Anadarko Petroleum 10-Q 2004 Q3 Quarterly report

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, 2004
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 _____.

     The number of shares outstanding of the Company's common stock as of September 30, 2004 is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.10 per share	247,336,924

TABLE OF CONTENTS
			Page
PART I
	Item 1.	Financial Statements
		Consolidated Statements of Income for the Three and Nine Months     Ended September 30, 2004 and 2003	-
		Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003	-
		Consolidated Statements of Comprehensive Income for the Three and     Nine Months Ended September 30, 2004 and 2003	-
		Consolidated Statements of Cash Flows for the Nine Months     Ended September 30, 2004 and 2003	-
		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		2004			2003			2004			2003
Revenues
Gas sales	$		823	$		762	$		2,438	$		2,165
Oil and condensate sales			589			458			1,643			1,337
Natural gas liquids sales			123			85			319			255
Other sales			27			35			65			87
Total			1,562			1,340			4,465			3,844
Costs and Expenses
Direct operating			177			158			498			445
Transportation and cost of product			67			49			183			142
Administrative and general			98			108			269			282
Depreciation, depletion and amortization			387			341			1,092			954
Other taxes			86			70			252			216
Impairments related to oil and gas properties			-			74			9			92
Total			815			800			2,303			2,131
Operating Income			747			540			2,162			1,713
Interest Expense and Other (Income) Expense
Interest expense			131			59			260			187
Other (income) expense			16			2			72			(25	)
Total			147			61			332			162
Income Before Income Taxes			600			479			1,830			1,551
Income Tax Expense			199			203			630			601
Net Income Before Cumulative Effect of Change
in Accounting Principle	$		401	$		276	$		1,200	$		950
Preferred Stock Dividends			2			2			4			4
Net Income Available to Common Stockholders Before
Cumulative Effect of Change in Accounting Principle	$		399	$		274	$		1,196	$		946
Cumulative Effect of Change in Accounting Principle			-			-			-			47
Net Income Available to Common Stockholders	$		399	$		274	$		1,196	$		993
Per Common Share
Net income - before change in accounting principle - basic	$		1.59	$		1.09	$		4.76	$		3.79
Net income - before change in accounting principle - diluted	$		1.58	$		1.09	$		4.72	$		3.74
Change in accounting principle - basic	$		-	$		-	$		-	$		0.19
Change in accounting principle - diluted	$		-	$		-	$		-	$		0.18
Net income - basic	$		1.59	$		1.09	$		4.76	$		3.98
Net income - diluted	$		1.58	$		1.09	$		4.72	$		3.92
Dividends	$		0.14	$		0.10	$		0.42	$		0.30
Average Number of Common Shares Outstanding - Basic			250			250			252			249
Average Number of Common Shares Outstanding - Diluted			253			251			254			254
See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,					December 31,
millions	2004					2003
ASSETS
Current Assets
Cash and cash equivalents	$		154			$		62
Accounts receivable, net of allowance:
Customers			1,030					778
Others			302					326
Other current assets			184					158
Total			1,670					1,324
Properties and Equipment
Original cost (includes unproved properties of $1,762 and $2,524
as of September 30, 2004 and December 31, 2003, respectively)			28,074					26,367
Less accumulated depreciation, depletion and amortization			10,040					8,971
Net properties and equipment - based on the full cost method
of accounting for oil and gas properties			18,034					17,396
Other Assets			440					437
Goodwill			1,395					1,389
Total Assets	$		21,539			$		20,546
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable		$		1,446			$	1,222
Accrued expenses				984				493
Current debt				364				-
Total				2,794				1,715
Long-term Debt				4,120				5,058
Other Long-term Liabilities
Deferred income taxes				4,274				4,252
Other				906				922
Total				5,180				5,174
Stockholders' Equity
Preferred stock, par value $1.00 per share
(2.0 million shares authorized, 0.1 million shares issued
as of September 30, 2004 and December 31, 2003)				89				89
Common stock, par value $0.10 per share
(450.0 million shares authorized, 261.4 million and 258.2 million shares
issued as of September 30, 2004 and December 31, 2003, respectively)				26				26
Paid-in capital				5,690				5,500
Retained earnings				4,289				3,199
Treasury stock (10.8 million and 3.2 million shares as of September 30, 2004 and
December 31, 2003, respectively)				(624	)			(166	)
Deferred compensation and ESOP (1.2 million and 1.6 million shares
as of September 30, 2004 and December 31, 2003, respectively)				(44	)			(69	)
Executives and Directors Benefits Trust, at market value
(2.0 million shares as of September 30, 2004 and December 31, 2003)				(132	)			(102	)
Accumulated other comprehensive income (loss):
Unrealized loss on derivative instruments				(154	)			(120	)
Foreign currency translation adjustments				363				300
Minimum pension liability				(58	)			(58	)
Total				151				122
Total				9,445				8,599
Commitments and Contingencies				-				-
Total Liabilities and Stockholders' Equity		$		21,539			$	20,546
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		2004				2003				2004				2003
Net Income Available to Common Stockholders	$		399		$		274		$		1,196		$		993
Add: Preferred Stock Dividends			2				2				4				4
Net Income Available to Common Stockholders
Before Preferred Stock Dividends			401				276				1,200				997
Other Comprehensive Income (Loss), Net of Income Taxes
Unrealized gain (loss) on derivative instruments:
Unrealized gain (loss) during the period1			(71	)			61				(186	)			(91	)
Reclassification adjustment for loss included in net
income2			61				44				152				93
Total unrealized gain (loss) on derivative instruments			(10	)			105				(34	)			2
Foreign currency translation adjustments3			132				7				63				242
Total			122				112				29				244
Comprehensive Income	$		523		$		388		$		1,229		$		1,241
1net of income tax benefit (expense) of:	$		42		$		(36	)	$		107		$		53
2net of income tax expense of:			(35	)			(25	)			(88	)			(53	)
3net of income tax expense of:			(19	)			(2	)			(6	)			(54	)
See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Nine Months Ended
		September 30
millions		2004				2003
Cash Flow from Operating Activities
Net income before cumulative effect of change in accounting principle	$		1,200		$		950
Adjustments to reconcile net income before cumulative effect of change
in accounting principle to net cash provided by operating activities:
Depreciation, depletion and amortization			1,092				954
Deferred income taxes			71				419
Impairments related to oil and gas properties			9				92
Other noncash items			78				21
			2,450				2,436
(Increase) decrease in accounts receivable			(232	)			29
Increase (decrease) in accounts payable and accrued expenses			658				(92	)
Other items- net			(119	)			(74	)
Net cash provided by operating activities			2,757				2,299
Cash Flow from Investing Activities
Additions to properties and equipment			(2,235	)			(2,149	)
Acquisition costs, net of cash acquired			(46	)			-
Sales and retirements of properties and equipment			469				39
Net cash used in investing activities			(1,812	)			(2,110	)
Cash Flow from Financing Activities
Additions to debt			208				435
Retirements of debt			(782	)			(459	)
Increase (decrease) in accounts payable, banks			(13	)			5
Sale of future hard minerals royalty revenues			158				-
Dividends paid			(110	)			(78	)
Purchase of treasury stock			(458	)			-
Retirement of preferred stock			-				(12	)
Issuance of common stock			136				24
Net cash used in financing activities			(861	)			(85	)
Effect of Exchange Rate Changes on Cash			8				6
Net Increase in Cash and Cash Equivalents			92				110
Cash and Cash Equivalents at Beginning of Period			62				34
Cash and Cash Equivalents at End of Period	$		154		$		144
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, 2004 and December 31, 2003, the results of operations for the three and nine months ended September 30, 2004 and 2003 and cash flows for the nine months ended September 30, 2004 and 2003. 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 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     Anadarko utilizes derivative instruments in its marketing activity, to manage foreign currency risk and to manage commodity price risk associated with its equity oil and gas production. Anadarko also utilizes derivatives to manage its exposure associated with the firm transportation keep-whole agreement. All derivatives, other than those that meet the normal purchases and sales exception, are carried on the balance sheet at fair value.

