Edgar Filing: ANADARKO PETROLEUM CORP

Anadarko Petroleum Corporation 3rd Qtr 2008 Form 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2008
Commission File No. 1-8968

ANADARKO PETROLEUM CORPORATION
1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046
(832) 636-1000

Incorporated in the	I.R.S. Employer Identification
State of Delaware	No. 76-0146568

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 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, 2008 is shown below:


Title of Class	Number of Shares Outstanding

Common Stock, par value $0.10 per share	459,039,638

TABLE OF CONTENTS


			Page
PART I

	Item 1.	Financial Statements

		Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2008 and 2007	-

		Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007	-

		Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2008 and 2007	-

		Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2008 and 2007	-

		Notes to Consolidated Financial Statements	-

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

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	-

	Item 4.	Controls and Procedures	-

PART II

	Item 1.	Legal Proceedings	-

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

	Item 6.	Exhibits	-

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		Three Months Ended									Nine Months Ended
		September 30									September 30

millions except per share amounts		2008					2007				2008				2007

Revenues and Other
Gas sales	$			2,395		$		871		$		5,089		$		3,108
Oil and condensate sales				3,217				1,262				4,911				3,558
Natural gas liquids sales				244				175				703				511
Gathering, processing and marketing sales				353				348				940				1,195
Gains (losses) on divestitures and other, net				(60	)			339				270				4,458

Total				6,149				2,995				11,913				12,830


Costs and Expenses
Oil and gas operating				274				256				778				868
Oil and gas transportation and other				140				113				400				342
Exploration				373				253				880				614
Gathering, processing and marketing				265				217				679				840
General and administrative				216				171				619				681
Depreciation, depletion and amortization				844				655				2,438				2,090
Other taxes				424				269				1,306				869
Impairments				56				-				67				40

Total				2,592				1,934				7,167				6,344


Operating Income				3,557				1,061				4,746				6,486

Other (Income) Expense
Interest expense				180				222				558				861
Other (income) expense, net				22				(8	)			(5	)			(60	)
Minority interests				10				-				15				-

Total				212				214				568				801


Income from Continuing Operations Before Income Taxes				3,345				847				4,178				5,685

Income Tax Expense				1,181				354				1,761				2,191


Income from Continuing Operations				2,164				493				2,417				3,494

Income (Loss) from Discontinued Operations, net of taxes				1				(12	)			58				22


Net Income				2,165				481				2,475				3,516


Preferred Stock Dividends				-				1				1				2


Net Income Available to Common Stockholders	$			2,165		$		480		$		2,474		$		3,514


Per Common Share
Income from continuing operations - basic	$			4.65		$		1.06		$		5.17		$		7.51
Income from continuing operations - diluted	$			4.62		$		1.05		$		5.14		$		7.48
Income (loss) from discontinued operations, net of taxes - basic	$			-		$		(0.03	)	$		0.13		$		0.05
Income (loss) from discontinued operations, net of taxes - diluted			$	-		$		(0.03	)	$		0.12		$		0.05
Net income available to common stockholders - basic	$			4.65		$		1.03		$		5.29		$		7.56
Net income available to common stockholders - diluted	$			4.62		$		1.03		$		5.26		$		7.53

Dividends	$			0.09		$		0.09		$		0.27		$		0.27

Average Number of Common Shares Outstanding - Basic				466				466				467				465

Average Number of Common Shares Outstanding - Diluted				468				468				470				467

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)

	September 30,		December 31,
millions	2008		2007

ASSETS
Current Assets
Cash and cash equivalents	$	1,980	$	1,268
Accounts receivable, net of allowance:
Customers		1,020		1,465
Others		1,128		1,111
Other current assets		855		642
Current assets held for sale		3		-


Total		4,986		4,486


Properties and Equipment
Cost (includes unproved properties of $10,879 and $13,106
as of September 30, 2008 and December 31, 2007, respectively)		46,073		44,205
Less accumulated depreciation, depletion and amortization		9,196		6,754


Net properties and equipment - based on the successful efforts method
of accounting for oil and gas properties		36,877		37,451


Other Assets		1,118		1,030


Goodwill and Other Intangible Assets		5,100		5,166


Long-term Assets Held for Sale		1,148		318


Total Assets	$	49,229	$	48,451

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Continued)
(Unaudited)

	September 30,			December 31,
millions	2008			2007

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	3,251		$	2,778
Accrued expenses		1,228			1,060
Current debt		1,708			1,396
Current liabilities associated with assets held for sale		45			-


Total		6,232			5,234


Long-term Debt		9,120			11,151


Midstream Subsidiary Note Payable to a Related Party		1,870			2,200


Other Long-term Liabilities
Deferred income taxes		9,805			10,214
Other		3,333			3,282
Long-term liabilities associated with assets held for sale		299			6


Total		13,437			13,502


Minority Interests		359			-


Stockholders' Equity
Preferred stock, par value $1.00 per share (2.0 million shares authorized,
zero and 0.05 million shares issued as of September 30, 2008 and		-			45
December 31, 2007, respectively)
Common stock, par value $0.10 per share (1.0 billion shares authorized, 470.4 million and 469.1 million shares issued as of September 30, 2008
and December 31, 2007, respectively)		47			47
Paid-in capital		5,660			5,511
Retained earnings		13,435			11,089
Treasury stock (11.4 million and 1.1 million shares as of September 30, 2008 and December 31, 2007, respectively)		(674	)		(55	)
Accumulated other comprehensive loss:
Unrealized loss on derivative instruments		(122	)		(132	)
Foreign currency translation adjustments		(1	)		(1	)
Pension and other postretirement plans		(134	)		(140	)

Total		(257	)		(273	)


Total		18,211			16,364


Commitments and Contingencies (Note 14)


Total Liabilities and Stockholders' Equity	$	49,229		$	48,451

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended									Nine Months Ended
	September 30									September 30

millions		2008				2007					2008				2007


Net Income Available to Common Stockholders	$		2,165		$		480		$			2,474		$		3,514

Add: Preferred Stock Dividends			-				1					1				2


Net Income			2,165				481					2,475				3,516


Other Comprehensive Income (Loss), net of taxes
Unrealized gains (losses) on derivative instruments:
Reclassification of (gains) losses to net income⁽¹⁾			4				2					10				2
Foreign currency translation adjustments			-				-					-				(1	)
Pension and other postretirement plans adjustments⁽²⁾			3				4					6				7


Total			7				6					16				8


Comprehensive Income	$		2,172		$		487		$			2,491		$		3,524


^{(1)net of income tax benefit (expense) of:}	$		(3	)	$		(1	)	$			(6	)	$		(1	)
^{(2)net of income tax benefit (expense) of:}			(1	)			(1	)				(3	)			(3	)

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

		Nine Months Ended
		September 30

millions		2008				2007

Cash Flow from Operating Activities
Net income	$		2,475		$		3,516
Less income from discontinued operations, net of taxes			58				22
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			2,438				2,090
Deferred income taxes			94				(1,060	)
Dry hole expense and impairments of unproved properties			637				454
Minority interests			15				-
Impairments			67				40
(Gains) losses on divestitures, net			(165	)			(4,400	)
Unrealized (gains) losses on derivatives			(277	)			544
Other non-cash items			87				100
Changes in assets and liabilities:
(Increase) decrease in accounts receivable			340				1,352
Increase (decrease) in accounts payable and accrued expenses			548				(1,575	)
Other items - net			(197	)			784


Cash provided by (used in) operating activities - continuing operations			6,004				1,823
Cash provided by (used in) operating activities - discontinued operations			(4	)			193

Net cash provided by (used in) operating activities			6,000				2,016



Cash Flow from Investing Activities
Acquisitions, net of cash acquired			-		(7			)
Additions to properties and equipment and dry hole costs	(3,354			)	(3,284			)
Divestitures of properties and equipment and other assets			688				7,766
Other - net			(147	)			(41	)


Cash provided by (used in) investing activities - continuing operations			(2,813	)	4,434
Cash provided by (used in) investing activities - discontinued operations			-				(69	)

Net cash provided by (used in) investing activities			(2,813	)	4,365



Cash Flow from Financing Activities
Borrowings from unconsolidated affiliates, net of issuance costs			1				2,879
Repayments of debt			(1,737	)			(8,325	)
Repayments on midstream subsidiary note payable			(330	)			-
Increase (decrease) in accounts payable, banks			19				(85	)
Dividends paid			(129	)			(130	)
Settlement of derivatives with a financing element			3				(61	)
Purchase of treasury stock			(619	)			(12	)
Repurchase and retirement of preferred stock			(45	)			(1	)
Issuance of common stock			19				86
Sale of subsidiary interests			347				-
Distributions to minority interests shareholders			(3	)			-


Cash provided by (used in) financing activities - continuing operations			(2,474	)			(5,649	)
Cash provided by (used in) financing activities - discontinued operations			-				-

Net cash provided by (used in) financing activities			(2,474	)			(5,649	)



Net Increase (Decrease) in Cash and Cash Equivalents			713				732


Cash and Cash Equivalents at Beginning of Period			1,268				511



Cash and Cash Equivalents at End of Period	$		1,981		$		1,243

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, gathering, processing and marketing of natural gas, crude oil, condensate and natural gas liquids (NGLs). The Company also engages in the hard minerals business through non-operated joint ventures and royalty arrangements. The terms "Anadarko" and "Company" refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

The information, as furnished herein, reflects all normal recurring adjustments that are, in the opinion of management, necessary for a fair statement of financial position as of September 30, 2008 and December 31, 2007, the results of operations for the three and nine months ended September 30, 2008 and 2007 and cash flows for the nine months ended September 30, 2008 and 2007. Certain amounts for prior periods have been reclassified to conform to the current presentation.

In preparing financial statements, 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 reporting period. On an ongoing basis, management reviews its estimates, including those related to determination of proved reserves, litigation, environmental liabilities, income taxes and fair values. Changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates.

The accompanying financial statements and notes should be read in conjunction with the Company's 2007 Annual Report on Form 10-K.

Assets Held for Sale and Discontinued Operations Certain assets were classified as held for sale as of September 30, 2008 and December 31, 2007. Additionally, the Company's Canadian operations, which were substantially divested in 2006, have been classified as discontinued operations. Unless otherwise indicated, information presented in the notes to the financial statements relates only to Anadarko's continuing operations. See Note 2.

Changes in Accounting Principles The Company adopted Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements," as of January 1, 2008. SFAS No. 157 does not require any additional fair value measurements. Rather, the pronouncement defines fair value, establishes a framework for measuring fair value under existing accounting pronouncements that require fair value measurements, and expands disclosures about fair value measurements. The Company elected to implement this Statement with the one-year deferral permitted by Financial Accounting Standards Board (FASB) Staff Position (FSP) 157-2 for nonfinancial assets and nonfinancial liabilities initially measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). The deferral applies to nonfinancial assets and liabilities initially measured at fair value such as business combinations and exchanges; impaired long lived assets (asset groups); intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which Anadarko uses fair value. The Company does not expect any significant impact on Anadarko's consolidated financial statements when the Company implements SFAS No. 157 for these assets and liabilities. See Note 6.

Additionally, as of January 1, 2008, Anadarko adopted FASB FSP FASB Interpretation (FIN) No. 39-1, "Amendment of FASB Interpretation No. 39," which amends FIN No. 39, "Offsetting of Amounts Related to Certain Contracts." The FSP permits netting fair values of derivative assets and liabilities for financial reporting purposes, if such assets and liabilities are with the same counterparty and subject to a master netting arrangement. The Company has elected to employ net presentation of derivative assets and liabilities when FSP FIN No. 39-1 conditions are met. This election is consistent with the Company's historical practice and, therefore, did not affect prior periods presented. However, the FSP also requires that when derivative assets and liabilities are presented net, fair value of the right to reclaim collateral assets held by counterparties or the obligation to return cash collateral received from counterparties is also offset against the net fair value of the corresponding derivative. Netting collateral assets and liabilities against corresponding derivative balances represents a change in accounting policy for Anadarko, and has been applied in all periods presented. As a result, collateral assets of $30 million at December 31, 2007 were reclassified and are presented as a reduction of liabilities. See Note 6.

Derivative Instruments Anadarko utilizes derivative instruments in conjunction with its marketing and trading activities and to manage the price risk attributable to the Company's forecasted sales of natural gas, oil and NGLs production. Anadarko also utilizes derivatives to manage its exposure associated with NGLs processing, interest rates and foreign currency exchange rates. All derivatives that do not satisfy the normal purchases and sales exception criteria are carried on the balance sheet at fair value and are included in other current assets, other assets, accrued expenses or other long-term liabilities, depending on the position (netted when appropriate) and the expected timing of settlement. See Note 6.

Effective January 1, 2007, Anadarko discontinued its application of hedge accounting to all commodity and interest rate derivatives. As a result of this change, both realized and unrealized gains and losses on derivative instruments are recognized in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting and residing in accumulated other comprehensive loss will be reclassified to earnings in future periods as the economic transactions to which the derivatives relate affect earnings.

Earnings Per Share The Company's basic earnings per share (EPS) amounts have been computed based on the average number of shares of common stock outstanding for the period. Diluted EPS amounts include the effect of the Company's outstanding stock options, restricted stock awards, restricted stock units and performance-based stock awards under the treasury stock method, if including such potential shares of common stock is dilutive. See Note 9.

Accounting for Sales of Subsidiary Member Interest Securities and Exchange Commission (SEC) Staff Accounting Bulletin No. 51, "Accounting for Sales of Stock by a Subsidiary" (SAB 51), provides guidance on accounting for the effect of issuances of a subsidiary's stock on the parent's investment in that subsidiary. SAB 51 allows registrants to elect an accounting policy of recording such increases or decreases in a parent's investment (SAB 51 credits or charges, respectively) either in income or in stockholders' equity. In accordance with the election provided in SAB 51, Anadarko adopted a policy of recording such SAB 51 credits or charges directly to paid-in capital in stockholders' equity. See Note 8.

Recently Issued Accounting Standards Not Yet Adopted In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities." SFAS No. 161 does not change the accounting policy for derivatives, but requires enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items (if any) are accounted for, and how they affect the Company's financial position, financial performance and cash flows. SFAS No. 161 is effective for Anadarko for annual and interim periods beginning with the first quarter of 2009. Early adoption is permitted. SFAS No. 161 is a disclosure requirement that does not affect Anadarko's consolidated financial position or results of operations.

In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) No. 03-6-1, "Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities." FSP EITF No. 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and therefore need to be included in the earnings allocation in calculating earnings per share under the two-class method described in SFAS No. 128, "Earnings per Share." FSP EITF No. 03-6-1 requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per share. FSP EITF No. 03-6-1 is effective for fiscal years beginning after December 15, 2008; earlier application is not permitted. The Company is currently evaluating the impact of FSP EITF No. 03-6-1 on the Company's reported earnings per share.

2. Divestitures and Other, Assets Held for Sale and Discontinued Operations

Gains (Losses) on Divestitures and Other During the first nine months of 2008, the Company closed the sales of certain oil and gas properties, primarily in the United States, for approximately $690 million. In May 2008, the Company's then wholly-owned subsidiary, Western Gas Partners, LP, completed an initial public offering. Net proceeds from the initial public offering were $321 million. See Note 8.

Since its adoption of the successful efforts method of accounting in the third quarter of 2007, the Company continues to evaluate the accuracy and completeness of its detailed records for properties and equipment. As part of this process, in March 2008, management identified in its oil and gas property records capitalized costs of $163 million attributable to properties that were divested in 2007. Because these costs were inadvertently excluded from the gain calculations, pretax gains on divestitures reported in the first and second quarter of 2007 were overstated by $75 million and $88 million, respectively. Management concluded that the misstatements were not material relative to 2007 interim and annual results, or to the 2008 period, and corrected the error in the first quarter of 2008 as a $163 million reduction in gains (losses) on divestitures and other, net.

