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 Quarter Ended September 30, 2005
Commission File No. 1-8968

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

Incorporated in the	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 tosuch filing requirements for the past 90 days. Yes   X      No _____.

Indicate by check mark whether the registrant is an accelerated filer. Yes    X     No _____.

Indicate by check mark whether the registrant is a shell company. Yes            No    X   .

The number of shares outstanding of the Company's common stock as of September 30, 2005 is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.10 per share	235,124,788

TABLE OF CONTENTS
			Page
PART I
	Item 1.	Financial Statements
		Consolidated Statements of Income for the Three and Nine Months     Ended September 30, 2005 and 2004	-
		Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004	-
		Consolidated Statements of Comprehensive Income for the Three and     Nine Months Ended September 30, 2005 and 2004	-
		Consolidated Statements of Cash Flows for the Nine Months     Ended September 30, 2005 and 2004	-
		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		2005				2004			2005				2004
Revenues
Gas sales	$		909		$		823	$		2,466		$		2,438
Oil and condensate sales			752				589			2,052				1,643
Natural gas liquids sales			119				123			333				319
Other sales			(24	)			27			25				65
Total			1,756				1,562			4,876				4,465
Costs and Expenses
Direct operating			131				177			398				498
Transportation and cost of product			75				67			217				183
General and administrative			99				98			311				269
Depreciation, depletion and amortization			334				387			991				1,092
Other taxes			101				86			281				252
Impairments related to oil and gas properties			13				-			13				9
Total			753				815			2,211				2,303
Operating Income			1,003				747			2,665				2,162
Interest Expense and Other (Income) Expense
Interest expense			50				131			152				260
Other (income) expense			(18	)			16			(14	)			72
Total			32				147			138				332
Income Before Income Taxes			971				600			2,527				1,830
Income Tax Expense			373				199			931				630
Net Income	$		598		$		401	$		1,596		$		1,200
Preferred Stock Dividends			2				2			4				4
Net Income Available to Common Stockholders	$		596		$		399	$		1,592		$		1,196
Per Common Share
Net income - basic	$		2.53		$		1.59	$		6.74		$		4.76
Net income - diluted	$		2.51		$		1.58	$		6.68		$		4.72
Dividends	$		0.18		$		0.14	$		0.54		$		0.42
Average Number of Common Shares Outstanding - Basic			235				250			236				252
Average Number of Common Shares Outstanding - Diluted			238				253			238				254

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,					December 31,
millions		2005					2004
ASSETS
Current Assets
Cash and cash equivalents		$	1,012				$	874
Accounts receivable, net of allowance:
Customers			1,151					1,040
Others			454					310
Other current assets			363					278
Total			2,980					2,502
Properties and Equipment
Original cost (includes unproved properties of $1,491 and $1,642
as of September 30, 2005 and December 31, 2004, respectively)			27,561					25,175
Less accumulated depreciation, depletion and amortization			10,278					9,262
Net properties and equipment - based on the full cost method
of accounting for oil and gas properties			17,283					15,913
Other Assets			463					468
Goodwill			1,286					1,309
Total Assets		$	22,012				$	20,192
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$			1,411		$			1,460
Accrued expenses				952					364
Current debt				72					169
Total				2,435					1,993
Long-term Debt				3,604					3,671
Other Long-term Liabilities
Deferred income taxes				4,539					4,414
Other				860					829
Total				5,399					5,243
Stockholders' Equity
Preferred stock, par value $1.00 per share (2.0 million shares authorized,
0.1 million shares issued as of September 30, 2005 and December 31, 2004)				89					89
Common stock, par value $0.10 per share (450.0 million shares authorized,
265.6 million and 262.2 million shares issued as of September 30, 2005 and
December 31, 2004, respectively)				27					26
Paid-in capital				6,021					5,741
Retained earnings				6,124					4,661
Treasury stock (28.4 million and 23.5 million shares as of September 30, 2005
and December 31, 2004, respectively)				(1,884	)				(1,476	)
ESOP (0.1 million shares as of December 31, 2004)				-					(7	)
Executives and Directors Benefits Trust, at market value
(2.0 million shares as of September 30, 2005 and December 31, 2004)				(193	)				(130	)
Accumulated other comprehensive income (loss):
Unrealized loss on derivative instruments				(92	)				(23	)
Foreign currency translation adjustments				560					482
Minimum pension liability				(78	)				(78	)
Total				390					381
Total				10,574					9,285
Commitments and Contingencies				-					-
Total Liabilities and Stockholders' Equity	$			22,012		$			20,192

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		2005				2004				2005				2004
Net Income Available to Common Stockholders	$		596		$		399		$		1,592		$		1,196
Add: Preferred Stock Dividends			2				2				4				4
Net Income Available to Common Stockholders
Before Preferred Stock Dividends			598				401				1,596				1,200
Other Comprehensive Income (Loss), Net of Income Taxes
Unrealized losses on derivative instruments:
Unrealized losses during the period1			(46	)			(71	)			(125	)			(186	)
Reclassification adjustment for losses included in net
income2			27				61				56				152
Total unrealized losses on derivative instruments			(19	)			(10	)			(69	)			(34	)
Foreign currency translation adjustments3			115				132				78				63
Total			96				122				9				29
Comprehensive Income	$		694		$		523		$		1,605		$		1,229
1net of income tax benefit of:	$		26		$		42		$		72		$		107
2net of income tax expense of:			(15	)			(35	)			(32	)			(88	)
3net of income tax expense of:			(15	)			(19	)			(10	)			(6	)

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Nine Months Ended
		September 30
millions		2005				2004
Cash Flow from Operating Activities
Net income	$		1,596		$		1,200
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization			991				1,092
Deferred income taxes			243				71
Impairments related to oil and gas properties			13				9
Other noncash items			(10	)			78
Changes in assets and liabilities:
Increase in accounts receivable			(249	)			(232	)
Increase in accounts payable and accrued expenses			357				658
Other items - net			(66	)			(119	)
Net cash provided by operating activities			2,875				2,757
Cash Flow from Investing Activities
Additions to properties and equipment			(2,393	)			(2,235	)
Acquisition costs, net of cash acquired			-				(46	)
Sales of properties and equipment			133				469
Net cash used in investing activities			(2,260	)			(1,812	)
Cash Flow from Financing Activities
Additions to debt			6				208
Retirements of debt			(170	)			(782	)
Increase (decrease) in accounts payable, banks			67				(13	)
Sale of future hard minerals royalty revenues			-				158
Dividends paid			(132	)			(110	)
Purchase of treasury stock			(408	)			(458	)
Issuance of common stock			149				136
Net cash used in financing activities			(488	)			(861	)
Effect of Exchange Rate Changes on Cash			11				8
Net Increase in Cash and Cash Equivalents			138				92
Cash and Cash Equivalents at Beginning of Period			874				62
Cash and Cash Equivalents at End of Period	$		1,012		$		154

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.  Summary of Significant Accounting Policies

General     Anadarko Petroleum Corporation is engaged in the exploration, development, production and marketing of natural gas, crude oil, condensate and natural gas liquids (NGLs). The Company also engages in the hard minerals business through non-operated joint ventures and royalty arrangements in several coal, trona (natural soda ash) and industrial mineral mines. The terms "Anadarko" and "Company" refer to Anadarko Petroleum Corporation and its 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, 2005 and December 31, 2004, the results of operations for the three and nine months ended September 30, 2005 and 2004 and cash flows for the nine months ended September 30, 2005 and 2004. 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 the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, Management reviews its estimates, including those related to litigation, environmental liabilities, income taxes, fair values and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Derivative Instruments     The majority of the derivative instruments utilized by Anadarko are in conjunction with its marketing and trading activities or to manage the price risk attributable to the Company's expected oil and gas production. Anadarko also periodically utilizes derivatives to manage its exposure associated with the firm transportation keep-whole agreement, foreign currency exchange rates and interest rates. All derivatives, other than those that meet the normal purchases and sales exception, are carried on the balance sheet at fair value.

       Anadarko prefers to apply hedge accounting for derivatives utilized to manage price risk associated with the Company's oil and gas production, foreign currency exchange rate risk and interest rate risk. However, some of these derivatives do not qualify for hedge accounting. In these instances, unrealized gains and losses are recognized currently in earnings. For those derivatives that qualify for hedge accounting, Anadarko formally documents the relationship of each hedge to the hedged item including the risk management objective and strategy for undertaking the hedge. Each hedge is also assessed for effectiveness quarterly. Under hedge accounting, the derivatives may be designated as a hedge of exposure to changes in fair values, cash flows or foreign currencies. If the hedge relates to the exposure of fair value changes to a recognized asset or liability or an unrecognized firm commitment, the unrealized gains and losses on the derivative and the unrealized losses and gains on the hedged item are both recognized currently in earnings. If the hedge relates to exposure of variability in the cash flow of a forecasted transaction, the effective portion of the unrealized gains and losses on the derivative is reported as a component of accumulated other comprehensive income and reclassified into earnings in the same period the hedged transaction is recorded. The ineffective portion of unrealized gains and losses attributable to cash flow hedges, if any, is recognized currently in other (income) expense. Hedge ineffectiveness is that portion of the derivative's unrealized gains and losses that exceed the hedged item's unrealized losses and gains. In those instances where it becomes probable that a hedged forecasted transaction will not occur, the unrealized gain or loss is reclassified from accumulated other comprehensive income to earnings in the current period. Accounting for unrealized gains and losses attributable to foreign currency hedges that qualify for hedge accounting is dependent on whether the hedge is a fair value or a cash flow hedge.