       Accounting for unrealized gains and losses related to derivatives used to manage foreign currency risk and commodity price risk associated with equity oil and gas production is dependent on whether the derivative instruments have been designated and qualify as part of a hedging relationship. Derivative instruments may be designated as a hedge of exposure to changes in fair values, cash flows or foreign currencies, if certain conditions are met. If the hedged exposure is to changes in fair value, the unrealized gains and losses on the derivative instrument, as well as the associated losses and gains on the hedged item, are recognized currently in earnings. If the hedged exposure is a cash flow exposure, the effective portion of the unrealized gains and losses on the derivative instrument is reported as a component of accumulated other comprehensive income and reclassified into revenues in the same period during which the hedged transaction affects e arnings. The ineffective portion of the gains and losses, if any, is recognized currently in other (income) expense. Hedge ineffectiveness is that portion of the fair value change of the hedge that exceeds the fair value change of the hedged item. In those instances where it is probable that a forecasted transaction subject to a cash flow hedge will not occur, the unrealized gain or loss is reclassified from accumulated other comprehensive income to revenues in the current period. Unrealized gains and losses on foreign currency hedges are recorded on the basis of whether the hedge is a fair value or cash flow hedge. Unrealized gains and losses on derivative instruments that do not qualify for hedge accounting are recognized currently in revenues.

       Anadarko formally documents the relationship of each hedge to a hedged item including the risk management objective and strategy for undertaking the hedge. Each hedge is also assessed for effectiveness quarterly.

       Derivative instruments, including both physical delivery and financially settled purchase and sale contracts, used in the Company's energy marketing and trading activities and the firm transportation keep-whole agreement are accounted for under the mark-to-market accounting method. Under this method, fair value changes are recognized currently in earnings. The marketing and trading margin related to equity production is recorded to gas and oil sales. The non-equity portion of the margin is recorded to other sales. Gains and losses related to the firm transportation keep-whole agreement are recorded to other (income) expense.

       The Company's derivative instruments are generally either exchange traded or valued by reference to a commodity that is traded in a liquid 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 prices, while the fair value of the long-term portion is estimated based on historical natural gas basis prices, discounted at 10% per year. SeeNote 8.

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 equity instruments is dilutive. Diluted EPS amounts also include the net effect of the Company's convertible debentures and Zero Yield Puttable Contingent Debt Securities (ZYP-CODES) assuming the conversions occurred at the beginning of the year through the period outstanding, if including such potential common shares is dilutive. SeeNote 11.

Recent Accounting Developments     As of the end of 2003, the Financial Accounting Standards Board (FASB) was considering whether oil and gas drilling rights were subject to the classification and disclosure provisions of Statement of Financial Accounting Standards (SFAS) No. 142, "Goodwill and Other Intangible Assets." In September 2004, the FASB issued FASB Staff Position (FSP) FAS 142-2, "Application of FASB Statement No. 142, Goodwill and Other Intangible Assets to Oil and Gas Producing Entities." This FSP confirms that SFAS No. 142 did not change the balance sheet classification or disclosure requirements for drilling and mineral rights of oil and gas producing entities. Anadarko classifies the cost of oil and gas drilling and mineral rights as properties and equipment.

       In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin (SAB) No. 106 regarding the application of SFAS No. 143, "Accounting for Asset Retirement Obligations," by oil and gas producing entities that follow the full cost accounting method. SAB No. 106, effective in the fourth quarter of 2004, states that after adoption of SFAS No. 143, the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the present value of estimated future net cash flows used for the full cost ceiling test calculation. Anadarko currently includes the future cash outflows associated with settling asset retirement obligations in the present value of estimated future net cash flows and reduces capitalized oil and gas costs by the asset retirement obligation accrued on the balance sheet. The Company does not expect the adoption of SAB No. 106 in the fourth quarter of 2004 to have any impact on Anadarko's financial statements, nor does it expect adoption to have a material effect on the results of the ceiling test calculation.