Additionally, an unrelated analysis led management to conclude that the net properties and equipment balance was understated by $81 million when compared to the detailed accounting records by property. That amount arose as a result of accounting adjustments to convert from the full cost to the successful efforts method, and could not be reasonably associated with specific properties. Accordingly, management removed the unidentified amount from the balance sheet, increasing the properties and equipment balance and increasing first quarter of 2008 earnings. The $81 million correction is reported in gains (losses) on divestitures and other, net for the nine months ended September 30, 2008.

After considering the effect of income taxes, the two adjustments recorded in the first quarter of 2008 related to the adoption of the successful efforts method of accounting in the third quarter of 2007 reduced net earnings for the nine months ended September 30, 2008 by $52 million. Net gains on divestitures for the three and nine months ended September 30, 2008 of $1 million and $328 million, respectively, related to the divestiture of certain oil and gas properties primarily in the United States in several unrelated transactions. Net gains on divestitures for the three months ended September 30, 2007 of $0.3 billion were primarily related to the divestiture of certain gathering and processing facilities. Net gains on divestitures for the nine months ended September 30, 2007 of $4.4 billion includes approximately $3.9 billion related to the divestiture of certain oil and gas properties and approximately $0.5 billion related to the divestiture of certain gathering and processing facilities.

Pending Divestitures and Assets Held for Sale In March 2008, the Company entered into an agreement to divest its 50% interest in the Peregrino field, offshore Brazil, and certain related assets. The agreement provides for consideration to Anadarko of $1.5 billion at closing. Additionally, in connection with the sale of its interest in the Peregrino field, Anadarko may receive contingent consideration in future periods. Contingent consideration is based on the value of oil produced from properties subject to the sale transaction. The Peregrino field is currently under development, with initial production expected in 2010. The timing of the closing of the Peregrino divestiture is contingent on approvals by the appropriate authorities, which are expected to be obtained in the fourth quarter of 2008.

Assets and liabilities associated with the Peregrino development are classified as held for sale as of September 30, 2008. For the held-for-sale asset, sale proceeds are expected to exceed the net carrying amount of the relevant asset and, therefore, no impairment was indicated.

In April 2008, Anadarko entered into an agreement to sell a wholly-owned subsidiary, which owns an 18% interest in Petroritupano, S.A. (Petroritupano), a Venezuelan mixed company whose other shareholders are Petróleos de Venezuela, S.A. (PDVSA) and Petrobras Energía, S.A., for $200 million. The closing of this transaction was subject to customary closing conditions, including receipt of approvals by Venezuelan authorities. Anadarko has been informed by the Venezuelan Ministry of Energy and Petroleum (MEP) that it will not grant approval of the sale transaction because PDVSA intends to acquire Anadarko's equity interest in Petroritupano. Anadarko has subsequently received a letter from Corporacion Venezolana del Petroleo, S.A. (CVP), an affiliate of PDVSA, in which CVP states its interest in acquiring Anadarko's equity interest in Petroritupano. At this time, Anadarko is unable to determine when the sale to CVP may be consummated. Anadarko's investment in Petroritupano is included in other assets at September 30, 2008.

Discontinued Operations In late 2006, Anadarko divested its Canadian oil and gas operations. Activity in 2008 and 2007 relates primarily to the impact of an adjustment to an indemnity obligation provided by the Company to the purchaser, as well as expenses associated with finalizing exit activities. See Note 14.

3. Inventories

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


	September 30,				December 31,
millions	2008				2007

Materials and supplies		$	256	$		202
Crude oil and NGLs			130			114
Natural gas			39			42


Total		$	425	$		358

4. Properties and Equipment

Suspended Exploratory Drilling Costs If an exploratory well has found sufficient quantities of hydrocarbons to justify its potential completion as a producing well, drilling costs associated with the well are initially capitalized, or suspended, pending determination of whether proved reserves can be attributed to the area as a result of drilling.

The following table presents the amount of suspended exploratory drilling costs at September 30, 2008 and December 31, 2007, and changes in those amounts for the first nine months of 2008. The table excludes amounts capitalized and subsequently reclassified to proved oil and gas properties or charged to expense in the same reporting period.

millions

Balance at December 31, 2007	$	308
Additions pending the determination of proved reserves		135
Reclassifications to proved oil and gas properties		(44	)
Charges to exploration expense		(53	)

Balance at September 30, 2008	$	346

The following table presents the total amount of suspended exploratory drilling costs as of September 30, 2008 by geographic area, including the year the costs were originally incurred.


				Year Costs Incurred

									2006
millions		Total		2008			2007		& Prior


United States - Offshore	$	122	$	(3	)	$	68	$	57
United States - Onshore		92		33			42		17
International		132		64			68		-

	$	346	$	94		$	178	$	74

Suspended exploratory drilling costs capitalized for a period greater than one year at September 30, 2008 (included in the table above)	$	251

The well costs that have been suspended for longer than one year are associated with 19 projects. The majority of such costs associated with projects in the United States are suspended pending the completion of an economic evaluation including, but not limited to, results of additional appraisal drilling, facilities, infrastructure, well test analysis, additional geological and geophysical data and approval of a development plan. The international projects with costs suspended for longer than one year are primarily suspended pending the results of additional appraisal drilling. Management believes these projects related to exploratory drilling costs have sufficient quantities of hydrocarbons to justify their potential development and is actively pursuing efforts to assess whether reserves can be attributed to their respective areas. If additional information becomes available that raises substantial doubt about the economic or operational viability of any of these projects, the associated costs will be expensed.

5. Debt and Interest Expense

Debt The following table represents the debt of the Company as of September 30, 2008 and December 31, 2007:

	September 30, 2008					December 31, 2007

millions	Principal		Carrying Value			Principal		Carrying Value


Current and long-term debt				$	10,828				$	12,547
Midstream subsidiary note payable to
a related party					1,870					2,200

Total debt	$	14,487		$	12,698	$	16,558		$	14,747

As of December 31, 2007, current debt included $1 billion under a variable-rate 354-day facility. This facility was fully repaid and concurrently retired in February 2008. In the third quarter of 2008, the Company retired $344 million aggregate principal amount of Floating Rate Notes due September 2009 and recognized a gain of $3 million, which is included in interest expense. During the first nine months of 2008, the Company repaid an aggregate principal amount of $2.1 billion of debt (including the variable-rate 354-day facility) that was outstanding at December 31, 2007.

In March 2008, the Company entered into a $1.3 billion, five-year Revolving Credit Agreement (RCA) with a syndicate of United States and foreign lenders. Under the terms of the RCA, the Company can, under certain conditions, request an increase in the borrowing capacity under the RCA up to a total available credit amount of $2.0 billion. The RCA has a maximum 65% debt to total book capitalization covenant (excluding non-cash charges). The RCA terminates in March 2013. The RCA replaced a $750 million revolving credit facility which was scheduled to mature in 2009 and was retired. As of September 30, 2008, the Company had nooutstanding borrowings under the RCA.

See Note 7 for Anadarko's notes payable to certain investees that do not affect the reported debt balance.

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

	Three Months Ended									Nine Months Ended
		September 30								September 30

millions		2008				2007				2008				2007


Gross interest expense -
Current debt, long-term debt and other	$		188		$		242		$		574		$		964
Midstream subsidiary note payable to a related party			20				-				82				-
Capitalized interest*			(28	)			(20	)			(98	)			(103	)

Net interest expense	$		180		$		222		$		558		$		861



*Included in the nine month period ended September 30, 2008 is additional capitalized interest related to a prior period of $16 million.

See Note 7 for interest expense incurred on certain notes payable to unconsolidated affiliates which is reported in other (income) expense.

6. Financial Instruments

Derivative Instruments In the normal course of business, the Company is exposed to commodity price risk. Management believes it is prudent to periodically reduce the Company's exposure to cash flow variability resulting from changing commodity prices by entering into derivative financial instruments intended to manage price risk associated with the Company's oil and gas production or gas processing operations. The types of derivative financial instruments utilized by the Company include futures, swaps and options. In addition to derivative financial instruments, the Company may also enter into fixed-price physical delivery sales contracts to manage cash flow variability. The Company's marketing and trading business routinely enters into derivative financial instruments and physical delivery contracts for trading purposes with the objective of generating profits from exposure to changes in market prices of natural gas, crude oil and NGLs. Derivative financial instruments are also used to manage price risk that is incurred to meet customers' pricing requirements and to fix margins on the future sale of natural gas and NGLs from the Company's leased storage facilities. The Company may also use options and swaps to manage exposure associated with changes in interest rates and foreign currency exchange rates.

Futures contracts are generally used to fix the price of expected future gas sales and oil sales at major industry trading locations; for example, Henry Hub, Louisiana for gas and Cushing, Oklahoma for oil. Commodity swap agreements are generally used to fix or float the price of oil and gas at major trading locations. Basis swaps are used to fix, or float, the price differential between the price of gas at Henry Hub and various other market locations. Physical delivery purchase and sale agreements require the receipt or delivery of physical product at a specified location and price. The pricing can be fixed or market-based. Options are generally used to fix a floor and a ceiling price (collar) for expected future oil and gas sales. Interest rate swaps are used to fix or float interest rates attributable to the Company's existing or anticipated indebtedness.

Settlements of exchange-traded contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the Intercontinental Exchange and have nominal credit risk. Over-the-counter traded swaps, options and physical delivery contracts expose the Company to credit risk to the extent the counterparty is unable to meet its settlement commitment. The Company monitors the creditworthiness of each counterparty and assesses the impact, if any, on fair value. In addition, the Company routinely exercises its contractual right to net realized gains against realized losses when settling with its swap and option counterparties.

Oil and Gas Activities At September 30, 2008 and December 31, 2007, the Company was party to derivative financial instruments intended to manage price risk associated with a portion of its expected future sales of its oil and gas production. Realized and unrealized gains and losses related to derivative financial instruments entered into to economically hedge the sales price of the Company's future sales of its oil and gas production are recognized in gas sales and oil and condensate sales, respectively, as they occur. For the quarters ended September 30, 2008 and 2007, unrealized gains (losses) of $2.3 billion and $(32) million, respectively, and realized gains (losses) of $(170) million and $133 million, respectively, were recorded in natural gas, oil and NGLs sales. For the nine months ended September 30, 2008 and 2007, unrealized gains (losses) of $239 million and $(545) million, respectively, and realized gains (losses) of $(570) million and $513 million, respectively, were recorded in natural gas, oil and NGLs sales.

The following table presents the fair value of the Company's commodity derivative financial instruments (excluding physical delivery sales contracts) and the accumulated other comprehensive loss representing net unrealized losses on those commodity derivatives that were previously subject to cash flow hedge accounting.


		September 30,			December 31,
millions		2008				2007

Fair Value -
Current asset	$		223		$		47
Current liability			(211	)			(156	)
Long-term asset			217				52
Long-term liability			(263	)			(207	)

Total	$		(34	)	$		(264	)


Accumulated other comprehensive loss before income taxes	$		(23	)	$		(21	)
Accumulated other comprehensive loss after income taxes	$		(14	)	$		(14	)

Below is a summary of the Company's derivative financial instruments related to its oil and gas production as of September 30, 2008. The natural gas prices are NYMEX Henry Hub. The crude oil prices reflect a combination of NYMEX Cushing and London Brent Dated.

			Average Price per MMBtu

	Volume				Floor
	(thousand		Ceiling		Purchased		Floor
	MMBtu/d)	Sold Price			Price	Sold Price

Natural Gas
Three-Way Collars ^(a)
Remainder of 2008	500	$	14.26	$	7.50	$	5.00
Remainder of 2008	900	$	9.14	$	7.50	$	5.50

	1,400	$	10.97	$	7.50	$	5.32

2009	530	$	11.25	$	7.50	$	5.45

					Volume
					(thousand	Price per
					MMBtu/d)		MMBtu

Basis Swaps
Remainder of 2008
Gulf Coast					560	$	(0.24	)
Mid Continent					365	$	(1.01	)
Rocky Mountains					455	$	(1.47	)
West Texas					35	$	(0.92	)

					1,415	$	(0.85	)

2009					1,200	$	(0.85	)
2010					345	$	(1.08	)


MMBtu - million British thermal units
MMBtu/d - million British thermal units per day

(a) A three-way collar is a combination of 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 (i.e., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

			Average Price per Barrel

					Floor
	Volume		Ceiling		Purchased		Floor
	(MBbls/d)	Sold Price			Price	Sold Price

Crude Oil

Three-Way Collars ^(a)
Remainder of 2008	31	$	87.09	$	49.09	$	34.09
Remainder of 2008	20	$	87.38	$	60.00	$	45.00
Remainder of 2008	35	$	101.39	$	60.00	$	45.00

	86	$	92.98	$	56.07	$	41.07

2009	48	$	87.04	$	52.51	$	37.51
2010	18	$	86.76	$	49.19	$	34.18
2011	3	$	86.00	$	50.00	$	35.00
2012	2	$	92.50	$	50.00	$	35.00


MBbls/d - thousand barrels per day

(a) A three-way collar is a combination of 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 (i.e., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

Marketing and Trading Activities Gains and losses attributable to the Company's marketing and trading derivative instruments (both physically and financially settled) are recognized currently in earnings. The marketing and trading gains and losses attributable to the Company's production are reported in gas sales, oil and condensate sales and NGLs sales. The marketing and trading gains and losses attributable to third-party production are reported in gathering, processing and marketing sales. The fair values of these derivatives as of September 30, 2008 and December 31, 2007 are as follows:

		September 30,			December 31,
millions		2008			2007

Fair Value -
Current asset	$		62		$	37
Current liability			(18	)		(25	)
Long-term asset			8			4
Long-term liability			(7	)		(5	)

Total	$		45		$	11

Interest Rate Swaps In January 2008, Anadarko entered into 18-month interest rate swaps with an aggregate notional value of $1.0 billion whereby the Company pays a weighted-average fixed interest rate of 2.74% and receives a floating interest rate indexed to the three-month LIBOR rate.

In 2006, the Company realized a pretax loss of $211 million ($132 million after tax) upon the settlement of interest rate swaps that hedged the interest rate risk of a then-anticipated debt issuance. Since the swaps qualified and were designated as cash flow hedges of the forecasted debt issuances, this loss was recognized in accumulated other comprehensive income, and is being amortized to interest expense over the term of the related debt. As of September 30, 2008 and December 31, 2007, the unamortized balance of the pretax accumulated other comprehensive loss was $169 million and $187 million, respectively, or $107 million and $119 million, respectively, net of tax effects.

Gains or (losses) (realized and unrealized) on interest rate swaps of $(2) million and $32 million were recorded as interest expense for the quarters ended September 30, 2008 and September 30, 2007, respectively. Gains or (losses) (realized and unrealized) on interest rate swaps of $3 million and $(13) million were recorded as interest expense for the nine months ended September 30, 2008 and September 30, 2007, respectively.

Fair Value As discussed in Note 1, the Company adopted SFAS No. 157 effective January 1, 2008. To estimate fair value, the Company utilizes observable market data when available, or models that utilize observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management's judgment, market participants would utilize in a fair value measurement.

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS No. 157 characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

Level 1 - inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).

Level 2 - inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3 - inputs that are not observable from objective sources, such as the Company's internally developed assumptions about market participant assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company's internally developed present value of future cash flows model that underlies the fair value measurement).