       Unrealized gains and losses attributable to derivative instruments used in the Company's marketing and trading activities (including both physical delivery and financially settled purchase and sale contracts), the firm transportation keep-whole agreement and derivatives used to manage the exposure of the keep-whole agreement are recognized currently in earnings. The marketing and trading unrealized gains and losses that are attributable to the Company's production are recorded to gas sales and oil and condensate sales. The marketing and trading unrealized gains and losses that are attributable to third-party production are recorded to other sales. The gains and losses attributable to the firm transportation keep-whole agreement and associated derivatives are recorded to other (income) expense.

       The Company's derivative instruments are either exchange traded or transacted in an over-the-counter market. Valuation is determined by reference to readily available public data. Option valuations are based on the Black-Scholes option pricing model and verified against third-party quotations. The fair value of the short-term portion of the firm transportation keep-whole agreement is calculated based on quoted natural gas basis differentials, while the fair value of the long-term portion is estimated based on an internally developed model that utilizes historical natural gas basis differentials. See Note 6.

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 and performance-based stock awards under the treasury stock method, if including such potential shares of common stock is dilutive. Diluted EPS amounts also include the net effect of the Company's Zero Yield Puttable Contingent Debt Securities (ZYP-CODES) assuming the conversion occurred at the beginning of the year, if including such potential common shares is dilutive. See Note 8.

New Accounting Principles and DevelopmentsIn September 2005, the Emerging Issues Task Force (EITF) concluded in Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty," that purchases and sales of inventory with the same party in the same line of business should be accounted for as nonmonetary exchanges, if entered into in contemplation of one another. Anadarko presents purchase and sale activities related to its marketing and trading activities on a net basis in the income statement. The Company does not expect the conclusion reached on EITF Issue No. 04-13 to have a material impact on the Company's consolidated financial statements.

       Financial Accounting Standards Board (FASB) Staff Position (FSP) FAS 109-1, ''Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,'' provides guidance on the application of Statement of Financial Accounting Standards (SFAS) No. 109, ''Accounting for Income Taxes,'' to the tax deduction on qualified production as provided for in the American Jobs Creation Act of 2004 (Jobs Act). FSP FAS 109-1 provides that the deduction should be treated as a special deduction under the provisions of SFAS No. 109. The adoption of FSP FAS 109-1 did not have a material impact on the consolidated financial statements.

       FSP FAS 109-2, ''Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004,'' provides guidance on the application of SFAS No. 109 to the special one-time dividends received deduction on the repatriation of certain undistributed foreign earnings to a U.S. taxpayer as provided for in the Jobs Act. In May 2005, Anadarko's Chief Executive Officer and Board of Directors approved a domestic reinvestment plan for a $500 million repatriation of foreign earnings under the Jobs Act. The $26 million tax effect of this repatriation was recorded as current tax expense in the second quarter financial statements.

2.  Stock-Based Compensation

       For share based awards granted or modified after January 2003, the Company uses the fair value method of accounting for stock-based employee compensation expense. For share based awards granted prior to 2003, Anadarko applies the intrinsic value method whereby no compensation expense is recognized for stock options granted with an exercise price equal to the market value of Anadarko common stock on the date of grant.

       If compensation expense for all stock option grants had been determined using the fair value method, the Company's pro forma net income and EPS would have been as shown below:

	Three Months Ended									Nine Months Ended
	September 30									September 30
millions except per share amounts		2005				2004				2005				2004
Net income available to common stockholders, as reported	$		596		$		399		$		1,592		$		1,196
Add: Stock-based employee compensation expense included
in income, after income taxes			4				4				14				11
Deduct: Total stock-based employee compensation expense
determined under the fair value method, after income taxes			(4	)			(5	)			(15	)			(15	)
Pro forma net income available to common stockholders	$		596		$		398		$		1,591		$		1,192
Basic EPS - as reported	$		2.53		$		1.59		$		6.74		$		4.76
Basic EPS - pro forma	$		2.53		$		1.59		$		6.74		$		4.74
Diluted EPS - as reported	$		2.51		$		1.58		$		6.68		$		4.72
Diluted EPS - pro forma	$		2.50		$		1.57		$		6.66		$		4.70

3.   Inventories

       Inventories are stated at the lower of average cost or market. The major classes of inventories, which are included in other current assets, are as follows:

	September 30,		December 31,
millions	2005		2004
Materials and supplies	$	84	$	79
Crude oil and NGLs		60		29
Natural gas		57		29
Total	$	201	$	137

4.  Properties and Equipment

       Oil and gas properties include costs of $1.5 billion and $1.6 billion at September 30, 2005 and December 31, 2004, respectively, which were excluded from capitalized costs being amortized. These amounts represent costs associated with unproved properties and major development projects. At September 30, 2005 and December 31, 2004, the Company's investment in countries where proved reserves have not been established was $152 million and $116 million, respectively. For the first nine months of 2005 and 2004, the Company made provisions for impairments of oil and gas properties of $13 and $9 million, respectively, related to international activities.

       Total interest cost incurred during the third quarter of 2005 and 2004 was $67 million and $151 million, respectively. Of these amounts, the Company capitalized $17 million and $20 million during the third quarter of 2005 and 2004, respectively, as part of the cost of properties. Total interest cost incurred during the first nine months of 2005 and 2004 was $204 million and $327 million, respectively. Of these amounts, the Company capitalized $52 million and $67 million during the first nine months of 2005 and 2004, respectively. The interest rates for capitalization are based on the Company's weighted average cost of borrowings used to finance the expenditures applied to costs excluded on which exploration, development and construction activities are in progress.

       Properties and equipment include internal costs related to exploration, development and construction activities of $37 million and $41 million capitalized during the third quarter of 2005 and 2004, respectively. For the first nine months of 2005 and 2004, the Company capitalized internal costs related to exploration, development and construction activities of $124 million and $127 million, respectively.

5.  Debt and Interest Expense

	September 30, 2005				December 31, 2004
millions	Principal		Carrying Value		Principal		Carrying Value
Total debt	$	3,796	$	3,676	$	3,966	$	3,840
Less current debt				72				169
Total long-term debt			$	3,604			$	3,671

During the second quarter of 2005, the Company redeemed for cash $170 million principal amount of 6.5% Notes due in May 2005. As of September 30, 2005, current debt represents $42 million principal amount of 7.375% Debentures due May 2006 and $30 million principal amount of Zero Yield Puttable Contingent Debt Securities due 2021 that may be put to the Company in March 2006 at the option of the holders.

	Three Months Ended										Nine Months Ended
			September 30								September 30
millions			2005			2004				2005						2004
Interest Expense
Gross interest expense		$		67		$	88		$			204		$	264
Premium and related expenses for early retirement of debt				-			63					-			63
Capitalized interest				(17	)		(20	)				(52	)		(67		)
Net interest expense		$		50		$	131		$			152		$	260

6.  Financial Instruments

Derivative Instruments       The Company is exposed to price risk from changing commodity prices. Management believes it is prudent to periodically minimize the variability in cash flows on a portion of its oil and gas production. To meet this objective, the Company enters into various types of derivative financial instruments to manage fluctuations in cash flows resulting from changing commodity prices. The Company also uses fixed price physical delivery sales contracts to accomplish this objective. The types of derivative financial instruments utilized by the Company include futures, swaps and options.

       Anadarko also enters into derivative financial instruments (futures, swaps and options) and physical delivery contracts for trading purposes with the objective of generating profits from exposure to changes in the market price of natural gas and crude oil. Derivative financial instruments are also used to meet customers' pricing requirements while achieving a price structure consistent with the Company's overall pricing strategy. In addition, the Company may use options and swaps to reduce exposure on its firm transportation keep-whole commitment with Duke Energy Corporation (Duke).

       Futures contracts are generally used to fix the price of expected future gas sales and oil sales at major industry trading locations; e.g., Henry Hub, Louisiana for gas and Cushing, Oklahoma for oil. 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 gas sales and oil sales. Settlements of futures contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the International Petroleum Exchange and have nominal credit risk. Swap, over-the-counter traded option and physical delivery agreements 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 valuation and hedge accounting criteria. In addition, the Company routinely exercises its contractual right to net realized gains against realized losses in settling with its swap and option counterparties.

Oil and Gas Activities       At September 30, 2005 and December 31, 2004, the Company had option contracts, swap contracts and fixed price physical delivery contracts in place to hedge the sales price of a portion of its expected future sales of equity oil and gas production. The fixed price physical delivery contracts are excluded from derivative accounting treatment under the normal sale provision. The derivative financial instruments receive hedge accountingtreatment if they qualify and are so designated. For those derivatives that do not qualify for hedge accounting, unrealized gains and losses are recognized currently in oil and gas revenues.

       The fair value and the accumulated other comprehensive income balance applicable to the derivative financial instruments (excluding the physical delivery sales contracts) are as follows:

		September 30,			December 31,
millions		2005				2004
Fair Value - Asset (Liability)
Current	$		(228	)	$		(58	)
Long-term			(30	)			(12	)
Total	$		(258	)	$		(70	)
Accumulated other comprehensive loss before income taxes	$		(143	)	$		(35	)
Accumulated other comprehensive loss after income taxes	$		(92	)	$		(22	)

       The difference between the fair value and the unrealized loss before income taxes recognized in accumulated other comprehensive income is due to premiums, recognition of unrealized gains and losses on derivatives that did not qualify for hedge accounting and hedge ineffectiveness.