2.  Stock-Based Compensation

       For options granted or modified after January 2003, the Company uses the fair value method of accounting for stock-based employee compensation expense. For options 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		2004			2003			2004			2003
Net income available to common stockholders, as reported		$	399		$	274		$	1,196			$	993
Add: Stock-based employee compensation expense included
in income, after income taxes			4			4			11				9
Deduct: Total stock-based employee compensation expense
determined under the fair value method, after income taxes			(5	)		(9	)		(15	)			(25	)
Pro forma net income available to common stockholders		$	398		$	269		$	1,192			$	977
Basic EPS - as reported		$	1.59		$	1.09		$	4.76			$	3.98
Basic EPS - pro forma		$	1.59		$	1.08		$	4.74			$	3.92
Diluted EPS - as reported		$	1.58		$	1.09		$	4.72			$	3.92
Diluted EPS - pro forma		$	1.57		$	1.07		$	4.70			$	3.87

3.  Divestitures

       In June 2004, Anadarko announced a refocused corporate strategy that includes the divestiture of certain properties. Following is a description of divestiture activity under the refocused strategy.

       During the third quarter of 2004, Anadarko entered into agreements for the sale of its Gulf of Mexico shelf properties through two transactions totaling approximately $1.3 billion. In September 2004, the Company closed on a portion of these agreements and received $325 million. The Company also completed the sale of its Canada Phase I properties for $142 million in the third quarter of 2004.

       Under full cost accounting rules, gain or loss on the sale or other disposition of oil and gas properties is not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The dispositions closed through September 2004 do not significantly alter the relationship between capitalized costs and proved reserves. Therefore, the proceeds from these transactions were recognized as an adjustment of capitalized costs in the respective cost centers.

       In October 2004, Anadarko closed on a second portion of Gulf of Mexico shelf properties and received $849 million. The Company has agreements in place to divest certain U.S. onshore properties for $958 million in cash and interests in two oil and gas fields in Wyoming. The remaining portion of the Gulf of Mexico shelf properties and the property divestitures with agreements in place are expected to close in the fourth quarter of 2004. Divestitures are recorded in the accounting period the transaction closes.

       Certain properties included in the sales transactions are subject to preferential rights of purchase. In the event preferential rights are exercised, Anadarko will sell the properties on substantially similar terms to the preferential right holders.

4.  Asset Retirement Obligations

       The majority of Anadarko's asset retirement obligations relate to the plugging and abandonment of oil and gas properties. In 2003, the Company adopted SFAS No. 143 which requires the fair value of a liability for an asset retirement obligation to be recorded in the period incurred and a corresponding increase in the carrying amount of the related long-lived asset. The related cumulative adjustment to 2003 net income was an increase of $74 million before income taxes or $47 million after income taxes, or $0.18 per share (diluted). Additionally, in 2003 the Company recorded an initial asset retirement obligation liability of $278 million and an increase to net properties and equipment and other assets of $352 million. The Company did not recalculate historical quarterly full cost ceiling test calculations in determining the cumulative adjustment to net income. The application of SFAS No. 143 did not have a material impact on the Company's deprec iation, depletion and amortization expense, net income or EPS in 2003. There was no impact on the Company's cash flow in 2003 as a result of adopting SFAS No. 143.

       The asset retirement obligations are recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.

       The following table provides a rollforward of the asset retirement obligations for the current period. Liabilities settled include, among other things, asset retirement obligations that were assumed by the purchasers of divested properties. Revisions in estimated liabilities include, among other things, revisions to estimated property lives and the timing of settling asset retirement obligations.

millions
Carrying amount of asset retirement obligations as of January 1, 2004	$	477
Liabilities incurred		15
Liabilities settled		(164	)
Accretion expense		22
Revisions in estimated liabilities		(63	)
Impact of foreign currency exchange rate changes		2
Carrying amount of asset retirement obligations as of September 30, 2004	$	289

5.  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	2004		2003
Materials and supplies	$	79	$	77
Natural gas		34		29
Crude oil and NGLs		29		19
Total	$	142	$	125

6.  Properties and Equipment

       Oil and gas properties include costs of $1.8 billion and $2.5 billion at September 30, 2004 and December 31, 2003, respectively, which were excluded from capitalized costs being amortized. These amounts represent costs associated with unproved properties and major development projects. The decrease in costs excluded is primarily due to certain unproved properties in the United States and Canada that the Company no longer intends to evaluate as a result of the refocused strategy announced in June 2004. At September 30, 2004 and December 31, 2003, the Company's investment in countries where proved reserves have not been established was $85 million and $76 million, respectively. For the first nine months of 2004 and 2003, the Company made provisions for impairments of oil and gas properties of $9 million and $92 million, respectively, related to international activities. The 2003 provisions for impairments included $68 million related to a third quarter 2003 ceiling test impairment of oil and gas properties in Qatar as a result of lower future production estimates and unsuccessful exploration activities.

       Interest expense during the third quarter of 2004 and 2003 was $88 million and $89 million, respectively. Of these amounts, the Company capitalized $20 million and $30 million during the third quarter of 2004 and 2003, respectively, as part of the cost of oil and gas properties. Interest expense during the first nine months of 2004 and 2003 was $264 million and $273 million, respectively. Of these amounts, the Company capitalized $67 million and $94 million during the first nine months of 2004 and 2003, 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 and development activities are in progress.

       Oil and gas properties include internal costs related to exploration and development activities of $41 million and $45 million capitalized during the third quarter of 2004 and 2003, respectively. For the first nine months of 2004 and 2003, the Company capitalized internal costs related to exploration and development activities of $127 million and $142 million, respectively.

7.  Debt and Interest Expense

		September 30, 2004				December 31, 2003
millions		Principal		Carrying Value		Principal		Carrying Value
Debt
Commercial Paper		$	195	$	195	$	-	$	-
Long-term Portion of Capital Lease			-		-		1		1
6.5% Notes due 2005			170		169		170		168
7.375% Debentures due 2006(1)			42		42		88		88
7% Notes due 2006(1)			51		50		174		171
5 3/8% Notes due 2007(1)			142		142		650		648
3.25% Notes due 2008			350		349		350		349
6.75% Notes due 2008(1)			46		45		116		111
7.8% Debentures due 2008(1)			8		8		11		11
7.3% Notes due 2009(2)			85		83		85		83
6 3/4% Notes due 2011			950		913		950		910
6 1/8% Notes due 2012(2)			400		395		400		395
5% Notes due 2012(2)			274		272		300		298
7.05% Debentures due 2018			114		106		114		105
Zero Yield Puttable Contingent
	Debt Securities due 2021		30		30		30		30
7.5% Debentures due 2026			112		106		112		106
7% Debentures due 2027			54		54		54		54
6.625% Debentures due 2028			17		17		17		17
7.15% Debentures due 2028			235		213		235		213
7.20% Debentures due 2029			135		135		135		135
7.95% Debentures due 2029			117		117		117		117
7 1/2% Notes due 2031			900		861		900		861
7.73% Debentures due 2096			61		61		61		61
7.5% Debentures due 2096			78		72		83		77
7 1/4% Debentures due 2096			49		49		49		49
Total debt		$	4,615	$	4,484	$	5,202	$	5,058
Less current debt					364				-
Total long-term debt				$	4,120			$	5,058
(1) A portion of this debt was retired under the Any and All Offer in September 2004.
(2) A portion of this debt was retired under the Maximum Tender Offer in October 2004.