In forming fair value estimates, the Company utilizes the most observable inputs available for the valuation technique utilized. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorized based upon the lowest level of input that is significant to the fair value measurement. For Anadarko, recurring fair value measurements are performed for interest rate derivatives, commodity derivatives and investments in trading securities. The fair value of commodity futures contracts are based on inputs that are quoted prices in active markets for identical assets or liabilities, thus resulting in Level 1 categorization of such measurements. The valuation of physical delivery purchase and sale agreements, over-the-counter financial swaps, three-way collars and deferred compensation arrangements are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. The Company categorizes these measurements as Level 2.

The following table sets forth, by level within the hierarchy, the fair value of the Company's financial assets and liabilities at September 30, 2008 that are measured at fair value each reporting period.

								Netting and
millions		Level 1		Level 2		Level 3		Collateral ⁽¹⁾			Total

Assets:
Commodity derivatives	$	23	$	866	$	-	$	(394	)	$	495
Trading securities		8		-		-		-			8
Interest rate derivatives		-		3		-		-			3

Total	$	31	$	869	$	-	$	(394	)	$	506

Liabilities:
Commodity derivatives	$	13	$	864	$	-	$	(508	)	$	369
Deferred compensation arrangements		-		24		-		-			24

Total	$	13	$	888	$	-	$	(508	)	$	393



^{(1) Represents the impact of netting assets, liabilities and collateral with counterparties with which the right of setoff exists. Cash collateral held by counterparties was $132 million at September 30, 2008. Cash collateral held by Anadarko was $18 million at September 30, 2008.}

The following table is a reconciliation of changes in the fair value of the net derivative assets (liabilities) classified as Level 3 in the fair value hierarchy.

	Nine Months Ended
millions	September 30, 2008

Balance as of the beginning of the period	$	(291	)
Realized and unrealized gains (losses)		(874	)
Purchases, issuances and settlements		38
Transfers in and/or out of Level 3		1,127

Balance as of September 30, 2008	$	-

Transfers out of Level 3 were the result of the Company implementing a marketing system in the second quarter of 2008. The new system utilizes observable market data or interpolates valuations using observable market data for all significant inputs.

7. Unconsolidated Affiliates

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 approximately $2.9 billion at the time of the contribution to newly formed unconsolidated entities in exchange for non-controlling 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, 2008, the carrying amount of these investments was $2.84 billion, while the carrying amount of notes payable to affiliates was $2.85 billion. Anadarko has legal right of setoff and intends to net-settle its obligations under each of the notes payable to the investees and the distributable value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the consolidated balance sheet and are included in other long-term liabilities - other for all periods presented. Other income (expense) for the three and nine months ended September 30, 2008 included interest expense on the notes payable to the investee entities of $(27) million and $(96) million, respectively, and equity in earnings from Anadarko's investments in the investee entities of $32 million and $106 million, respectively. Other income (expense) for the three and nine months ended September 30, 2007 included interest expense on the notes payable to the investees of $(37) million and $(54) million, respectively, and equity in earnings on Anadarko's investments in these entities of $37 million and $54 million, respectively.

8. Minority Interests

Master Limited Partnership During the second quarter of 2008, Western Gas Partners, LP (WES) completed its initial public offering of 20.8 million common units (representing a 38.4% limited partner interest) for net proceeds of $321 million ($343 million less $22 million for underwriting discounts and structuring fees). WES is a Delaware limited partnership formed by Anadarko to own, operate, acquire and develop midstream assets. Anadarkocontributed assets to WES in exchange for a 2% general partner interest and100% of the WES incentive distribution rights and common and subordinated units, together representing an aggregate 59.6% limited partner interest in WES. In addition, Anadarko maintains control over the assets owned by WES through ownership of the general partner interests. Proceeds were used to reduce debt.

The common units have preference over the subordinated units with respect to cash distributions. Accordingly, all proceeds from the sale of the partnership units were recorded as minority interest on the consolidated balance sheet. The subordinated units will convert into an equal number of common units upon termination of the subordination period. Generally, the subordination period will end when either:

(i)	WES has paid at least $0.30 per quarter on each outstanding common unit, subordinated unit and general partner unit for any three consecutive four quarterly periods ending on or after June 30, 2011; or
(ii)	WES has paid at least $0.45 per quarter on each outstanding common unit, subordinated unit and general partner unit for any four consecutive quarters.

When the subordinated units convert to common units, the Company will recognize additional paid-in capital in stockholders' equity in accordance with SAB 51.

The results of operations and financial position of WES are included in the consolidated financial statements of Anadarko; in addition, the portion of WES' results of operations that is attributable to units held by the public (units not held by Anadarko) is recorded as minority interests.

Pursuant to the terms of its partnership agreement, WES is required to pay a minimum quarterly distribution of $0.30 per unit to the extent it has sufficient cash available for distribution. During the third quarter of 2008, WES paid a prorated quarterly cash distribution of $0.1582 per unit for the second quarter of 2008, which corresponds to a quarterly distribution of $0.30 per unit on a full quarter basis.

9. Stockholders' Equity

Preferred Stock For the first and second quarters of 2008 and for the first, second and third quarters of 2007, dividends of $13.65 per share (equivalent to $1.365 per depositary share) were paid to holders of the Company's preferred stock. Anadarko redeemed and subsequently retired the remaining depositary shares for $45 million in the second quarter of 2008.

Common Stock The computation of basic and diluted EPS from continuing operations is as follows:

		Three Months Ended							Three Months Ended
		September 30, 2008							September 30, 2007

						Per Share							Per Share
millions except per share amounts		Income		Shares		Amount		Income			Shares		Amount

Basic EPS
Income from continuing
operations		$	2,164					$		493
Preferred stock dividends			-							1

Income from continuing
operations available to
common stockholders		$	2,164		466	$	4.65	$		492		466	$	1.06


Diluted EPS
Effect of dilutive stock options,
restricted stock and performance-
based stock awards			-		2					-		2


Income from continuing
operations available to
common stockholders	$		2,164		468	$	4.62	$		492		468	$	1.05

		Nine Months Ended							Nine Months Ended
		September 30, 2008							September 30, 2007

						Per Share							Per Share
millions except per share amounts		Income		Shares		Amount		Income			Shares		Amount

Basic EPS
Income from continuing
operations		$	2,417					$		3,494
Preferred stock dividends			1							2

Income from continuing
operations available to
common stockholders		$	2,416		467	$	5.17	$		3,492		465	$	7.51


Diluted EPS
Effect of dilutive stock options,
restricted stock and performance-
based stock awards			-		3					-		2


Income from continuing
operations available to
common stockholders	$		2,416		470	$	5.14	$		3,492		467	$	7.48

For the three and nine months ended September 30, 2008, awards for 1.1 million and 1.3 million average shares, respectively, of common stock were excluded from the diluted EPS calculation because their inclusion would have been anti-dilutive. For the three and nine months ended September 30, 2007, awards for 1.7 million and 2.9 million average shares, respectively, of common stock were excluded from the diluted EPS calculation because their inclusion would have been anti-dilutive.

In August 2008, the Company announced a $5 billion share repurchase program under which shares may be repurchased either in the open market or through privately negotiated transactions. The program replaces the prior repurchase program and is authorized to extend through August 2011. The repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. During the quarter ended September 30, 2008, Anadarko purchased 10.0 million shares of common stock for $600 million under the program.

The covenants in certain of the Company's agreements provide for a maximum debt to total book capitalization ratio of 65%, excluding non-cash charges. Although these covenants do not specifically restrict the payment of any dividends, the impact of dividends paid on this capitalization ratio must be considered prior to the payment of dividends in order to ensure the maximum debt to total book capitalization ratio is not exceeded. Based on these covenants, as of September 30, 2008, retained earnings of approximately $11.4 billion were not limited as to the payment of dividends.

10. Statements of Cash Flows Supplemental Information

The following table presents supplemental cash flow information. Cash paid for interest is net of amounts capitalized.


		Nine Months Ended
		September 30

millions			2008			2007

Cash paid (including discontinued operations):
Interest	$			619	$		880
Income taxes	$			823	$		1,611

Non-cash investing activities:
Receipt of an equity investment in exchange for interests in oil
and gas properties (See Note 7)	$			-	$		1,000
Receipt of an equity investment in exchange for interests in natural gas
gathering systems and associated processing plants (See Note 7)	$			-	$		1,879
Fair value of properties and equipment received
in non-cash exchange transactions	$			108	$		88

The difference between cash and cash equivalents on the consolidated balance sheet and statement of cash flows at September 30, 2008 is $1 million related to Peregrino assets, which is included in current assets held for sale on the consolidated balance sheet.

11. Segment Information

Anadarko's primary business segments are vertically integrated within the oil and gas industry. These segments are managed separately because of the nature of their products and services, as well as unique technology, distribution and marketing requirements. The Company's three 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's and third-party oil and gas production. The marketing segment sells most of Anadarko's production, as well as commodities purchased from third parties.

To assess the operating results of Anadarko's segments, management uses income from continuing operations before income taxes, interest expense, exploration expense, DD&A expense and impairments (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, but is monitored by management as part of costs incurred in exploration and development activities. Similarly, depreciation 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 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 income from continuing operations and other performance measures, such as operating income or cash flow from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income from continuing operations before income taxes.

		Three Months Ended						Nine Months Ended
		September 30						September 30

millions		2008			2007			2008			2007


Consolidated Adjusted EBITDAX	$		4,798	$		1,977	$		8,121	$		9,290
Exploration expense			373			253			880			614
Depreciation, depletion and amortization			844			655			2,438			2,090
Impairments			56			-			67			40
Interest expense			180			222			558			861

Income from continuing operations before income taxes	$		3,345	$		847	$		4,178	$		5,685

The following table presents selected financial information for Anadarko's operating segments. Information presented as "Other and Intersegment Eliminations" includes results from hard minerals joint ventures and royalty arrangements, operating activities that are not considered operating segments, as well as corporate and financing activities.


	Oil and Gas										Other and
	Exploration										Intersegment
millions	& Production				Midstream		Marketing				Eliminations					Total


Three Months Ended September 30:

2008
Sales revenues		$	3,397	$		76		$	2,736			$	-		$		6,209
Intersegment revenues			2,355			326			(2,565	)			(116	)			-
Gains (losses) on divestitures and other, net			1			-			-				(61	)			(60	)

Total revenues and other			5,753			402			171				(177	)			6,149

Operating costs and expenses ⁽¹⁾			901			288			122				8				1,319
Other (income) expense, net			-			-			-				22				22
Minority interests			-			10			-				-				10

Total costs and expenses			901			298			122				30				1,351

Adjusted EBITDAX		$	4,852	$		104		$	49			$	(207	)	$		4,798

2007
Sales revenues	$	1,279	$	52	$	1,326		$	(1	)	$	2,656
Intersegment revenues		968		260		(1,160	)		(68	)		-
Gains (losses) on divestitures and other, net		7		300		-			32			339

Total revenues and other		2,254		612		166			(37	)		2,995

Operating costs and expenses ⁽¹⁾		632		217		106			71			1,026
Other (income) expense, net		-		-		-			(8	)		(8	)

Total costs and expenses		632		217		106			63			1,018

Adjusted EBITDAX	$	1,622	$	395	$	60		$	(100	)	$	1,977

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

Oil and Gas

Other and

Exploration

Intersegment

millions

& Production

  Midstream

Marketing

Eliminations

Total

Nine Months Ended September 30:

2008

Sales revenues

$

4,762

$

219

$

6,662

$

-

$

11,643

Intersegment revenues

5,708

911

(6,245

)

(374

)

-

Gains (losses) on divestitures

     and other, net

168

(3

)

-

105

270

   Total revenues and other

10,638

1,127

417

(269

)

11,913

Operating costs and expenses ⁽¹⁾

2,641

786

343

12

3,782

Other (income) expense, net

-

-

-

(5

)

(5

)

Minority interests

-

15

-

-

15

   Total costs and expenses

2,641

801

343

7

3,792

Adjusted EBITDAX

$

7,997

$

326

$

74

$

(276

)

$

8,121

2007

Sales revenues

$

4,166

$

155

$

4,113

$

(62

)

$

8,372

Intersegment revenues

2,802

1,026

(3,624

)

(204

)

-

Gains (losses) on divestitures

     and other, net

3,869

532

-

57

4,458

   Total revenues and other

10,837

1,713

489

(209

)

12,830

Operating costs and expenses ⁽¹⁾

2,065

885

322

328

3,600

Other (income) expense, net

-

-

-

(60

)

(60

)

   Total costs and expenses

2,065

885

322

268

3,540

Adjusted EBITDAX

$

8,772

$

828

$

167

$

(477

)

$

9,290

September 30, 2008:

Net properties and equipment

$

32,308

$

2,983

$

27

$

1,559

$

36,877

Goodwill

$

4,839

$

110

$

-

$

-

$

4,949

December 31, 2007:

Net properties and equipment

$

33,150

$

2,694

$

28

$

1,579

$

37,451

Goodwill

$

4,847

$

108

$

-

$

-

$

4,955

^{(1)     Operating costs and expenses exclude exploration, DD&A and impairment expenses since they are excluded from Adjusted EBITDAX. Included in the Midstream segment for the nine months ended September 30, 2008 is a reduction of accrued expenses related to a prior period of $29 million.

12.  Income Taxes

       Following is a summary of income tax expense and effective tax rates for the three and nine months ended September 30, 2008 and September 30, 2007, respectively.

Three Months Ended

Nine Months Ended

September 30

September 30

millions except percentages

2008

2007

2008

2007

Income tax expense

$

1,181

$

354

$

1,761

$

2,191

Effective tax rate

35

%

42

%

42

%

39

%

       The effective tax rates for the three and nine months ended September 30, 2008 include an increase to the 35% statutory rate attributable to the accrual of the Algerian exceptional profits tax which is non-deductible for Algerian income tax purposes, other foreign taxes in excess of federal statutory rates, state income taxes and other items. This increase in the 35% statutory rate is offset by a foreign tax rate applicable to the Company's pending divestiture of its 50% interest in the Peregrino field, offshore Brazil, which is a rate lower than the 35% U.S. statutory rate, and other items. The variance from the 35% statutory rate in 2007 is primarily caused by the accrual of the Algerian exceptional profits tax which is non-deductible for Algerian income tax purposes, other foreign taxes in excess of federal statutory rates, losses in non-taxable foreign jurisdictions, state income taxes (including the effect of a second quarter 2007 state income tax reduction resulting from enacted Texas legislation) and other items.

       For the three and nine months ended September 30, 2008, $44 million and $92 million, respectively, of the previously established Financial Accounting Standards Board Interpretation No. 48 (FIN 48), "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" liability and associated interest were settled with the taxing authorities.

13.  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 retired employees. Health care benefits are funded by contributions from the Company and the retiree. The Company's retiree life insurance plan is noncontributory.
       During the nine months ended September 30, 2008, the Company made contributions of $61 million to its funded pension plans, $11 million to its unfunded pension plans and $17 million to its unfunded other postretirement benefit plans. Contributions to the funded plans increase the plan assets while contributions to unfunded plans are used for current benefit payments. The Company is evaluating the amount of contributions to be made to its funded pension plans for the remainder of 2008. The evaluation will consider the impact of recent market volatility on the plan assets. If market conditions remain at levels similar to September 30, 2008 levels, contributions to the funded pension plans are expected to be approximately $150 million for the remainder of 2008. Contributions to the unfunded pension plans and unfunded other postretirement benefit plans are expected to be $2 million and $5 million, respectively, for the remainder of 2008.
       The following table sets forth the Company's pension and other postretirement benefit costs.