       Below is a summary of the Company's financial derivative instruments and fixed price, physical delivery sales contracts related to its oil and gas activities as of September 30, 2005, including the hedged volumes per day and the related weighted-average prices. The natural gas prices, except for basis swaps, are NYMEX Henry Hub. The prices for basis swaps are a volumetric weighted average of the differentials from Henry Hub. The crude oil prices are a combination of NYMEX Cushing and Brent Dated. Cash flow hedges on natural gas beyond 2006 and on crude oil beyond 2011 are not significant.

							Fourth
							Quarter					Annual
							2005					2006
Natural Gas
Two-Way Collars (thousand MMBtu/d)								26					10
Price per MMBtu
Ceiling sold price				$				5.65			$			5.88
Floor purchased price				$				3.76			$			4.00
Three-Way Collars (thousand MMBtu/d)								269					-
Price per MMBtu
Ceiling sold price				$				9.37			$			-
Floor purchased price				$				5.00			$			-
Floor sold price				$				4.01			$			-
Fixed Price (thousand MMBtu/d)								18						11
Price per MMBtu				$				2.95			$			2.87
Total (thousand MMBtu/d)								313						21
Basis Swaps (thousand MMBtu/d)								119						12
Price per MMBtu				$				(0.18		)	$			(0.30			)
MMBtu/d - million British thermal units per day
		Fourth														Five Year
		Quarter				Annual										Average
		2005				2006										2007-2011
Crude Oil
Two-Way Collars (MBbls/d)			2						1							-
Price per barrel
Ceiling sold price	$		26.32		$				26.32						$	-
Floor purchased price	$		22.00		$				22.00						$	-
Three-Way Collars (MBbls/d)			43						-							9
Price per barrel
Ceiling sold price	$		46.89		$				-						$	85.43
Floor purchased price	$		32.28		$				-						$	49.46
Floor sold price	$		27.28		$				-						$	34.46
Total (MBbls/d)			45						1							9
MBbls/d - thousand barrels per day

       A two-way collar is a combination of options, a sold call and a purchased put. The sold call establishes a maximum price (ceiling) and the purchased put establishes a minimum price (floor) the Company will receive for the volumes under contract. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The sold call establishes a maximum price the Company will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.The fixed price hedges consist of swaps and physical delivery contracts and establish a fixed price the Company will receive for the volumes under contract.

       Cash flow hedge accounting is being applied to 260 thousand MMBtu/d of the natural gas three-way collars for the remainder of 2005. For crude oil, cash flow hedge accounting is being applied to all three-way collars except for 14 MBbls/d for the remainder of 2005.

Marketing and Trading Activities     Unrealized gains and losses attributed to the Company's marketing and trading derivative instruments (both physically and financially settled) are recognized currently in earnings. The fair values of these derivatives as of September 30, 2005 and December 31, 2004 are as follows:

		September 30,			December 31,
millions		2005			2004
Fair Value - Asset (Liability)
Current	$		(51	)	$	11
Long-term			(4	)		5
Total	$		(55	)	$	16

Firm Transportation Keep-Whole Agreement     A company Anadarko acquired in 2000 was a party to several long-term firm gas transportation agreements that supported its gas marketing program within its gathering, processing and marketing (GPM) business segment, which was sold in 1999 to Duke. Most of these agreements were transferred to Duke in the GPM disposition. One agreement was retained, but is managed and operated by Duke. Anadarko is not responsible for the operations of any of the contracts and does not utilize the associated transportation assets to transport the Company's natural gas. As part of the GPM disposition, Anadarko pays Duke if transportation market values fall below the fixed contract transportation rates, while Duke pays Anadarko if the transportation market values exceed the contract transportation rates (keep-whole agreement). This keep-whole agreement will be in effect until February 2009.

       The Company may periodically use derivative instruments to reduce its exposure to potential decreases in future transportation market values. While derivatives are intended to reduce the Company's exposure to declines in the market value of firm transportation, they also limit the potential to benefit from increases in the market value of firm transportation. Due to decreased liquidity, the use of derivative instruments to manage this risk is generally limited to the forward 12 months. Unrealized gains and losses attributed to the keep-whole agreement and any associated derivative instruments are recognized currently in earnings.

       The fair value of the short-term portion of the firm transportation keep-whole agreement is calculated based on quoted natural gas basis differentials. Basis differentials are the difference in value between gas at various delivery points and the NYMEX gas futures contract price. Management believes that natural gas basis differential quotes beyond the next 12 months are not reliable indicators of fair value due to decreasing liquidity. Accordingly, the fair value of the long-term portion is estimated based on historical regional natural gas basis differentials. The Company recognized other income of $29 million and other expense of $6 million for the quarter ended September 30, 2005 and 2004, respectively, and other income of $18 million and other expense of $3 million for the nine months ended September 30, 2005 and 2004, respectively, related to the keep-whole agreement and associated derivative instruments. Net payments to Duke for the quarter ended September 30, 2005 and 2004 were $6 million and $4 million, respectively, and net payments to Duke for the nine months ended September 30, 2005 and 2004 were $9 million and $16 million, respectively. As of September 30, 2005, other current assets included $13 million and other long-term liabilities included $34 million related to the keep-whole agreement and associated derivative instruments. As of December 31, 2004, accounts payable included $15 million and other long-term liabilities included $39 million related to the keep-whole agreement and associated derivative instruments.

       Anticipated undiscounted and discounted (receivables) liabilities for the firm transportation keep-whole agreement at September 30, 2005 are as follows:

millions		Undiscounted				Discounted
2005	$		(9	)	$		(9	)
2006			3				2
2007			22				19
2008			10				8
2009			1				1
Total	$		27		$		21

       As of September 30, 2005 and December 31, 2004, the Company's derivative financial instrument hedges in place related to the firm transportation keep-whole agreement were not significant.

7.  Preferred Stock

       For the first, second and third quarters of 2005 and 2004, dividends of $13.65 per share (equivalent to $1.365 per Depositary Share) were paid to holders of preferred stock.

8.  Common Stock

       The reconciliation between basic and diluted EPS is as follows:

		Three Months Ended							Three Months Ended
		September 30, 2005							September 30, 2004
						Per Share								Per Share
	millions except per share amounts	Income		Shares		Amount		Income				Shares		Amount
Basic EPS
Net income available to
common stockholders		$	596		235	$	2.53	$			399		250	$	1.59
Effect of convertible debentures
and ZYP-CODES			-		1						-		1
Effect of dilutive stock options and
performance-based stock awards			-		2						-		2
Diluted EPS
Net income available to
common stockholders plus
assumed conversion		$	596		238	$	2.51	$			399		253	$	1.58
		Nine Months Ended							Nine Months Ended
		September 30, 2005							September 30, 2004
						Per Share								Per Share
	millions except per share amounts	Income		Shares		Amount		Income				Shares		Amount
Basic EPS
Net income available to
common stockholders		$	1,592		236	$	6.74	$		1,196			252	$	4.76
Effect of convertible debentures
and ZYP-CODES			-		-					-			-
Effect of dilutive stock options and
performance-based stock awards			-		2					-			2
Diluted EPS
Net income available to
common stockholders plus
assumed conversion		$	1,592		238	$	6.68	$		1,196			254	$	4.72

       During the three and nine months ended September 30, 2004, options for 0.4 million and 1.0 million average shares, respectively, of common stock were excluded from the diluted EPS calculation because the options' exercise price was greater than the average market price of common stock for the periods.

       The Company initiated a $2 billion stock buyback program in June 2004 under which shares were repurchased either in the open market or through privately negotiated transactions. During the nine months ended September 30, 2005, Anadarko purchased 4.9 million shares of common stock for $406 million under the program. During October 2005, the Company purchased an additional 3.2 million shares of common stock for $285 million, completing the program.

       The Company's credit agreement allows for a maximum capitalization ratio of 60% debt, exclusive of the effect of any noncash writedowns. Under the maximum debt capitalization ratio, retained earnings were not restricted as to the payment of dividends at September 30, 2005 and December 31, 2004.

9.  Statements of Cash Flows Supplemental Information

       The amounts of cash paid for interest (net of amounts capitalized) and income taxes are as follows:

		Nine Months Ended
		September 30
millions			2005			2004
Interest	$			100	$		206
Income taxes	$			275	$		26

10.  Segment Information

       The following table illustrates information related to Anadarko's business segments. The segment shown as All Other and Intercompany Eliminations includes other smaller operating units, corporate activities, financing activities and intercompany eliminations.