       In September 2004, Anadarko made cash tender offers in order to acquire $1.2 billion aggregate principal amount of certain series of its outstanding debt. The tender offers consisted of two separate offers: an Any and All Offer and a Maximum Tender Offer. In September 2004, $750 million principal amount of Notes and Debentures was purchased in the Any and All Offer, which is reflected in the table above. In October 2004, an additional $455 million principal amount was purchased by the Company in the Maximum Tender Offer. The Company used proceeds from asset divestitures, bridge loans, commercial paper and cash to fund the debt reductions.

       In September 2004, the Company terminated its existing revolving credit agreement and entered into a $750 million, five-year Revolving Credit Agreement with a syndicate of 20 U.S. and Canadian lenders. Under the terms of the agreement, the Company can, under certain conditions, request an increase up to a total commitment level of $1.25 billion. The facility has a maximum 60% debt to capital covenant (not affected by noncash charges); however, there are not any material adverse change covenants in the agreement. The agreement terminates in August 2009. As of September 30, 2004, the Company had no outstanding borrowings under this agreement.

	Three Months Ended										Nine Months Ended
			September 30								September 30
millions			2004				2003				2004				2003
Interest Expense
Interest expense		$		88		$		89		$		264		$		273
Premium and related expenses for early retirement of debt(1)				63				-				63				8
Capitalized interest				(20	)			(30	)			(67	)			(94	)
Net interest expense		$		131		$		59		$		260		$		187
(1)An additional $40 million in premiums and related expenses associated with the October 2004 retirement
of debt will be reflected in fourth quarter 2004 operating results.

8.  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 Field Services, Inc. (Duke). Essentially all of the derivatives used for trading purposes have a term of less than one year, with most having a term of less than three months.

       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 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 ex pose 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. 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, 2004 and December 31, 2003, 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 accounting treatment if they qualify. Mark-to-market accounting is applied to those that do not qualify for hedge accounting.

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		2004				2003
Fair Value - Asset (Liability)
Current	$		(283	)	$		(232	)
Long-term			(36	)			(10	)
Total	$		(319	)	$		(242	)
Accumulated other comprehensive loss before income taxes	$		(244	)	$		(193	)
Accumulated other comprehensive loss after income taxes	$		(154	)	$		(122	)

       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 certain derivatives that did not qualify for hedge accounting, hedge ineffectiveness and foreign currency hedges. Net losses of $172 million ($109 million after income taxes) in the accumulated other comprehensive income balance as of September 30, 2004 are expected to be reclassified into gas and oil sales during the fourth quarter of 2004 as the hedged transactions occur.

       Below is a summary of the Company's financial derivative instruments and physical delivery sales contracts through 2005 related to its oil and gas activities as of September 30, 2004, including the hedged volumes per day and the related weighted-average prices. A substantial portion of these hedges qualify for and receive hedge accounting treatment. There are no significant cash flow hedges beyond 2005.

		Fourth
		Quarter			Annual
		2004				2005
Natural Gas
Two-Way Collars (thousand MMBtu/d)		44				26
NYMEX price per MMBtu
Ceiling sold price	$	6.43		$		5.65
Floor purchased price	$	4.29		$		3.76
Three-Way Collars (thousand MMBtu/d)		269				249
NYMEX price per MMBtu
Ceiling sold price	$	5.30		$		9.20
Floor purchased price	$	3.65		$		4.96
Floor sold price	$	2.67		$		3.97
Fixed Price (thousand MMBtu/d)		245				33
NYMEX price per MMBtu	$	3.83		$		3.46
Total (thousand MMBtu/d)		558				308
Basis Swaps (thousand MMBtu/d)		183				153
Price per MMBtu	$	(0.12	)	$		(0.18	)
Crude Oil
Two-Way Collars (MBbls/d)		3				2
NYMEX price per barrel
Ceiling sold price	$	26.32		$		26.32
Floor purchased price	$	22.00		$		22.00
Three-Way Collars (MBbls/d)		38				43
NYMEX price per barrel
Ceiling sold price	$	30.00		$		46.89
Floor purchased price	$	24.61		$		32.28
Floor sold price	$	20.13		$		27.28
Fixed Price (MBbls/d)		26				-
NYMEX price per barrel	$	27.22		$		-
Total (MBbls/d)		67				45
MMBtu - million British thermal units
MMBtu/d - million British thermal units per day
MBbls/d - thousand barrels per day

       A two-way collar is a combination of 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.

Marketing and Trading Activities     The Company's marketing and trading derivative financial instruments are accounted for on a mark-to-market basis. The fair values of these derivatives as of September 30, 2004 and December 31, 2003 are as follows:

		September 30,		December 31,
millions		2004		2003
Fair Value - Asset (Liability)
Current	$		55	$	33
Long-term			6		4
Total	$		61	$	37

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 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 the earlier of each contrac t's expiration date or 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. Net (payments to) receipts from Duke for the quarter ended September 30, 2004 and 2003 were $(4) million. Net (payments to) receipts from Duke for the nine months ended September 30, 2004 and 2003 were $(16) million and $19 million, respectively. This keep-whole agreement and any associated derivative instruments are accounted for on a mark-to-market basis.

