and in each case, plus an applicable margin.

Obligations incurred under the $5.0 billion Facility, as well as certain obligations Anadarko has to lenders or their affiliates pursuant to certain derivative instruments discussed in Note 9, 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 $5.0 billion Facility contains various customary covenants with which Anadarko must comply, including, but not limited to, limitations on incurrence of indebtedness, liens on assets, and asset sales. Anadarko is also required to maintain, at the end of each quarter, (i) a Consolidated Leverage Ratio of no more than 4.5 to 1.0 (relative to Consolidated EBITDAX for the most recent period of four calendar quarters), (ii) a ratio of Current Assets to Current Liabilities of no less than 1.0 to 1.0, and (iii) a Collateral Coverage Ratio of no less than 1.75 to 1.0, in each case, as defined in the $5.0 billion Facility. The Collateral Coverage Ratio is the ratio of an annually redetermined value of pledged assets to outstanding loans under the $5.0 billion Facility. Additionally, to borrow from the $5.0 billion Facility, the Collateral Coverage Ratio must be no less than 1.75 to 1.0 after giving pro forma effect to the requested borrowing. The Company was in compliance with all applicable covenants at September 30, 2010, and there were no restrictions on its ability to utilize the available capacity of the $5.0 billion Facility.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. Debt and Interest Expense (Continued)

WES Revolving Credit Facility In connection with the acquisition of certain midstream assets from Anadarko in August 2010, WES borrowed $200 million under its senior unsecured revolving credit facility (the RCF). At September 30, 2010, WES was in compliance with the covenants contained in its RCF and had outstanding borrowings of $320 million, with $130 million of available borrowing capacity. The RCF matures in October 2012 and bears interest at LIBOR plus an applicable margin ranging from 2.375% to 3.250%, for a rate of 2.63% at September 30, 2010.

WES Term Loan Also in August 2010, WES borrowed $250 million under a three-year, unsecured term loan from a group of banks (the Term Loan). The Term Loan contains various customary covenants and bears interest at LIBOR plus an applicable margin ranging from 2.50% to 3.50% (for a rate of 3.26% at September 30, 2010) depending upon WES’s consolidated leverage ratio, as defined in the agreement governing the Term Loan.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
millions	2010		2009		2010		2009
Current debt, long-term debt and other⁽¹⁾	$	224	$	129	$	618	$	522
Midstream subsidiary note payable to a related party⁽²⁾		11		9		24		32
(Gain) loss on early debt retirements and commitment termination⁽³⁾		17		—		89		(2)
Capitalized interest		(34)		(17)		(89)		(48)

Interest expense	$	218	$	121	$	642	$	504

⁽¹⁾	Included in the three- and nine-month periods ended September 30, 2009, is the reversal of the $78 million liability for unpaid interest related to the DWRRA dispute.

⁽²⁾	Included in the three- and nine-month periods ended September 30, 2010, is $7 million and $9 million, respectively, of unamortized debt issuance costs associated with the retirement of the Midstream Subsidiary Note.

⁽³⁾

(Gain) loss on early retirements of debt in 2010 are the result of repurchasing $1.0 billion aggregate principal amount of debt discussed above. Also included in the three- and nine-month periods ended September 30, 2010, is $17 million for upfront commitment and structuring costs associated with a previously contemplated term-loan facility.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Stockholders’ Equity

Common Stock The reconciliation between basic and diluted earnings per share (EPS) from income attributable to common stockholders is as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
millions except per-share amounts	2010		2009		2010		2009
Income (loss):
Net income (loss) attributable to common stockholders	$	(26)	$	200	$	650	$	(364)
Less: Distributions on participating securities		—		—		1		—
Less: Undistributed income allocated to participating securities		—		2		4		—

Basic	$	(26)	$	198	$	645	$	(364)

Diluted	$	(26)	$	198	$	645	$	(364)


Shares:
Basic
Weighted-average common shares outstanding		496		491		495		476
Dilutive effect of stock options and performance-based stock awards		—		2		1		—

Diluted		496		493		496		476

Excluded⁽¹⁾		12		6		6		14

Income (loss) per common share:
Basic	$	(0.05)	$	0.40	$	1.30	$	(0.77)
Diluted	$	(0.05)	$	0.40	$	1.30	$	(0.77)
Dividends per common share	$	0.09	$	0.09	$	0.27	$	0.27

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

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Commitments and Contingencies

The following discussion of the Company’s commitments and contingencies excludes discussion related to the Deepwater Horizon events and the Moratorium. See Note 2 and Note 3.

General Litigation charges and adjustments of $1 million and $4 million increased income before income taxes for the three and nine months ended September 30, 2010, respectively. Litigation charges and adjustments of $1 million and $46 million decreased income before income taxes for the three and nine months ended September 30, 2009, respectively. The Company is a defendant in a number of lawsuits and is involved in governmental proceedings, including, but not limited to, royalty claims, contract claims and environmental claims. The Company has also been named as a defendant in various personal injury claims, including claims by employees of third-party contractors alleging exposure to asbestos, silica and benzene while working at refineries (previously owned by predecessors of acquired companies) located in Texas, California and Oklahoma. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Litigation The Company is subject to various claims by its royalty owners in the regular course of business as an oil and gas producer, including disputes regarding measurement, post-production costs and expenses and royalty valuations. The Company was named as a defendant in a case styled U.S. of America ex rel. Harrold E. Wright v. AGIP Petroleum Co., et al. filed in September 2000 in the United States District Court for the Eastern District of Texas, Lufkin Division. Kerr-McGee Corporation (Kerr-McGee) was also named as a defendant in this legal proceeding. This lawsuit generally alleges that the Company, including Kerr-McGee, and other industry defendants knowingly undervalued natural gas in connection with royalty payments on production from federal and Indian lands. Based on the Company’s present understanding of these various governmental and False Claims Act proceedings, the Company believes that it has substantial defenses to these claims and is vigorously asserting such defenses. However, if the Company is found to have violated the False Claims Act, the Company could be subject to a variety of damages, including treble damages and substantial monetary fines. The claims against the Company have not been set for trial. The Company has reached a tentative settlement with the United States Government and the Relators, which, if finalized, will resolve this litigation against Anadarko and Kerr-McGee, as well as several administrative actions. The tentative settlement must be approved by various levels of authority within the United States Government, which could take up to a year. Management has accrued a liability for the estimated settlement amount. The Company believes that an additional loss, in excess of the amount accrued, is unlikely to have a material adverse effect on Anadarko’s consolidated financial position, results of operations or cash flows.

In January 2009, Tronox Incorporated (Tronox), a former wholly owned subsidiary of Kerr-McGee that held Kerr-McGee’s chemical business, and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (the Court). Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance (the Adversary Proceeding). Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee. Tronox seeks, among other things, to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko as well as punitive damages, and litigation fees and costs. In addition, Tronox seeks to equitably subordinate and/or disallow all claims asserted by Anadarko and Kerr-McGee in the bankruptcy cases. Anadarko and Kerr-McGee moved to dismiss the complaint in its entirety. In March 2010, the Court issued an opinion granting in part and denying in part Anadarko’s and Kerr-McGee’s motion to dismiss the complaint. Notably, the Court dismissed Tronox’s request for punitive damages relating to their fraudulent conveyance claims with prejudice. The Court granted Tronox leave to replead certain of its common law claims, and Tronox filed an amended complaint in April 2010. Anadarko and Kerr-McGee have moved to dismiss three breach of fiduciary duty-related claims in the amended complaint. That motion has been briefed and is awaiting disposition by the Court.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Commitments and Contingencies (Continued)

The United States filed a motion to intervene in the Adversary Proceeding, asserting that it has an independent cause of action against Anadarko, Kerr-McGee and Tronox under the Federal Debt Collection Procedures Act relating primarily to environmental cleanup obligations allegedly owed to the United States by Tronox. That motion to intervene has been granted, and the United States is now a co-plaintiff against Anadarko and Kerr-McGee in the Adversary Proceeding. Anadarko and Kerr-McGee have moved to dismiss the United States’ complaint-in-intervention, but that motion currently has been stayed by order of the Court.

In June 2010, Anadarko and Kerr-McGee filed a motion in Tronox’s Chapter 11 cases to compel Tronox to assume or reject the Master Separation Agreement (together with all annexes, related agreements, and ancillary agreements thereto, the MSA). In July 2010, in response to this motion, Tronox announced to the Court that it would reject the MSA effective as of July 22, 2010. In August 2010, the Court entered into a Stipulation and Agreed Order among Tronox, Anadarko, and Kerr-McGee authorizing the rejection of the MSA. Anadarko and Kerr-McGee subsequently filed amended proofs of claim, which include claims for damages arising from such rejection of the MSA. During the quarter ended September 30, 2010, the Company reversed a $95 million liability for the reimbursement obligation that was provided by Kerr-McGee to Tronox pursuant to the terms of the MSA. The Company will continue to monitor events subsequent to the MSA rejection and will assess the impact of future events on the Company’s consolidated financial position, results of operations and cash flows. See Guarantees and Indemnifications section of this Note 12.

In August 2010, Tronox filed a motion seeking, among other things, (i) authority to enter into a certain plan support agreement and equity-commitment agreement (together, the Plan Support Agreements) and (ii) approval of procedures for a rights offering. Anadarko and Kerr-McGee filed an objection to the motion. In the objection, Anadarko and Kerr-McGee requested that the Court order mediation of the Adversary Proceeding. Tronox and the United States opposed mediation, citing, in support of their position, a lack of sufficient discovery. The Court declined to order mediation at this time. In September 2010, the Court entered an order authorizing Tronox to enter into the Plan Support Agreements and approved the rights offering procedures. Anadarko and Kerr-McGee, however, are not subject to the rights offering procedures.

In September 2010, Tronox filed a Proposed First Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code (the Plan) and a related disclosure statement (the Disclosure Statement), which modify and supersede the terms of the earlier plan and disclosure statement filed in July 2010. The Plan contemplates, among other things, that (a) the claims of the United States (as well as other federal, state, local or tribal governmental entities having regulatory authority or responsibilities with respect to environmental laws) related to Tronox’s environmental liabilities at legacy sites, will be settled through the creation of certain environmental response trusts and a litigation trust to which Tronox will contribute the following consideration: (i) $270 million in cash, (ii) 88% of the proceeds from the Adversary Proceeding, (iii) certain Nevada assets, including the real property located in Henderson, Nevada, and (iv) certain other insurance and financial assurance assets worth at least $50 million; (b) certain creditors who have asserted tort claims against Tronox will receive the following consideration from a trust to be created under the Plan: (i) $13 million in cash, (ii) 12% of the proceeds from the Adversary Proceeding, and (iii) certain insurance assets, including the net proceeds of certain insurance settlements; (c) certain creditors who have asserted general unsecured claims against Tronox will receive the following consideration: (i) their pro rata share of 16.9% of the common equity of reorganized Tronox and (ii) the right to purchase additional common equity of reorganized Tronox up to a certain amount; (d) certain parties who have asserted claims against Tronox for breach of contract, indemnification, contribution, reimbursement or cost recovery related to environmental monitoring or remediation will receive the following bifurcated consideration: (i) 50% of the claim will receive the same treatment as holders of Class 3 general unsecured claims and (ii) 50% of the claim will receive the same treatment as holders of Class 4 tort claims; and (e) existing equity holders will receive their pro rata share of warrants to purchase the number of shares equivalent to 5% of the common equity of reorganized Tronox if they vote to accept the Plan. Objections to the Disclosure Statement were filed by various interested parties, including Anadarko and Kerr-McGee. The Court has approved the Disclosure Statement and authorized Tronox to begin soliciting votes to accept or reject the Plan. The hearing to consider confirmation of the Plan is currently scheduled for November 17, 2010. It is unclear whether the current Plan will be approved or implemented, and what, if any, effect the Plan might have on the course, cost or outcome of the Adversary Proceeding.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Commitments and Contingencies (Continued)

In addition, a consolidated class action complaint has been filed in the United States District Court for the Southern District of New York 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. The complaint alleges causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort claim liabilities. The plaintiffs allege that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including in connection with Tronox’s initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. Anadarko, Kerr-McGee and other defendants moved to dismiss the class action complaint and in June 2010, the Court issued an opinion and order dismissing the plaintiffs’ complaint against Anadarko, but granted the plaintiffs leave to re-plead their claims. The court further granted in part and denied in part the motions to dismiss by Kerr-McGee and certain of its former officers and directors, but permitted plaintiffs leave to re-plead certain of the dismissed claims. Plaintiffs’ amended complaint was filed in July 2010. In August 2010, Anadarko moved to dismiss plaintiffs’ complaint in whole and Kerr-McGee moved to dismiss plaintiffs’ allegations against it in part. The plaintiffs have responded to both motions. Anadarko and Kerr-McGee will file respective briefs in reply during the fourth quarter of 2010.

The Company intends to continue to defend itself vigorously.

Deepwater Royalty Relief Act In 1995, the United States Congress passed the Deepwater Royalty Relief Act (DWRRA) to stimulate exploration and production of oil and natural gas by providing relief from the obligation to pay royalties on certain federal leases located in the deep waters of the Gulf of Mexico. The Company currently owns interests in several deepwater Gulf of Mexico leases. After the passage of the DWRRA, the Minerals Management Service (MMS) (which was recently renamed the BOEMRE) inserted price thresholds into leases issued in 1996, 1997 and 2000 that effectively eliminated the DWRRA royalty relief if these price thresholds were exceeded.