Pension Benefits

Other Benefits

Three Months Ended

Three Months Ended

September 30

September 30

millions

    2008

2007

2008

2007

Components of net periodic benefit cost

Service cost

$

14

$

14

$

4

$

3

Interest cost

19

20

5

5

Expected return on plan assets

(19

)

(19

)

-

-

Amortization of prior service cost (credit)

-

-

-

-

Amortization of actuarial losses

2

2

-

-

Termination benefits

-

4

-

-

Settlements

-

1

-

-

Curtailments

-

-

-

2

Net periodic benefit cost

$

16

$

22

$

9

$

10

Pension Benefits

Other Benefits

Nine Months Ended

Nine Months Ended

September 30

September 30

millions

    2008

2007

2008

2007

Components of net periodic benefit cost

Service cost

$

41

$

45

$

11

$

12

Interest cost

58

60

15

15

Expected return on plan assets

(59

)

(61

)

-

-

Amortization of prior service cost (credit)

1

1

(1

)

-

Amortization of actuarial losses

7

12

-

1

Termination benefits

-

30

-

5

Settlements

-

-

-

-

Curtailments

-

(4

)

-

1

Net periodic benefit cost

$

48

$

83

$

25

$

34

14.  Commitments and Contingencies

Commitments  In February 2008, the Company extended the terms of a drilling rig contract, which gave rise to an additional $586 million commitment for minimum lease payments in years 2010 through 2013. The portion of these lease payments associated with exploratory wells and development wells, net of amounts billed to partners, will initially be capitalized as a component of oil and gas properties, and either depreciated in future periods or written off as exploration expense. The future minimum lease payments for the Company's operating leases were $5.2 billion at September 30, 2008 compared to $5.5 billion at December 31, 2007.

Contingencies   Litigation charges and adjustments of $103 million and $109 million were recognized for the three and nine months ended September 30, 2008, respectively. Litigation charges and adjustments of $22 million and $56 million were recognized for the three and nine months ended September 30, 2007, respectively. The Company is a defendant in a number of lawsuits and is involved in governmental proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. The Company has also been named as a defendant in various personal injury claims, including claims by employees of third-party contractors alleging exposure to asbestos, silica and benzene while working at refineries (previously owned by 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 consolidated financial position, results of operations or cash flow of the Company.

Litigation   The Company is subject to various claims from its royalty owners in the regular course of business as an oil and gas producer, including disputes regarding measurement, costs and expenses beyond the wellhead and basis for royalty valuations. The Company was named as a defendant in a case styled U.S. of America ex rel. Harold E. Wright v. AGIP Company, et al. filed in September 2000 in the U.S. 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 117 other defendants undervalued natural gas in connection with a payment of royalties 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 intends to vigorously assert such defenses. However, if the Company is found to have violated the False Claims Act, the Company could be subject to a variety of sanctions, including treble damages and substantial monetary fines. All defendants jointly filed a motion to dismiss the action on jurisdictional grounds based on Mr. Wright's failure to qualify as the original source of the information underlying his fraud claims, and the Company filed additional motions to dismiss on separate grounds. On September 14, 2005, the trial court declined an early appeal of its order denying the defendants' motion to dismiss. Mr. Wright passed away in August 2008. Meanwhile, the discovery process is ongoing. The court has entered an order whereby the case will be tried in phases. Prior to its acquisition by Anadarko, Kerr-McGee reached a settlement with the government; however, the court permitted Mr. Wright to conduct additional discovery to test the reasonableness of the settlement. Discovery is currently underway. Neither the Anadarko nor the Kerr-McGee cases are scheduled for trial. Management has accrued a liability for only the settlement amount. The Company believes that an additional loss, if any, is unlikely to have a material adverse effect on Anadarko's financial position, results of operations or cash flows.

       The Company was named as a defendant in a case styled Ivan J. Simmons, Madaline M. Thompson and Gaylon Lee Mitchusson v. Anadarko Petroleum Corporation, which was filed in February 2004 and is pending in the District Court in Caddo County, Oklahoma. Plaintiffs claim the Company failed to correctly pay royalties on gas, arguing that costs associated with compression, gathering, dehydration, and processing should not have been deducted or factored into the royalty calculation. Plaintiffs are seeking an award of monetary and punitive damages. In January 2008, the District Judge issued an order certifying this case as a class action. The defined class generally includes all royalty interest owners in Oklahoma wells where the Company is or was the operator, working interest owner or lessee and relates only to payment of hydrocarbons produced from those wells since 1985. The Company has accrued a liability for this matter and has filed an interlocutory appeal of this class certification order with the Oklahoma Supreme Court seeking to reverse the District Court's certification order.

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. After the passage of the DWRRA, the Minerals Management Service (MMS), an agency of the Department of the Interior (DOI), inserted price thresholds into leases issued in 1996, 1997 and 2000 that effectively eliminated this royalty relief if these price thresholds were exceeded. The 1998 and 1999 leases did not contain price threshold provisions. The Company currently owns interests in several deepwater Gulf of Mexico leases granted during the 1996-2000 time period (some originally owned by Kerr-McGee). 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 believes royalties are suspended under the DWRRA. The 2006 Order is based on the assertion that the DOI has the discretion to eliminate royalty relief under the DWRRA when oil and natural gas prices exceed certain levels specified by the DOI. KMOG believes that the DOI does not have the discretion to eliminate royalty relief on the DWRRA leases issued from 1996 through 2000 and accordingly, is contesting the 2006 Order. In that regard, on March 17, 2006, KMOG filed a lawsuit styled Kerr-McGee Oil and Gas Corp. v. C. Stephen Allred, Assistant Secretary for Land & Minerals Mgt. and the Deprt of the Interior (Kerr-McGee v. Allred) in the U.S. District Court for the Western District of Louisiana against the DOI for injunctive and declaratory relief with respect to the DOI's claims for additional royalties. KMOG and the DOI agreed to mediate the dispute voluntarily and although the parties participated actively in the mediation, the mediation concluded without resolution of the dispute.
       In May 2007, KMOG filed a motion for summary judgment, and in October 2007 the District Court for the Western District of Louisiana ruled in favor of KMOG. The DOI has appealed the decision to the U.S. Court of Appeals for the Fifth Circuit, which has scheduled oral arguments for early December 2008.
       During September 2008, the MMS issued to Anadarko another order (the 2008 Order) to perform restructured accounting and pay royalties covering 17 deepwater leases, including seven leases covered by the 2006 Order. The DOI, relying upon its position that it has the discretion to eliminate royalty relief under the DWRRA through price thresholds, is seeking payment for alleged "past due" oil and gas royalties for years 2003 (gas only) and 2004 through 2007 plus interest. Generally the 2008 Order covers time periods not included in the 2006 Order. In October 2008, Anadarko filed an administrative appeal of the 2008 Order with the MMS and requested approval from the MMS to self-bond. Also, Anadarko filed a motion for a stay of the 2008 Order and was granted a stay for six months pending the outcome of Kerr-McGee v Allred.
        The Company has accrued a liability of approximately $600 million, which, as of September 30, 2008, is equal to the royalties (plus accrued interest) that could be owed on the leases listed in the 2006 Order and the 2008 Order and other 1996, 1997 and 2000 leases granted to Anadarko and KMOG in the Gulf of Mexico that contain similar price threshold provisions to the leases from the 2006 Order and the 2008 Order currently in dispute. The liability will continue to be adjusted monthly as production is sold and sales prices are confirmed, until the resolution of the matter is final. Under the applicable statutes, regulations and lease terms attributable to the 1998 and 1999 leases, no royalties are owed on production from these leases until the applicable royalty suspension volumes are exhausted; accordingly, no amounts have been accrued for potential royalty payments under those leases.

Guarantees and Indemnifications  Under the terms of the Master Separation Agreement, dated as of November 28, 2005, entered into between Kerr-McGee and Tronox Incorporated (Tronox), a former wholly-owned subsidiary 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 is limited to a maximum aggregate reimbursement of $100 million. As of September 30, 2008 the Company has a liability recorded for the remaining guarantee obligation of $96 million.

       The Company also provides certain indemnifications in connection with 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 potential future audit adjustments that may be imposed by the Canadian taxing authorities for tax years prior to the sale. During the first and second quarter of 2008, the purchaser notified Anadarko that $79 million and $11 million, respectively, of the indemnity is no longer relevant as a result of effective settlement of the underlying contingent obligation. Accordingly, the Company reversed a portion of its recorded liability. At September 30, 2008, the liability for the remaining indemnity obligation is $46 million. The Company believes it is probable that this obligation will be settled with the purchaser in cash.

Other  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 with respect to these actions will not have a material adverse effect on the Company's 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. As of September 30, 2008, the Company's balance sheet included a $129 million liability for remediation and reclamation obligations, most of which were incurred by companies that Anadarko has acquired. The Company continually monitors the liability recorded and the remediation and reclamation process.

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, and those statements preceded by, followed by or that otherwise include the words "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 have been correct. Important factors that could cause actual results to differ materially from the Company's expectations include, but are not limited to, the Company's assumptions about energy markets, 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, NGLs and other products or services, 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 changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations, potential environmental obligations arising from Kerr-McGee's former chemical business, the securities or capital markets, our ability to repay debt, 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 Policies and Estimates" included in the Company's 2007 Annual Report on Form 10-K, this Form 10-Q and in the Company's other public filings, press releases and discussions with Company management. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements.

Overview

General  Anadarko Petroleum Corporation's primary line of business is the exploration, development, production, gathering, processing and marketing of natural gas, crude oil, condensate and natural gas liquids (NGLs). The Company's major areas of operations are located in the United States and Algeria. The Company also has activity in China, Brazil and several other countries. The Company's focus is on adding high-margin oil and natural gas reserves at competitive costs and continuing to develop more efficient and effective ways of exploring for and producing oil and gas. Unless the context otherwise requires, the terms "Anadarko" or "Company" refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.
       The following discussion pertains to Anadarko's financial condition, results of operations and changes in financial condition. Following is an index by major category of discussion including a brief description of the contents:

Table of Contents

Page

Financial Results - comparative discussion of financial results of operations

-

Operating Results - discussion of business activities

-

Capital Resources and Liquidity - discussion of sources and uses of cash, outlook on operations and

    material financial arrangements, obligations and commitments

-

Recent Accounting Developments - discussion of accounting guidance effective in future periods

-

Results of Continuing Operations

Selected Data

  Three Months Ended

Nine Months Ended

September 30

September 30

millions except per share amounts

2008

2007

2008

2007

Financial Results

Sales revenues

$

6,209

$

2,656

$

11,643

$

8,372

Gains (losses) on divestitures and other, net

(60

)

339

270

4,458

   Total revenues and other

6,149

2,995

11,913

12,830

Costs and expenses

2,592

1,934

7,167

6,344

Other (income) expense

212

214

568

801

Income tax expense

1,181

354

1,761

2,191

Income from continuing operations

$

2,164

$

493

$

2,417

$

3,494

Earnings per common share - diluted

$

4.62

$

1.05

$

5.14

$

7.48

Average number of common shares outstanding - diluted

468

468

470

467

Operating Results

Adjusted EBITDAX⁽¹⁾

4,798

1,977

8,121

9,290

Sales volumes (MMBOE)

51

47

154

158

Capital Resources and Liquidity

Cash provided by operating activities

$

6,004

$

1,823

Capital expenditures

$

3,469

$

2,993

^{(1)  See Segment Analysis-Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a Generally

     Accepted Accounting Principles (GAAP) measure, and a reconciliation of Adjusted EBITDAX to income

     from continuing operations before income taxes, which is presented in accordance with GAAP.}

       In conjunction with the 2006 acquisitions of Kerr-McGee Corporation (Kerr-McGee) and Western Gas Resources, Inc. (Western), Anadarko implemented an asset realignment program. The goal of the Kerr-McGee and Western acquisitions was to provide a more economically efficient platform with higher and more consistent growth potential, with the intent of divesting properties that were no longer deemed to be core to Anadarko's operations. During 2007, the Company successfully completed the majority of the divestitures associated with the realignment program. Divestitures under the realignment program in 2007 and 2006 contributed proceeds of approximately $17 billion before income taxes. Unless noted otherwise, the following information relates to continuing operations. See Outlook for additional information.

       Since its adoption of the successful efforts method of accounting in the third quarter of 2007, the Company continues to evaluate the accuracy and completeness of its detailed records for properties and equipment. As part of this process, in March 2008, management identified in its oil and gas property records capitalized costs of $163 million attributable to properties that were divested in 2007. Because these costs were inadvertently excluded from the gain calculations, pretax gains on divestitures reported in the first and second quarter of 2007 were overstated by $75 million and $88 million, respectively. Management concluded that the misstatements were not material relative to 2007 interim and annual results, or to the 2008 periods, and corrected the error in the first quarter of 2008 as a $163 million reduction in gains (losses) on divestitures and other, net.
       Additionally, an unrelated analysis led management to conclude that the net properties and equipment balance was understated by $81 million when compared to the detailed accounting records by property. That amount arose as a result of accounting adjustments to convert from the full cost to the successful efforts method, and could not be reasonably associated with specific properties. Accordingly, management removed the unidentified amount from the balance sheet, increasing the properties and equipment balance and increasing first quarter of 2008 earnings. The $81 million correction is reported in gains (losses) on divestitures and other, net for the nine months ended September 30, 2008.
       After considering the effect of income taxes, the two adjustments recorded in the first quarter of 2008 related to the adoption of the successful efforts method of accounting in the third quarter of 2007, reduced net earnings for the nine months ended September 30, 2008 by $52 million.

Financial Results

Net Income  In the third quarter of 2008, Anadarko's income from continuing operations was $2.2 billion or $4.62 per share (diluted). This compares to income from continuing operations of $493 million or $1.05 per share (diluted) for the third quarter of 2007. For the nine months ended September 30, 2008, Anadarko's income from continuing operations was $2.4 billion or $5.14 per share (diluted). This compares to income from continuing operations of $3.5 billion or $7.48 per share (diluted) for the same period of 2007.
       The increase in income from continuing operations for the three months ended September 30, 2008 compared to the same period of 2007 was primarily due to higher natural gas, oil and NGLs sales, including the impact of derivatives, and lower interest expense, partially offset by a decrease in gains on divestitures, higher costs and expenses and higher income tax expense. The decrease in income from continuing operations for the nine months ended September 30, 2008 compared to the same period of 2007 was primarily due to a decrease in gains on divestitures, an increase in losses on derivatives and higher costs and expenses, partially offset by higher natural gas, oil and NGLs sales, excluding the impact of derivatives, lower interest expense and lower income tax expense. Gains on divestitures in 2007 relate primarily to the Company's asset realignment program which was initiated in 2006 in conjunction with the Kerr-McGee and Western acquisitions.

Sales Revenues

Three Months Ended

Nine Months Ended

September 30

September 30

millions

2008

2007

2008

2007

Gas sales

$

2,395

$

871

$

5,089

$

3,108

Oil and condensate sales

3,217

1,262

4,911

3,558

Natural gas liquids sales

244

175

703

511

Gathering, processing and marketing sales

353

348

940

1,195

Total

$

6,209

$

2,656

$

11,643

$

8,372

       Anadarko's sales revenues for the three and nine months ended September 30, 2008 increased 134% and 39%, respectively, compared to the same periods of 2007. The increase for the quarter was due primarily to higher natural gas, oil and condensate and NGLs commodity prices, including the impact of derivatives, and higher sales volumes in the Rockies, partially offset by lower sales volumes associated with properties that were divested in 2007. The increase for the year to date period was due primarily to higher natural gas, oil and condensate, and NGLs commodity prices, excluding the impact of derivatives, partially offset by an increase in losses on derivatives and lower sales volumes associated with properties that were divested in 2007.
       The Company's sales revenues for the three months ended September 30, 2008 and 2007 were increased by $2.4 billion and reduced by $(36) million, respectively, of net unrealized gains (losses) on derivatives. The Company's sales revenues for the nine months ended September 30, 2008 and 2007 were increased by $274 million and reduced by $(593) million, respectively, of net unrealized gains (losses) on derivatives. Any realization of these gains (losses) is expected to be substantially offset by the value realized from that portion of the Company's production covered by the derivative instruments.