       The fair value of the short-term portion of the firm transportation keep-whole agreement is calculated based on quoted natural gas basis prices. Basis is the difference in value between gas at various delivery points and the NYMEX gas futures contract price. Management believes that natural gas basis price 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 natural gas basis prices, discounted at 10% per year. Management also periodically evaluates the supply and demand factors (such as expected drilling activity, anticipated pipeline construction projects, expected changes in demand at pipeline delivery points, etc.) that may impact the future market value of the firm transportation capacity to determine if the estimated fair value should be adjusted. The Company recognized other expense of $6 million and $ 8 million for the quarter ended September 30, 2004 and 2003, respectively, and other expense of $3 million and other income of $10 million for the nine months ended September 30, 2004 and 2003, respectively, related to the keep-whole agreement and associated derivative instruments. As of September 30, 2004, accounts payable included $25 million and other long-term liabilities included $38 million related to the keep-whole agreement and associated derivative instruments. As of December 31, 2003, accounts payable included $27 million and other long-term liabilities included $49 million related to the keep-whole agreement and associated derivative instruments.

       Anticipated undiscounted and discounted liabilities for the firm transportation keep-whole agreement at September 30, 2004 are as follows:

millions		Undiscounted			Discounted
2004	$		9	$		9
2005			21			20
2006			19			16
2007			14			11
2008			9			6
2009			1			1
Total	$		73	$		63

       As of September 30, 2004 and December 31, 2003, the Company had no material volumes under derivative financial instrument hedges related to the firm transportation keep-whole agreement.

9.  Sale of Future Hard Minerals Royalty Revenues

       In May 2004, the Company entered into an agreement whereby it sold a portion of its future royalties associated with existing coal and trona leases to a third party for $158 million, net of transaction costs. The Company conveyed a limited-term nonparticipating royalty interest which was carved out of the Company's royalty interests that entitles the third party to receive up to $229 million in future coal and trona royalty revenue over an 11-year period. Additionally, the third party is entitled to receive 5% of the aggregate royalties earned during the first ten years of the agreement that exceed $400 million. The Company retains 100% of the aggregate royalty payment receipts between $229 million and $400 million during the term of the agreement and 95% of the aggregate royalty payment receipts that are in excess of $400 million during the first ten years of the agreement. The third party relies solely on the royalty paym ents to recover their investment and, as such, has the risk of the royalties not being sufficient to recover their investment over the term of the agreement.

       Proceeds of $155 million from this transaction have been accounted for as deferred revenues and classified as liabilities on the balance sheet. The deferred revenues will be amortized to other sales on a unit-of-revenue basis over the term of the agreement. During the three and nine months ended September 30, 2004, the Company amortized $2 million and $6 million, respectively, of deferred revenues to other sales revenues as a result of this agreement. Proceeds from the transaction are reported in financing activities in the statement of cash flows and were used primarily to repurchase shares of Anadarko common stock.

       The specified amounts that the third-party investor expects to receive, prior to the 5% of any excess described above, are shown below. These amounts and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the agreement.

millions
2004	$	11
2005		23
2006		24
2007		24
2008		24
Later years		123
Total	$	229

10.  Preferred Stock

       For the first, second and third quarters of 2004 and 2003, dividends of $13.65 per share (equivalent to $1.365 per Depositary Share) were paid to holders of preferred stock.

11.  Common Stock

       The reconciliation between basic and diluted EPS is as follows:

		Three Months Ended							Three Months Ended
		September 30, 2004							September 30, 2003
						Per Share							Per Share
	millions except per share amounts	Income		Shares		Amount		Income			Shares		Amount
Basic EPS
Net income available before change
in accounting principle		$	399		250	$	1.59	$		274		250	$	1.09
Effect of convertible debentures
and ZYP-CODES			-		1					-		-
Effect of dilutive stock options and
performance-based stock awards			-		2					-		1
Diluted EPS
Net income available before change
in accounting principle plus
assumed conversion		$	399		253	$	1.58	$		274		251	$	1.09

		Nine Months Ended							Nine Months Ended
		September 30, 2004							September 30, 2003
						Per Share							Per Share
	millions except per share amounts	Income		Shares		Amount		Income			Shares		Amount
Basic EPS
Net income available before change
in accounting principle		$	1,196		252	$	4.76	$		946		249	$	3.79
Effect of convertible debentures
and ZYP-CODES			-		-					3		4
Effect of dilutive stock options and
performance-based stock awards			-		2					-		1
Diluted EPS
Net income available before change
in accounting principle plus
assumed conversion		$	1,196		254	$	4.72	$		949		254	$	3.74

      For 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. During the three and nine months ended September 30, 2003, options for 8.5 million and 8.8 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.

       In June 2004, the Company announced a stock buyback program to purchase up to $2 billion in shares of common stock and that it intends to purchase the majority of the authorized amount in shares within a year. Shares may be repurchased either in the open market or through privately negotiated transactions. The repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. During the third quarter of 2004, the Company purchased 5.0 million shares of common stock for $308 million under the program. For the nine months ended September 30, 2004, Anadarko purchased 7.6 million shares of common stock for $458 million under 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, 2004 and December 31, 2003.

12.  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		2004			2003
Interest	$		184	$		169
Income taxes	$		26	$		89

13.  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:
2004
Revenues		$	522	$		34		$		9		$	997		$		1,562
Intersegment revenues			995			4				-			(999	)			-
Total revenues			1,517			38				9			(2	)			1,562
Income (loss) before income taxes		$	829	$		(9	)	$		8		$	(228	)	$		600
2003
Revenues		$	761	$		50		$		5		$	524		$		1,340
Intersegment revenues			522			3				-			(525	)			-
Total revenues			1,283			53				5			(1	)			1,340
Impairments related to oil and gas properties			74			-				-			-				74
Income (loss) before income taxes		$	591	$		14		$		5		$	(131	)	$		479
Nine Months Ended September 30:
2004
Revenues		$	1,952	$		113		$		30		$	2,370		$		4,465
Intersegment revenues			2,388			11				-			(2,399	)			-
Total revenues			4,340			124				30			(29	)			4,465
Impairments related to oil and gas properties			9			-				-			-				9
Income (loss) before income taxes		$	2,405	$		(2	)	$		26		$	(599	)	$		1,830
Net properties and equipment		$	16,133	$		347		$		1,194		$	360		$		18,034
Goodwill		$	1,395	$		-		$		-		$	-		$		1,395
2003
Revenues		$	2,206	$		105		$		22		$	1,511		$		3,844
Intersegment revenues			1,504			11				-			(1,515	)			-
Total revenues			3,710			116				22			(4	)			3,844
Impairments related to oil and gas properties			92			-				-			-				92
Income (loss) before income taxes		$	1,905	$		29		$		19		$	(402	)	$		1,551
Net properties and equipment		$	15,125	$		249		$		1,200		$	439		$		17,013
Goodwill		$	1,473	$		-		$		-		$	-		$		1,473