In January 2006, the DOI issued an order (the 2006 Order) to Kerr-McGee Oil and Gas Corporation (KMOG), a subsidiary of Kerr-McGee, to pay oil and gas royalties and accrued interest on KMOG’s deepwater Gulf of Mexico production associated with eight 1996, 1997 and 2000 leases, for which KMOG considered royalties to be suspended under the DWRRA. KMOG successfully appealed the 2006 Order, and the DOI’s petition for a writ of certiorari with the United States Supreme Court was denied on October 5, 2009.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Commitments and Contingencies (Continued)

The MMS issued two additional orders to Anadarko in 2008 and 2009 to pay “past-due” royalties and interest covering several deepwater Gulf of Mexico leases. Anadarko filed administrative appeals with the MMS for the 2008 and 2009 orders (which were stayed pending a final non-appealable judgment relating to the 2006 Order). As a result of the Supreme Court’s denial of certiorari, the MMS notified Anadarko on February 25, 2010, that the 2008 and 2009 orders had been withdrawn.

Guarantees and Indemnifications Under the terms of the MSA entered into between Kerr-McGee and Tronox, Kerr-McGee agreed to reimburse Tronox for 50% of certain qualifying environmental-remediation costs incurred and paid by Tronox and its subsidiaries before November 28, 2012, subject to certain limitations and conditions. The reimbursement obligation under the MSA was limited to a maximum aggregate reimbursement of $100 million. During the quarter ended September 30, 2010, the Company reversed to non-operating income the remaining $95 million liability recorded for this reimbursement obligation as a result of a court-authorized rejection of the MSA. See Litigation section of this Note 12.

The Company also provides certain indemnifications in relation to asset dispositions. These indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. In connection with the 2006 sale of its Canadian subsidiary, the Company indemnified the purchaser for audit adjustments that may be imposed by the Canadian taxing authorities for periods prior to the sale. At September 30, 2010, other long-term liabilities include a $53 million liability for this contingency. The Company believes it is probable that the remaining indemnification will be settled with the purchaser in cash.

Other The Company’s Consolidated Balance Sheets at September 30, 2010, include a long-term asset and corresponding long-term liability of $237 million, representing the Company’s 27% ownership in and obligation for construction costs to date of a floating production, storage and offloading vessel (FPSO) to be used in its Ghana operations. At December 31, 2009, the Company’s Consolidated Balance Sheets include a liability of $129 million for the Company’s share of FPSO construction costs incurred through December 31, 2009. In May 2010, a lease agreement was executed by the FPSO operator, with lease commencement expected to occur in the fourth quarter 2010, once the vessel has been delivered and accepted. The Company expects to record a capital lease asset and obligation when the lease term begins.

The Company is subject to other legal proceedings, claims and liabilities which arise in the ordinary course of its business. In the opinion of Anadarko, the liability (if any) with respect to these claims will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state and local laws and regulations. At September 30, 2010, the Company’s Consolidated Balance Sheets include an $89 million liability for remediation and reclamation obligations. The Company continually monitors the remediation and reclamation process and adjusts its liability for these obligations as necessary.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

13. Income Taxes

The following table is a summary of the Company’s income tax expense (benefit) and effective tax rates.


	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2010			2009			2010			2009
Income tax expense (benefit)	$	94		$	207		$	660		$	(142)
Effective tax rate		109	%		50	%		49	%		29	%

The increase from the 35% statutory rate for the three months ended September 30, 2010, is primarily attributable to tax expense associated with the accrual of the Algerian exceptional profits tax (which is non-deductible for Algerian income tax purposes), U.S. tax on foreign income inclusions and distributions, other foreign taxes in excess of the federal statutory rate, and the unfavorable resolution of tax contingencies. This increase in the effective tax rate is partially reduced by U.S. income tax benefits associated with foreign exploration, the federal manufacturing deduction, state income taxes and other items. The increase in the Company’s effective tax rate as compared to the 35% statutory rate for the nine months ended September 30, 2010, is primarily attributable to the accrual of the Algerian exceptional profits tax, U.S. tax on foreign income inclusions and distributions, other foreign taxes in excess of the federal statutory rate, state income taxes and the unfavorable resolution of tax contingencies. This increase in the effective tax rate is partially reduced by U.S. income tax benefits associated with foreign exploration, the federal manufacturing deduction and other items.

The increase from the 35% statutory rate for the three months ended September 30, 2009, is primarily attributable to the accrual of the Algerian exceptional profits tax, U.S. tax on foreign income inclusions and distributions, other foreign taxes in excess of the federal statutory rate, and changes in tax contingencies, partially reduced by U.S. income tax benefits associated with foreign exploration, state income taxes and other items. The decrease from the 35% statutory rate for the nine months ended September 30, 2009, is primarily attributable to benefits associated with changes in tax contingencies and state income taxes, partially reduced by the accrual of the Algerian exceptional profits tax, other foreign taxes in excess of the federal statutory rate, U.S. tax on foreign income inclusions and distributions, and other items.

14. Supplemental Cash Flow Information

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


	Nine Months Ended September 30,
millions	2010		2009
Cash paid:
Interest	$	579	$	593
Income taxes	$	209	$	145
Non-cash investing activities:
Fair value of properties and equipment received in non-cash exchange transactions	$	32	$	39

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information

Anadarko’s primary business segments are vertically integrated within the oil and gas industry. These segments are separately managed due to distinct operational differences and unique technology, distribution and marketing requirements. The Company’s three reportable operating segments are oil and gas exploration and production, midstream, and marketing. The 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, gas and NGLs production. The marketing segment sells most of Anadarko’s production, as well as third-party purchased volumes.

To assess the operating results of Anadarko’s segments, the chief operating decision maker analyzes income (loss) before income taxes, interest expense, exploration expense, depreciation, depletion and amortization (DD&A) expense and impairments, less net income attributable to noncontrolling interests (Adjusted EBITDAX). Anadarko’s definition of Adjusted EBITDAX excludes exploration expense, as exploration expense is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A expense 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. The Company’s definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions to stockholders.

Adjusted EBITDAX may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income or cash flow 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	2010		2009		2010		2009
Income (loss) before income taxes	$	86	$	413	$	1,352	$	(483)
Exploration expense		296		224		649		813
Depreciation, depletion and amortization expense		962		909		2,845		2,648
Impairments		20		5		147		79
Interest expense		218		121		642		504
Less: Net income attributable to noncontrolling interests		18		6		42		23

Consolidated Adjusted EBITDAX	$	1,564	$	1,666	$	5,593	$	3,538

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information (Continued)

The following table presents selected financial information for Anadarko’s operating segments. Information presented below as “Other and Intersegment Eliminations” includes results from hard minerals non-operated joint ventures and royalty arrangements, operating activities that are not considered operating segments, as well as corporate, financing and certain hedging activities.


millions	Oil and Gas Exploration & Production		Midstream		Marketing		Other and Intersegment Eliminations		Total
Three Months Ended September 30, 2010:
Sales revenues	$	1,320	$	45	$	1,151	$	—	$	2,516
Intersegment revenues		950		198		(1,051)		(97)		—
Gains (losses) on divestitures and other, net		(3)		—		—		37		34

Total revenues and other		2,267		243		100		(60)		2,550

Operating costs and expenses⁽¹⁾		750		127		116		83		1,076
(Gains) losses on commodity derivatives, net		—		—		—		(200)		(200)
(Gains) losses on other derivatives, net		—		—		—		221		221
Other (income) expense, net		—		—		—		(129)		(129)
Net income attributable to noncontrolling interests		—		18		—		—		18

Total		750		145		116		(25)		986

Adjusted EBITDAX	$	1,517	$	98	$	(16)	$	(35)	$	1,564


Three Months Ended September 30, 2009:
Sales revenues	$	1,092	$	49	$	1,026	$	—	$	2,167
Intersegment revenues		835		178		(931)		(82)		—
Gains (losses) on divestitures and other, net		27		(1)		—		24		50
Reversal of accrual for DWRRA dispute		657		—		—		—		657

Total revenues and other		2,611		226		95		(58)		2,874

Operating costs and expenses⁽¹⁾		646		135		121		55		957
(Gains) losses on commodity derivatives, net		—		—		—		134		134
(Gains) losses on other derivatives, net		—		—		—		131		131
Other (income) expense, net		—		—		—		(20)		(20)
Net income attributable to noncontrolling interests		—		6		—		—		6

Total		646		141		121		300		1,208

Adjusted EBITDAX	$	1,965	$	85	$	(26)	$	(358)	$	1,666

⁽¹⁾	Operating costs and expenses exclude exploration, DD&A and impairment expenses since these expenses are excluded from Adjusted EBITDAX.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information (Continued)


millions	Oil and Gas Exploration & Production		Midstream		Marketing		Other and Intersegment Eliminations		Total
Nine Months Ended September 30, 2010:
Sales revenues	$	4,116	$	145	$	3,948	$	—	$	8,209
Intersegment revenues		3,259		630		(3,593)		(296)		—
Gains (losses) on divestitures and other, net		(15)		—		—		99		84

Total revenues and other		7,360		775		355		(197)		8,293

Operating costs and expenses ⁽¹⁾		2,228		444		349		139		3,160
(Gains) losses on commodity derivatives, net		—		—		—		(1,052)		(1,052)
(Gains) losses on other derivatives, net		—		—		—		656		656
Other (income) expense, net		—		—		—		(106)		(106)
Net income attributable to noncontrolling interests		—		42		—		—		42

Total		2,228		486		349		(363)		2,700

Adjusted EBITDAX	$	5,132	$	289	$	6	$	166	$	5,593


Nine Months Ended September 30, 2009:
Sales revenues	$	2,372	$	172	$	3,268	$	—	$	5,812
Intersegment revenues		2,659		511		(2,913)		(257)		—
Gains (losses) on divestitures and other, net		41		3		—		70		114
Reversal of accrual for DWRRA dispute		657		—		—		—		657

Total revenues and other		5,729		686		355		(187)		6,583

Operating costs and expenses⁽¹⁾		1,887		423		356		191		2,857
(Gains) losses on commodity derivatives, net		—		—		—		503		503
(Gains) losses on other derivatives, net		—		—		—		(315)		(315)
Other (income) expense, net		—		—		—		(23)		(23)
Net income attributable to noncontrolling interests		—		23		—		—		23

Total		1,887		446		356		356		3,045

Adjusted EBITDAX	$	3,842	$	240	$	(1)	$	(543)	$	3,538

⁽¹⁾	Operating costs and expenses exclude exploration, DD&A and impairment expenses since these expenses are excluded from Adjusted EBITDAX.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

16. Pension Plans and Other Postretirement Benefits

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

During the nine months ended September 30, 2010, the Company made contributions of $89 million to its funded pension plans, $7 million to its unfunded pension plans and $15 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 2010, the Company expects to contribute $2 million to its funded pension plans, $12 million to its unfunded pension plans and $4 million to its unfunded other postretirement benefit plans.

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


	Pension Benefits				Other Benefits
	Three Months Ended September 30,				Three Months Ended September 30,
millions	2010		2009		2010		2009
Components of net periodic benefit cost
Service cost	$	17	$	13	$	3	$	1
Interest cost		21		20		4		4
Expected return on plan assets		(21)		(17)		—		—
Amortization of actuarial loss (gain)		16		11		(1)		—
Amortization of prior service cost (credit)		1		—		—		—

Net periodic benefit cost	$	34	$	27	$	6	$	5


	Pension Benefits				Other Benefits
	Nine Months Ended September 30,				Nine Months Ended September 30,
millions	2010		2009		2010		2009
Components of net periodic benefit cost
Service cost	$	52	$	40	$	7	$	6
Interest cost		63		59		12		13
Expected return on plan assets		(62)		(53)		—		—
Amortization of actuarial loss (gain)		48		36		(2)		(1)
Amortization of prior service cost (credit)		2		1		(1)		(1)
Settlements		—		10		—		—

Net periodic benefit cost	$	103	$	93	$	16	$	17

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

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, 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 and the price of natural gas, 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 and foreign and local environmental laws and regulations;

•

the outcome of events in the Gulf of Mexico related to the Deepwater Horizon events;

•

the success of BP Exploration & Production Inc.’s (BP) response and clean-up efforts related to the Deepwater Horizon events;

•

current and potential legal proceedings, and environmental or other obligations arising from the Deepwater Horizon events, the Oil Pollution Act of 1990 (OPA) and other regulatory obligations, and the joint operating agreement (JOA) for the Macondo well;

•

the legislative and regulatory changes, such as delays in the processing and approval of drilling permits, that may impact the Company’s Gulf of Mexico and International offshore operations resulting from the deepwater drilling moratoria (collectively, the Moratorium), which was recently lifted;

•

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

•

the creditworthiness of the Company’s financial counterparties and operating partners;

•

the securities, capital or credit markets;

•

the Company’s ability to repay its debt;

•

the impact of downgrades to the Company’s credit rating, the ability of the Company to post required collateral, if requested, and the Company’s ability to improve its credit rating;

•

the outcome of any proceedings related to the Algerian exceptional profits tax; and

•

other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates” included in the Company’s 2009 Annual Report on Form 10-K, the Company’s Quarterly Report on Form 10-Q for the quarters ended March 31 and June 30, 2010, 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 Item 1, and the information set forth in Risk Factors under Item 1A, as well as the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Item 8 of the 2009 Annual Report on Form 10-K, and the information set forth in Risk Factors under Item 1A of the 2009 Annual Report on Form 10-K.