	Oil and Gas				Marketing						All Other and
	Exploration				and						Intercompany
millions	and Production				Trading				Minerals		Eliminations					Total
Three Months Ended September 30:
2005
Total revenues		$	1,746	$		1		$		8		$	1		$		1,756
Impairments related to oil and gas properties			13			-				-			-				13
Operating income (loss)		$	1,124	$		(47	)	$		7		$	(81	)	$		1,003
2004
Total revenues		$	1,517	$		38		$		9		$	(2	)	$		1,562
Operating income (loss)		$	829	$		(3	)	$		8		$	(87	)	$		747
Nine Months Ended September 30:
2005
Total revenues		$	4,763	$		97		$		33		$	(17	)	$		4,876
Impairments related to oil and gas properties			13			-				-			-				13
Operating income (loss)		$	2,963	$		(50	)	$		29		$	(277	)	$		2,665
Net properties and equipment		$	15,387	$		381		$		1,189		$	326		$		17,283
Goodwill		$	1,286	$		-		$		-		$	-		$		1,286
2004
Total revenues		$	4,340	$		124		$		30		$	(29	)	$		4,465
Impairments related to oil and gas properties			9			-				-			-				9
Operating income (loss)		$	2,405	$		1		$		26		$	(270	)	$		2,162
Net properties and equipment		$	16,133	$		347		$		1,194		$	360		$		18,034
Goodwill		$	1,395	$		-		$		-		$	-		$		1,395

11.  Other (Income) Expense

       Other (income) expense consists of the following:

		Three Months Ended										Nine Months Ended
				September 30									September 30
millions			2005					2004					2005				2004
Operating lease settlement	$				-		$		-		$			-		$		63
Firm transportation keep-whole contract valuation					(29	)			6					(18	)			3
Ineffectiveness of derivative financial instruments					20				5					21				2
Interest income					(6	)			(2	)				(15	)			(4	)
Foreign currency transaction (gains) losses					(1	)			(3	)				-				(5	)
Other					(2	)			10					(2	)			13
Total	$				(18	)	$		16		$			(14	)	$		72

      Foreign currency transaction (gains) losses for the three and nine months ended September 30, 2005 exclude zero and ($3) million, respectively, related to the remeasurement of the Venezuelan deferred tax liability, which amounts are included in income tax expense. For the three and nine months ended September 30, 2004, foreign currency transaction (gains) losses exclude zero and ($6) million, respectively, in transaction gains related to the remeasurement of the Venezuelan deferred tax liability, which amounts are included in income tax expense. The operating lease settlement in 2004 relates to the Corpus Christi West Plant Refinery.

12.  Commitments

Transportation Commitments     In June 2005, the Company entered into precedent agreements with a third party in order to secure delivery of natural gas from a liquefied natural gas facility Anadarko is constructing in Nova Scotia, Canada, called Bear Head, to prospective markets in eastern Canada and the northeastern United States. The third party has agreed to expand the capacity of its pipeline so it can accommodate the projected natural gas volumes from Bear Head. The precedent agreements signed by the parties establish the conditions on which the third party will proceed with design, regulatory approvals and construction of the expansion facilities, and be obligated to transport a specified volume of gas. As a condition to entering into the precedent agreements, Anadarko executed firm service agreements for transportation on the Canadian and United States portions of the pipeline. Upon satisfaction of the obligations under the precedent agreements, the initial term of the transportation agreements is 20 years.

       Based on current assumptions, Anadarko projects that annual demand charges due under the firm transportation service agreements may be in the range of $123 million to $182 million per year for the first five years from commencement of full service, potentially escalating by up to 5% in year six and 10% in year seven, exclusive of fuel and surcharges. No later than the eighth year from commencement of full service, rates under the agreements are to be redetermined based on then current conditions. The parties currently expect partial service under the agreements to commence between November 2007 and November 2008, and full service to commence between June 2008 and November 2009.

       The precedent agreements contain certain termination rights. The Company's potential reimbursement obligation under the precedent agreements increases over time as the third party incurs pre-service costs. This reimbursement obligation is expected to increase from about $8 million at December 2005 to $100 million at December 2006, up to a maximum of $215 million in May 2007.

Long-term Drilling Rig Commitments     In September 2005, Anadarko announced a plan to secure the necessary drilling rigs to execute its deepwater strategy over the next six years. As part of the plan, Anadarko with two other producers signed a four-year rig-share agreement under which a third party will build and own a new semi-submersible drilling rig with a target delivery date of mid-2008. Anadarko committed to 50% of the rig time at a cost of almost $200 million over the contract term. The Company also executed a three-year drilling contract to secure the Belford Dolphin drillship at a cost of $460 million. It is anticipated the vessel will bereleased to Anadarko beginning in mid-2007. The Company also has multi-year contracts for drilling rigs onshore in the United States and Canada. The contract for the Belford Dolphin drillship and certain contracts for onshore United States drilling rigs are being accounted for as operating leases. In November 2005, Anadarko executed three-year contracts for the drillships Discoverer Spirit and Deepwater Millennium, for operations starting in mid-2007, at a combined cost of $985 million over the respective contract periods.

Leases     The future minimum lease payments for the Company's operating leases were $1 billion at September 30, 2005 compared to $390 million at December 31, 2004. The increase is primarily due to drilling rig commitments that qualify as operating leases.

13.  Pension Plans and Other Postretirement Benefits

       The Company has defined benefit pension plans and supplemental pension plans that are noncontributory pension plans. The Company also has a foreign pension plan which is a 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, with the retiree contributions adjusted according to the provisions of the Company's health care plans. The Company's retiree life insurance plan is noncontributory. The Company uses a December 31 measurement date for the majority of its plans.

       During the nine months ended September 30, 2005, the Company made contributions of $56 million to its funded pension plans, $4 million to its unfunded pension plans and $5 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. During the remainder of 2005, the Company expects to contribute about $2 million to its funded pension plans, $1 million to its unfunded pension plans and $2 million to its unfunded other postretirement benefit plans.

       The following table sets forth the Company's pension and other postretirement benefit cost.

	Pension Benefits						Other Benefits
	Three Months Ended						Three Months Ended
	September 30						September 30
millions	2005			2004			2005		2004
Components of net periodic benefit cost
Service cost	$	9		$	6		$	4	$	2
Interest cost		9			7			2		3
Expected return on plan assets		(9	)		(8	)		-		-
Special termination benefits		-			1			-		-
Amortization of actuarial losses and prior service cost		4			4			-		1
Net periodic benefit cost	$	13		$	10		$	6	$	6

	Pension Benefits						Other Benefits
	Nine Months Ended						Nine Months Ended
	September 30						September 30
millions	2005			2004			2005		2004
Components of net periodic benefit cost
Service cost	$	27		$	18		$	11	$	8
Interest cost		28			23			7		7
Expected return on plan assets		(27	)		(24	)		-		-
Special termination benefits		-			1			-		-
Amortization of actuarial losses and prior service cost		13			10			1		3
Net periodic benefit cost	$	41		$	28		$	19	$		18

14.  Contingencies

General     Litigation charges of $2 million and $29 million were expensed for the three and nine months ended September 30, 2005, respectively. Litigation charges of $2 million and $28 million were expensed for the three and nine months ended September 30, 2004, 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 located in Texas, California and Oklahoma. Two companies Anadarko acquired in 2000 and 2002 sold the refineries prior to being acquired by Anadarko. 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 its business as an oil and gas producer, including disputes regarding measurement, costs and expenses beyond the wellhead and basis valuations. Among such claims, 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. (the ''Gas Qui Tam case'') filed in September 2000 in the U.S. District Court for the Eastern District of Texas, Lufkin Division. This lawsuit generally alleges that the Company and 118 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 the various governmental and False Claims Act proceedings described above, 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 Civil 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. Meanwhile, the discovery process is ongoing. The court has set a trial date in 2007. Management is unable to determine a reasonable range of loss, if any, related to this matter.

Environmental Matters     In December 2003, Anadarko Gathering Company voluntarily disclosed the findings of an internal environmental audit for its facilities in Kansas to the Kansas Department of Health and Environment (KDHE). In April 2005, KDHE submitted to Anadarko a Consent Decree and Final Order (Order) alleging certain violations of the Clean Air Act. The Order included an assessment of a proposed penalty amount of $169,000. Anadarko is in discussions with the KDHE to negotiate the final penalty amount.

Other Matters     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 effect on the Company.

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 oil, natural gas, natural gas liquids (NGLs) and other products or services, the price of oil, natural gas, NGLs and other products or services, implementation of plans concerning the Bear Head liquefied natural gas facility, currency exchange rates, 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, the securities or capital markets and other factors disclosedunder "Regulatory Matters and Additional Factors Affecting Business" and "Critical Accounting Policies and Estimates" in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in the Company's 2004 Annual Report on Form 10-K. 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 and marketing of natural gas, crude oil, condensate and NGLs. The Company's major areas of operations are located in the United States, Canada and Algeria. The Company is also active in Venezuela, Qatar 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 subsidiaries.

       During 2004, Anadarko implemented an asset realignment that resulted in the divestiture of certain non-core properties in the latter half of 2004 through a series of unrelated transactions. The divestitures represented about 20% of the Company's 2004 oil and gas production. The Company used proceeds from these asset sales to reduce debt, repurchase Anadarko common stock and otherwise to have funds available for reinvestment in other strategic options.