14.  Other (Income) Expense

       Other (income) expense consists of the following:

	Three Months Ended										Nine Months Ended
			September 30								September 30
millions			2004				2003				2004				2003
Operating lease settlement		$		-		$		-		$		63		$		-
Firm transportation keep-whole contract valuation				6				8				3				(10	)
Foreign currency exchange gains				(3	)			(1	)			(5	)			(15	)
Ineffectiveness of derivative financial instruments				5				(6	)			2				(3	)
Other				8				1				9				3
Total other (income) expense		$		16		$		2		$		72		$		(25	)

      The operating lease settlement in 2004 relates to the Corpus Christi West Plant Refinery (West Plant). SeeNote 17. Foreign currency exchange (gains) losses for the three and nine months ended September 30, 2004, exclude zero and $(6) million, respectively, related to the remeasurement of the Venezuelan deferred tax liability. For the three and nine months ended September 30, 2003, foreign currency exchange (gains) losses exclude zero and $8 million, respectively, related to the remeasurement of the Venezuelan deferred tax liability. These amounts are included in income tax expense.

15.  Commitments

      The future minimum lease obligations for the Company's operating leases were $414 million at September 30, 2004 compared to $398 million at December 31, 2003. The increase is primarily due to the operating lease settlement. SeeNote 17.

16.  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, 2004, the Company made contributions of $76 million to funded pension plans, $38 million to unfunded pension plans and $8 million to 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 2004, the Company expects to contribute $1 million to funded pension plans, $1 million to unfunded pension plans and $1 million to unfunded other postretirement benefit plans.

       In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Under FSP FAS 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," the Company made a one-time election to defer accounting for the effect of the Act for the year ended December 31, 2003. In May 2004, the FASB issued FSP FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," which superseded FSP FAS 106-1 and became effective in the third quarter of 2004. The Company believes that its other postretirement benefit plan benefits are actuari ally equivalent to Medicare Part D and that it is eligible for the federal subsidy for sponsors under the Act. The effect of the Act was recognized on a prospective basis beginning in the third quarter of 2004. The adoption of FSP FAS 106-2 did not materially affect the Company's consolidated financial statements.

       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	2004				2003					2004			2003
Components of net periodic benefit cost
Service cost	$		6		$	6				$		2	$	1
Interest cost			7			8						3		3
Expected return on plan assets			(8	)		(7	)					-		-
Special termination benefits			1			3						-		-
Amortization values and deferrals			4			3						1		1
Net periodic benefit cost	$		10		$	13				$		6	$	5
		Nine Months Ended						Nine Months Ended
		September 30									September 30
millions		2004			2003						2004		2003
Components of net periodic benefit cost
Service cost		$	18		$	16					$	8	$	5
Interest cost			23			25						7		7
Expected return on plan assets			(24	)		(22	)					-		-
Special termination benefits			1			3						-		-
Amortization values and deferrals			10			10						3		2
Net periodic benefit cost		$	28		$	32					$	18	$	14

17.  Contingencies

General     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 numerous claims by employees of third-party contractors alleging exposure to asbestos, silica and benzene while working at a refinery in Corpus Christi, Texas. A company Anadarko acquired by merger in 2000 sold the refinery in segments in 1987 and 1989. 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 of the Company, although results of operations and cash flow could be significantly impacted in the reporting periods in which such matters are resolved. Discussed below are several specific proceedings.

Royalty 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 styledU.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. The case was transferred to the U.S. District Court, Multi-District Litigation (MDL) Docket pending in Wyoming. 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. The MDL Panel remanded the case to the federal court in Lufkin, Texas without ruling on the motions for dismissal. The proceedings were delayed for procedural reasons as the case was remanded and a new judge was appointed; however, hearings on the Company's motions for dismissal were held in August 2004 and the Company expects a ruling by the end of 2004.

       A group of royalty owners purporting to represent Anadarko's gas royalty owners in Texas was granted class action certification styledNeinast, Russell, et al. v. Union Pacific Resources Company, et al. in December 1999, by the 21st Judicial District Court of Washington County, Texas, in connection with a gas royalty underpayment case against the Company. This certification did not constitute a review by the Court of the merits of the claims being asserted. The royalty owners' pleadings did not specify the damages being claimed, although a demand for damages in the amount of $66 million was asserted. The Company appealed the class certification order. A favorable decision from the Houston Court of Appeals decertified the class. The royalty owners did not appeal this matter to the Texas Supreme Court and the decision from the Houston Court of Appeals became final in the second quarter of 2002. In the fourth quarter of 2003, the royalty owners filed a new petition alleging that the class may properly be brought so long as "sub-class" groups are broken out. The same attorneys who filed the Neinast lawsuit as a state-wide class action also filed a lawsuit, styledHankins, Lowell F., et al. v. Union Pacific Resources Group Inc., et al., in the 112th Judicial District Court, Crockett County, Texas. The two lawsuits are substantially identical, except that the Hankins lawsuit is limited to royalty owners in Crockett and Sutton Counties. The Texas Supreme Court has reversed certification of this class; however, as with the Neinast case, the plaintiffs indicated that they would seek certification of sub-classes and continue to prosecute the claims. The Company has reached an agreement in principle to settle these cases, subject to judicial approval. The Company expects the court to approve the settlement in late 2004 or early 2005.