Analysis of Oil and Gas Operations Sales Revenues

       The following table provides a summary of the effects of changes in volumes, prices and derivatives gains and losses on Anadarko's sales revenues for the three and nine months ended September 30, 2008 compared to the same periods of 2007.

Three Months Ended

September 30

Natural

Oil and

millions

Gas

Condensate

NGLs

2007 sales revenues

$

871

$

1,262

$

175

   Changes associated with sales volumes

154

(112

)

(5

)

   Changes in prices, excluding derivatives

670

696

74

   Changes in realized derivative gains and losses

(102

)

(201

)

-

   Changes in unrealized derivative gains and losses

802

1,572

-

2008 sales revenues

$

2,395

$

3,217

$

244

Nine Months Ended

September 30

Natural

Oil and

millions

Gas

Condensate

NGLs

2007 sales revenues

$

3,108

$

3,558

$

511

   Changes associated with sales volumes

204

(505

)

(63

)

   Changes in prices, excluding derivatives

1,532

2,402

255

   Changes in realized derivative gains and losses

(455

)

(628

)

-

   Changes in unrealized derivative gains and losses

700

84

-

2008 sales revenues

$

5,089

$

4,911

$

703

       The Company utilizes derivative instruments to manage the risk of a decrease in the market prices for its anticipated sales of natural gas, crude oil, condensate and NGLs. This activity is referred to as price risk management. The impact of price risk management (including realized and unrealized gains and losses) increased revenues $2.2 billion during the third quarter of 2008 compared to an increase of $101 million in the third quarter of 2007. The impact of price risk management (including realized and unrealized gains and losses) decreased revenues $331 million during the first nine months of 2008 compared to a decrease of $32 million in the first nine months of 2007. See Energy Price Risk under Part I, Item 3 and Note 6 - Financial Instruments under Part I, Item 1 of this Form 10-Q.

       The following sections provide a more detailed analysis of the Company's natural gas, crude oil and NGLs sales volumes and prices.

Analysis of Oil and Gas Operations Sales Volumes

  Three Months Ended

Nine Months Ended

September 30

September 30

2008

2007

2008

2007

Barrels of Oil Equivalent (MMBOE)

   United States

44

39

134

134

   Algeria

6

6

16

18

   Other International

1

2

4

6

   Total

51

47

154

158

Barrels of Oil Equivalent per Day (MBOE/d)

   United States

473

428

489

492

   Algeria

64

65

57

64

   Other International

15

17

16

21

   Total

552

510

562

577

MMBOE - million barrels of oil equivalent

MBOE/d - thousand barrels of oil equivalent per day

       Anadarko's daily sales volumes for the third quarter of 2008 include a decrease in sales volumes of 9 MBOE/d associated with the impact of the 2007 divestitures. Excluding 2007 divested property volumes, daily sales volumes in the third quarter of 2008 increased 51 MBOE/d compared to the same period of 2007. Despite continuing repairs at the end of the third quarter of 2008 to third-party downstream infrastructure as a result of the 2008 hurricane activity, volumes in the United States increased 47 MBOE/d in the third quarter of 2008 primarily due to higher sales volumes in the Rockies. Other International volumes increased during the third quarter of 2008 primarily due to higher sales volumes in China of 5 MBOE/d. For the nine months ended September 30, 2008, Anadarko's daily sales volumes include a decrease of 58 MBOE/d associated with the impact of the 2007 divestitures. Excluding 2007 divested property volumes, daily sales volumes for the first nine months of 2008 increased 43 MBOE/d compared to the same period of 2007. Volumes in the United States increased 49 MBOE/d the first nine months of 2008 primarily due to higher sales volumes in the Rockies and the Gulf of Mexico. Volumes in Algeria decreased 7 MBOE/d for the first nine months of 2008 primarily as a result of lower production due to maintenance and a statutory shutdown.

Natural Gas Sales Volumes, Average Prices and Revenues

Three Months Ended

Nine Months Ended

September 30

September 30

2008

2007

2008

2007

United States

   Sales volumes-Bcf

183

151

548

513

                                MMcf/d

1,994

1,637

2,000

1,877

   Price per Mcf, excluding derivatives

$

8.36

$

4.70

$

8.55

$

5.75

     Realized gains (losses) on derivatives

0.13

0.84

(0.15

)

0.73

     Unrealized gains (losses) on derivatives

4.57

0.24

0.89

(0.42

)

        Gains (losses) on derivatives

$

4.70

$

1.08

$

0.74

$

0.31

   Total average price per Mcf

$

13.06

$

5.78

$

9.29

$

6.06

   Gas sales revenues (millions)

$

2,395

$

871

$

5,089

$

3,108

Bcf - billion cubic feet

MMcf/d - million cubic feet per day

Mcf - thousand cubic feet

       The Company's daily natural gas sales volumes for the three and nine months ended September 30, 2008 include a decrease in sales volumes of 16 MMcf/d and 203 MMcf/d, respectively, associated with the 2007 divestitures. Excluding 2007 divested property volumes, daily sales volumes for the three and nine months ended September 30, 2008 increased 373 MMcf/d and 326 MMcf/d, respectively, compared to the same periods of 2007. The increase for both the quarter and year to date periods of 2008 compared to the same periods of 2007 was primarily due to higher sales volumes in the Gulf of Mexico of 207 MMcf/d and 230 MMcf/d, respectively, as a result of the start up of the Independence Hub and increased production in the Rockies of 192 MMcf/d and 144 MMcf/d, respectively. Production of natural gas is generally not directly affected by seasonal swings in demand.

       Excluding the impact of gains and losses on derivatives, Anadarko's average natural gas price for the three and nine months ended September 30, 2008 increased 78% and 49%, respectively, compared to the same periods of 2007. The relative difference in 2008 and 2007 prices is primarily attributed to lower year-over-year natural gas storage volumes across the quarter coupled with lower liquefied natural gas volumes available to the United States consumer as a result of increased demand and pricing in both Europe and Asia. As of September 30, 2008, the Company has implemented price risk management on about 66% of its anticipated natural gas wellhead sales volumes for the remainder of 2008.

Crude Oil and Condensate Sales Volumes, Average Prices and Revenues

Three Months Ended

Nine Months Ended

September 30

September 30

2008

2007

2008

2007

United States

   Sales volumes-MMBbls

9

10

32

36

                                MBbls/d

103

116

117

134

   Price per barrel, excluding derivatives

$

114.26

$

72.12

$

107.89

$

61.13

     Realized gains (losses) on derivatives

(15.27

)

0.65

(11.35

)

3.83

     Unrealized gains (losses) on derivatives

106.14

(7.21

)

(2.90

)

(8.20

)

        Total gains (losses) on derivatives

$

90.87

$

(6.56

)

$

(14.25

)

$

(4.37

)

   Total average price per barrel

$

205.13

$

65.56

$

93.64

$

56.76

Algeria

   Sales volumes-MMBbls

6

6

16

18

                                MBbls/d

64

65

57

64

   Price per barrel, excluding derivatives

$

116.55

$

75.83

$

114.51

$

68.08

     Realized gains (losses) on derivatives

(8.39

)

-

(8.20

)

-

     Unrealized gains (losses) on derivatives

85.29

1.38

(9.92

)

(1.72

)

        Total gains (losses) on derivatives

$

76.90

$

1.38

$

(18.12

)

$

(1.72

)

   Total average price per barrel

$

193.45

$

77.21

$

96.39

$

66.36

Other International

   Sales volumes-MMBbls

1

2

4

6

                                MBbls/d

15

17

16

21

   Total average price per barrel

$

105.28

$

63.52

$

98.73

$

56.13

Total

   Sales volumes-MMBbls

16

18

52

60

                                MBbls/d

182

198

190

219

   Total price per barrel, excluding derivatives

$

114.34

$

72.63

$

109.10

$

62.68

     Realized gains (losses) on derivatives

(11.60

)

0.38

(9.42

)

2.35

     Unrealized gains (losses) on derivatives

90.11

(3.76

)

(4.77

)

(5.53

)

        Total gains (losses) on derivatives

$

78.51

$

(3.38

)

$

(14.19

)

$

(3.18

)

   Total average price per barrel

$

192.85

$

69.25

$

94.91

$

59.50

   Total oil and condensate sales revenues (millions)

$

3,217

$

1,262

$

4,911

$

3,558

MMBbls - million barrels

MBbls/d - thousand barrels per day

       Anadarko's daily crude oil and condensate sales volumes for the three and nine months ended September 30, 2008 include a decrease in sales volumes of 6 MBbls/d and 19 MBbls/d, respectively, associated with the 2007 divestitures. Excluding 2007 divested property volumes, daily sales volumes in the three and nine months ended September 30, 2008 decreased 10 MBbls/d and 10 MBbls/d, respectively, compared to the same periods of 2007. The decrease in the third quarter of 2008 was primarily due to lower crude oil sales volumes of 16 MBbls/d in the Gulf of Mexico due to 2008 hurricane activity and lower crude oil sales volumes of 4 MBbls/d in Alaska, partially offset by an increase of 6 MBbls/d in the Rockies and 5 MBbls/d in China. The decrease during the first nine months of 2008 was primarily due to lower crude oil sales volumes of 7 MBbls/d in the Gulf of Mexico due to 2008 hurricane activity, lower crude oil sales volumes of 7 MBbls/d in Algeria, primarily as a result of lower production due to maintenance and a statutory shutdown and lower crude oil sales volumes of 3 MBbls/d in Alaska, partially offset by higher crude oil sales volumes of 6 MBbls/d in the Rockies. Production of oil usually is not affected by seasonal swings in demand.

       Excluding the impact of gains and losses on derivatives, Anadarko's average crude oil price for the three and nine months ended September 30, 2008 increased 57% and 74%, respectively, compared to the same periods of 2007. The higher crude oil prices were attributed primarily to limited excess production capacity, heightened geopolitical tension and increased demand in Asia; particularly China and India. As of September 30, 2008, the Company has utilized price risk management on approximately 54% of its anticipated oil and condensate sales volumes for the remainder of 2008.

Natural Gas Liquids Sales Volumes, Average Prices and Revenues

Three Months Ended

Nine Months Ended

September 30

September 30

2008

2007

2008

2007

United States

   Sales volumes-MMBbls

4

4

11

12

                                MBbls/d

38

39

39

45

   Price per barrel

$

69.30

$

48.39

$

65.17

$

41.57

   Natural gas liquids sales revenues (millions)

$

244

$

175

$

703

$

511

       NGLs sales represent revenues 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, 2008 decreased 3% and 13%, respectively, compared to the same periods of 2007. The decrease for the quarter was primarily due to a decrease of 2 MBbls/d in the Southern Region. The decrease for the nine months ended was primarily due to a 5 MBbls/d decrease associated with the 2007 divestitures. For the three and nine months ended September 30, 2008, the average NGLs price increased 43% and 57%, respectively, compared to the same periods of 2007. NGLs production is dependent on natural gas and NGLs prices as well as the economics of processing the natural gas to extract NGLs. Production of NGLs usually is not affected by seasonal swings in demand.

Gathering, Processing and Marketing Revenues

Three Months Ended

Nine Months Ended

September 30

September 30

millions

2008

2007

2008

2007

Gathering and processing sales

$

337

$

260

$

920

$

1,022

Marketing sales

16

88

20

173

Total

$

353

$

348

$

940

$

1,195

       Gathering and processing revenues represent revenues derived from gathering and processing natural gas from sources other than the Company's production. Marketing sales primarily represent the margin earned on sales of gas, oil and NGLs purchased from third parties. During the quarter ended September 30, 2008, gathering and processing sales increased $77 million compared to the same period of 2007. This increase was primarily due to higher revenues related to higher product prices and gathering rates. During the nine months ended September 30, 2008, gathering and processing sales decreased $102 million compared to the first nine months of 2007. This decrease was primarily due to lower volumes as a result of the 2007 divestitures, partially offset by higher product prices and gathering rates. Marketing sales in the three and nine months ended September 30, 2008 decreased primarily due to lower margins on firm transportation contracts and less third-party marketing activity.

Costs and Expenses

Three Months Ended

Nine Months Ended

September 30

September 30

millions

2008

2007

2008

2007

Oil and gas operating

$

274

$

256

$

778

$

868

Oil and gas transportation and other

140

113

400

342

Exploration

373

253

880

614

Gathering, processing and marketing

265

217

679

840

General and administrative

216

171

619

681

Depreciation, depletion and amortization

844

655

2,438

2,090

Other taxes

424

269

1,306

869

Impairments

56

-

67

40

Total

$

2,592

$

1,934

$

7,167

$

6,344

       During the third quarter of 2008, Anadarko's costs and expenses increased 34% compared to the third quarter of 2007 due to the following factors:

-

Oil and gas operating expense increased 7% primarily due to an increase of $20 million in compensation expense, and higher operating costs in the Rockies of approximately $20 million, partially offset by a decrease of $20 million associated with the 2007 divestitures.

-

Oil and gas transportation and other expenses increased 24% primarily due to higher surface owner payments in the Rockies and higher transportation charges in the Rockies and Southern Region and due to expenses associated with the Independence Hub startup in July 2007.

-

Exploration expense increased $120 million primarily due to an impairment of unproved properties in Trinidad of $55 million, a $40 million impairment of unproved properties in the Gulf of Mexico and higher dry hole expense of $36 million in the Gulf of Mexico.

-

Gathering, processing and marketing (GPM) expenses increased $48 million. Costs associated with gathering and processing operations increased $57 million primarily due to an increase in cost of product due to higher prices and higher direct operating expense. Marketing transportation costs decreased $9 million.

-

General and administrative (G&A) expense increased 26% primarily due to a $41 million increase in benefit plans expense.

-

Depreciation, depletion and amortization (DD&A) expense increased 29%. DD&A expense associated with oil and gas properties increased approximately $127 million due to higher costs associated with acquiring, finding and developing oil and gas reserves and approximately $50 million due to higher sales volumes from retained properties. Depreciation of other properties and equipment increased $9 million.

-

Other taxes increased 58% primarily due to increased production and severance taxes related to higher commodity prices, an increase in the Algerian exceptional profits tax expense of $42 million, an increase in the windfall profits tax in China of $22 million and increased ad valorem taxes.

-

Impairments of $37 million and $19 million were related to Midstream segment assets and Oil and Gas Exploration and Production segment properties in the United States, respectively.

       For the nine months ended September 30, 2008, Anadarko's costs and expenses increased 13% compared to the same period of 2007 due to the following factors:

-

Oil and gas operating expense decreased 10% primarily due to a decrease of $112 million associated with the 2007 divestitures, lower insurance expenses of $24 million related to Gulf of Mexico properties and lower demand charges of $20 million in the Gulf of Mexico, partially offset by an increase of $22 million in compensation expense, higher operating costs of $21 million in the Rockies and higher gas processing fees of $27 million in the Gulf of Mexico due to expenses associated with the startup of Independence Hub in July 2007.

-

Oil and gas transportation and other expenses increased 17% primarily due to higher surface owner payments in the Rockies and higher transportation charges in the Rockies and Southern Region and due to expenses associated with the Independence Hub startup.