Results for the Three and Nine Months Ended September 30, 2005

Selected Data
	Three Months Ended							Nine Months Ended
		September 30						September 30
millions except per share amounts		2005			2004			2005			2004
Financial Results
Revenues	$		1,756	$		1,562	$		4,876	$		4,465
Costs and expenses			753			815			2,211			2,303
Interest expense and other (income) expense			32			147			138			332
Income tax expense			373			199			931			630
Net income available to common stockholders	$		596	$		399	$		1,592	$		1,196
Earnings per share - diluted	$		2.51	$		1.58	$		6.68	$		4.72
Average number of common shares outstanding - diluted			238			253			238			254
Operating Results
Sales volumes (MMBOE)			39			49			119			145
Capital Resources and Liquidity
Cash flow from operating activities							$		2,875	$		2,757
Capital expenditures							$		2,407	$		2,254
MMBOE - million barrels of oil equivalent

Financial Results

Net Income     In the third quarter of 2005, Anadarko's net income available to common stockholders was $596 million or $2.51 per share (diluted). This compares to net income available to common stockholders of $399 million or $1.58 per share (diluted) for the third quarter of 2004. For the nine months ended September 30, 2005, Anadarko's net income available to common stockholders was $1.6 billion, or $6.68 per share (diluted). This compares to net income available to common stockholders of $1.2 billion, or $4.72 per share (diluted) for the same period in 2004. The increases in net income were primarily due to higher net realized commodity prices and lower expenses, partially offset by lower volumes associated with divestitures in late 2004. The increases in earnings per share were also due to lower average shares outstanding in 2005 as a result of stock repurchases in late 2004 and 2005.

Revenues
	Three Months Ended								Nine Months Ended
		September 30							September 30
millions		2005				2004			2005			2004
Gas sales	$		909		$		823	$		2,466	$		2,438
Oil and condensate sales			752				589			2,052			1,643
Natural gas liquids sales			119				123			333			319
Other sales			(24	)			27			25			65
Total	$		1,756		$		1,562	$		4,876	$		4,465

       Anadarko's total revenues for the three and nine months ended September 30, 2005 increased 12% and 9%, respectively, compared to the same periods of 2004 due to higher net realized commodity prices and higher sales volumes from core oil and gas properties, partially offset by lower volumes resulting from the divestiture of non-core properties in late 2004.

       The impact of hedges and marketing activities decreased total gas, oil and condensate revenues $110 million during the third quarter of 2005 compared to a decrease of $156 million in the same period of 2004. The favorable change of $46 million is primarily due to a decrease in oil and gas sales volumes hedged. For the third quarter of 2005, these activities resulted in lower realized natural gas prices of $0.09 per thousand cubic feet (Mcf) and lower realized oil prices of $6.63 per barrel compared to market prices. For the third quarter of 2004, these activities resulted in lower realized natural gas prices of $0.33 per Mcf and lower realized oil prices of $5.90 per barrel compared to market prices.

       The impact of hedges and marketing activities decreased total gas, oil and condensate revenues $129 million during the nine months ended September 30, 2005 compared to a decrease of $300 million in the same period of 2004. The favorable change of $171 million is primarily due to a decrease in oil and gas sales volumes hedged. For the nine months ended September 30, 2005, these activities resulted in higher realized natural gas prices of $0.07 per Mcf and lower realized oil prices of $3.54 per barrel compared to market prices. For the nine months ended September 30, 2004, these activities resulted in lower realized natural gas prices of $0.25 per Mcf and lower realized oil prices of $3.54 per barrel compared to market prices.

       The decrease in other sales for the three and nine months ended September 30, 2005 include $53 million and $59 million, respectively, related to unrealized losses on natural gas and NGLs storage related derivative contracts.

Analysis of Sales Volumes
	Three Months Ended					Nine Months Ended
		September 30				September 30
		2005		2004		2005		2004
Barrels of Oil Equivalent (MMBOE)
United States			26		34		80		98
Canada			5		7		15		23
Algeria			6		6		18		18
Other International			2		2		6		6
Total			39		49		119		145
Barrels of Oil Equivalent per Day (MBOE/d)
United States			284		374		293		362
Canada			56		80		56		81
Algeria			65		63		66		64
Other International			21		17		21		21
Total			426		534		436		528
MBOE/d - thousand barrels of oil equivalent per day

       For the three and nine months ended September 30, 2005, Anadarko's daily sales volumes decreased 20% and 17%, respectively, compared to the same periods of 2004. These decreases were primarily due to lower sales volumes in the United States and Canada as a result of divestitures of non-core properties in late 2004, representing about 25% or 130 MBOE/d of the nine months ended September 30, 2004 sales volumes. In addition, the Company estimates that combined onshore and offshore hurricane-related shut-ins and delays reduced third quarter 2005 sales volumes by 400,000 barrels of oil equivalent. These decreases were partially offset by higher volumes associated with successful drilling onshore in the United States.

Natural Gas Sales Volumes and Average Prices
	Three Months Ended							Nine Months Ended
		September 30						September 30
		2005			2004			2005			2004
United States (Bcf)			101			132			311			378
MMcf/d			1,098			1,428			1,142			1,382
Price per Mcf	$		7.16	$		4.96	$		6.36	$		5.01
Canada (Bcf)			26			35			77			108
MMcf/d			284			385			281			392
Price per Mcf	$		7.08	$		4.81	$		6.28	$		5.03
Total (Bcf)			127			167			388			486
MMcf/d			1,382			1,813			1,423			1,774
Price per Mcf	$		7.15	$		4.93	$		6.35	$		5.01
Bcf - billion cubic feet
MMcf/d - million cubic feet per day

       The Company's daily natural gas sales volumes for the third quarter of 2005 were down 24% compared to the third quarter of 2004. For the first nine months of 2005, the Company's daily natural gas sales volumes were down 20% compared to the same period of 2004. The decreases were primarily due to the impact of divestitures in the United States and Canada in late 2004, partially offset by higher volumes associated with successful drilling onshore in the mid-continent of the United States. Production of natural gas is generally not directly affected by seasonal swings in demand.

       The Company's average realized natural gas price for the three and nine months ended September 30, 2005 increased 45% and 27%, respectively, compared to the same periods in 2004. The increase in prices in 2005 is attributed to continued strong demand in North America and an active hurricane season in the Gulf of Mexico impacting supply and infrastructure. The higher prices include the impact of commodity price hedges on 23% and 22% of natural gas sales volumes, during the three and nine months ended September 30, 2005, respectively, that reduced the Company's exposure to low prices and limited participation in higher prices. As of September 30, 2005, the Company has hedged about 23% of its anticipated natural gas wellhead sales volumes for the remainder of 2005. See Energy Price Risk under Item 3 of this Form 10-Q.

Crude Oil and Condensate Sales Volumes and Average Prices
	Three Months Ended							Nine Months Ended
		September 30						September 30
		2005			2004			2005			2004
United States (MMBbls)			6			8			18			24
MBbls/d			68			92			67			88
Price per barrel	$		42.84	$		31.83	$		41.76	$		30.94
Canada (MMBbls)			1			1			2			4
MBbls/d			8			14			8			14
Price per barrel	$		53.97	$		38.86	$		48.89	$		35.63
Algeria (MMBbls)			6			6			18			18
MBbls/d			65			63			66			64
Price per barrel	$		61.18	$		38.37	$		53.58	$		34.21
Other International (MMBbls)			2			2			6			6
MBbls/d			21			17			21			21
Price per barrel	$		42.31	$		30.20	$		37.70	$		27.06
Total (MMBbls)			15			17			44			52
MBbls/d			162			186			162			187
Price per barrel	$		50.80	$		34.42	$		46.40	$		31.98
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, 2005 were down 13% compared to the same periods of 2004 primarily due to the impact of divestitures in the United States and Canada in late 2004. These decreases were partially offset by higher volumes in the United States associated with expansion of production facilities in Alaska and successful drilling in the western states. The first half of 2005 was also impacted by higher volumes associated with production startup at the Marco Polo deepwater platform in mid-2004. Production of oil usually is not affected by seasonal swings in demand.

       Anadarko's average realized crude oil price for the three and nine months ended September 30, 2005 increased 48% and 45%, respectively, compared to the same periods of 2004. These higher crude oil prices in 2005 were attributed to continued political unrest in the Middle East, increased worldwide demand and the impact of hurricanes in the Gulf of Mexico on oil production and infrastructure. These higher prices include the impact of commodity price hedges on 28% of crude oil and condensate sales volumes during the three and nine months ended September 30, 2005 that reduced the Company's exposure to low prices and limited participation in higher prices. As of September 30, 2005, the Company has hedged about 28% of its anticipated oil and condensate sales volumes for the remainder of 2005. See Energy Price Risk under Item 3 of this Form 10-Q.

Natural Gas Liquids Sales Volumes and Average Prices
	Three Months Ended							Nine Months Ended
		September 30						September 30
		2005			2004			2005			2004
Total (MMBbls)			3			4			10			12
MBbls/d			34			46			37			45
Price per barrel	$		37.61	$		29.16	$		33.07	$		25.90

       The Company's daily NGLs sales volumes for the third quarter of 2005 decreased 26% compared to the same period of 2004. For the nine months ended September 30, 2005, the Company's daily NGLs sales volumes decreased 18% compared to the same period of 2004. The decreases were primarily due to the impact of divestitures in the United States in late 2004.

       During the third quarter of 2005, the average NGLs price increased 29% compared to the same period of 2004. For the nine months ended September 30, 2005, the average NGLs price increased 28% compared to the same period of 2004. NGLs production is dependent on natural gas and NGLs prices as well as the economics of processing the natural gas to extract NGLs.