OVERVIEW

Anadarko Petroleum Corporation is among the world’s largest independent oil and natural-gas exploration and production companies. Anadarko is engaged in the exploration, development, production and marketing of natural gas, crude oil, condensate and NGLs. The Company also engages in the gathering, processing and treating of natural gas, and transporting natural gas, crude oil and NGLs. The Company’s operations are located in the United States, Algeria, Brazil, China, Cote d’Ivoire, Ghana, Indonesia, Mozambique, Sierra Leone and several other countries. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

DEEPWATER HORIZON EVENTS

DEEPWATER DRILLING MORATORIUM AND OTHER RELATED MATTERS

Anadarko ceased all drilling operations in the Gulf of Mexico in accordance with the Moratorium, which resulted in the suspension of operations of two operated deepwater wells (Lucius and Nansen) and one non-operated deepwater well (Vito). The Moratorium was lifted effective October 12, 2010, but the Company is unable to resume drilling operations until the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) approves new drilling permits. Refer to Note 3—Deepwater Drilling Moratorium and Other Related Matters in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information on the Moratorium.

OPERATING HIGHLIGHTS

Significant operational highlights by area during the third quarter of 2010 include the following:

United States Onshore

•

The Company’s Rocky Mountain Region (Rockies) achieved third-quarter sales volumes of 274 thousand barrels of oil equivalent per day (MBOE/d), representing a 10% increase over the third quarter of 2009.

•

The Company’s Southern and Appalachia Region achieved third-quarter sales volumes of 128 MBOE/d, representing a 9% increase over the third quarter of 2009.

Gulf of Mexico

•

For information on the Deepwater Horizon events, see Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

•

There was no drilling activity in the third quarter due to the Moratorium, see Note 3—Deepwater Drilling Moratorium and Other Related Matters in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

•

The Company’s Gulf of Mexico third-quarter sales volumes were 148 MBOE/d, representing a 9% decrease from the third quarter of 2009.

International

•

The Owo discovery well (18% working interest) encountered 174 net feet of high-quality oil pay in the Deepwater Tano Block offshore Ghana.

•

The Owo sidetrack well (18% working interest) encountered an additional 115 net feet of pay in the Deepwater Tano Block offshore Ghana, including 52 net feet of high-quality oil pay, 43 net feet of condensate pay and 20 net feet of natural gas pay.

•

The Ironclad prospect (43% working interest) in Mozambique was drilled to a total depth of 17,400 feet. The well encountered oil saturated sands in a tight reservoir, but did not encounter commercial quantities of hydrocarbons and was plugged and abandoned.

•

The Wahoo South well offshore Brazil in BM-C-30 (30% working interest) was drilled to a depth of 17,056 feet. Hydrocarbons were encountered; however, the evaluation program did not prove the hydrocarbons to be recoverable and the well was plugged and abandoned.

FINANCIAL HIGHLIGHTS

Significant financial highlights during the third quarter of 2010 include the following:

•

The Company generated $1.0 billion of cash flow from operations and ended the quarter with $4.2 billion of cash on hand.

•

In August 2010, the Company completed a public offering of $2.0 billion of 6.375% Senior Notes due 2017 (the $2.0 billion Senior Notes), and used a portion of the net proceeds to retire $1.3 billion of outstanding indebtedness maturing in 2012. Also, in October 2010, the Company redeemed $422 million of 6.750% Senior Notes due in May 2011.

•

In September 2010, the Company entered into a five-year $5.0 billion senior secured revolving credit facility (the $5.0 billion Facility), which replaced the Company’s $1.3 billion revolving credit agreement scheduled to mature in 2013.

The following discussion pertains to Anadarko’s financial condition, results of operations and changes in financial condition. Any increases or decreases “for the three months ended September 30, 2010” refer to the comparison of the three months ended September 30, 2010 to the three months ended September 30, 2009, and any increases or decreases “for the nine months ended September 30, 2010” refer to the comparison of the nine months ended September 30, 2010 to the nine months ended September 30, 2009. The primary factors that affect the Company’s results of operations include, among other things, commodity prices for natural gas, crude oil and NGLs, sales volumes, the Company’s ability to discover additional oil and natural-gas reserves, the cost of finding such reserves, and operating costs.

RESULTS OF OPERATIONS

Selected Data


	Three Months Ended September 30,				Nine Months Ended September 30,
millions except per-share amounts	2010		2009		2010		2009
Financial Results
Total revenues and other⁽¹⁾	$	2,550	$	2,874	$	8,293	$	6,583
Costs and expenses		2,354		2,095		6,801		6,397
Other (income) expense⁽¹⁾		110		366		140		669
Income tax expense (benefit)		94		207		660		(142)
Net income (loss) attributable to common stockholders	$	(26)	$	200	$	650	$	(364)
Net income (loss) per common share attributable to common stockholders - diluted	$	(0.05)	$	0.40	$	1.30	$	(0.77)
Average number of common shares outstanding - diluted		496		493		496		476
Operating Results
Adjusted EBITDAX⁽²⁾	$	1,564	$	1,666	$	5,593	$	3,538
Sales volumes (MMBOE)		58		57		179		167

MMBOE—million barrels of oil equivalent

⁽¹⁾

Commodity derivative activity previously reported in Total revenues and other, has been reclassified to Other (income) expense. See Basis of Presentation in Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

⁽²⁾	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 third quarter of 2010, Anadarko’s net loss attributable to common stockholders was $26 million or $0.05 per share (diluted). This compares to net income attributable to common stockholders of $200 million or $0.40 per share (diluted) for the third quarter of 2009. For the nine months ended September 30, 2010, Anadarko’s net income attributable to common stockholders was $650 million or $1.30 per share (diluted), compared to a net loss attributable to common stockholders of $364 million or $0.77 per share (diluted) for the same period of 2009.

Sales Revenues, Volumes and Prices


	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
Gas sales	$	809		32 %	$	614	$	2,692		25 %	$	2,148
Oil and condensate sales		1,298		7		1,218		4,138		49		2,768
Natural-gas liquid sales		227		37		166		736		102		365

Total	$	2,334		17	$	1,998	$	7,566		43	$	5,281

Anadarko’s sales revenues for the three and nine months ended September 30, 2010, increased primarily due to higher commodity prices and increased production volumes, as follows:


	Three Months Ended September 30,
millions	Natural Gas		Oil and Condensate		NGLs		Total
2009 sales revenues	$	614	$	1,218	$	166	$	1,998
Changes associated with sales volumes		25		(80)		34		(21)
Changes associated with prices		170		160		27		357

2010 sales revenues	$	809	$	1,298	$	227	$	2,334


	Nine Months Ended September 30,
	Natural Gas		Oil and Condensate		NGLs		Total
2009 sales revenues	$	2,148	$	2,768	$	365	$	5,281
Changes associated with sales volumes		49		249		145		443
Changes associated with prices		495		1,121		226		1,842

2010 sales revenues	$	2,692	$	4,138	$	736	$	7,566

The following table provides Anadarko’s sales volumes for the three and nine months ended September 30, 2010, compared to 2009.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
Barrels of Oil Equivalent
(MMBOE except percentages)
United States		52		4 %		51		160		8 %		148
International		6		(11)		6		19		1		19

Total		58		2		57		179		7		167


Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States		568		4		547		584		8		541
International		61		(11)		69		71		1		70

Total		629		2		616		655		7		611

Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Other (Income) Expense—(Gains) Losses on Commodity Derivatives, net below. Production of natural gas, crude oil and NGLs is usually 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,
	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
United States
Sales volumes—Bcf		205		4 %		197		632		2 %		618
MMcf/d		2,234		4		2,144		2,316		2		2,264
Price per Mcf	$	3.94		27	$	3.11	$	4.26		23	$	3.47
Gas sales revenues (millions)	$	809		32	$	614	$	2,692		25	$	2,148

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

The Company’s daily natural-gas sales volumes increased 90 MMcf/d for the three months ended September 30, 2010. This increase was primarily a result of higher volumes in the Rockies due to increased drilling activity, partially offset by lower sales volumes related to maintenance downtime in the Gulf of Mexico. The Company’s daily natural-gas sales volumes increased 52 MMcf/d for the nine months ended September 30, 2010. The increase resulted from higher volumes in the Rockies as discussed above and increased drilling in the Maverick Basin, Haynesville Shale and Marcellus Shale.

The average natural-gas price Anadarko received increased for the three and nine months ended September 30, 2010, primarily attributable to an increase in demand.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
United States
Sales volumes—MMBbls		12		(4)%		13		37		14 %		32
MBbls/d		131		(4)		136		133		14		117
Price per barrel	$	72.65		14	$	63.75	$	73.85		37	$	53.73

International
Sales volumes—MMBbls		6		(11)%		6		19		1 %		19
MBbls/d		61		(11)		69		71		1		70
Price per barrel	$	75.83		14	$	66.28	$	75.66		37	$	55.27

Total
Sales volumes—MMBbls		18		(6)%		19		56		9 %		51
MBbls/d		192		(6)		205		204		9		187
Total price per barrel	$	73.67		14	$	64.60	$	74.48		37	$	54.31
Total oil and condensate sales revenues (millions)	$	1,298		7	$	1,218	$	4,138		49	$	2,768

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s daily crude-oil and condensate sales volumes decreased 13 MBbls/d for the three months ended September 30, 2010, primarily due to natural production declines and construction downtime in the Gulf of Mexico, and scheduling of cargo liftings in Algeria. Partially offsetting these decreases were increases in crude-oil sales volumes as a result of the Company’s migration from drilling in dry-gas areas to drilling in liquid-rich areas in the Rockies and Southern and Appalachia Region. Anadarko’s daily crude-oil and condensate sales volumes increased 17 MBbls/d for the nine months ended September 30, 2010. This increase was primarily due to higher crude-oil sales volumes of 12 MBbls/d in the Gulf of Mexico due to the third-quarter 2009 completion of repairs to third-party downstream infrastructure that was damaged during the 2008 hurricane season, and additional production that came online during the second quarter of 2009. In addition, crude-oil sales volumes increased due to the migration from drilling in dry-gas areas to drilling in liquid-rich areas in the Rockies and Southern and Appalachia Region.

Anadarko’s average crude-oil price increased for the three and nine months ended September 30, 2010, as a result of increased global demand.

Natural-Gas Liquids Sales Volumes, Average Prices and Revenues


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
United States
Sales volumes—MMBbls		6		21 %		5		18		40 %		13
MBbls/d		65		21		54		65		40		47
Price per barrel	$	38.11		14	$	33.41	$	41.23		44	$	28.58
Natural-gas liquids sales revenues (millions)	$	227		37	$	166	$	736		102	$	365

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. The Company’s daily NGLs sales volumes for the three and nine months ended September 30, 2010, increased 11 MBbls/d and 18 MBbls/d, respectively. These increases were primarily driven by operations in the Rockies where natural-gas production increased, an additional natural-gas processing train was brought online late in the second quarter of 2009 and new processing agreements were entered into late in 2009, partially offset by maintenance downtime on a natural-gas processing train in the Rockies during the three months ended September 30, 2010.

The average NGLs price increased for the three and nine months ended September 30, 2010, primarily due to higher crude-oil prices and sustained global petrochemical demand.

Gathering, Processing and Marketing Margin


	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
Gathering, processing and marketing sales	$	182		8 %	$	169	$	643		21 %	$	531
Gathering, processing and marketing expenses		134		(11)		151		466		(1)		469

Margin	$	48		167	$	18	$	177		185	$	62

For the three months ended September 30, 2010, gathering, processing and marketing margin increased $30 million primarily due to higher margins on natural-gas sales from inventory and lower transportation costs. For the nine months ended September 30, 2010, gathering, processing and marketing margin increased $115 million primarily due to higher prices for NGLs and condensate, which increased revenue under percent-of-proceeds and keep-whole contracts, higher margins and volumes associated with natural-gas sales from inventory, and lower transportation costs, partially offset by an increase in cost of product as well as the absence of gas-processing margins associated with assets divested in 2009.

Reversal of Accrual for DWRRA Dispute

In January 2006, the Department of the Interior (DOI) issued an order (the 2006 Order) to Kerr-McGee Oil and Gas Corporation (KMOG), a subsidiary of Kerr-McGee Corporation (Kerr-McGee), to pay oil and gas royalties and accrued interest on KMOG’s deepwater Gulf of Mexico production associated with eight 1996, 1997 and 2000 leases, for which KMOG considered royalties to be suspended under the Deepwater Royalty Relief Act (DWRRA). KMOG successfully appealed the 2006 Order, and the DOI’s petition for a writ of certiorari with the United States Supreme Court was denied on October 5, 2009.

Based on the U.S. Supreme Court’s denial of the DOI’s petition for review by the court, Anadarko reversed its $657 million accrued liability in the third quarter of 2009 for royalties on leases listed in the 2006 order, as well as on similar orders to pay issued in 2008 and 2009, and other deepwater Gulf of Mexico leases with similar price threshold provisions. In addition, the Company reversed its $78 million accrued liability for unpaid interest on these amounts in the third quarter of 2009. For more information on the DWRRA dispute, see Note 12—Commitments and Contingencies - Deepwater Royalty Relief Act in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Costs and Expenses


	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
Oil and gas operating	$	207		3 %	$	201	$	590		(11)%	$	660
Oil and gas transportation and other		220		30		169		607		15		527
Exploration		296		32		224		649		(20)		813

For the three months ended September 30, 2010, oil and gas operating expenses increased primarily due to increased production in the Rockies and Southern and Appalachia Region. For the nine months ended September 30, 2010, oil and gas operating expenses decreased primarily due to cost savings that continued to be realized from programs initiated in response to lower commodity prices in early 2009. These cost savings programs included deferrals of certain workovers, favorable vendor negotiations and other operating efficiencies. Oil and gas operating expenses also decreased due to lower surface maintenance and outside-operated expenses in the Gulf of Mexico, primarily due to timing of well work.