-

Exploration expense increased $266 million primarily due to a $122 million impairment of unproved properties in the Gulf of Mexico, a $55 million impairment of unproved properties in Trinidad, a $40 million impairment of unproved properties in Brazil, higher dry hole costs of $66 million in the Gulf of Mexico, a $31 million increase in geological and geophysical costs, primarily in Mozambique, $17 million related to a joint-venture termination and increases in other miscellaneous exploration costs, partially offset by lower international dry hole expense of $40 million primarily in Nigeria, Benin, Indonesia and China, and lower impairments in China of $28 million.

-

GPM expenses decreased $161 million. Costs associated with gathering and processing operations decreased $124 million primarily due to 2007 divestitures and a reduction of accrued expenses related to a prior period of $29 million, partially offset by an increase in cost of product due to higher prices and direct operating costs from retained operations. Marketing transportation costs decreased $33 million.

-

G&A expense decreased 9% primarily due to lower compensation expense of $53 million, a $39 million decrease in employee severance and termination benefits and decreases in legal, consulting and audit fees primarily associated with the 2007 asset realignment program and 2007 system integration projects, partially offset by higher benefit plans expense of $45 million.

-

DD&A expense increased 17%. DD&A expense associated with oil and gas properties increased approximately $393 million due to higher costs associated with acquiring, finding and developing oil and gas reserves. This increase was partially offset by a decrease of approximately $34 million due to lower sales volumes from retained properties and a decrease in depreciation of other properties and equipment of $17 million.

-

Other taxes increased 50% primarily due to increased production and severance taxes related to higher commodity prices, an increase in the Algerian exceptional profits tax of $81 million, increases associated with the effects of a windfall profits tax in China of $71 million, a new Alaskan severance tax of $45 million and increased ad valorem taxes. This increase was partially offset by a decrease in the Algerian exceptional profits tax expense primarily attributable to a change in the estimate of the 2006 exceptional profits tax recognized in the first quarter of 2007.

-

Impairments of $37 million and $30 million for nine months ended September 30, 2008 were related to Midstream segment assets and Oil and Gas Exploration and Production segment properties in the United States, respectively.

Other (Income) Expense

   Three Months Ended

Nine Months Ended

September 30

September 30

millions

2008

2007

2008

2007

Interest Expense

Gross interest expense -

   Current debt, long-term debt and other

$

188

$

242

$

574

$

964

   Midstream subsidiary note payable to a related party

20

-

82

-

Capitalized interest

(28

)

(20

)

(98

)

(103

)

Net interest expense

180

222

558

861

Other (Income) Expense, net

Interest income

(13

)

(22

)

(34

)

(66

)

Other

35

14

29

6

Total other (income) expense, net

22

(8

)

(5

)

(60

)

Minority interests

10

-

15

-

Total

$

212

$

214

$

568

$

801

       Anadarko's gross interest expense for the three and nine months ended September 30, 2008 decreased 14% and 32%, respectively, compared to the same periods of 2007. The decreases in 2008 were primarily due to a decrease in average debt levels.
       For the quarter ended September 30, 2008, interest capitalized increased $8 million compared to the quarter ended September 30, 2007 primarily due to higher capitalized costs that qualify for interest capitalization. For the first nine months of 2008, the decrease was due to the completion of several large projects in 2007 that qualified for capitalized interest in the first nine months of 2007.

Income Tax Expense

Three Months Ended

Nine Months Ended

September 30

September 30

millions except percentages

2008

2007

2008

2007

Income tax expense

$

1,181

$

354

$

1,761

$

2,191

Effective tax rate

35

%

42

%

42

%

39

%

       For the three months and nine months ended September 30, 2008, income tax expense related to continuing operations increased 234% and decreased 20%, respectively, compared to the same periods of 2007 primarily due to an increase in income before income taxes for the third quarter of 2008 compared to the third quarter of 2007 and a decrease in income before income taxes for the nine months ended September 30, 2008 compared to the same period of 2007.
       The effective tax rates for the three and nine months ended September 30, 2008 include an increase to the 35% statutory rate attributable to the accrual of the Algerian exceptional profits tax which is non-deductible for Algerian income tax purposes, other foreign taxes in excess of federal statutory rates, state income taxes and other items. This increase in the 35% statutory rate is offset by a foreign tax rate applicable to the Company's pending divestiture of its 50% interest in the Peregrino field, offshore Brazil, which is a rate lower than the 35% U.S. statutory rate, and other items. The variance from the 35% statutory rate in 2007 is primarily caused by the accrual of the Algerian exceptional profits tax which is non-deductible for Algerian income tax purposes, other foreign taxes in excess of federal statutory rates, losses in non-taxable foreign jurisdictions, state income taxes (including the effect of a second quarter 2007 state income tax reduction resulting from enacted Texas legislation) and other items.
       For the three and nine months ended September 30, 2008, $44 million and $92 million, respectively, of the previously established Financial Accounting Standards Board Interpretation No. 48 (FIN 48), "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" liability and associated interest were settled with the taxing authorities. The Company estimates that $70 million to $80 million of unrecognized tax benefits related to adjustments to taxable income, credits, and associated interest previously recorded pursuant to FIN 48 will reverse within the next 12 months due to statute expirations and audit settlements. The Company does not anticipate these reversals to have a significant impact on the effective tax rate.

Operating Results

Segment Analysis - Adjusted EBITDAX  To assess the operating results of Anadarko's segments, management uses income from continuing operations before income taxes, interest expense, exploration expense, DD&A expense and impairments (Adjusted EBITDAX). The Company'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, but 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, as capital expenditures are evaluated at the time capital costs are incurred. Anadarko's definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to the Company'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 shareholders.

       Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies, and therefore, the Company's consolidated Adjusted EBITDAX should be considered in conjunction with income from continuing operations 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 income from continuing operations 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 from continuing operations before income taxes.

Adjusted EBITDAX

Three Months Ended

Nine Months Ended

September 30

September 30

millions

2008

2007

2008

2007

   Oil and gas exploration and production

$

4,852

$

1,622

$

7,997

$

8,772

   Midstream

104

395

326

828

   Marketing

49

60

74

167

   Other and intersegment eliminations

(207

)

(100

)

(276

)

(477

)

Consolidated Adjusted EBITDAX

$

4,798

$

1,977

$

8,121

$

9,290

Exploration expense

373

253

880

614

Depreciation, depletion and amortization expense

844

655

2,438

2,090

Impairments

56

-

67

40

Interest expense

180

222

558

861

Income from continuing operations before income taxes

$

3,345

$

847

$

4,178

$

5,685

Oil and Gas Exploration and Production   The increase in Adjusted EBITDAX for the three months ended September 30, 2008 compared to the same period of 2007 was primarily due to gains on derivatives, the impact of higher commodity prices and higher sales volumes, primarily in the Rockies, partially offset by lower sales volumes as a result of the 2007 divestitures. The Company's sales revenues include the impact of price risk management (including realized and unrealized gains and losses) which increased oil and gas revenues $2.2 billion during the third quarter of 2008, compared to an increase of $101 million in the third quarter of 2007. Of these amounts for the third quarter of 2008 and 2007, $2.3 billion and $(32) million, respectively, were related to net unrealized gains (losses) on derivatives intended to manage price risk on oil and gas sales. The decrease in Adjusted EBITAX for the nine months ended September 30, 2008 compared to the same period of 2007 was primarily due to decreases in gains (losses) on divestitures and other, net of $3.7 billion, losses on derivatives and lower sales volumes as a result of the 2007 divestitures, partially offset by the impact of higher commodity prices and higher sales volumes primarily in the Gulf of Mexico and the Rockies. The Company's sales revenues include the impact of price risk management activities (including realized and unrealized gains and losses) which decreased oil and gas revenues by $331 million during the first nine months of 2008, compared to a decrease of $32 million in the first nine months of 2007. Of these amounts, $239 million and $(545) million for the nine months ended September 30, 2008 and 2007, respectively, were related to net unrealized gains (losses) on derivatives intended to manage price risk on oil and gas sales.

Midstream   The decrease in Adjusted EBITDAX for the three and nine months ended September 30, 2008 compared to the same periods of 2007 resulted primarily from decreases in gains (losses) on divestitures and other, net of $300 million and $535 million, respectively, and lower volumes as a result of the 2007 divestitures.

Marketing   Marketing earnings primarily represent the margin earned on sales of gas, oil and NGLs purchased from third parties. Adjusted EBITDAX for the three and nine months ended September 30, 2008 was lower compared to the same periods of 2007 primarily due to lower margins on firm transportation contracts.

Other and Intersegment Eliminations   Other and intersegment eliminations consists primarily of corporate costs that are not allocated to the operating segments and income from hard minerals investments and royalties. The decrease in Adjusted EBITDAX for the three months ended September 30, 2008 compared to the same period of 2007 was primarily due to a decrease in gains (losses) on divestitures and other, netand an increase in benefit plans expense. The increase in Adjusted EBITDAX for the nine months ended September 30, 2008 compared to the same period of 2007 was primarily due to an increase in gains (losses) on divestitures and other, net, a decrease in compensation expense, a decrease in employee severance and termination benefits and decreases in legal, consulting and audit fees primarily associated with the 2007 asset realignment program and the 2007 system integration projects, partially offset by higher benefit plans expense.

Divestitures   During the first nine months of 2008, the Company closed the sales of certain oil and gas properties, primarily in the United States, for approximately $690 million. Net gains on divestitures for the three and nine months ended September 30, 2008 of $1 million and $328 million, respectively, primarily related to the divestiture of oil and gas properties in the United States in several unrelated transactions. Net gains on divestitures for the three months ended September 30, 2007 of $0.3 billion were primarily related to the divestiture of certain gathering and processing facilities. Net gains on divestitures for the nine months ended September 30, 2007 of $4.4 billion includes approximately $3.9 billion related to the divestiture of certain oil and gas properties and approximately $0.5 billion related to the divestiture of certain gathering and processing facilities.
       The sale of Anadarko's interest in the Kaskida prospect closed in April 2008. In addition, in May 2008, Anadarko sold certain of its oil and gas properties in northern Louisiana.
       In March 2008, the Company entered into an agreement to divest its 50% interest in the Peregrino field, offshore Brazil, and certain related assets. The agreement provides for consideration to Anadarko of $1.5 billion at closing. Additionally, in connection with the sale of its interest in the Peregrino field, Anadarko may receive contingent consideration in future periods. Contingent consideration is based on the value of oil produced from properties subject to the sale transaction. The Peregrino field is currently under development, with initial production expected in 2010. The timing of the closing of the Peregrino divestiture is contingent on approvals by the appropriate authorities, which are expected to be obtained in the fourth quarter of 2008.
       In April 2008, Anadarko entered into an agreement to sell a wholly-owned subsidiary, which owns an 18% interest in Petroritupano, S.A. (Petroritupano), a Venezuelan mixed company whose other shareholders are Petróleos de Venezuela, S.A. (PDVSA) and Petrobras Energía, S.A., for $200 million. The closing of this transaction was subject to customary closing conditions, including receipt of approvals by Venezuelan authorities. Anadarko has been informed by the Venezuelan Ministry of Energy and Petroleum (MEP) that it will not grant approval of the sale transaction because PDVSA intends to acquire Anadarko's equity interest in Petroritupano. Anadarko has subsequently received a letter from Corporacion Venezolana del Petroleo, S.A. (CVP), an affiliate of PDVSA, in which CVP states its interest in acquiring Anadarko's equity interest in Petroritupano. At this time, Anadarko is unable to determine when the sale to CVP may be consummated. Anadarko's investment in Petroritupano is included in other assets at September 30, 2008.
       Net proceeds from pending asset divestitures are expected to be used for debt reduction.

Capital Resources and Liquidity

Overview   Anadarko's primary sources of cash during the first nine months of 2008 were cash flow from operating activities, proceeds from divestitures and the master limited partnership initial public offering. The Company used cash primarily to fund Anadarko's capital spending program, to retire debt, to repurchase Anadarko common stock, to pay dividends and redeem preferred stock.

Sources of Cash

Cash Flow from Operating Activities   Anadarko's cash flow from continuing operating activities during the nine months ended September 30, 2008 was $6.0 billion compared to $1.8 billion for the same period of 2007. The increase in cash flow was attributed to higher commodity prices and lower estimated income tax payments in 2008 compared to 2007 primarily related to the 2007 divestitures, partially offset by the effect of lower sales volumes primarily associated with the 2007 divestitures, and realized derivative losses in 2008. Excluding the impact of acquisitions and divestitures, fluctuations in commodity prices have been the primary reason for the Company's short-term changes in cash flow from operating activities.

Divestitures   During the first nine months of 2008, the Company closed the sales of certain oil and gas properties, primarily in the United States, for approximately $690 million. Net gains on divestitures for the nine months ended September 30, 2008 of $328 million primarily related to the divestiture of oil and gas properties in the United States in several unrelated transactions. Net gains on divestitures for the nine months ended September 30, 2007 of $4.4 billion includes approximately $3.9 billion related to the divestiture of certain oil and gas properties and approximately $0.5 billion related to the divestiture of certain gathering and processing facilities.

Master Limited Partnership Initial Public Offering   During the second quarter of 2008, Western Gas Partners, LP (WES) completed its initial public offering of 20.8 million common units (representing a 38.4% limited partner interest) for net proceeds of $321 million ($343 million less $22 million for underwriting discounts and structuring fees). WES is a Delaware limited partnership formed by Anadarko to own, operate, acquire and develop midstream assets. Anadarkocontributed assets to WES in exchange for a 2% general partner interest and100% of the WES incentive distribution rights and common and subordinated units, together representing an aggregate 59.6% limited partner interest in WES. In addition, Anadarko maintains control over the assets owned by WES through ownership of the general partner interests. Proceeds were used to reduce debt.
       The common units have preference over the subordinated units with respect to cash distributions. Accordingly, all proceeds from the sale of the partnership units were recorded as minority interest on the consolidated balance sheet. The subordinated units will convert into an equal number of common units upon termination of the subordination period. Generally, the subordination period will end when either:

(i)

WES has paid at least $0.30 per quarter on each outstanding common unit, subordinated unit and general partner unit for any three consecutive four quarterly periods ending on or after June 30, 2011; or

(ii)

WES has paid at least $0.45 per quarter on each outstanding common unit, subordinated unit and general partner unit for any four consecutive quarters.

       When the subordinated units convert to common units, the Company will recognize additional paid-in capital in stockholders' equity in accordance with Securities and Exchange Commission (SEC) Staff Accounting Bulletin No. 51, "Accounting for Sales of Stock by a Subsidiary" (SAB 51).
       The results of operations and financial position of WES are included in the consolidated financial statements of Anadarko; in addition, the portion of WES' results of operations that is attributable to units held by the public (units not held by Anadarko) is recorded as minority interests.
       Pursuant to the terms of its partnership agreement, WES is required to pay a minimum quarterly distribution of $0.30 per unit to the extent it has sufficient cash available for distribution. During the third quarter of 2008, WES paid a prorated quarterly cash distribution of $0.1582 per unit for the second quarter of 2008, which corresponds to a quarterly distribution of $0.30 per unit on a full quarter basis. On October 24, 2008, WES declared a quarterly cash distribution of $0.30 per unit for the third quarter of 2008.

Uses of Cash

Capital Expenditures   The following table shows the Company's capital expenditures relating to continuing operations, by category.