Costs and Expenses
	Three Months Ended							Nine Months Ended
		September 30						September 30
millions		2005			2004			2005			2004
Direct operating	$		131	$		177	$		398	$		498
Transportation and cost of product			75			67			217			183
General and administrative			99			98			311			269
Depreciation, depletion and amortization			334			387			991			1,092
Other taxes			101			86			281			252
Impairments related to oil and gas properties			13			-			13			9
Total	$		753	$		815	$		2,211	$		2,303

       During the third quarter of 2005, Anadarko's costs and expenses decreased 8% compared to the third quarter of 2004 due to the following factors:

- Direct operating expense was down 26% primarily due to the impact of divestitures in late 2004.

- Transportation and cost of product expense increased 12% primarily due to higher natural gas transportation and NGLs transportation costs. The $8 million increase in transportation cost was primarily due to a change in the Company's marketing strategy whereby the Company is transporting a higher percentage of its natural gas volumes to higher priced markets. These cost increases are offset by higher natural gas, NGLs and other sales revenues.

- General and administrative (G&A) expense increased slightly primarily due to an increase of $5 million in compensation, pension and other postretirement benefits expenses attributed primarily to the rising cost of attracting and retaining a highly qualified workforce and the Company's decision to provide a more performance-based compensation program to a broader base of employees. This increase also reflects the continued upward pressure on benefits expenses, including the impact of lower discount rates on estimated pension and other postretirement benefits expenses. These increases were mostly offset by a decrease in legal and consulting expenses.

- Depreciation, depletion and amortization (DD&A) expense decreased 14%. DD&A expense includes a decrease of $77 million related to lower production volumes, partially offset by an increase of $27 million primarily due to higher costs associated with finding and developing oil and gas reserves (including the transfer of excluded costs to the DD&A pool).

- Other taxes increased 17% primarily related to higher net realized commodity prices.

- Impairments of oil and gas properties in 2005 were related to other international activities.

       For the nine months ended September 30, 2005, Anadarko's costs and expenses decreased 4% compared to the same period of 2004 due to the following factors:

- Direct operating expense was down 20% primarily due to the impact of divestitures in late 2004, partially offset by an increase in operating expenses associated with production beginning from the Marco Polo platform in mid-2004.

- Transportation and cost of product expense increased 19% primarily due to a $23 million increase in natural gas transportation expenses and an $11 million increase in NGLs transportation and fractionation costs. The increase in NGLs transportation and fractionation cost was primarily due to a change in the Company's marketing strategy whereby the Company is fractionating its raw NGLs stream into the individual products in order to obtain higher sales proceeds for NGLs. These cost increases are offset by higher natural gas, NGLs and other sales revenues.

- G&A expense increased 16% primarily due to an increase of $36 million in compensation, pension and other postretirement benefits expenses. G&A expense was also impacted by higher legal and consulting fees.

- DD&A expense decreased 9%. DD&A expense includes a decrease of $192 million related to lower production volumes, partially offset by an increase of $103 million primarily due to higher costs associated with finding and developing oil and gas reserves (including the transfer of excluded costs to the DD&A pool).

- Other taxes increased 12% primarily related to higher net realized commodity prices.

- Impairments of oil and gas properties in 2005 and 2004 were related to other international activities.

Interest Expense and Other (Income) Expense

	Three Months Ended											Nine Months Ended
			September 30									September 30
millions			2005				2004				2005							2004
Interest Expense
Gross interest expense		$		67			$	88		$				204		$			264
Premium and related expenses for early retirement of debt				-				63						-					63
Capitalized interest				(17	)			(20	)					(52	)				(67	)
Net interest expense				50				131						152					260
Other (Income) Expense
Operating lease settlement				-				-						-					63
Firm transportation keep-whole contract valuation				(29	)			6						(18	)				3
Ineffectiveness of derivative financial instruments				20				5					21						2
Interest income				(6	)			(2	)					(15	)				(4	)
Foreign currency transaction (gains) losses				(1	)			(3	)					-					(5	)
Other				(2	)			10						(2	)				13
Total other (income) expense				(18	)			16						(14	)				72
Total		$		32		$		147		$				138			$		332

Interest Expense     Anadarko's gross interest expense for the three and nine months ended September 30, 2005 decreased 24% and 23%, respectively, compared to the same periods of 2004 primarily due to lower average outstanding debt. Interest expense for the three and nine months ended September 30, 2004 included $63 million of premiums and related expenses for the early retirement of debt in the third quarter of 2004. Debt has decreased $1.4 billion since June 30, 2004. For the three and nine months ended September 30, 2005, capitalized interest decreased 15% and 22%, respectively, compared to the same periods of 2004. The decrease was primarily due to lower capitalized costs that qualify for interest capitalization.

Other (Income) Expense     For the three months ended September 30, 2005, other income increased $34 million compared to the same period of 2004, primarily due to a favorable change of $35 million related to the effect of higher market values for firm transportation subject to the keep-whole agreement, a $12 million favorable change in other, primarily related to environmental remediation expense in 2004 and an increase in interest income of $4 million, partially offset by a $15 million unfavorable change related to the ineffectiveness of derivative financial instruments. For the nine months ended September 30, 2005, other expense decreased $86 million compared to the same period of 2004, primarily due to the 2004 operating lease settlement of $63, a favorable change of $21 million related to the effect of higher market values for firm transportation subject to the keep-whole agreement, a $15 million favorable change in other, primarily related to environmental remediation expense in 2004 and an increase in interest income of $11 million, partially offset by a $19 million unfavorable change related to the ineffectiveness of derivative financial instruments and a decrease in foreign currency transaction gains of $5 million. For additional information see Energy Price Risk and Foreign Currency Risk under Item 3 of this Form 10-Q.

Income Tax Expense
	Three Months Ended									Nine Months Ended
		September 30								September 30
millions except percentages		2005				2004				2005				2004
Income tax expense	$		373		$		199		$		931		$		630
Effective tax rate			38	%			33	%			37	%			34	%

       For the three and nine months ended September 30, 2005, income taxes increased 87% and 48%, respectively, compared to the same periods of 2004 primarily due to higher income before income taxes. The effective tax rates for the three and nine months ended September 30, 2005 increased from the same periods in 2004 primarily due to income taxes related to foreign operations. Variances from the 35% statutory rate are caused by income taxes related to foreign activities, state income taxes, enhanced oil recovery credits and other items. In May 2005, Anadarko's Chief Executive Officer and Board of Directors approved a domestic reinvestment plan for a $500 million repatriation of foreign earnings under the Jobs Act. The $26 million tax effect of this repatriation was recorded as current tax expense in the second quarter financial statements. The tax effect of the repatriation plan represents a non-recurring item, which increases the effective tax rate for the nine months ended September 30, 2005.

Operating Results

Exploration and Development Activities     During the third quarter of 2005, Anadarko participated in a total of 241 wells, including 199 gas wells, 40 oil wells and 2 dry holes. This compares to a total of 204 wells, including 175 gas wells, 24 oil wells and 5 dry holes during the third quarter of 2004.

       For the first nine months of 2005, Anadarko participated in a total of 669 wells, including 539 gas wells, 122 oil wells and 8 dry holes. This compares to a total of 810 wells, including 599 gas wells, 180 oil wells and 31 dry holes during the first nine months of 2004.

Marketing Strategies

       The Company's marketing department actively manages sales of its natural gas, crude oil and NGLs. The Company markets its production to customers at competitive prices, attempting to maximize realized prices while managing credit exposure. The market knowledge gained through the marketing effort is valuable to the corporate decision making process. The Company's sales of natural gas, crude oil, condensate and NGLs are generally made at the market prices of those products at the time of sale.

       The Company also purchases natural gas, crude oil and NGLs volumes for resale primarily from partners and producers near Anadarko's production. These purchases allow the Company to aggregate larger volumes and attract larger, creditworthy customers, which allows the Company to seek to maximize prices received for the Company's production. The Company sells natural gas under a variety of contracts and may also receive a service fee related to the level of reliability and service required by the customer. The Company has the marketing capability to move large volumes of gas into and out of the "daily" gas market to take advantage of any price volatility.

       The Company may also engage in trading activities for the purpose of generating profits from exposure to changes in market prices of gas, oil, condensate and NGLs. However, the Company does not engage in market-making practices nor does it trade in any non-energy-related commodities. The Company's trading risk position, typically, is a net short position that is offset by the Company's natural long position as a producer. See Energy Price Risk under Item 3 of this Form 10-Q.

       Since 2002, all segments of the energy market experienced increased scrutiny of their financial condition, liquidity and credit. This has been reflected in rating agency credit downgrades of many merchant energy trading companies. Anadarko has not experienced any material financial losses associated with credit deterioration of third-party purchasers; however, in certain situations the Company has declined to transact with some counterparties and changed its sales terms to require some counterparties to pay in advance or post letters of credit for purchases.

Capital Resources and Liquidity

Overview     Anadarko's primary source of cash during the first nine months of 2005 was cash flow from operating activities. The Company used cash flow primarily to fund its capital spending program, repurchase Anadarko common stock, increase cash and pay dividends. In addition, the Company used $170 million of cash from the 2004 divestitures to retire debt. The Company funded its capital investment programs during the first nine months of 2004 primarily through cash flow from operating activities.

Cash Flow from Operating Activities     Anadarko's cash flow from operating activities during the nine months ended September 30, 2005 was $2.9 billion compared to $2.8 billion for the same period of 2004. An increase in 2005 cash flow attributed to higher net realized commodity prices was mostly offset by lower sales volumes resulting from the 2004 divestitures.