For the three and nine months ended September 30, 2010, oil and gas transportation and other expenses increased primarily due to higher gas gathering and transportation costs attributable to increased production in both the Rockies and Southern and Appalachia Region, and the expensing of drilling rig lease payments of $15 million and $27 million, respectively, that would have been capitalized as drilling costs if the rigs had not been prohibited from drilling due to the Moratorium. See Note 3—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 discussion regarding the Company’s decision to invoke force majeure on certain drilling rigs in the Gulf of Mexico. Partially offsetting the increase in oil and gas transportation and other expenses for the nine months ended September 30, 2010, were costs associated with drilling rig contract termination fees incurred in 2009 as a result of lower commodity prices in 2009.

Exploration expense increased by $72 million for the three months ended September 30, 2010, primarily due to dry hole expense in Mozambique of $39 million and Brazil of $34 million. Exploration expense decreased by $164 million for the nine months ended September 30, 2010, primarily due to $159 million lower dry hole expense in the Gulf of Mexico, lower impairments of unproved properties of $22 million, primarily in Nigeria and China, and termination costs of $19 million incurred in connection with the Company’s 2009 exit from Nigeria, partially offset by higher dry hole expense in various other international locations of $53 million, including Brazil and Mozambique as discussed above.


	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
General and administrative	$	275		23 %	$	223	$	688		5 %	$	658
Depreciation, depletion and amortization		962		6		909		2,845		7		2,648
Other taxes		240		13		213		809		49		543
Impairments		20		NM		5		147		86		79

NM—percentage change does not provide

meaningful information

For the three and nine months ended September 30, 2010, general and administrative (G&A) expense increased primarily due to legal fees, insurance, and employee expenses related to salaries, bonus and benefit plans.

For the three months ended September 30, 2010, depreciation, depletion and amortization (DD&A) expense included $70 million associated with a depleted field in the Gulf of Mexico. For the nine months ended September 30, 2010, DD&A expense increased by $197 million of which $146 million was due to higher sales volumes and $70 million related to the fully depleted field mentioned above.

For the three months ended September 30, 2010, other taxes increased primarily due to higher commodity prices and higher gas and NGLs volumes resulting in increased United States production and severance taxes of $19 million and Chinese windfall profits tax of $6 million, as well as increased ad valorem taxes of $6 million primarily due to higher assessed property values. For the nine months ended September 30, 2010, other taxes increased primarily due to higher commodity prices and higher volumes resulting in increased United States production and severance taxes of $111 million, Algerian exceptional profits tax expense of $91 million and Chinese windfall profits tax of $30 million, as well as increased ad valorem taxes of $32 million primarily due to higher assessed property values.

Impairments for the three months ended September 30, 2010, were primarily attributable to $18 million of oil and gas exploration and production operating segment properties located in the United States. Impairments for the three months ended September 30, 2009, included $5 million of marketing operating segment intangible assets related to certain transportation contracts that declined in value due to decreased margins between certain market locations. Impairments for the nine months ended September 30, 2010, included $137 million of oil and gas exploration and production operating segment properties located in the United States, $114 million of which related to a production platform that remains idle with no immediate plan for use, and for which a limited market currently exists. The platform was impaired to its estimated fair value of $25 million. Impairments for the nine months ended September 30, 2009, included $74 million of marketing operating segment intangible assets and $5 million oil and gas exploration and production operating segment properties located in the United States. The marketing operating segment impairments related to certain transportation contracts that declined in value due to decreased margins between certain market locations. The oil and gas exploration and production operating segment impairments were primarily a result of the economic and commodity price environment.

Other (Income) Expense


	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
Interest Expense
Current debt, long-term debt and other	$	224		74 %	$	129	$	618		18 %	$	522
Midstream subsidiary note payable to a related party		11		22		9		24		(25)		32
(Gain) loss on early debt retirements and commitment termination		17		NM		—		89		NM		(2)
Capitalized interest		(34)		100		(17)		(89)		85		(48)

Interest Expense	$	218		80	$	121	$	642		27	$	504

For the three and nine months ended September 30, 2010, interest expense increased $97 million and $138 million, respectively, primarily due to the reversal of $78 million in the third quarter of 2009 for previously accrued interest expense related to the DWRRA dispute, $17 million of costs expensed in September 2010 in connection with the termination of a previously contemplated term-loan facility, and $7 million of expensed unamortized debt issuance costs, the recognition of which was triggered by the retirement of the Midstream Subsidiary Note Payable to a Related Party due 2012 (Midstream Subsidiary Note) in August 2010. Also, for the nine months ended September 30, 2010, interest expense included losses on early retirements of debt of $72 million, resulting from the repurchase of $1.0 billion aggregate principal amount of senior notes pursuant to the Company’s first-quarter 2010 tender offer. These increases were partially offset by increases in capitalized interest primarily due to higher construction-in-progress balances related to long-term capital projects. 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 except percentages	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
(Gains) Losses on Commodity Derivatives, net
Realized (gains) losses
Natural gas	$	(155)		72 %	$	(90)	$	(337)		27 %	$	(266)
Oil and condensate		(2)		(33)		(3)		(2)		(96)		(48)

Total realized (gains) losses		(157)		69		(93)		(339)		8		(314)

Unrealized (gains) losses
Natural gas		(122)		147		257		(522)		182		634
Oil and condensate		79		NM		(30)		(191)		NM		183

Total unrealized (gains) losses		(43)		119		227		(713)		187		817

Total (gain) loss on commodity derivatives, net	$	(200)		NM	$	134	$	(1,052)		NM	$	503

The Company utilizes commodity derivative instruments to manage the risk of a decrease in the market prices for its anticipated sales of natural gas and crude oil. The change in (gain) loss on commodity derivatives, net includes the impact of derivatives entered into or settled and price changes related to open positions at September 30 of each year. For additional information on (gains) losses on commodity derivatives, see Note 9—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	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
(Gains) Losses on Other Derivatives, net
Realized (gains) losses - interest rate derivatives and other	$	—		100 %	$	5	$	—		(100)%	$	(525)
Unrealized (gains) losses - interest rate derivatives and other		221		(75)		126		656		NM		210

Total (gain) loss on other derivatives, net	$	221		(69)	$	131	$	656		NM	$	(315)

Anadarko enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to mitigate exposure to unfavorable interest-rate changes. In December 2008, Anadarko entered into interest-rate swap contracts as a fixed-rate payor to mitigate the cost of potential 2011 and 2012 debt issuances. During periods of declining ten- and thirty-year U.S. Treasury yields, the fair value of this swap portfolio declines, which occurred during the three months ended September 30, 2009 and 2010, and the nine months ended September 30, 2010. Conversely, when ten- and thirty-year U.S. Treasury yields rise, the fair value of this swap portfolio increases, which occurred during the nine months ended September 30, 2009. For additional information, see Note 9—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	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
Other (Income) Expense, net
Interest income	$	(3)		50 %	$	(2)	$	(10)		(38)%	$	(16)
Other		(126)		NM		(18)		(96)		NM		(7)

Total other (income) expense, net	$	(129)		NM	$	(20)	$	(106)		NM	$	(23)

Under the terms of the Master Separation Agreement (together with all annexes, related agreements, and ancillary agreements thereto, the MSA) entered into between Kerr-McGee and Tronox, a former wholly owned subsidiary of Kerr-McGee that held Kerr-McGee’s chemical business, Kerr-McGee agreed to reimburse Tronox for 50% of certain qualifying environmental-remediation costs incurred and paid by Tronox and its subsidiaries before November 28, 2012, subject to certain limitations and conditions. The reimbursement obligation under the MSA was limited to a maximum aggregate reimbursement of $100 million. During the quarter ended September 30, 2010, the Company reversed the remaining $95 million liability for the reimbursement obligation that was provided by Kerr-McGee to Tronox pursuant to the terms of the MSA. See Note 12—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for further discussion of events related to Tronox and this obligation.

In addition, foreign currency gains increased other income for the three months ended September 30, 2010, primarily related to exchange-rate changes applicable to foreign currency purchased in anticipation of funding future expenditures on major development projects. For the nine months ended September 30, 2010, other income also increased due to lower legal accruals. In addition, foreign currency losses decreased other income for the nine months ended September 30, 2010, primarily attributable to cash held in escrow pending final determination of the Company’s Brazilian tax liability attributable to its 2008 divestiture of Peregrino field offshore Brazil.

Income Tax Expense


	Three Months Ended September 30,				Nine Months Ended September 30,
millions except percentages	2010		2009		2010		2009
Income tax expense (benefit)	$	94	$	207	$	660	$	(142)
Effective tax rate		109 %		50 %		49 %		29 %

For the three months ended September 30, 2010, income tax expense decreased primarily due to a decrease in income before income taxes. For the nine months ended September 30, 2010, income tax expense increased primarily due to an increase in income before income taxes.

Net Income Attributable to Noncontrolling Interests

For the three and nine months ended September 30, 2010, the Company’s net income attributable to noncontrolling interests of $18 million and $42 million, respectively, primarily related to a 45.8% public ownership interest in Western Gas Partners, LP (WES), a consolidated subsidiary of the Company.

OPERATING RESULTS

Segment Analysis—Adjusted EBITDAX To assess the operating results of Anadarko’s segments, the chief operating decision maker analyzes income (loss) before income taxes, interest expense, exploration expense, DD&A expense and impairments, less net income attributable to noncontrolling interests (Adjusted EBITDAX). Anadarko’s definition of Adjusted EBITDAX, which is not a GAAP measure, excludes exploration expense, as exploration expense is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A expense 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. The Company’s definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. 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 flow 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.

Adjusted EBITDAX


	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2010		Inc/(Dec) vs. 2009		2009		2010		Inc/(Dec) vs. 2009		2009
Income (loss) before income taxes	$	86		(79)%	$	413	$	1,352		NM	$	(483)
Exploration expense		296		32		224		649		(20)%		813
Depreciation, depletion and amortization expense		962		6		909		2,845		7		2,648
Impairments		20		NM		5		147		86		79
Interest expense		218		80		121		642		27		504
Less: Net income attributable to noncontrolling interests		18		NM		6		42		83		23

Consolidated Adjusted EBITDAX	$	1,564		(6)	$	1,666	$	5,593		58	$	3,538

Adjusted EBITDAX by segment
Oil and gas exploration and production	$	1,517		(23)%	$	1,965	$	5,132		34 %	$	3,842
Midstream		98		15		85		289		20		240
Marketing		(16)		38		(26)		6		NM		(1)
Other and intersegment eliminations		(35)		90		(358)		166		131		(543)

Oil and Gas Exploration and Production Adjusted EBITDAX for the three months ended September 30, 2010, decreased due to the 2009 reversal of amounts previously accrued in connection with the DWRRA dispute, partially offset by the impact of higher commodity prices and higher sales volumes. Adjusted EBITDAX for the nine months ended September 30, 2010, increased primarily due to the impact of higher commodity prices and higher sales volumes, partially offset by the 2009 reversal of amounts previously accrued in connection with the DWRRA dispute.

Midstream The increase in Adjusted EBITDAX for the three months ended September 30, 2010, was primarily due to lower operating expenses and lower gathering and transportation expenses. The increase in Adjusted EBITDAX for the nine months ended September 30, 2010, resulted primarily from an increase in revenue due to higher prices for NGLs and condensate, which increased revenues earned under percent-of-proceeds and keep-whole contracts, partially offset by higher cost of product resulting from higher commodity prices and the absence of gas-processing margins associated with assets divested in 2009.

Marketing Marketing earnings primarily represent the margin earned on sales of natural gas, oil, and NGLs purchased from third parties. Adjusted EBITDAX for the three and nine months ended September 30, 2010, increased primarily due to higher margins and volumes associated with natural-gas sales from inventory, and lower transportation costs.

Other and Intersegment Eliminations Other and intersegment eliminations consist primarily of corporate costs, realized and unrealized gains and losses on derivatives and income from hard minerals investments and royalties. The increase in Adjusted EBITDAX for the three months ended September 30, 2010, was primarily due to higher realized and unrealized gains on commodity derivatives in 2010 and the reversal of the remaining $95 million liability for the reimbursement obligation that was provided by Kerr-McGee to Tronox pursuant to the terms of the MSA, partially offset by higher unrealized losses on interest-rate swaps in 2010. The increase in Adjusted EBITDAX for the nine months ended September 30, 2010, was primarily due to realized and unrealized gains on commodity derivatives in 2010 and the reversal of the remaining $95 million liability for the reimbursement obligation discussed above, partially offset by unrealized losses on interest-rate swaps in 2010 and realized gains on interest-rate swaps in 2009.

LIQUIDITY AND CAPITAL RESOURCES

Overview Anadarko manages its capital needs over the long term to fund capital expenditures, debt-service obligations, and dividend payments primarily from cash flows from operating activities, and enters into debt and equity transactions to maintain the desired capital structure and 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 first nine months of 2010, cash flow from operating activities and the issuance of the $2.0 billion Senior Notes were the primary means of generating cash. Anadarko used this cash primarily for capital investment and the repayment of existing debt, and had cash on hand of $4.2 billion at September 30, 2010. 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 conditions. During the third quarter of 2010, the Company further enhanced its liquidity in response to the Company’s potential exposure to future obligations related to the Deepwater Horizon events.

Liquidity Considerations The Company has a variety of funding sources available, including cash on hand of $4.2 billion at September 30, 2010, an asset portfolio that provides ongoing cash-flow-generating capacity and opportunities for liquidity enhancement through divestitures and joint venture arrangements. In addition, the Company has access to the $5.0 billion Facility, which was undrawn at September 30, 2010, and had remaining available capacity of $4.6 billion (net of $399 million of outstanding letters of credit). For further information, see Revolving Credit Facility below.