Nine Months Ended

September 30

millions

2008

2007

Property acquisition

    Development - proved

$

-

$

8

    Exploration - unproved

243

40

Development

2,208

1,793

Exploration

490

446

Capitalized interest

95

101

  Total oil and gas capital expenditures

3,036

2,388

Gathering, processing and marketing and other

433

605

Total capital expenditures*

$

3,469

$

2,993

*  Capital expenditures in the table above are presented on an accrual basis. Additions to properties and equipment on

    the consolidated statement of cash flows reflect capital expenditures on a cash basis, when payments are made.

       During the nine months ended September 30, 2008, Anadarko's capital spending increased 16% compared to the same period of 2007 primarily due to an increase in development drilling in the Rockies and Southern Region and property acquisitions in the Gulf of Mexico.

Debt   At September 30, 2008, Anadarko's total debt was $12.7 billion compared to total debt of $14.7 billion at December 31, 2007. As of December 31, 2007, current debt included $1 billion under a variable-rate 354-day facility. This facility was fully repaid and concurrently retired in February 2008. In the third quarter of 2008, the Company retired $344 million aggregate principal amount of Floating Rate Notes due September 2009. During the first nine months of 2008, the Company repaid an aggregate principal amount of $2.1 billion of debt (including the variable-rate 354-day facility) that was outstanding at December 31, 2007.
       In March 2008, the Company entered into a $1.3 billion, five-year Revolving Credit Agreement (RCA) with a syndicate of United States and foreign lenders. Under the terms of the RCA, the Company can, under certain conditions, request an increase in the borrowing capacity under the RCA up to a total available credit amount of $2.0 billion. The RCA has a maximum 65% debt to total book capitalization covenant (excluding non-cash charges). The RCA terminates in March 2013. The RCA replaced a $750 million revolving credit facility which was scheduled to mature in 2009 and was retired. As of September 30, 2008, the Company had no outstanding borrowings under the RCA.
       The following table shows the Company's debt-to-capital ratio.

September 30,

December 31,

millions

2008

2007

Current debt

$

1,708

$

1,396

Long-term debt

9,120

11,151

   Total debt excluding related party debt

10,828

12,547

Midstream subsidiary note payable to a related party

1,870

2,200

   Total debt

$

12,698

$

14,747

Equity

$

18,211

$

16,364

Debt-to-capital ratio

                  41.1%

47.4

%

Common Stock Repurchase Program   The Company's Board of Directors authorized a $5 billion share repurchase program in August 2008. The program replaces the prior repurchase program and is authorized to extend through August 2011. Shares may be repurchased either in the open market or through privately negotiated transactions. During the third quarter of 2008, Anadarko purchased 10.0 million shares of common stock for $600 million under the program. The Company expects to purchase additional shares under the program as anticipated excess cash flow is realized; however, the repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. At September 30, 2008, $4.4 billion remained available for stock repurchases under the program.

Dividends     In both the first nine months of 2008 and 2007, Anadarko paid $128 million in dividends to its common stockholders (nine cents per share in the first, second and third quarters of both 2008 and 2007). Anadarko has paid a dividend to its common stockholders continuously since becoming an independent 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.
       The covenants in the Company's credit agreements provide for a maximum debt to total book capitalization ratio of 65%, excluding non-cash charges. Although the covenants of the agreements do not specifically restrict the payment of dividends,the Company could be limited in the amount of dividends it could pay in order to stay below the maximum debt to total book capitalization ratio. Based on these covenants, retained earnings of approximately $11.4 billion were not limited as to the payment of dividends at September 30, 2008.

       During the nine months ended September 30, 2008 and 2007, Anadarko paid $1 million and $2 million, respectively, in preferred stock dividends. The preferred stock was redeemed in the second quarter of 2008.

Margin Deposits   The Company is required to provide margin deposits whenever its unrealized losses with a counterparty exceed predetermined credit limits, and in some cases only until negotiated maximum limits are reached. Both exchange and over-the-counter traded derivative instruments may be subject to margin deposit requirements. Given the Company's price risk management position and price volatility, the Company may be required from time to time to deposit cash with or provide letters of credit to its counterparties in order to satisfy these deposit requirements. The Company manages its exposure to margin requirements through negotiated credit arrangements with counterparties, which may include collateral caps. If credit thresholds are exceeded, the Company utilizes available cash or letters of credit to satisfy margin requirements and maintains ample available committed credit facilities to meet its obligations. The Company's current derivative positions continue to ratably settle such that at year end, the Company's working capital along with its RCA could withstand margin calls resulting from a significant increase in commodity prices. The Company had net margin deposits (cash collateral) of $114 million and $51 million outstanding at September 30, 2008 and December 31, 2007, respectively. See Note 1 - Summary of Significant Accounting Policies and Note 6 - Financial Instruments of the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Fair Value   The Company adopted the provisions of SFAS No. 157 effective January 1, 2008.  The Company determined that as of January 1, 2008 and March 31, 2008, it utilized unobservable (Level 3) inputs in determining the fair value of its commodity options. The Company uses the Black-Scholes-Merton option pricing model to determine the value of commodity option contracts. In the second quarter of 2008, the Company implemented a marketing system. The new system utilizes observable market data or interpolates valuations using observable market data for all significant inputs. Commodity options are now categorized as Level 2. Changes in the fair values of derivatives affect results of operations, but, excluding cash collateral requirements, will not affect Anadarko's liquidity or capital until settled. See margin deposits discussed above for information on cash collateral.

       Changes in the fair value of commodity option derivatives are reflected in income before taxes within revenues, net, in the period of the change. The Company has historical experience in valuing the derivative instruments it holds, and compares these values against market and its counterparties. The Company believes it is unlikely that an independent third party would value the Company's option contracts at a significantly different amount than what is reflected in the Company's financial statements.
       See Note 1 - Summary of Significant Accounting Policies and Note 6 - Financial Instruments of the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Outlook

       The Company's goals include continuing to find or acquire high-margin oil and gas reserves at competitive prices while keeping operating costs at efficient levels.

       The objective of the Kerr-McGee and Western acquisitions in 2006 was to provide a more economically efficient platform with higher and more consistent growth potential, with the intent of divesting properties that were no longer deemed to be core to Anadarko's operations. During 2007, the Company successfully completed the majority of the divestiture stage of the realignment program. As expected, Anadarko's proved reserves after completing the divestitures were about equal to levels before the acquisitions. The new portfolio is intended to be better balanced, with lower-risk U.S. onshore resource plays complementing the volatility inherent in the Company's deepwater Gulf of Mexico and international programs.
       The Company has an approved 2008 capital spending budget of approximately $5.0 billion. The Company has allocated about 65% of capital spending to development activities, 20% to exploration activities, 10% to gas gathering and processing activities, and the remaining 5% for capitalized interest and other items. The Company expects capital spending by area to be approximately 30% for the Rockies, 20% for the Southern region, 25% for the Gulf of Mexico, 15% for International and Alaska and 10% for Midstream. Emphasis will be on production growth in the Rockies and continued development in the Gulf of Mexico, including the start-up of the Blind Faith platform. The Company's capital discipline strategy is to set capital activity at levels that can be funded with operating cash flows. Anadarko believes that its expected level of cash flow will be sufficient to fund the Company's projected operational program for 2008.
       If capital expenditures were to exceed operating cash flow, funds would be supplemented as needed by short-term borrowings. To facilitate such borrowings, the Company has in place a $1.3 billion committed credit agreement, which is supplemented by various non-committed credit lines that may be offered by certain banks from time to time at then-quoted rates. As of September 30, 2008, the Company had no outstanding borrowings under its credit facility. The Company's policy is to limit commercial paper borrowings to levels that are fully supported by unused balances from its committed credit facilities. The Company may choose to refinance certain portions of these short-term borrowings by issuing long-term debt in the public or private debt markets. To facilitate such financings, the Company may sell securities under its shelf registration statement filed with the SEC in September 2006.
       The Company continuously monitors its debt position and coordinates its capital expenditure program with expected cash flows and projected debt repayment schedules. The Company will continue to evaluate funding alternatives, including property divestitures and additional borrowings, to secure funds when needed.

Obligations and Commitments

       In 2007, Anadarko entered into notes payable, due in 2042, with unconsolidated affiliates with an aggregate value of $2.9 billion. Anadarko has the legal right to setoff and intends to net-settle these obligations with the distributable value of its interest in the corresponding unconsolidated affiliate. The related interest expense on these obligations is approximately $112 million per year for a total interest expense over the remaining life of the obligation of approximately $3.8 billion. The related interest expense on these obligations and Anadarko's equity in earnings for Anadarko's investments in these entities are recorded in other income (expense), net. See Note 7 - Unconsolidated Affiliates of the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Recent Accounting Developments

       In March 2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities" (SFAS No. 161). SFAS No. 161 does not change the accounting policy for derivatives, but requires enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items (if any) are accounted for, and how they affect the Company's financial position, financial performance, and cash flows. SFAS No. 161 is effective for Anadarko for annual and interim periods beginning with the first quarter of 2009. Early adoption is permitted. SFAS No. 161 is a disclosure requirement that does not affect Anadarko's consolidated financial position or results of operations.

        In June 2008, the FASB issued FASB Staff Position (FSP) Emerging Issues Task Force (EITF) No. 03-6-1, "Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities." FSP EITF No. 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and therefore need to be included in the earnings allocation in calculating earnings per share under the two-class method described in SFAS No. 128, "Earnings per Share." FSP EITF No. 03-6-1 requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per share. FSP EITF No. 03-6-1 is effective for fiscal years beginning after December 15, 2008; earlier application is not permitted. The Company is currently evaluating the impact of FSP EITF No. 03-6-1 on the Company's reported earnings per share.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

       The Company's primary market risks are fluctuations in energy prices and interest rates. These fluctuations can affect revenues and cash flow from operating, investing and financing activities. The Company's risk management policy provides 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 derivative instruments utilized by the Company is governed by the risk management policy and can vary from year to year. Both exchange and over-the-counter traded derivative instruments may be subject to margin deposit requirements. Given the Company's price risk management position and price volatility, the Company may be required from time to time to deposit cash or provide letters of credit with its counterparties in order to satisfy these margin requirements. For additional information see Capital Resources and Liquidity - Margin Deposits 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 5 - Debt and Interest Expense and Note 6 - Financial Instruments of 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 is the pricing for natural gas, crude oil and NGLs. Management expects energy prices to remain volatile and unpredictable. If energy prices decline significantly, revenues and cash flow would significantly decline. In addition, a non-cash impairment of the Company's oil and gas properties could be required under successful efforts accounting rules if future oil and gas commodity prices 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 322 Bcf of natural gas and 34 MMBbls of crude oil as of September 30, 2008. As of September 30, 2008, the Company had a net unrealized loss of $34 million on these derivative instruments. Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would increase the loss by approximately $351 million. However, this loss would be substantially offset by an increase in the value of that portion of the Company's production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes   As of September 30, 2008, the Company had a net unrealized gain of $45 million (losses of $25 million and gains of $70 million) on derivative financial instruments entered into for trading purposes. Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would result in a reduction of the gain on these derivative instruments by $7 million.

Interest Rate Risk   As of September 30, 2008, Anadarko had outstanding $3.5 billion of variable-rate debt (including the midstream subsidiary note payable to a related party) and $9.2 billion of fixed-rate debt. A 10% increase in LIBOR interest rates would increase gross interest expense approximately $12 million per year.
       In January 2008, Anadarko entered into 18-month interest rate swaps effective March 2008 with an aggregate notional value of $1.0 billion whereby the Company pays a weighted-average fixed interest rate of 2.74% and receives a floating interest rate indexed to the three-month LIBOR rate.

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. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the issuer's management, including its Chief Executive Officer and Chief 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, 2008.

Changes in Internal Control over Financial Reporting

      There were no changes in Anadarko's internal control over financial reporting during the third quarter of 2008 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

Environmental Matters   The Environmental Protection Agency (EPA) and the Department of Justice (DOJ) have alleged that spills at the Company's Salt Creek and Elk Basin fields violated provisions of the federal Clean Water Act and that the facilities had inadequate Spill Prevention Control and Countermeasure (SPCC) plans and facility response plans (FRP). The Company sold Elk Basin to a third party in 2007 but the Company agreed to retain responsibility for the historical spills, SPCC and FRP issues. The Company is currently in discussions with the EPA and DOJ and has a tentative understanding to resolve the matter by paying a fine of approximately $1 million, subject to negotiating the terms of a satisfactory settlement agreement. In the opinion of management, the liability with respect to these actions will not have a material effect on the consolidated financial position, results of operations or cash flow of the Company.

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 2008.

Total number of

Approximate dollar

Total

shares purchased

value of shares that

number of

Average

as part of publicly

may yet be

shares

price paid

announced plans

  purchased under the

Period

purchased ⁽¹⁾

per share

or programs

  plans or programs ⁽²⁾

July 1-31

200,088

$

69.99

-

August 1-31

8,315,171

$

59.84

8,298,755

September 1-30

1,730,495

$

59.85

1,725,475

Third Quarter 2008

10,245,754

$

60.04

10,024,230

$

4,400,000,000

⁽¹⁾

During the third quarter of 2008, 10,024,230 shares were purchased under the Company's share repurchase program. During the third quarter of 2008, 221,524 shares purchased were related to stock received by the Company for the payment of withholding taxes due on shares issued under employee stock plans.

⁽²⁾

In August 2008, the Company announced a share repurchase program to purchase up to $5 billion in shares of common stock. The program replaces the prior repurchase program and 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; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Exhibit

Original Filed

File

Number

Description

Exhibit

Number

3(a)

Restated Certificate of Incorporation

4(a) to Form S-3 dated

333-60496

of Anadarko Petroleum Corporation,

May 9, 2001

dated August 28, 1986

(b)

By-laws of Anadarko Petroleum Corporation,

3.1 to Form 8-K dated

1-8968

amended and restated as of May 20, 2008

May 27, 2008

(c)

Certificate of Amendment of Anadarko's

4.1 to Form 8-K dated

1-8968

Restated Certificate of Incorporation

July 28, 2000

(d)

Certificate of Amendment of Anadarko's

3(d) to Form 10-Q

1-8968

Restated Certificate of Incorporation

for quarter ended

June 30, 2006

4(a)

Rights Agreement, dated as of October 29,

4.1 to Form 8-A dated

1-8968

1998, between Anadarko Petroleum

October 30, 1998

Corporation and The Chase Manhattan Bank

(b)

Amendment No. 1 to Rights Agreement, dated

2.4 to Form 8-K dated

1-8968

as of April 2, 2000 between Anadarko and

April 2, 2000

The Rights Agent

(c)

Underwriting Agreement, dated September 14,

2006, among Anadarko Petroleum Corporation

and the Underwriters

1.1 to Form 8-K dated

September 19, 2006

1-8968

(d)

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 dated

September 19, 2006

1-8968

(e)

Second Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A.

4.1 to Form 8-K dated

October 5, 2006

1-8968

(f)

Ninth Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A.