       Fluctuations in commodity prices have been the primary reason for the Company's short-term changes in cash flow from operating activities. Anadarko holds derivative instruments to help manage commodity price risk. Sales volume changes can also impact cash flow in the short-term, but have not been as volatile as commodity prices in prior years. Sales volume decreases in 2005 associated with divestitures made in 2004 are expected to result in lower cash flow from operating activities. Anadarko's long-term cash flow from operating activities is dependent on commodity prices, reserve replacement and the level of costs and expenses required for continued operations.

Capital Expenditures     The following table shows the Company's capital expenditures by category.

		Nine Months Ended
		September 30
millions		2005			2004
Development	$		1,522	$		1,630
Exploration			489			312
Property acquisition
Development - proved			31			5
Exploration - unproved			122			57
Capitalized interest and internal costs related to exploration
and development activities			168			194
Total oil and gas			2,332			2,198
Gathering and other			75			56
Total*	$		2,407	$		2,254
* Excludes asset retirement costs and includes actual asset retirement expenditures.

       During the nine months ended September 30, 2005, Anadarko's capital spending increased 7% compared to the same period of 2004. The variances in the mix of oil and gas spending reflect the Company's available opportunities based on the near-term ranking of projects by net asset value potential.

Common Stock Repurchase Plan     The Company initiated a $2 billion stock buyback program in June 2004 under which shares were repurchased either in the open market or through privately negotiated transactions. During the nine months ended September 30, 2005, Anadarko purchased 4.9 million shares of common stock for $406 million under the program. During October 2005, the Company purchased an additional 3.2 million shares of common stock for $285 million, completing the program.

Debt    As of September 30, 2005 and December 31, 2004, Anadarko's total debt was $3.68 billion and $3.84 billion, respectively. The decrease in debt was due to the redemption of $170 million principal amount of 6.5% Notes due May 2005.

Dividends     In the first nine months of 2005 and 2004, Anadarko paid $128 million and $106 million, respectively, in dividends to its common stockholders (18 cents per share in the first, second and third quarters of 2005 and 14 cents per share in the first, second and third quarters of 2004). Anadarko has paid a dividend to its common stockholders continuously since becoming an independent company in 1986. For the nine months ended September 30, 2005 and 2004, Anadarko also paid $4 million in preferred stock dividends.

       The Company's credit agreement allows for a maximum capitalization ratio of 60% debt, exclusive of the effect of any noncash writedowns. As of September 30, 2005, Anadarko's capitalization ratio was 26% debt. Under the maximum debt capitalization ratio, retained earnings were not restricted as to the payment of dividends at September 30, 2005.

Outlook     The Company currently expects 2005 capital spending to range between $3.1 billion and $3.3 billion. The increase of $300 million from the first quarter of 2005 levels is primarily for new long-term strategic opportunities in U.S. onshore lease acquisition and delineation drilling, a coalbed methane water pipeline in Wyoming and additional deepwater Gulf of Mexico exploration and development. The Company's 2005 capital spending was determined at an investment level that is less than anticipated cash flow using recent New York Mercantile Exchange prices; therefore, net cash flow from operations in 2005 is expected to be higher than capital spending.

       Anadarko's strategy with respect to its capital program is to maintain a steady level of activity despite the volatile nature of commodity prices. This is accomplished by setting capital activity at levels that are self-funding at mid-cycle oil and gas prices. When prices exceed that level, as is currently the case, costs tend to increase as well. The cash generated in excess of the amount needed to fund the steady level of capital activity is: systematically used to build additional balance sheet strength through debt reductions; returned to shareholders through stock repurchases; or otherwise made available for reinvestment in other strategic options. Alternatively, when prices are below the Company's mid-cycle targets, Anadarko can draw upon its strengthened debt capacity to fund a steady level of capital activity.

Obligations and Commitments

Transportation Commitments     In June 2005, the Company entered into precedent agreements with a third party in order to secure delivery of natural gas from a liquefied natural gas facility Anadarko is constructing in Nova Scotia, Canada, called Bear Head, to prospective markets in eastern Canada and the northeastern United States. The third party has agreed to expand the capacity of its pipeline so it can accommodate the projected natural gas volumes from Bear Head. The precedent agreements signed by the parties establish the conditions on which the third party will proceed with design, regulatory approvals and construction of the expansion facilities, and be obligated to transport a specified volume of gas. As a condition to entering into the precedent agreements, Anadarko executed firm service agreements for transportation on the Canadian and United States portions of the pipeline. Upon satisfaction of the obligations under the precedent agreements, the initial term of the transportation agreements is 20 years.

       Based on current assumptions, Anadarko projects that annual demand charges due under the firm transportation service agreements may be in the range of $123 million to $182 million per year for the first five years from commencement of full service, potentially escalating by up to 5% in year six and 10% in year seven, exclusive of fuel and surcharges. No later than the eighth year from commencement of full service, rates under the agreements are to be redetermined based on then current conditions. The parties currently expect partial service under the agreements to commence between November 2007 and November 2008, and full service to commence between June 2008 and November 2009.

       The precedent agreements contain certain termination rights. The Company's potential reimbursement obligation under the precedent agreements increases over time as the third party incurs pre-service costs. This reimbursement obligation is expected to increase from about $8 million at December 2005 to $100 million at December 2006, up to a maximum of $215 million in May 2007.

Long-term Drilling Rig Commitments     In September 2005, Anadarko announced a plan to secure the necessary drilling rigs to execute its deepwater strategy over the next six years. A review of the Company's worldwide deepwater drilling inventory, along with the tightening deepwater rig market, led Anadarko to proceed to lock in the drilling rigs it needs to execute upon its strategy. Nearly two-thirds of the contracted rig time is intended to delineate and develop discoveries, with the remainder for high potential exploration.

       As part of the plan, Anadarko, with two other producers, signed a four-year rig-share agreement under which a third party will build and own a new semi-submersible drilling rig with a target delivery date of mid-2008. Anadarko committed to 50% of the rig time at a cost of almost $200 million over the contract term. The Company also executed a three-year drilling contract to secure the Belford Dolphin drillship at a cost of $460 million. It is anticipated the vessel will be released to Anadarko beginning in mid-2007. The Company also has multi-year contracts for drilling rigs onshore in the United States and Canada. The contract for the Belford Dolphin drillship and certain contracts for onshore United States drilling rigs are being accounted for as operating leases. In November 2005, Anadarko executed three-year contracts for the drillships Discoverer Spirit and Deepwater Millennium, for operations starting in mid-2007, at a combined cost of $985 million over the respective contract periods.

       Anadarko's current deepwater Gulf of Mexico development projects include the K2, K2 North and Genghis Khan fields in the Green Canyon area and seven natural gas fields in the eastern Gulf of Mexico. Anadarko also has working interests in several non-operated exploration wells currently in progress, including the announced Knotty Head commercial discovery, which will need delineation and development. The Company has identified multiple additional prospects throughout the deepwater Gulf of Mexico and has prospects offshore West Africa, Georgia and Gabon. The Company's expanded rig position could provide leverage into additional opportunities if further tightening of the deepwater rig market materializes.

       The Company believes these rig-contracting efforts offer compelling economics and facilitate its deepwater drilling strategy. In addition to addressing the cost side of the equation, the Company also hedged a portion of its forecasted crude oil sales for the time period covered by the rig commitments to help manage the risk of potential declines in market-based rig rates.

Operating Leases The future minimum lease payments for the Company's operating leases were $1 billion at September 30, 2005 compared to $390 million at December 31, 2004. The increase is primarily due to drilling rig commitments that qualify as operating leases.

Marketing and Trading Contracts     The following tables provide additional information as of September 30, 2005 regarding the Company's marketing and trading portfolio of physical delivery and financially settled derivative contracts and the firm transportation keep-whole agreement and related financial derivative instruments. The increase in marketing and trading liabilities is primarily due to unrealized losses of $59 million on natural gas and NGLs storage related derivative contracts.

				Firm
	Marketing			Transportation
millions	and Trading			Keep-Whole				Total
Fair value of contracts outstanding as of
December 31, 2004 - assets (liabilities)	$	16		$	(54	)	$		(38	)
Contracts realized or otherwise settled during 2005		(13	)		15				2
Fair value of new contracts when entered into during 2005		-			-				-
Other changes in fair value		(58	)		18				(40	)
Fair value of contracts outstanding as of
September 30, 2005 - assets (liabilities)	$	(55	)	$	(21	)	$		(76	)

		Fair Value of Contracts as of September 30, 2005
Assets (Liabilities) millions		Maturity less than 1 Year				Maturity 1-3 Years				Maturity 4-5 Years			Maturity in excess of 5 Years			Total
Marketing and Trading
Prices actively quoted	$		(51	)	$		(5	)	$		1		$	-	$	(55	)
Prices based on models and other valuation
methods			-				-				-			-		-
Firm Transportation Keep-Whole
Prices actively quoted	$		13		$		-		$		-		$	-	$	13
Prices based on models and other valuation
methods			-				(31	)			(3	)		-		(34	)
Total
Prices actively quoted	$		(38	)	$		(5	)	$		1		$	-	$	(42	)
Prices based on models and other valuation
methods			-				(31	)			(3	)		-		(34	)

Recent Accounting Developments     In September 2005, the Emerging Issues Task Force (EITF) concluded in Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty," that purchases and sales of inventory with the same party in the same line of business should be accounted for as nonmonetary exchanges, if entered into in contemplation of one another. Anadarko presents purchase and sale activities related to its marketing and trading activities on a net basis in the income statement. The Company does not expect the conclusion reached on EITF Issue No. 04-13 to have a material impact on the Company's consolidated financial statements.