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 and, based on information currently available, any potential future obligations related to the Deepwater Horizon events. Anadarko is currently unable to predict the ultimate impact of the Deepwater Horizon events on the Company’s liquidity and financial condition. See Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

In September 2010, the Company entered into the $5.0 billion Facility, see Revolving Credit Facility below. In August 2010, Anadarko issued the $2.0 billion Senior Notes and used $1.3 billion of the proceeds to fully retire the Midstream Subsidiary Note. As a result of issuing the $2.0 billion Senior Notes, Anadarko did not enter into a previously contemplated term-loan facility. These transactions further enhanced Anadarko’s liquidity and financial flexibility by extending the maturity of a portion of the Company’s near-term maturities and significantly increasing the Company’s capacity for immediate access to capital through the $5.0 billion Facility.

Revolving Credit Facility In September 2010, the Company entered into the five-year $5.0 billion Facility, which replaced the Company’s $1.3 billion revolving credit agreement that was scheduled to mature in 2013.

Borrowings under the $5.0 billion Facility will bear interest, at the Company’s election, at (i) the London Interbank Offered Rate (LIBOR) plus a margin ranging from 2.75% to 3.75%, based on the Company’s credit rating, or (ii) the greatest of (a) the JPMorgan Chase Bank prime rate, (b) the federal funds rate plus 0.50%, and (c) one-month LIBOR plus 1%, and in each case, plus an applicable margin.

Obligations incurred under the $5.0 billion Facility, as well as certain obligations Anadarko has to lenders or their affiliates pursuant to certain derivative instruments as discussed in Note 9—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 of the Company’s exploration and production assets located in the United States and 65% of the capital stock of certain wholly owned foreign subsidiaries.

The Company incurred upfront underwriting, structuring, arrangement and other costs in connection with the $5.0 billion Facility. These costs were capitalized and will be amortized over the five-year credit commitment term. The cost of capital to the Company under the terms of the $5.0 billion Facility is greater than the cost of capital to the Company under the $1.3 billion revolving credit agreement previously in effect due to the increased size of the $5.0 billion Facility and higher borrowing margins. For example, outstanding borrowings under the $5.0 billion Facility at September 30, 2010, would bear a LIBOR-based interest rate margin of 2.75% as compared to a margin of 0.55% provided for under the $1.3 billion credit agreement previously in effect. Costs ultimately incurred under the $5.0 billion Facility will vary with the level of facility utilization, the ultimate borrowing terms and Anadarko’s corporate credit rating.

Near-Term Debt Maturities During the nine months ended September 30, 2010, the Company issued $2.8 billion aggregate principal amount of senior notes and used a portion of the net proceeds to retire the Midstream Subsidiary Note scheduled to mature in 2012 and $1.0 billion aggregate principal amount of senior notes scheduled to mature in 2011 and 2012. Further, in October 2010, the Company redeemed $422 million outstanding principal balance of 6.750% Senior Notes due in May 2011. The Company’s principal amount of near-term scheduled debt maturities after the October 2010 redemption is $285 million in 2011 and $480 million in 2012, totaling $765 million, or $1.5 billion including the Zero Coupons which could be put to the Company in 2012. The amount for 2012 includes $310 million of WES credit facility borrowings. The Company does not have any scheduled debt maturities for the remainder of 2010.

In a 2006 private offering, Anadarko received $500 million of loan proceeds upon issuing the Zero-Coupon Senior Notes due 2036 (the Zero Coupons) with an aggregate principal amount due at maturity of $2.4 billion, reflecting a yield to maturity of 5.24%. The holder elected not to exercise an option to put a portion of the then-accreted value of the Zero Coupons to Anadarko in October 2010. The holder does not have an option to put the Zero Coupons to Anadarko in 2011. However, the holder has the right to cause the Company to repay up to 100% of the then-accreted value of the Zero Coupons in October of each year starting in 2012. The accreted value of the Zero Coupons is expected to be approximately $680 million in October 2012.

The Company considers its cash-flow-generating capacity and access to additional liquidity sufficient to continue to satisfy the Company’s debt service and other obligations, including the potential early repayment of the Zero Coupons if the put option is exercised by the holder.

Effects of Credit Rating Downgrade As a consequence of uncertainties regarding the possible range of Anadarko’s potential obligations related to the Deepwater Horizon events, in June 2010, Moody’s Investor Service (Moody’s) lowered the Company’s senior unsecured credit rating from “Baa3” to “Ba1” and placed its long-term ratings under review for further possible downgrade (the credit rating downgrade), while S&P and Fitch each affirmed their “BBB-” rating with a negative outlook. In September 2010, Moody’s announced that it concluded its review and confirmed Anadarko’s “Ba1” credit rating and changed the rating outlook to stable.

As a result of the credit rating downgrade in June 2010, the Company’s credit thresholds with its derivative counterparties were reduced and in many cases eliminated. As a result, the Company has been required to increase the amount of collateral posted with derivative counterparties when the Company’s net derivative trading position is a liability. No counterparties have requested termination or full settlement of derivative positions. Entering into the $5.0 billion Facility permits certain of the Company’s derivative counterparties (those extending commitments under the $5.0 billion Facility) to receive security interests in specified assets of the Company, thereby reducing the Company’s requirements to post cash collateral for net derivative liability positions. The Company is actively negotiating the execution of security-interest amendments to the International Swaps and Derivatives Association, Inc. (ISDA) agreements with these counterparties. As these amendments are executed, the Company’s cash collateral requirements will decrease.

The credit rating downgrade also increases the likelihood of Anadarko being required to post collateral as financial assurance of its performance under other contractual arrangements, such as pipeline transportation contracts, oil and gas sales contracts and work commitments. As of September 30, 2010, $528 million of letters of credit were provided as assurance of the Company’s performance under various contractual arrangements and commitments, compared to $339 million at December 31, 2009.

WES Funding Sources Anadarko’s consolidated subsidiary, WES, has committed borrowing capacity of $450 million under its own senior unsecured revolving credit facility (RCF) which extends through October 2012. In connection with the August 2010 acquisition of certain midstream assets from Anadarko, WES borrowed $200 million under the RCF. Outstanding borrowings under the RCF, which bear interest at LIBOR plus an applicable margin ranging from 2.375% to 3.250% (2.63% at September 30, 2010), were $320 million at September 30, 2010, with $130 million remaining borrowing capacity. The credit rating downgrade of Anadarko did not affect the availability of credit or the cost of borrowing under the WES RCF.

Also in August 2010, WES borrowed $250 million under a three-year, unsecured term loan from a group of banks (the Term Loan). The Term Loan contains various customary covenants and bears interest at LIBOR plus an applicable margin ranging from 2.50% to 3.50% (for a rate of 3.26% at September 30, 2010) depending upon WES’s consolidated leverage ratio, as defined in the Term Loan agreement.

Insurance Coverage and Other Indemnities Anadarko maintains property and casualty insurance that includes coverage for physical damage to the Company’s properties, blowout/control of well, restoration and redrill, sudden and accidental pollution, third-party liability, workers’ compensation and employers’ liability, and other risks. The below-stated insurance limits for blowout/control of well and for third-party liabilities are reduced proportionally to Anadarko’s participating interest in a venture. Some of the below-stated limits are aggregate amounts, but most policies allow for reinstatement. Anadarko’s insurance coverage includes deductibles which must be met prior to recovery. Additionally, the Company’s insurance is subject to exclusions and limitations and there is no assurance that such coverage will adequately protect the Company against liability from all potential consequences and damages.

Anadarko’s property and casualty insurance policies renew in June of each year, with the next renewals scheduled for June 2011. In light of the Deepwater Horizon events, the Company may not be able to secure similar coverage for the same costs if at all. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that the Company considers economically acceptable. Refer to Note 2—Deepwater Horizon Events—Insurance Recoveries in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for discussion of the Company’s insurance coverage applicable to the Deepwater Horizon events.

The Company’s current insurance coverage, which was obtained subsequent to the Deepwater Horizon events, includes physical damage to Anadarko’s properties on a replacement cost basis; $500 million in limit for loss of production income for the Independence Hub facility; $500 million for an offshore blowout/control of well, restoration and redrill, and pollution from an offshore blowout ($75 million for onshore); $275 million aircraft liability; $675 million in limit for third-party liabilities. The Company’s total limit is approximately $1.2 billion (which is reduced proportionally to the Company’s participating interest in a venture) for the negative environmental impacts of an offshore blowout. If caused by a named windstorm, there is currently no coverage for physical damage to the Company’s properties, loss of production income for the Independence Hub facility, blowout/control of well, or restoration and redrill.

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

Following is a discussion of significant sources and uses of cash flows during the period. Forward-looking information related to the Company’s liquidity and capital resources is discussed in Outlook that follows.

Sources of Cash

Operating Activities Anadarko’s cash flow from operating activities during the nine months ended September 30, 2010, was $3.9 billion compared to $2.8 billion for the same period of 2009. The increase in 2010 cash flow is primarily attributable to higher commodity prices, higher sales volumes and the impact of changes in working capital items.

Fluctuations in commodity prices are the primary reason for the Company’s short-term changes in cash flow from operating activities; however, Anadarko enters into commodity derivative instruments that help to manage these fluctuations. Sales-volume changes also impact short-term cash flow, but have not been as volatile as commodity prices. Anadarko’s long-term cash flow from operating activities is dependent upon commodity prices, sales volumes, reserve replacement, the amount of costs and expenses required for continued operations and debt service, as well as any potential obligation to fund Deepwater Horizon event-related liabilities. Refer to Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for discussion and analysis of these events.

Investing Activities During the nine months ended September 30, 2010, Anadarko received proceeds of $44 million before income taxes related to several property divestiture transactions. Additionally, in connection with the retirement of the Midstream Subsidiary Note and the associated liquidation of Trinity Associates LLC (Trinity), Anadarko received $100 million cash representing the return of the Company’s original investment in Trinity.

Financing Activities During the nine months ended September 30, 2010, the Company received net proceeds of $2.7 billion related to the issuance of $2.8 billion aggregate principal amount of senior notes and used the net proceeds to redeem $2.6 billion aggregate principal amount of 2011 and 2012 debt maturities. See Uses of Cash for debt repayments.

As discussed in Revolving Credit Facility above, in September 2010, Anadarko entered into the $5.0 billion Facility. In connection with the $5.0 billion Facility, the Company incurred upfront underwriting, structuring, arrangement and other costs totaling $172 million. No borrowings were made under the $5.0 billion Facility upon closing and through the date of filing this Form 10-Q.

During the nine months ended September 30, 2010, Anadarko’s consolidated subsidiary, WES, borrowed a total of $670 million under the Term Loan and RCF to fund the acquisition of certain midstream assets from Anadarko. During the second quarter of 2010, WES issued approximately five million common units in a public offering, realizing net proceeds of $97 million, which WES used to repay a portion of its outstanding RCF borrowings.

During the nine months ended September 30, 2010, Anadarko realized $90 million from the issuance of common stock as a result of employee exercises of stock options and the associated income tax benefit, and used $35 million to repurchase a portion of shares of common stock issued to employees to satisfy withholding tax requirements.

Uses of Cash

In addition to ongoing funding of operating costs and expenses, including interest cost and taxes, Anadarko invests significant capital to acquire, explore and develop oil and natural-gas resources and midstream infrastructure, and makes debt repayments.

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


	Nine Months Ended September 30,
millions	2010		2009
Property acquisition
Exploration—unproved	$	457	$	55
Exploration		723		620
Development		2,262		1,897
Capitalized interest		87		42

Total oil and gas capital expenditures		3,529		2,614
Gathering, processing and marketing and other		363		256

Total capital expenditures*	$	3,892	$	2,870

* Capital expenditures in the table above are presented on an accrual basis. Additions to properties and equipment on the consolidated statements of cash flows include only those capital expenditures funded with cash payments during the period.

For the nine months ended September 30, 2010, Anadarko’s capital spending increased 36% primarily due to an increase in exploration lease acquisitions onshore and offshore United States, and higher expenditures related to construction, primarily in Algeria.

During the first quarter of 2010, the Company entered into a joint-venture agreement that requires a third-party joint-venture partner to fund up to $1.5 billion of Anadarko’s share of future acquisition, drilling, completion, equipment and other capital expenditures to earn a 32.5% interest in Anadarko’s Marcellus shale assets, primarily located in north-central Pennsylvania. As of September 30, 2010, $335 million of the total $1.5 billion has been funded.

Debt Retirements and Repayments In March and April 2010, Anadarko completed repurchases of $1.0 billion in aggregate principal of its outstanding debt, incurring $71 million of early-tender premium, which is included in interest expense.

In 2010, Anadarko’s wholly owned midstream subsidiary repaid the $1.6 billion Midstream Subsidiary Note, including retiring the remaining $1.3 billion balance in August 2010 funded with proceeds from the $2.0 billion Senior Notes offering. For additional information related to the Midstream Subsidiary Note, see Note 8—Investments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

During the second quarter of 2010, WES repaid $100 million outstanding under its RCF primarily from proceeds related to its public offering discussed in Sources of Cash.

In October 2010, Anadarko used $435 million to redeem the remaining $422 million principal amount of the Company’s 6.750% Senior Notes due May 2011. The Company has no scheduled debt maturities for the remainder of 2010.

Margin Deposits and Other Collateral Both exchange and over-the-counter traded derivative instruments may be subject to margin deposit requirements. Exchange-broker margin requirements are determined by a standard industry algorithm, which requires a market-risk-based margin level be maintained on positions outstanding from the date of trade execution through settlement. For derivatives with over-the-counter counterparties, the Company may be required to provide margin deposits for unrealized losses on derivative positions. The Company manages its exposure to over-the-counter margin requirements through negotiated credit arrangements with counterparties, which may include collateral caps. When credit thresholds are exceeded, the Company utilizes available cash or letters of credit to satisfy margin requirements and maintains sufficient available committed credit facilities to satisfy its obligations. With respect to its derivative instruments, the Company had margin deposits outstanding and held cash collateral from its counterparties of $229 million and $20 million, respectively, at September 30, 2010, and $105 million and zero, respectively, at December 31, 2009. For additional information on derivatives, see Effects of Credit Rating Downgrade above, and Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Common Stock Dividends and Distributions to Noncontrolling WES Interest Owners During the first nine months of 2010 and 2009, Anadarko paid $136 million and $131 million, respectively, in dividends to its common stockholders (nine cents per share quarterly in 2010 and 2009). Anadarko has paid a dividend to its common stockholders quarterly since becoming an independent public company in 1986. The amount of future dividends for Anadarko common stock will depend on earnings, financial conditions, capital requirements and other factors, and will be determined by the Board of Directors on a quarterly basis.