4.2 to Form 8-K dated

October 5, 2006

1-8968

*31(a)

Rule 13a-14(a)/15d-14(a) Certification -

Chief Executive Officer

*(b)

Rule 13a-14(a)/15d-14(a) Certification -

Chief Financial Officer

   *32

Section 1350 Certifications

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 4, 2008

By:

/s/ R. A. WALKER

R. A. Walker

Senior Vice President, Finance and

Chief Financial Officer}}

Table of Contents
	Page
Financial Results - comparative discussion of financial results of operations	-
Operating Results - discussion of business activities	-
Capital Resources and Liquidity - discussion of sources and uses of cash, outlook on operations and material financial arrangements, obligations and commitments	-
Recent Accounting Developments - discussion of accounting guidance effective in future periods	-

	Three Months Ended
	September 30

		Natural			Oil and
millions		Gas			Condensate			NGLs


2007 sales revenues	$	871		$	1,262		$	175
Changes associated with sales volumes		154			(112	)		(5	)
Changes in prices, excluding derivatives		670			696			74
Changes in realized derivative gains and losses		(102	)		(201	)		-
Changes in unrealized derivative gains and losses		802			1,572			-

2008 sales revenues	$	2,395		$	3,217		$	244


	Nine Months Ended
	September 30

		Natural			Oil and
millions		Gas			Condensate			NGLs


2007 sales revenues	$	3,108		$	3,558		$	511
Changes associated with sales volumes		204			(505	)		(63	)
Changes in prices, excluding derivatives		1,532			2,402			255
Changes in realized derivative gains and losses		(455	)		(628	)		-
Changes in unrealized derivative gains and losses		700			84			-

2008 sales revenues	$	5,089		$	4,911		$	703

2007
Sales revenues	$	4,166	$	155	$	4,113		$	(62	)	$	8,372
Intersegment revenues		2,802		1,026		(3,624	)		(204	)		-
Gains (losses) on divestitures and other, net		3,869		532		-			57			4,458

Total revenues and other		10,837		1,713		489			(209	)		12,830

Operating costs and expenses ⁽¹⁾		2,065		885		322			328			3,600
Other (income) expense, net		-		-		-			(60	)		(60	)

Total costs and expenses		2,065		885		322			268			3,540

Adjusted EBITDAX	$	8,772	$	828	$	167		$	(477	)	$	9,290


September 30, 2008:
Net properties and equipment	$	32,308	$	2,983	$	27		$	1,559		$	36,877

Goodwill	$	4,839	$	110	$	-		$	-		$	4,949



December 31, 2007:
Net properties and equipment	$	33,150	$	2,694	$	28		$	1,579		$	37,451

Goodwill	$	4,847	$	108	$	-		$	-		$	4,955


	Pension Benefits						Other Benefits

	Three Months Ended						Three Months Ended
	September 30						September 30

millions	2008			2007			2008		2007

Components of net periodic benefit cost
Service cost	$	14		$	14		$	4	$	3
Interest cost		19			20			5		5
Expected return on plan assets		(19	)		(19	)		-		-
Amortization of prior service cost (credit)		-			-			-		-
Amortization of actuarial losses		2			2			-		-
Termination benefits		-			4			-		-
Settlements		-			1			-		-
Curtailments		-			-			-		2

Net periodic benefit cost	$	16		$	22		$	9	$	10

Results of Continuing Operations

Selected Data

	Three Months Ended								Nine Months Ended
		September 30							September 30


millions except per share amounts		2008				2007			2008			2007


Financial Results
Sales revenues	$		6,209		$		2,656	$		11,643	$		8,372
Gains (losses) on divestitures and other, net			(60	)			339			270			4,458

Total revenues and other			6,149				2,995			11,913			12,830
Costs and expenses			2,592				1,934			7,167			6,344
Other (income) expense			212				214			568			801
Income tax expense			1,181				354			1,761			2,191

Income from continuing operations	$		2,164		$		493	$		2,417	$		3,494

Earnings per common share - diluted	$		4.62		$		1.05	$		5.14	$		7.48
Average number of common shares outstanding - diluted			468				468			470			467

Operating Results
Adjusted EBITDAX⁽¹⁾			4,798				1,977			8,121			9,290
Sales volumes (MMBOE)			51				47			154			158

Capital Resources and Liquidity
Cash provided by operating activities								$		6,004	$		1,823
Capital expenditures								$		3,469	$		2,993



^{(1) See Segment Analysis-Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a Generally Accepted Accounting Principles (GAAP) measure, and a reconciliation of Adjusted EBITDAX to income from continuing operations before income taxes, which is presented in accordance with GAAP.}

Sales Revenues

	Three Months Ended							Nine Months Ended
		September 30						September 30

millions		2008			2007			2008			2007


Gas sales	$		2,395	$		871	$		5,089	$		3,108
Oil and condensate sales			3,217			1,262			4,911			3,558
Natural gas liquids sales			244			175			703			511
Gathering, processing and marketing sales			353			348			940			1,195

Total	$		6,209	$		2,656	$		11,643	$		8,372

Analysis of Oil and Gas Operations Sales Volumes


	Three Months Ended					Nine Months Ended
		September 30				September 30

		2008		2007		2008		2007

Barrels of Oil Equivalent (MMBOE)
United States			44		39		134		134
Algeria			6		6		16		18
Other International			1		2		4		6

Total			51		47		154		158


Barrels of Oil Equivalent per Day (MBOE/d)
United States			473		428		489		492
Algeria			64		65		57		64
Other International			15		17		16		21

Total			552		510		562		577



MMBOE - million barrels of oil equivalent
MBOE/d - thousand barrels of oil equivalent per day

Natural Gas Sales Volumes, Average Prices and Revenues



	Three Months Ended							Nine Months Ended
		September 30						September 30

		2008			2007			2008				2007


United States
Sales volumes-Bcf			183			151			548				513
MMcf/d			1,994			1,637			2,000				1,877
Price per Mcf, excluding derivatives	$		8.36	$		4.70	$		8.55		$		5.75
Realized gains (losses) on derivatives			0.13			0.84			(0.15	)			0.73
Unrealized gains (losses) on derivatives			4.57			0.24			0.89				(0.42	)

Gains (losses) on derivatives	$		4.70	$		1.08	$		0.74		$		0.31


Total average price per Mcf	$		13.06	$		5.78	$		9.29		$		6.06
Gas sales revenues (millions)	$		2,395	$		871	$		5,089		$		3,108



Bcf - billion cubic feet
MMcf/d - million cubic feet per day
Mcf - thousand cubic feet

Crude Oil and Condensate Sales Volumes, Average Prices and Revenues

	Three Months Ended									Nine Months Ended
		September 30								September 30

		2008				2007				2008				2007


United States
Sales volumes-MMBbls			9				10				32				36
MBbls/d			103				116				117				134
Price per barrel, excluding derivatives	$		114.26		$		72.12		$		107.89		$		61.13
Realized gains (losses) on derivatives			(15.27	)			0.65				(11.35	)			3.83
Unrealized gains (losses) on derivatives			106.14				(7.21	)			(2.90	)			(8.20	)

Total gains (losses) on derivatives	$		90.87		$		(6.56	)	$		(14.25	)	$		(4.37	)


Total average price per barrel	$		205.13		$		65.56		$		93.64		$		56.76

Algeria
Sales volumes-MMBbls			6				6				16				18
MBbls/d			64				65				57				64
Price per barrel, excluding derivatives	$		116.55		$		75.83		$		114.51		$		68.08
Realized gains (losses) on derivatives			(8.39	)			-				(8.20	)			-
Unrealized gains (losses) on derivatives			85.29				1.38				(9.92	)			(1.72	)

Total gains (losses) on derivatives	$		76.90		$		1.38		$		(18.12	)	$		(1.72	)

Total average price per barrel	$		193.45		$		77.21		$		96.39		$		66.36

Other International
Sales volumes-MMBbls			1				2				4				6
MBbls/d			15				17				16				21
Total average price per barrel	$		105.28		$		63.52		$		98.73		$		56.13

Total
Sales volumes-MMBbls			16				18				52				60
MBbls/d			182				198				190				219
Total price per barrel, excluding derivatives	$		114.34		$		72.63		$		109.10		$		62.68
Realized gains (losses) on derivatives			(11.60	)			0.38				(9.42	)			2.35
Unrealized gains (losses) on derivatives			90.11				(3.76	)			(4.77	)			(5.53	)

Total gains (losses) on derivatives	$		78.51		$		(3.38	)	$		(14.19	)	$		(3.18	)


Total average price per barrel	$		192.85		$		69.25		$		94.91		$		59.50
Total oil and condensate sales revenues (millions)	$		3,217		$		1,262		$		4,911		$		3,558



MMBbls - million barrels
MBbls/d - thousand barrels per day

Natural Gas Liquids Sales Volumes, Average Prices and Revenues

	Three Months Ended						Nine Months Ended
		September 30					September 30

		2008			2007		2008			2007


United States
Sales volumes-MMBbls			4			4			11			12
MBbls/d			38			39			39			45
Price per barrel	$		69.30	$		48.39		$	65.17		$	41.57
Natural gas liquids sales revenues (millions)	$		244	$		175		$	703		$	511

Gathering, Processing and Marketing Revenues

	Three Months Ended						Nine Months Ended
		September 30					September 30

millions		2008			2007		2008		2007


Gathering and processing sales	$		337	$		260	$	920	$	1,022
Marketing sales			16			88		20		173

Total	$		353	$		348	$	940	$	1,195

-	Oil and gas operating expense increased 7% primarily due to an increase of $20 million in compensation expense, and higher operating costs in the Rockies of approximately $20 million, partially offset by a decrease of $20 million associated with the 2007 divestitures.
-	Oil and gas transportation and other expenses increased 24% primarily due to higher surface owner payments in the Rockies and higher transportation charges in the Rockies and Southern Region and due to expenses associated with the Independence Hub startup in July 2007.
-	Exploration expense increased $120 million primarily due to an impairment of unproved properties in Trinidad of $55 million, a $40 million impairment of unproved properties in the Gulf of Mexico and higher dry hole expense of $36 million in the Gulf of Mexico.
-	Gathering, processing and marketing (GPM) expenses increased $48 million. Costs associated with gathering and processing operations increased $57 million primarily due to an increase in cost of product due to higher prices and higher direct operating expense. Marketing transportation costs decreased $9 million.
-	General and administrative (G&A) expense increased 26% primarily due to a $41 million increase in benefit plans expense.
-	Depreciation, depletion and amortization (DD&A) expense increased 29%. DD&A expense associated with oil and gas properties increased approximately $127 million due to higher costs associated with acquiring, finding and developing oil and gas reserves and approximately $50 million due to higher sales volumes from retained properties. Depreciation of other properties and equipment increased $9 million.
-	Other taxes increased 58% primarily due to increased production and severance taxes related to higher commodity prices, an increase in the Algerian exceptional profits tax expense of $42 million, an increase in the windfall profits tax in China of $22 million and increased ad valorem taxes.
-	Impairments of $37 million and $19 million were related to Midstream segment assets and Oil and Gas Exploration and Production segment properties in the United States, respectively.

-	Oil and gas operating expense decreased 10% primarily due to a decrease of $112 million associated with the 2007 divestitures, lower insurance expenses of $24 million related to Gulf of Mexico properties and lower demand charges of $20 million in the Gulf of Mexico, partially offset by an increase of $22 million in compensation expense, higher operating costs of $21 million in the Rockies and higher gas processing fees of $27 million in the Gulf of Mexico due to expenses associated with the startup of Independence Hub in July 2007.
-	Oil and gas transportation and other expenses increased 17% primarily due to higher surface owner payments in the Rockies and higher transportation charges in the Rockies and Southern Region and due to expenses associated with the Independence Hub startup.
-	Exploration expense increased $266 million primarily due to a $122 million impairment of unproved properties in the Gulf of Mexico, a $55 million impairment of unproved properties in Trinidad, a $40 million impairment of unproved properties in Brazil, higher dry hole costs of $66 million in the Gulf of Mexico, a $31 million increase in geological and geophysical costs, primarily in Mozambique, $17 million related to a joint-venture termination and increases in other miscellaneous exploration costs, partially offset by lower international dry hole expense of $40 million primarily in Nigeria, Benin, Indonesia and China, and lower impairments in China of $28 million.
-	GPM expenses decreased $161 million. Costs associated with gathering and processing operations decreased $124 million primarily due to 2007 divestitures and a reduction of accrued expenses related to a prior period of $29 million, partially offset by an increase in cost of product due to higher prices and direct operating costs from retained operations. Marketing transportation costs decreased $33 million.
-	G&A expense decreased 9% primarily due to lower compensation expense of $53 million, a $39 million decrease in employee severance and termination benefits and decreases in legal, consulting and audit fees primarily associated with the 2007 asset realignment program and 2007 system integration projects, partially offset by higher benefit plans expense of $45 million.
-	DD&A expense increased 17%. DD&A expense associated with oil and gas properties increased approximately $393 million due to higher costs associated with acquiring, finding and developing oil and gas reserves. This increase was partially offset by a decrease of approximately $34 million due to lower sales volumes from retained properties and a decrease in depreciation of other properties and equipment of $17 million.
-	Other taxes increased 50% primarily due to increased production and severance taxes related to higher commodity prices, an increase in the Algerian exceptional profits tax of $81 million, increases associated with the effects of a windfall profits tax in China of $71 million, a new Alaskan severance tax of $45 million and increased ad valorem taxes. This increase was partially offset by a decrease in the Algerian exceptional profits tax expense primarily attributable to a change in the estimate of the 2006 exceptional profits tax recognized in the first quarter of 2007.
-	Impairments of $37 million and $30 million for nine months ended September 30, 2008 were related to Midstream segment assets and Oil and Gas Exploration and Production segment properties in the United States, respectively.

						Total number of		Approximate dollar
		Total				shares purchased		value of shares that
		number of		Average		as part of publicly		may yet be
		shares		price paid		announced plans		purchased under the
Period		purchased ⁽¹⁾		per share		or programs		plans or programs ⁽²⁾


July 1-31			200,088	$	69.99		-
August 1-31			8,315,171	$	59.84		8,298,755
September 1-30			1,730,495	$	59.85		1,725,475

Third Quarter 2008			10,245,754	$	60.04		10,024,230		$	4,400,000,000


⁽¹⁾	During the third quarter of 2008, 10,024,230 shares were purchased under the Company's share repurchase program. During the third quarter of 2008, 221,524 shares purchased were related to stock received by the Company for the payment of withholding taxes due on shares issued under employee stock plans.
⁽²⁾	In August 2008, the Company announced a share repurchase program to purchase up to $5 billion in shares of common stock. The program replaces the prior repurchase program and 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.


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

Exhibit		Original Filed	File
Number	Description	Exhibit	Number


3(a)	Restated Certificate of Incorporation	4(a) to Form S-3 dated	333-60496
	of Anadarko Petroleum Corporation,	May 9, 2001
	dated August 28, 1986

(b)	By-laws of Anadarko Petroleum Corporation,	3.1 to Form 8-K dated	1-8968
	amended and restated as of May 20, 2008	May 27, 2008

(c)	Certificate of Amendment of Anadarko's	4.1 to Form 8-K dated	1-8968
	Restated Certificate of Incorporation	July 28, 2000

(d)	Certificate of Amendment of Anadarko's	3(d) to Form 10-Q	1-8968
	Restated Certificate of Incorporation	for quarter ended
		June 30, 2006

4(a)	Rights Agreement, dated as of October 29,	4.1 to Form 8-A dated	1-8968
	1998, between Anadarko Petroleum	October 30, 1998
	Corporation and The Chase Manhattan Bank

(b)	Amendment No. 1 to Rights Agreement, dated	2.4 to Form 8-K dated	1-8968
	as of April 2, 2000 between Anadarko and	April 2, 2000
	The Rights Agent

(c)	Underwriting Agreement, dated September 14, 2006, among Anadarko Petroleum Corporation and the Underwriters	1.1 to Form 8-K dated September 19, 2006	1-8968

(d)	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 dated September 19, 2006	1-8968

(e)	Second Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A.	4.1 to Form 8-K dated October 5, 2006	1-8968

(f)	Ninth Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A.	4.2 to Form 8-K dated October 5, 2006	1-8968

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

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

*32	Section 1350 Certifications

	ANADARKO PETROLEUM CORPORATION
	(Registrant)



November 4, 2008	By:	/s/ R. A. WALKER

		R. A. Walker Senior Vice President, Finance and Chief Financial Officer