Other Developments     Anadarko's operations in Venezuela are governed by an Operating Service Agreement (OSA) that was entered into in November 1993 between the Company and an affiliate of Petroleos de Venezuela, S.A. (PDVSA), the national oil company of Venezuela. Anadarko's partner in the OSA, Petrobras Energia Venezuela (Petrobras), acts as operator. In April 2005, the Venezuelan Ministry of Energy and Petroleum announced that all OSAs concluded by PDVSA between 1992 and 1997 will be subject to renegotiation. In addition, the Venezuelan tax authority recently announced its intention to assess a 50% hydrocarbon income tax rate, plus interest and penalties, to taxpayers operating under OSAs, for all open tax years, rather than the 34% income tax rate applicable to service companies. The Company and Petrobras recently signed a Transitory Agreement with PDVSA. Under this agreement, the parties are obligated to negotiate in good faith for the conversion of the OSA to a company in which the Company, Petrobras and PDVSA will each have an interest. PDVSA is expected to have a majority participation interest in this company. The Company cannot predict at this time the outcome of these negotiations.

       Related to these developments, PDVSA has limited the fees paid to the Company by applying a cap to the revenues with respect to the oil production from the OSA. The Company's revenues for the three and nine months ended September 30, 2005 were reduced by $6 million and $31 million, respectively, to reflect the cumulative estimated impact of the reduced fees through September 2005. The Company has recorded year to date September 2005 revenues from Venezuela of $140 million. For the year ended December 31, 2004, approximately 2% of the Company's net income and total assets were associated with operations located in Venezuela. The Company is unable to determine the impact of the current situation in Venezuela on future operating results at this time.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

       The Company's primary market risks are fluctuations in energy prices, foreign currency exchange rates and interest rates. These fluctuations can affect revenues and the cost of 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. For information regarding the Company's accounting policies related to derivatives and additional information related to the Company's derivative instruments, seeNote 1 - Summary of Significant Accounting Policies and Note 6 - Financial Instruments of the Notes to Consolidated Financial Statements under 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, NGLs and the firm transportation keep-whole agreement. Management expects energy prices to remain volatile and unpredictable. If energy prices decline significantly, revenues and cash flow would significantly decline. In addition, a noncash writedown of the Company's oil and gas properties could be required under full cost accounting rules if prices declined significantly, even if it is only for a short period of time. Below is a sensitivity analysis of the Company's commodity price related derivative instruments.

Derivative Instruments Held for Non-Trading Purposes    The Company had equity production hedges of 33 Bcf of natural gas and 21 MMBbls of crude oil as of September 30, 2005 (excluding physical delivery fixed price contracts). As of September 30, 2005, the Company had a net unrealized loss of $258 million on these derivative instruments. Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would result in an additional loss on these derivative instruments of approximately $100 million. However, this loss would be substantially offset by a gain in the value of that portion of the Company's equity production that is hedged.

Derivative Instruments Held for Trading Purposes     As of September 30, 2005, the Company had a net unrealized gain of $94 million (gains of $104 million and losses of $10 million) on derivative financial instruments entered into for trading purposes and a net unrealized loss of $149 million (losses of $173 million and gains of $24 million) on physical delivery contracts entered into for trading purposes and accounted for as derivatives. Utilizing the actual derivative contractual volumes and assuming a 10% increase in underlying commodity prices, the potential additional loss on these derivative instruments would be $8 million.

Firm Transportation Keep-Whole Agreement     A company Anadarko acquired in 2000 was a party to several long-term firm gas transportation agreements that supported its gas marketing program within its gathering, processing and marketing (GPM) business segment, which was sold in 1999 to Duke Energy Corporation (Duke). As part of the GPM disposition, Anadarko pays Duke if transportation market values fall below the fixed contract transportation rates, while Duke pays Anadarko if the transportation market values exceed the contract transportation rates (keep-whole agreement). This keep-whole agreement will be in effect until the earlier of each contract's expiration date or February 2009. The Company may periodically use derivative instruments to reduce its exposure under the keep-whole agreement to potential decreases in future transportation market values. Due to decreased liquidity, the use of derivative instruments to manage this risk is generally limited to the forward 12 months. As of September 30, 2005, other current assets included $13 million and other long-term liabilities included $34 million related to this agreement. As of December 31, 2004, accounts payable included $15 million and other long-term liabilities included $39 million related to this agreement. A 10% unfavorable change in the September 30, 2005 prices would result in an additional loss of $32 million on the keep-whole agreement. The future gain or loss from this agreement cannot be accurately predicted. For additional information related to the keep-whole agreement see Note 6 - Financial Instruments of the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

       For additional information regarding the Company's marketing and trading portfolio and the firm transportation keep-whole agreement, see Marketing Strategies under Item 2 of this Form 10-Q.

Interest Rate Risk     Anadarko is also exposed to risk resulting from changes in interest rates as a result of the Company's floating rate obligations. The Company believes the potential effect that reasonably possible near term changes in interest rates may have on interest expense or the fair value of the Company's fixed rate debt instruments is not material. The Company did not have any derivative instruments related to interest rate risk in place as of September 30, 2005.

Foreign Currency Risk     The Company has Canadian subsidiaries which use the Canadian dollar as their functional currency. The Company's other international subsidiaries use the U.S. dollar as their functional currency. To the extent that business transactions in these countries are not denominated in the respective country's functional currency, the Company is exposed to foreign currency exchange rate risk.

       A Canadian subsidiary has notes and debentures denominated in U.S. dollars. The potential foreign currency remeasurement impact on earnings from a 10% unfavorable change in the September 30, 2005 Canadian exchange rate against the U.S. dollar would be a loss of about $5 million based on the outstanding debt at September 30, 2005.

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 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, 2005.

Changes in Internal Control over Financial Reporting

       There were no changes in Anadarko's internal control over financial reporting during the quarter ended September 30, 2005 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

        See Note 14 - Contingencies of the Notes to Consolidated Financial Statements under Part I - Item 1 of this Form 10-Q.

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

       The following table sets forth information with respect to repurchases by the Company of its shares of common stock during the third quarter of 2005.

					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		1,826,683	$	88.00		1,814,500
August		235,763	$	87.12		235,000
September		300,000	$	92.70		300,000
Third Quarter 2005		2,362,446	$	88.51		2,349,500		$	285,000,000

(1)	During the third quarter of 2005, 2,349,500 shares were purchased under the Company's share repurchase programs. During the third quarter of 2005, 12,946 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 June 2004, the Company announced a stock buyback program to purchase up to $2 billion in shares of common stock. During October 2005, the Company purchased an additional 3.2 million shares of common stock for $285 million, completing the program.

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	3(b) to Form 10-Q	1-8968
	Corporation, as amended	for quarter ended
		September 30, 2004
(c)	Certificate of Amendment of Anadarko's	4.1 to Form 8-K dated	1-8968
	Restated Certificate of Incorporation	July 28, 2000
4(a)	Certificate of Designation of 5.46%	4(a) to Form 8-K dated	1-8968
	Cumulative Preferred Stock, Series B	May 6, 1998
(b)	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
(c)	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
10.1	Precedent Agreement between Maritimes &	10.1 to Form 8-K dated	1-8968
	Northeast Pipeline, LLC and Anadarko LNG	July 6, 2005
	Marketing LLC
10.2	Anadarko Guaranty of Anadarko LNG Marketing	10.2 to Form 8-K dated	1-8968
	LLC's obligations under the Service Agreement	July 6, 2005
10.3	Anadarko Guaranty of Anadarko LNG Marketing	10.3 to Form 8-K dated	1-8968
	LLC's obligations under the Precedent Agreement	July 6, 2005
10.4	Precedent Agreement between Maritimes &	10.4 to Form 8-K dated	1-8968
	Northeast Pipeline Limited Partnership and	July 6, 2005
	Anadarko Canada LNG Marketing, Corp.
10.5	Anadarko Guarantee of Anadarko Canada LNG	10.5 to Form 8-K dated	1-8968
	Marketing, Corp.'s obligations under the Service	July 6, 2005
	Agreement
10.6	Anadarko Guarantee of Anadarko Canada LNG	10.6 to Form 8-K dated	1-8968
	Marketing, Corp.'s obligations under the Precedent	July 6, 2005
	Agreement
10.7	Form of Service Agreement for Rate Schedule	10.7 to Form 8-K dated	1-8968
	MN365	July 6, 2005
10.8	Service Agreement for Toll Schedule MN365	10.8 to Form 8-K dated	1-8968
		July 6, 2005
10.9	Base Rate Agreement	10.9 to Form 8-K dated	1-8968
		July 6, 2005
10.10	Summary of Director Compensation	10.1 to Form 8-K dated	1-8968
		May 17, 2005
10.11	Summary of Material Terms of Employment -	10.1 to Form 8-K dated	1-8968
	R. A. Walker	August 11, 2005
*12	Computation of Ratios of Earnings to Fixed
	Charges and Earnings to Combined Fixed
	Charges and Preferred Stock Dividends
*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 8, 2005	By:	/s/ R. A. WALKER
		R. A. Walker - Senior Vice President,
		Finance and Chief Financial Officer