Anadarko’s consolidated subsidiary, WES, distributed to its unitholders other than Anadarko an aggregate of $30 million during the nine months ended September 30, 2010. 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 $0.33 per common unit for the fourth quarter of 2009 to $0.37 per common unit for the third quarter of 2010 (to be paid in November 2010).

Outlook

Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by exploring for, acquiring and developing oil and natural-gas resources vital to the world’s health and welfare. Anadarko employs the following strategy to achieve this mission:

•

identify and commercialize resources;

•

explore in a high-potential, proven basins;

•

employ a global business development approach; and

•

ensure financial discipline and flexibility.

Developing a portfolio of primarily unconventional resources provides the Company a stable base of capital-efficient, predictable and repeatable development opportunities which, in turn, positions the Company for consistent growth at competitive rates.

Exploring in high-potential, proven and emerging basins worldwide provides the Company with differential growth opportunities. Anadarko’s exploration success creates value by expanding its future resource potential, while providing the flexibility to manage risk by monetizing discoveries.

Anadarko’s global business development approach transfers core skills across the globe to assist in the discovery and development of world-class resources that are accretive to the Company’s performance. These resources help form an optimized global portfolio where both surface and subsurface risks are actively managed.

A strong balance sheet is essential for the development of the Company’s assets, and Anadarko is committed to disciplined investments in its businesses to manage through commodity price cycles. Maintaining financial discipline enables the Company to capitalize on the flexibility of its global portfolio, while allowing the Company to pursue new strategic and tactical growth opportunities.

The cause of the Deepwater Horizon events is not yet fully known. This introduces significant uncertainty with respect to the Company’s assessment of its potential future liquidity needs and how such needs may be satisfied. Refer to Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. Also, the credit rating downgrade in June 2010 has negatively impacted the Company’s cost of debt and margin requirements and has required the Company to post collateral as financial assurance of its performance under contractual arrangements, such as pipeline transportation and derivative contracts. In September 2010, the Company entered into the $5.0 billion Facility, which permits certain of the Company’s derivative counterparties (those extending commitments under the $5.0 billion Facility) to receive security interests in specified assets of the Company, thereby reducing the Company’s requirements to post cash collateral for net derivative liability positions. The Company is actively negotiating the execution of security-interest amendments to the ISDA agreements with these counterparties. As these amendments are executed, the Company’s cash collateral requirements will decrease. For further discussion, see Liquidity and Capital Resources.

The Company remains committed to the execution of its worldwide exploration, appraisal and development programs. The Company’s capital spending, including expensed geological and geophysical costs, is expected to be in the range of its 2010 capital spending budget of $5.3 billion to $5.5 billion, although approximately 4% of this capital spending has been re-allocated from the Gulf of Mexico to other areas. The Company has allocated approximately 65% of its capital spending to development activities, 25% to exploration activities and 10% to gas-gathering and processing activities and other business activities. The Company expects its 2010 capital spending by area to be approximately 44% for the United States onshore region and Alaska, 16% for the Gulf of Mexico, 30% for International and 10% for Midstream and other. The Company’s primary emphasis will be on managing near-term growth opportunities with a commitment to worldwide exploration and the continued development of large oil projects in Algeria, offshore Ghana and in the deepwater Gulf of Mexico.

In order to increase the predictability of 2010 cash flows, Anadarko has entered into strategic derivative positions, which, as of September 30, 2010, cover approximately 80% and 65% of its anticipated natural-gas sales volumes and oil and condensate sales volumes, respectively, for the remainder of 2010, and approximately 25% and 55% of its anticipated natural-gas sales volumes and oil and condensate sales volumes, respectively, for the full year of 2011. In addition, the Company has commodity derivative positions in place for 2012. See Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

If capital expenditures exceed operating cash flow and cash on hand, additional funding would be provided by short-term borrowings under the $5.0 billion Facility, which had available capacity of $4.6 billion at September 30, 2010, as well as asset divestitures and joint venture arrangements. 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 conditions.

In March 2010, the Patient Protection and Affordable Care Act (the PPACA) and the Health Care and Education Reconciliation Act of 2010 (HCERA), which makes various amendments to certain aspects of the PPACA (the HCERA and, together with PPACA, the Acts), were signed into law. Among numerous other items, the Acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy and impose excise taxes on high-cost health plans. Anadarko is not a recipient of the Medicare Part D tax benefit; therefore, the Company will not be impacted by this part of the new legislation. The Company will continue to monitor the potential impact of these new regulations as details emerge over the next several months and years. At this point in time, we are not aware of any material impacts to the Company.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173) was signed into law. Among numerous other items, HR 4173 requires most derivative transactions to be centrally cleared and/or executed on an exchange, and additional capital and margin requirements will be prescribed for most non-cleared trades starting in 2011. Additionally, financial institutions are required to spin off commodity, agriculture and energy swaps business into a separately capitalized affiliate, which may reduce the number of available counterparties with whom the Company could contract. This new law requires numerous studies to be performed by federal agencies to determine implementation specifics. For example, the Consumer Futures Trading Commission is evaluating the implementation specifics of exempting certain end users from the clearing requirements of HR 4173; however, the Company can not predict at this time whether and to what extent any such exemption would be applicable to its activities. While the Company cannot predict the potential impact of HR 4173, it will continue to monitor its potential impact as the resulting regulations emerge over the next several months and years.

The recent events in the Gulf of Mexico, combined with increased regulation in the U.S. and other countries, may result in delays and increased drilling and operating costs worldwide. The Company is currently unable to assess the potential impact as regulations are pending.

Credit Risk

Credit risk is represented by Anadarko’s exposure to non-payment or non-performance by the Company’s customers and counterparties. Generally, non-payment or non-performance results from a customer’s or counterparty’s inability to satisfy obligations. Anadarko monitors the creditworthiness of its customers and counterparties and establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact of a counterparty’s creditworthiness on fair value. The Company has the ability to require cash collateral as well as letters of credit from its financial counterparties to mitigate its exposure above assigned credit thresholds. With respect to non-financial counterparties, the Company has the ability to require prepayments or letters of credit to offset credit exposure when necessary. The Company routinely exercises its contractual right to net realized gains against realized losses when settling with its other counterparties.

Obligations and Commitments

Oil and Gas Activities The Company is obligated to fund 27% of the construction costs of a floating production, storage and offloading vessel (FPSO) to be used in its Ghana operations. The Company’s share of total construction costs is $237 million at September 30, 2010. In May 2010, a lease agreement was executed by the FPSO operator, with lease commencement expected to occur in the fourth quarter of 2010, once the vessel has been delivered and accepted. The Company expects to record a capital lease asset and obligation when the lease term begins.

REGULATORY MATTERS, ENVIRONMENTAL AND ADDITIONAL FACTORS AFFECTING BUSINESS

Environmental, Health and Safety Regulations

Anadarko’s business operations are subject to numerous international, federal, state and local environmental, health and safety laws and regulations pertaining to the release, emission or discharge of materials into the environment; the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes); the occupational health and safety of employees; or otherwise relating to the prevention, mitigation or remediation of pollution, or the preservation or protection of natural resources, wildlife or the environment. The more significant of these existing environmental, health and safety laws and regulations include the following United States laws and regulations, as amended from time to time:

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The U.S. Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring and reporting requirements.

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The U.S. Federal Water Pollution Control Act, also known as the federal Clean Water Act (CWA), which regulates discharges of pollutants from facilities to state and federal waters.

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The U.S. Oil Pollution Act of 1990, which subjects owners and operators of vessels, onshore facilities and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to strict liability for removal costs and damages arising from an oil spill in waters of the U.S.

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U.S. Department of the Interior regulations, which relate to offshore oil and natural gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages.

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The Comprehensive Environmental Response, Compensation and Liability Act of 1980, a remedial statute that imposes strict liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.

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The U.S. Resource Conservation and Recovery Act, which governs the treatment, storage and disposal of solid wastes, including hazardous wastes.

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The U.S. Federal Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources.

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The U.S. Emergency Planning and Community Right-to-Know Act, which requires facilities to disseminate information on chemical inventories to employees as well as local emergency planning committees and response departments.

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The U.S. Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances and appropriate control measures.

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The National Environmental Policy Act, which requires federal agencies, including the DOI, to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment.

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The Endangered Species Act, which restricts activities that may affect federally-identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas.

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The Marine Mammal Protection Act, which ensures the protection of marine mammals through the prohibition, with certain exceptions, of the taking of marine mammals in U.S. waters and by U.S. citizens on the high seas and which may require the implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas.

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The Migratory Bird Treaty Act, which implemented various treaties and conventions between the U.S. and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas.

These laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, in discharges to surface water, and in disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, the occurrence of delays in the development of projects, and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. Compliance with these laws and regulations also, in most cases, requires new or amended permits that may contain new or more stringent technological standards or limits on emissions, discharges, disposals or other releases in association with new or modified operations. Application for these permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with public notice and comment periods required prior to the issuance or amendment of a permit as well as the agency’s processing of an application. Many of the delays associated with the permitting process are beyond the control of the Company.

Many states and foreign countries where the Company operates also have, or are developing, similar environmental laws, regulations or analogous controls governing many of these same types of activities. While the legal requirements may be similar in form, in some cases the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly alter or delay the development of an oil and natural gas project or substantially increase the cost of doing business.

Anadarko is also subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations.

Federal and state occupational safety and health laws require the Company to organize information about materials, some of which may be hazardous or toxic, that are used, released or produced in Anadarko’s operations. Certain portions of this information must be provided to employees, state and local governmental authorities and responders, and local citizens. The Company is also subject to the safety hazard communication requirements and reporting obligations set forth in federal workplace standards.

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards and water quality standards, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on the Company’s operations in the United States and in other countries in which Anadarko operates. Notable areas of potential impacts include air emission monitoring and compliance and remediation obligations in the United States.

As a result of the Deepwater Horizon events, the Company has reviewed its potential responsibilities under both OPA and CWA. OPA imposes, on the responsible parties, joint and several liability for all clean-up and response costs, natural resource damages, and other damages such as lost revenues, damages to real or personal property, damages to subsistence users of natural resources, and lost profits and earning capacity. While OPA requires that a responsible party pay for all clean-up and response costs, it currently limits liability for damages to $75 million, exclusive of response and remediation expenses (for which there is no cap), except in cases of gross negligence, willful misconduct, or the violation of an applicable federal safety, construction, or operating regulation. The United States Government may take legislative or other action to increase or eliminate, perhaps even retroactively, the liability cap. As for damages to natural resources, the government may recover damages for injury to, loss of, destruction of, or loss of use of natural resources which may include the costs to repair, replace or restore those or like resources. The CWA governs discharges into waters of the United States and provides for penalties in the event of unauthorized discharges into those waters. Under the CWA, these include, among other penalties, civil penalties that may be assessed in an amount not more than $37,500 per day or $1,100 per barrel of oil discharged. In cases of gross negligence or willful misconduct, such civil penalties that may be sought by the United States Environmental Protection Agency are increased to not less than $140,000 per day and not more than $4,300 per barrel.

As of the date of filing this Form 10-Q with the SEC, the government has not assessed or made a demand against the Company for damages or penalties under OPA, CWA, and other similar local, state and federal environmental legislation related to the Deepwater Horizon events. For additional information on environmental issues related to the Deepwater Horizon events, see Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

The Company has made and will continue to make operating and capital expenditures, some of which may be material, to comply with environmental, health and safety laws and regulations. These are necessary business costs in the Company’s operations and in the oil and natural gas industry. Although the Company is not fully insured against all environmental, health and safety risks, and the Company’s insurance does not cover any penalties or fines that may be issued by a governmental authority, it maintains insurance coverage that it believes is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental, health and safety laws and regulations, as well as claims for damages to property or persons, resulting from the Company’s operations, could result in substantial costs and liabilities, including administrative, civil and criminal penalties, to Anadarko. The Company believes that it is in material compliance with existing environmental, health and safety regulations. Further, the Company believes that the cost of maintaining compliance with these existing laws and regulations will not have a material adverse effect on its business, financial position or results of operations or cash flows, but new or more stringently applied or enforced existing laws and regulations could increase the cost of doing business, and such increases could be material.

CRITICAL ACCOUNTING ESTIMATES

Goodwill

During the second quarter of 2010, a decline in fair value of Anadarko’s oil and gas exploration and production reporting unit was indicated as a result of the Deepwater Horizon events discussed in Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q and general uncertainty arising in connection with the Moratorium and uncertain related regulatory impacts. In estimating the fair value of its oil and gas reporting unit, the Company assumes production profiles utilized in its estimation of reserves that are disclosed in the Company’s supplemental oil and gas disclosures at year end, market prices based on the forward price curve for oil and gas as of the test date (adjusted for location and quality differentials), capital and operating costs consistent with pricing and expected inflation rates, and discount rates that management believes a market participant would utilize based upon the risks inherent in Anadarko’s operations. The goodwill impairment test of the oil and gas exploration and production reporting unit as of June 30, 2010, considered the Company’s continued association with the Deepwater Horizon events. The results of this impairment test indicated that the fair value of the oil and gas exploration and production reporting unit exceeded the carrying value of the reporting unit.