       A royalty owner action styledTexasOsage Royalty Pool, Inc. v. UPRG, Inc., UP Fuels, Inc., et al.was filed in January 1997 in the 335th District Court of Lee County, Texas. The case involves allegations that a company Anadarko acquired by merger in 2000, UPRG, Inc., failed to properly pay royalties due Texas Osage. In addition, the plaintiff contends that the Company failed to comply with express and implied provisions of various leases between April 1993 and the present. The Company has reached an agreement in principle to settle this case, subject to final documentation. The Company expects to finalize the settlement and disburse the funds in 2004.

       The nine months ended September 30, 2004 include charges of $27 million, before income taxes, related to royalty litigation settlement agreements.

T-Bar X Lawsuit     T-Bar X Limited Company v. Anadarko Petroleum Corporation, a case filed in the 82nd Judicial District Court of Robertson County, Texas, involves a dispute regarding a confidentiality agreement that Anadarko executed in August 1999. On January 28, 2004, based upon a jury verdict, the court entered a $145 million judgment in favor of the plaintiff as follows: $40 million in actual damages; $100 million in punitive damages; and $5 million in pre-judgment interest. In April 2004, the plaintiff voluntarily reduced the punitive damage amount to $80 million, thereby reducing the total judgment amount to $125 million. The Company believes that it has strong arguments for a reversal on appeal. Anadarko and outside counsel believe that, following appeals, it is not probable that the judgment will be affirmed. If the judgment is reversed and remanded for a new trial, Anadarko will vigorously defend itself on retrial. While the ultimat e outcome and impact of this claim on Anadarko cannot be predicted with certainty, Anadarko believes that the resolution of these proceedings will not have a material adverse effect on its consolidated financial position.

Other     The Company is subject to other legal proceedings, claims and liabilities that arise in the ordinary course of its business. In the opinion of the Company, the liability with respect to these actions will not have a material effect on the Company.

Lease Agreement     The Company, through one of its affiliates (formerly a subsidiary of Union Pacific Resources Group, Inc. or UPRG), is a party to a lease agreement for the West Plant, a refinery facility located in Corpus Christi, Texas. The initial term of the lease expired December 31, 2003, but Anadarko has renewal options extending through January 31, 2011 at fair market rental rates. On January 31, 2011, the Company has the right to purchase the West Plant at a fair market sales value computed using a defined formula. In conjunction with UPRG exiting the refinery business in 1987, the West Plant was subleased to CITGO Petroleum Corporation (CITGO) under terms substantially the same as the Company's lease, with sublease payments during any renewal period equal to the lesser of the fair market rental rates as determined in the Company's lease or $5 million. Additionally, CITGO has the option under the sublease to purchase the West Plant from the Co mpany on January 31, 2011 at a specified purchase price.

       For the renewal term, the fair market rental rates of the West Plant were to be determined by the appraisal process specified in the lease agreement. In order to resolve certain issues raised by the appraisers, the parties entered into an arbitration agreement. Through the arbitration process, issues of contractual interpretation were clarified to allow the appraisers to complete their fair market determination. Prior to the completion of the fair market rental rate determination by the appraisers, Anadarko and the lessor agreed to rental rates for the period 2004 - 2011 and a maximum purchase price at the end of the lease term. The Company estimated the purchase price to be $12.5 million less than the agreed upon maximum purchase price. Since the agreed upon rental rates exceeded the capped sublease payments from CITGO and the Company's estimated purchase price exceeded CITGO's specified purchase price in 2011, the Company recorded a liabili ty of $63 million in the first quarter of 2004. This amount represented the present value of the excess of the annual rental amounts payable to the lessor over the amounts under the sublease for 2004 - 2011 as well as the present value of the excess of the estimated purchase price payable to the lessor in 2011 over CITGO's specified purchase price.

       In September 2004, the Company and the lessor reached an agreement whereby the purchase price for the West Plant on January 31, 2011 was set and the Company agreed to purchase such on that date. The agreed upon price equals the cost used to calculate the previously recorded $63 million liability and, as a result, has no effect on third quarter 2004 income.

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. S uch statements are subject to various risks and uncertainties, and actual results could differ materially from those expressed or implied by such statements due to a number of factors in addition to those discussed elsewhere in this Form 10-Q and in the Company's other public filings, press releases and discussions with Company management. Anadarko undertakes no obligation to publicly update or revise any forward looking statements. See "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 2003 Annual Report on Form 10-K.

Overview

General       Anadarko Petroleum Corporation's primary line of business is the exploration, development, production and marketing of natural gas, crude oil, condensate and natural gas liquids (NGLs). The Company's major areas of operations are located in the United States, Canada and Algeria. Anadarko 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 finding and development 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 and its subsidiaries.

Refocused Corporate Strategy       In June 2004, Anadarko announced a refocused corporate strategy. Strategy execution involves an asset realignment that is expected to result in the divestiture of properties representing about 15% of Anadarko's year-end 2003 proved reserves and about 25% of existing oil and gas production, with after-tax proceeds expected to exceed $2.5 billion. The Company now expects after tax cash proceeds to be about $2.7 billion, including the sale of future hard minerals royalty revenues. Additionally, certain of the assets have been identified as candidates for exchange for assets that would further the Company's strategy. The Company is using proceeds from asset sales to reduce debt, repurchase Anadarko common stock under a $2 billion program authorized by the Company's Board of Directors and otherwise to have funds available for reinvestment in other strategic options.

       The strategy refocuses the Company's efforts and capital on the areas where it has consistently produced its best results; institutionalizes a process to manage the Company's assets differently; lowers the reinvestment required to maintain existing production levels; and strengthens Anadarko's financial discipline and strategic flexibility. The Company's properties are separated into two broad categories and managed to serve different roles within the overall portfolio. "Foundation" assets are those with efficient reinvestment features to hold production flat or to grow production modestly, and that generally have low underlying decline rates over a long period of time. Today, these assets are primarily onshore North America and are expected to generate significant free cash that can be reinvested into growth areas. "Growth platforms" are expected to become increasingly global in nature and currently include the Gulf of Mexico deepwater, Algeria and Qatar. Growth platform assets are expected to deliver differentiated growth rates by targeting high-potential, exploration-focused investments or new ventures that may include acquisitions as entry vehicles.