At September 30, 2010, the Company had $5.3 billion of goodwill recorded as a result of past business combinations that was allocated to its three reporting units: $5.2 billion to oil and gas exploration and production; $134 million to gathering and processing; and $5 million to transportation. The Company will complete its annual impairment assessment of goodwill during the fourth quarter of 2010.

Uncertainty related to the Deepwater Horizon events discussed in Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, difficulty or potential delays in obtaining drilling permits, significant declines in commodity prices, or other unanticipated events could result in further goodwill impairment tests in the near term, the results of which may have a material adverse impact on the Company’s results of operations.

Impairment of Assets

As of September 30, 2010, the average five-year NYMEX natural-gas strip decreased as compared to December 31, 2009. While the decrease in the natural-gas strip price did not result in material impairments for the three months ended September 30, 2010, a further decrease in forward natural-gas prices could result in impairments which could be material to our results of operations.

Environmental Obligations and Other Contingencies

Management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for environmental, litigation and other contingent matters. Provisions for such matters are charged to expense when it is probable that a liability has been incurred and a reasonable estimate of the liability can be made. Estimates of environmental liabilities are based on a variety of factors, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and existing laws and regulations. In future periods, a number of factors could significantly change the Company’s estimate of its environmental liabilities, such as the completion of ongoing investigations, final determinations as to contractual contingencies, failure of other parties to satisfy joint and several environmental obligations, changes in laws and regulations, changes in the interpretation or administration of laws and regulations, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental or other contingent matters and actual costs may vary significantly from the Company’s estimates. The Company’s in-house legal counsel and environmental personnel regularly assess these contingent liabilities and, in certain circumstances, third-party legal counsel or consultants are retained. For additional information related to the Deepwater Horizon events, see Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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 payments and receipts denominated in foreign currencies. 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 derivative instruments utilized by the Company include futures, swaps, options and fixed-price physical-delivery contracts. The volume of commodity derivative instruments utilized 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 its counterparties in order to satisfy these margin requirements. For additional information see Liquidity and Capital Resources—Uses of Cash—Margin Deposits and Other Collateral under Part I, Item 2 of this Form 10-Q.

For information regarding the Company’s accounting policies and additional information related to the Company’s derivative and financial instruments, see Note 1—Summary of Significant Accounting Policies, Note 9—Derivative Instruments and Note 10—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

ENERGY PRICE RISK The Company’s most significant market risk relates to the pricing for natural gas, crude oil and NGLs. Management expects energy prices to remain volatile and unpredictable. As energy prices decline or rise significantly, revenues and cash flow significantly decline or rise. In addition, a non-cash write-down of the Company’s oil and gas properties may be required if future oil and gas commodity prices experience a sustained, significant decline. Below is a sensitivity analysis of 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 equity production of 558 Bcf of natural gas and 58 MMBbls of crude oil as of September 30, 2010. At September 30, 2010, the Company had a net asset derivative position of $607 million on these derivative instruments. Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $356 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $289 million. However, a gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes At September 30, 2010, the Company had a net asset derivative position of $25 million (gains of $33 million and losses of $8 million) on derivative instruments entered into for trading purposes. Utilizing the actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would not materially impact the Company’s loss or gain on these derivative instruments.

INTEREST-RATE RISK As of September 30, 2010, $570 million of WES borrowings under its RCF and Term Loan, which are included in Anadarko’s reported debt balance, were subject to variable interest rates. The balance of Anadarko’s long-term debt (or 96% of Anadarko’s consolidated debt) was at a fixed rate. Accordingly, a 10% increase in LIBOR would not materially impact the Company’s interest cost on currently outstanding debt.

Increases in market rates of interest will unfavorably impact the interest cost of future debt issuances. To mitigate this risk, in December 2008 and January 2009, Anadarko entered into interest-rate swap agreements with a combined notional principal amount of up to $3.0 billion, whereby the Company locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR. Since the swaps were initiated, the Company refinanced a portion of its 2011 and 2012 debt maturities, and after the October 2010 redemption of $422 million discussed under Near-Term Debt Maturities, the Company had $765 million of remaining scheduled debt maturities for 2011 and 2012, or $1.5 billion including the Zero Coupons which could be put to the Company in 2012. The Company may settle some or all of its interest-rate swap positions in connection with future debt issuances, if any, and will settle any remaining positions when the interest-rate swaps are scheduled to terminate in 2011 and 2012. At September 30, 2010, the Company had a net liability derivative position of $604 million related to interest-rate swaps. A 10% increase or decrease in the three-month LIBOR interest-rate curve would increase or decrease, respectively, the fair value of outstanding interest-rate swap agreements by approximately $44 million. For a summary of the Company’s open interest-rate derivative positions, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

In June 2010, Moody’s downgraded the Company’s senior unsecured credit rating from “Baa3” to “Ba1.” For additional information concerning the effects on interest rates related to the downgrade, see Liquidity and Capital Resources.

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. As of September 30, 2010, near-term foreign-currency-denominated expenditures are expected to be primarily in euros, Brazilian reais and British pounds sterling. Management mitigates a portion of its exposure to foreign-currency exchange-rate risk, as discussed below.

With respect to its international oil and gas development projects, Anadarko is a party to contracts containing commitments extending through January 2012 which are impacted by euro-to-U.S. dollar exchange rates. During the first quarter of 2010, the Company purchased approximately $210 million U.S. dollar equivalent of euros (€) in order to manage euro exchange-rate risk relative to the U.S. dollar for 2010 euro-denominated expenditures. At September 30, 2010, euro-denominated cash of approximately €135 million, or $185 million in U.S. dollar equivalent, is included in cash and cash equivalents. Additionally, Anadarko entered into euro-U.S. dollar collars, which are effective during 2011, for an aggregate notional principal amount of €113 million. The combination of euro purchases already executed and financial collars in effect during 2011 substantially mitigates Anadarko’s exposure to fluctuations in the euro-to-U.S. dollar exchange rate inherent in its existing capital expenditure commitments.

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934. The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and to ensure that the information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of September 30, 2010.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the third quarter of 2010 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

DEEPWATER HORIZON EVENTS – RELATED PROCEEDINGS In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. Response and clean-up efforts are being conducted by BP Exploration & Production Inc. (BP), the operator and 65% owner of the well, and by other parties, all under the direction of the Unified Command of the United States Coast Guard (the Unified Command or USCG). On July 15, 2010, after several attempts to contain the oil spill, BP successfully installed a capping stack that shut in the well and prevented the further release of hydrocarbons. Installation of the capping stack was a temporary solution that was followed by a successful “static kill” cementing operation completed on August 5, 2010. The Macondo well was permanently plugged on September 19, 2010, when BP completed a “bottom kill” cementing operation in connection with the successful interception of the well by a relief well. Investigations by the federal government and other parties into the cause of the well blowout, explosion, and resulting oil spill, as well as other matters arising from or relating to these events, are ongoing.

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

Lawsuits seeking to place limitations on the Company’s projects in the Gulf of Mexico have also been filed by non-governmental organizations against various governmental agencies.

TRONOX PROCEEDINGS In January 2009, Tronox Incorporated (Tronox), a former wholly owned subsidiary of Kerr-McGee Corporation (Kerr-McGee) that held Kerr-McGee’s chemical business, and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (the Court). Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance (the Adversary Proceeding). Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee. Tronox seeks, among other things, to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko as well as punitive damages, and litigation fees and costs. In addition, Tronox seeks to equitably subordinate and/or disallow all claims asserted by Anadarko and Kerr-McGee in the bankruptcy cases. Anadarko and Kerr-McGee moved to dismiss the complaint in its entirety. In March 2010, the Court issued an opinion granting in part and denying in part Anadarko’s and Kerr-McGee’s motion to dismiss the complaint. Notably, the Court dismissed, with prejudice, Tronox’s request for punitive damages relating to their fraudulent conveyance claims. The Court granted Tronox leave to replead certain of its common law claims, and Tronox filed an amended complaint in April 2010. Anadarko and Kerr-McGee have moved to dismiss three breach of fiduciary duty-related claims in the amended complaint. That motion has been briefed and is awaiting disposition by the Court.

The Company intends to continue to defend itself vigorously.

See Note 2—Deepwater Horizon Events, Note 3—Deepwater Drilling Moratorium and Other Related Matters and Note 12—Commitments and Contingencies under Part I, Item 1 of this Form 10-Q.

Item 1A. Risk Factors

Consider carefully the risk factors included below, as well as those under the caption “Risk Factors” under Part I, Item 1A in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, together with all of the other information included in this document, in the Company’s Annual Report on Form 10-K and in the Company’s other public filings, press releases and discussions with Company management.

We may be subject to claims and liability as a result of being a co-lessee of the Mississippi Canyon block 252 lease and our ownership of a 25% non-operating interest in the Macondo exploration well in the Gulf of Mexico, which suffered a blowout and drilling rig explosion in April 2010, resulting in loss of life and a significant oil spill.

In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. Response and clean-up efforts are being conducted by BP Exploration & Production Inc. (BP), the operator and 65% owner of the well, and by other parties, all under the direction of the Unified Command of the United States Coast Guard (the Unified Command or USCG). On July 15, 2010, after several attempts to contain the oil spill, BP successfully installed a capping stack that shut in the well and prevented the further release of hydrocarbons. Installation of the capping stack was a temporary solution that was followed by a successful “static kill” cementing operation completed on August 5, 2010. The Macondo well was permanently plugged on September 19, 2010, when BP completed a “bottom kill” cementing operation in connection with the successful interception of the well by a relief well. Investigations by the federal government and other parties into the cause of the well blowout, explosion, and resulting oil spill, as well as other matters arising from or relating to these events, are ongoing.

BP has sought reimbursement from Anadarko for amounts BP has paid or committed to pay for spill-response efforts, grants, damage claims and costs incurred by the federal government through provisions of the joint operating agreement (JOA), which is the contract governing the relationship between BP and the non-operating working interest owners of the Mississippi Canyon block 252 lease and the Macondo well. Contractual language in the JOA, which governs the relationship among the operator and the two non-operating parties, generally provides that BP, as operator, is entitled to reimbursement of certain costs and expenses from the other working interest owners in proportion to their ownership interest in the well. With respect to the operator’s duties and liabilities, the JOA provides that BP, as operator, owes duties to the non-operating parties (including Anadarko) to perform the drilling of the well in a good and workmanlike manner and to comply with all applicable laws and regulations. The JOA dictates BP, as operator, is not liable to non-operating parties for losses sustained or liabilities incurred, except for losses resulting from the operator’s gross negligence or willful misconduct. The JOA dictates that liability for losses, damages, costs, expenses, or claims involving activities or operations shall be borne by each party in proportion to its participating interest, except that when liability results from the gross negligence or willful misconduct of a party, that party shall be solely responsible for liability resulting from its gross negligence or willful misconduct.

BP has invoiced the Company an aggregate $2.6 billion for what BP considers to be Anadarko’s 25% proportionate share of actual costs through September 30, 2010. In addition, BP has invoiced Anadarko for anticipated near-term future costs related to the Deepwater Horizon events. Anadarko has withheld reimbursement to BP for Deepwater Horizon event-related invoices pending the completion of various ongoing investigations into the cause of the well blowout, explosion, and subsequent release of hydrocarbons. Final determination of the root causes of the Deepwater Horizon events could materially impact the Company’s potential obligations under the JOA. To the extent that we are ultimately determined to be responsible for our allocable share of the operator’s costs under the JOA, we expect our costs to be significantly in excess of the coverage limits under our insurance program.

BP, Anadarko and other parties, including parties that do not own an interest in the Macondo well, such as the drilling contractor, have been notified by the USCG of their status as an RP under OPA. Under OPA, RPs may be held jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims directly related to the spill and spill cleanup. The USCG has directly billed the RPs for reimbursement of spill-related response costs incurred by the USCG and other federal and state agencies. The RPs have each received identical invoices for total costs, without specification or stipulation of any allocation of costs between or among the RPs. As a 25% non-operating working interest owner in the Macondo well, a co-lessee of the Mississippi Canyon Block 252 lease, and an RP under OPA, we may incur liability under currently existing environmental laws and regulations and we may be asked to contribute to the significant and ongoing response and remediation expenses.

To date, as operator, BP has paid all USCG invoices as well as other costs and has sought reimbursement from Anadarko for a 25% portion of these costs through the JOA. To the extent that BP discontinues payment or is otherwise unable to satisfy its obligations under OPA for any reason, we would be exposed to additional liability for spill-response and remediation expenses. We have similar exposure relative to the other RPs where the failure on the part of any other such RPs to satisfy their OPA obligations would expose us to potential liability.

As more facts become known, it is reasonably possible that the Company may be required to recognize a liability related to the Deepwater Horizon events, and that liability could be material to the Company’s consolidated financial position, results of operations and cash flows. For example, new information arising out of the legal-discovery process could alter the legal assessment as to the likelihood of the Company incurring a liability related to its existing JOA contingent obligations. Moreover, if BP discontinues payment or is otherwise unable to satisfy its obligations, the Company could be required to recognize an OPA-related environmental liability. Similarly, if other RPs do not satisfy their obligations under OPA, the Company could incur additional liability. In addition, while OPA contains a $75 million cap for certain costs and damages, exclusive of response and remediation expenses (for which there is no cap), the United States Government may take legislative or other action to increase or eliminate the cap, perhaps even retroactively.

As part of its pledge to pay all legitimate claims related to the Deepwater Horizon events, BP announced in June 2010 that it had agreed to contribute $20 billion into an escrow fund over a four-year period to support an independent claims facility, the purpose of which is, according to BP, “to satisfy legitimate claims including natural resource damages and state and local response costs” resulting from the Deepwater Horizon events, with fines and penalties to be excluded from the fund and paid separately. As claims are paid out of this escrow fund, we may be asked to contribute to the payment of such claims pursuant to the JOA. As described above, we are continuing to evaluate our contractual rights and obligations under the JOA. If the parties are unable to reach an agreement on liability, one of the possible outcomes is to pursue arbitration under the JOA. In any arbitration, the weight to be given to evidence would be determined by the arbitrators. The Company cannot guarantee the success of any such arbitration proceeding.

While we will seek any and all protections available to us pursuant to the JOA or otherwise as well as our insurance coverage, an adverse resolution of our contractual rights and responsibilities to BP under the JOA or the failure of BP and other RPs to satisfy their obligations under OPA could subject us to significant monetary damages and other penalties, such as CWA penalties, which could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

For all of these reasons or if we were to suffer the other effects described in this risk factor and the following risk factors, our actual liabilities relating to the Deepwater Horizon events could exceed our estimates, and we could incur additional liabilities that we are unable to reasonably estimate at this time, and these events could have a material adverse effect on our financial position, results of operations, cash flows, growth and prospects, including, without limitation, our ability to obtain debt, equity or other financing on acceptable terms, or at all. In addition, the new $5.0 billion senior secured revolving credit facility, which we entered into in September 2010, contains covenants limiting our ability to incur additional debt or pledge additional assets, subject to exceptions. These limitations could adversely affect our ability to obtain additional financing for any future liabilities that may arise in connection with the Deepwater Horizon events.

We have been named as a defendant in various litigation as a result of the Deepwater Horizon events. The outcome of existing and future claims could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

In July 2010, a public hearing of the United States Judicial Panel on Multidistrict Litigation (JPML) was held to consider motions of various plaintiffs and BP to consolidate Deepwater Horizon event-related lawsuits filed in various federal courts into a consolidated Multidistrict Litigation (MDL) in a single venue. In August 2010, the JPML created MDL No. 2179 to administer essentially all litigation filed in federal court involving Deepwater Horizon event-related claims. Federal Judge Carl Barbier will preside over this MDL in the Eastern District of Louisiana in New Orleans, Louisiana. In October 2010, the court appointed four plaintiffs’ attorneys to serve on a Plaintiff Executive Committee (PEC) and also appointed 15 of the plaintiffs’ attorneys to a Plaintiffs’ Steering Committee (PSC). The PEC will coordinate the responsibilities of the PSC, appear at status conferences representing the PSC, and provide any further administrative or logistical functions as the court may order. The court issued a case management order that initially establishes a schedule for procedural matters, discovery and trial of the MDL cases. The case management order sets, for trial beginning in June 2011, one or more cases brought against BP as an RP under OPA to serve as test cases for liability and damage issues. The court has not yet selected the specific cases to be tried. Also, the court scheduled a February 2012 trial date to determine the limitation and liability allocation issues for the parties involved in the Deepwater Horizon events, which will also address whether Transocean Ltd. can limit its liability under admiralty law to the value of the Deepwater Horizon drilling rig. The parties to the MDL are engaged in document discovery.

Lawsuits seeking to place limitations on the Company’s projects in the Gulf of Mexico have also been filed by non-governmental organizations against various governmental agencies.

Additional proceedings related to the Deepwater Horizon events may be filed against Anadarko. These proceedings may involve civil claims for damages or governmental investigative, regulatory or enforcement actions. The adverse resolution of any proceedings related to the Deepwater Horizon events could subject us to significant monetary damages, fines and other penalties, which could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

The additional deepwater drilling laws and regulations, delays in the processing and approval of permits and other related developments resulting from the recently lifted deepwater drilling moratoria in the Gulf of Mexico may have a material adverse effect on our business, financial condition or results of operations.

The Moratorium did not apply to workovers, completions, plugging and abandonment or production activities; however, in order to continue such activities, the Company is required to comply with additional safety inspection and certification requirements that were set forth in two Notices to Lessees and Operators (NTL) issued by the BOEMRE in June 2010.

On June 8, 2010, the BOEMRE issued an NTL implementing certain safety measures recommended by the Secretary of the Interior in his 30-day safety report to the President of the United States. This NTL requires additional inspections to be conducted and safety measures to be implemented prior to conducting any floating drilling operations with a subsea blowout preventer (BOP) system or surface BOP system, including workovers, completions, and plugging and abandonment operations. On June 18, 2010, the BOEMRE issued another NTL requiring additional information from operators regarding existing and future Exploration Plans, Development and Production Plans and Development and Coordination Documents, all of which may have a significant impact on the timing of and ability to execute exploration and development operations across the Gulf of Mexico.

On October 14, 2010, the DOI published in the Federal Register an interim final drilling safety rule, effective immediately, enacting into law the June 8, 2010 NTL. After a 60-day public comment period, the rule will become final, either in its current form, or as may be modified by the DOI based on comments received. On October 15, 2010, the DOI published in the Federal Register a final rule requiring operators to develop and implement Safety and Environmental Management Systems (SEMS) for all Gulf of Mexico operations. In addition, the United States Government may issue further safety and environmental laws or regulations regarding operations in the Gulf of Mexico. These additional rules and regulations, delays in the processing and approval of permits and possible additional actions could adversely affect new drilling and ongoing development efforts in the Gulf of Mexico. Among other adverse impacts, these additional measures could delay or disrupt our operations, result in increased costs and limit activities in certain areas of the Gulf of Mexico. We cannot predict with any certainty the full impact of any new laws or regulations.

In June 2010, the Company gave written notice of termination to the drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on June 19, 2010. The drilling contractor filed an Original Answer in July 2010 denying the Moratorium constituted a force majeure event and asserted that Anadarko had breached the drilling contract. If the Company does not prevail in its claim, it could be obligated to pay the rig contract rate from the contract-termination date through March 2011, the end of the original contract term. The disputed rentals for that period could result in approximately $90 million of cost.

In September 2010, the Company gave written notice of termination to another drilling contractor of a rig that had been placed in force majeure, and the Company filed a lawsuit against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on September 18, 2010. The drilling contractor filed a Motion to Dismiss and an Original Answer on October 5, 2010. The Company responded to the Motion to Dismiss on October 26, 2010. If the Company does not succeed in its claim, it could be obligated to pay the rig contract rate from the contract-termination date through March 2013, the end of the original contract term. The disputed rentals for that period could result in approximately $377 million of cost.

In September 2010, the BOEMRE issued an NTL that requires lessees to plug all wells that have been idle for the past five years and decommission related equipment. Lessees have 120 days from October 15, 2010, to submit a company-wide plan for decommissioning facilities and wells. The Company is currently evaluating the regulations, and is not yet able to determine the effect these new requirements may have on existing asset retirement obligations related to affected wells.

Other governments may also adopt safety, environmental or other laws and regulations that would adversely impact our offshore developments in other areas of the world, including offshore Brazil, West Africa, Mozambique and Southeast Asia. Additional United States or foreign government laws or regulations would likely increase the costs associated with the offshore operations of our drilling contractors. As a result, our drilling contractors may seek to pass increased operating costs to us through higher day-rate charges or through cost escalation provisions in existing contracts.

In addition to increased governmental regulation, we currently expect that insurance costs will increase across the energy industry and certain insurance coverage may be subject to reduced availability or not available on economically reasonable terms, if at all. In particular, the events in the Gulf of Mexico relating to the Macondo well may make it increasingly difficult to obtain offshore property damage, well control and similar insurance coverage. The potential increased costs and risks associated with offshore development may also result in certain current participants allocating resources away from offshore development and discourage potential new participants from undertaking offshore development activities. Accordingly, we may encounter increased difficulty identifying suitable partners willing to participate in our offshore drilling projects and prospects.

Further, as the deepwater Gulf of Mexico (as well as international deepwater locations) lacks the extent of physical and oilfield service infrastructure present in shallower waters, it may be difficult for us to quickly or effectively execute on any contingency plans related to future events similar to the Macondo well oil spill.

The matters described above, individually or in the aggregate, could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

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

Prior to its acquisition by Anadarko, Kerr-McGee, through an initial public offering and spin-off transaction, disposed of its chemical manufacturing business. A new publicly traded corporation, Tronox, resulted from this transaction. After the Tronox initial public offering and spin off, Kerr-McGee was acquired by a wholly owned subsidiary of Anadarko and, as a result, became a wholly owned subsidiary of Anadarko. Under the terms of the MSA, which was entered into in connection with the Tronox initial public offering, Kerr-McGee agreed to reimburse Tronox for certain qualifying environmental-remediation costs associated with those businesses, subject to certain limitations and conditions. The reimbursement obligation under the MSA was limited to a maximum aggregate reimbursement amount of $100 million. As described below, Tronox has rejected the MSA in its Chapter 11 cases and therefore Kerr-McGee is no longer obligated to reimburse Tronox under the terms of the agreement. Following Tronox’s rejection of the MSA, Anadarko and Kerr-McGee filed amended proofs of claim, which include claims for damages arising from such rejection of the MSA. The Company is currently analyzing further implications of the rejection of the MSA. As described below, Tronox and certain third parties have claimed that Kerr-McGee and Anadarko have additional liability for costs allegedly attributable to the facilities and operations owned by Tronox and for Kerr-McGee’s activities prior to the date a subsidiary of Anadarko acquired Kerr-McGee.

In January 2009, Tronox and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York. In connection with these bankruptcy cases, Tronox filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance. Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee. Tronox seeks to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko as well as litigation fees and costs. In addition, Tronox seeks to equitably subordinate and/or disallow all claims asserted by the Company in the bankruptcy cases.

In addition, a consolidated class action complaint has been filed in the United States District Court for the Southern District of New York 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. The complaint alleges causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort claim liabilities. The plaintiffs allege that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including filings made in connection with Tronox’s initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. Anadarko, Kerr-McGee and other defendants moved to dismiss the class action complaint and in June 2010, the Court issued an opinion and order dismissing the plaintiffs’ complaint against Anadarko, but granted the plaintiffs leave to re-plead their claims. The court further granted in part and denied in part the motions to dismiss by Kerr-McGee and certain of its former officers and directors, but permitted plaintiffs leave to re-plead certain of the dismissed claims. Plaintiffs’ amended complaint was filed in July 2010. In August 2010, Anadarko moved to dismiss plaintiffs’ complaint in whole and Kerr-McGee moved to dismiss plaintiffs’ allegations against it in part. The plaintiffs have responded to both motions. Anadarko and Kerr-McGee will file respective briefs in reply during the fourth quarter of 2010.

In June 2010, Anadarko and Kerr-McGee filed a motion in Tronox’s Chapter 11 cases to compel Tronox to assume or reject the MSA. On July 21, 2010, in response to this motion Tronox announced to the Court that it would reject the MSA effective as of July 22, 2010. In August 2010, the Court entered into a Stipulation and Agreed Order among Tronox, Anadarko, and Kerr-McGee authorizing the rejection of the MSA. Anadarko and Kerr-McGee subsequently filed amended proofs of claim, which includes claims for damages arising from such rejection of the MSA.

An adverse resolution of any proceedings related to Tronox could subject us to significant monetary damages and other penalties, which could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

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

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

The following table sets forth information with respect to repurchases by the Company of its shares of common stock during the third quarter of 2010.


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⁽²⁾

July 1-31		180,143	$	38.07		—
August 1-31		191	$	50.66		—
September 1-30		527	$	51.58		—

Third Quarter 2010		180,861	$	38.12		—	$	4,400,000,000

⁽¹⁾	During the third quarter of 2010, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee stock plan share issuances, which are not within the scope of the Company’s share-repurchase program.

⁽²⁾

In August 2008, the Company announced a share-repurchase program to purchase up to $5 billion in shares of common stock. The program is authorized to extend through August 2011; however, the repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time.

Item 6. Exhibits

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith or designated with asterisks (**) and are furnished 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 21, 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 21, 2009	3.4 to Form 8-K filed on May 22, 2009	1-8968

4	(i)	Trustee Indenture dated as of September 19, 2006, Anadarko Petroleum Corporation to the Bank of New York Trust Company, N.A.	4.1 to Form 8-K filed on September 19, 2006	1-8968

	(ii)	Officers’ Certificate of Anadarko Petroleum Corporation dated August 9, 2010, establishing the 6.375% Senior Notes due 2017	4.1 to Form 8-K filed on August 12, 2010	1-8968

	(iii)	Form of 6.375% Senior Notes due 2017	4.2 to Form 8-K filed on August 12, 2010	1-8968

10	(i)	Retention Agreement, dated August 2, 2010	10.1 to Form 8-K filed on August 6, 2010	1-8968

	(ii)	$5,000,000,000 Revolving Credit Agreement, dated as of September 2, 2010, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., DnB NorBank ASA, The Royal Bank of Scotland plc, Société Général, and Wells Fargo Bank, N.A., as Syndication Agents, and the several lenders named therein.	10.1 to Form 8-K filed on September 8, 2010	1-8968

* 31	(i)	Rule 13a–14(a)/15d–14(a) Certification - Chief Executive Officer

*	(ii)	Rule 13a–14(a)/15d–14(a) Certification - Chief Financial Officer

* 32		Section 1350 Certifications

** 101	.INS	XBRL Instance Document

** 101	.SCH	XBRL Schema Document

** 101	.CAL	XBRL Calculation Linkbase Document

** 101	.LAB	XBRL Label Linkbase Document

** 101	.PRE	XBRL Presentation Linkbase Document

** 101	.DEF	XBRL Definition Linkbase Document

SIGNATURES

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


	ANADARKO PETROLEUM CORPORATION
	(Registrant)

November 1, 2010	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin
		Senior Vice President, Finance and
		Chief Financial Officer