       Properties identified for divestiture under the refocused strategy are estimated to include between 325 and 350 million barrels of oil equivalent (MMBOE) of year-end 2003 proved reserves and between 115 and 125 thousand barrels of oil equivalent per day (MBOE/d) of existing production volumes. Most of the identified properties to be divested are located in the shallow waters of the Gulf of Mexico shelf, Western Canadian Sedimentary basin and the mid-continent region of the United States.

       During the third quarter of 2004, Anadarko entered into agreements for the sale of its Gulf of Mexico shelf properties through two transactions totaling approximately $1.3 billion representing an estimated 99 MMBOE of proved reserves as of year-end 2003 and net production of approximately 47 MBOE/d. In September 2004, the Company closed on a portion of these agreements and received $325 million. In October 2004, Anadarko closed on a second portion of the agreements and received $849 million. The remaining sales of these Gulf of Mexico shelf properties are expected to close in the fourth quarter of 2004. The Company also completed the sale of its Canada Phase I properties for $142 million in the third quarter of 2004 representing an estimated 10 MMBOE of proved reserves as of year-end 2003 and net production of approximately 5 MBOE/d.

       The Company has in place sale agreements representing 115 MMBOE of proved reserves located in the United States as of year-end 2003 with net production of approximately 42 MBOE/d, for proceeds of approximately $958 million and interests in two oil and gas fields in Wyoming. The Company also has sales agreements pending representing 61 MMBOE of proved reserves located in Canada as of year-end 2003 with net production of approximately 23 MBOE/d. The asset sales with agreements in place or pending are expected to close in the fourth quarter of 2004. Most of the remaining properties identified for divestiture, which are primarily located in the mid-continent region of the United States, are expected to be exchanged for assets that fit within the Company's strategy. The North American asset sales are expected to close by year-end 2004, while miscellaneous international assets are anticipated to close by the end of the first quarter of 2005.

       Certain properties included in these sale transactions are subject to preferential rights of purchase. In the event preferential rights are exercised, Anadarko will sell the properties on substantially similar terms to the preferential right holders.

       In addition, under full cost accounting rules, gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. As a result, the Company does not currently expect these divestitures to result in any material gains or losses in future results of operations. The dispositions closed through September 2004 do not significantly alter the relationship between capitalized costs and proved reserves. Therefore, these transactions were recognized as an adjustment of capitalized costs in the respective country cost centers.

Results for the Three and Nine Months Ended September 30, 2004

Selected Data
		Three Months Ended							Nine Months Ended
			September 30						September 30
millions except per share amounts			2004			2003			2004			2003
Financial Results
Revenues		$		1,562	$		1,340	$		4,465	$		3,844
Costs and expenses				815			800			2,303			2,131
Interest expense and other (income) expense				147			61			332			162
Income tax expense				199			203			630			601
Net income available to common stockholders before
	cumulative effect of change in accounting principle	$		399	$		274	$		1,196	$		946
Net income available to common stockholders		$		399	$		274	$		1,196	$		993
Earnings per share - before cumulative effect
	of change in accounting principle - diluted	$		1.58	$		1.09	$		4.72	$		3.74
Earnings per share - diluted		$		1.58	$		1.09	$		4.72	$		3.92
Operating Results
Sales volumes (MMBOE)				49			50			145			142
Capital Resources and Liquidity
Capital expenditures								$		2,254	$		2,165
Cash flow from operating activities								$		2,757	$		2,299

Financial Results

Net Income     In the third quarter of 2004, Anadarko's net income was $399 million or $1.58 per share (diluted). This compares to net income of $274 million or $1.09 per share (diluted) for the third quarter of 2003. For the nine months ended September 30, 2004, Anadarko's net income was $1.2 billion, or $4.72 per share (diluted). This compares to net income before the cumulative effect of change in accounting principle of $946 million, or $3.74 per share (diluted) for the nine months ended September 30, 2003. The increases in net income were primarily due to higher commodity prices, partially offset by higher expenses.

       In 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations," and the related cumulative adjustment in the first quarter of 2003 was an increase of $47 million after income taxes, or $0.18 per share (diluted). Including the accounting change, net income was $993 million or $3.92 per share (diluted) for the first nine months of 2003.

Revenues
	Three Months Ended							Nine Months Ended
		September 30						September 30
millions		2004			2003			2004			2003
Gas sales	$		823	$		762	$		2,438	$		2,165
Oil and condensate sales			589			458			1,643			1,337
Natural gas liquids sales			123			85			319			255
Other sales			27			35			65			87
Total	$		1,562	$		1,340	$		4,465	$		3,844

       Anadarko's total revenues for the three and nine months ended September 30, 2004 increased 17% and 16%, respectively, compared to the same periods of 2003 primarily due to higher commodity prices.

       The impact of hedges and marketing activities resulted in lower realized prices of $0.33 per thousand cubic feet (Mcf) of gas and $5.90 per barrel of oil for the third quarter of 2004 compared to market prices, which decreased revenues $156 million. For the third quarter of 2003, the impact of hedges and marketing activities resulted in lower realized prices of $0.03 per Mcf of gas and $0.99 per barrel of oil compared to market prices, which decreased revenues $21 million. For the nine months ended September 30, 2004, the impact of hedges and marketing activities resulted in lower realized prices of $0.25 per Mcf of gas and $3.54 per barrel of oil compared to market prices, which decreased revenues $300 million. For the nine months ended September 30, 2003, the impact of hedges and marketing activities resulted in lower realized prices of $0.39 per Mcf of gas and $1.36 per barrel of oil compared to market prices, which decreased revenues $257 mil lion.

Analysis of Sales Volumes
	Three Months Ended					Nine Months Ended
		September 30				September 30
		2004		2003		2004		2003
Barrels of Oil Equivalent (MMBOE)
United States			34		35		98		100
Canada			7		8		23		23
Algeria			6		5		18		14
Other International			2		2		6		5
Total			49		50		145		142
Barrels of Oil Equivalent per Day (MBOE/d)
United States			374		387		362		369
Canada			80		79		81		82
Algeria			63		51		64		52
Other International			17		24		21		19
Total			534		541		528		522

       During the third quarter of 2004, Anadarko's daily sales volumes decreased slightly compared to the third quarter of 2003 primarily due to lower sales volumes in the western United States and lower volumes in Qatar primarily due to the timing of cargo liftings, partially offset by higher sales volumes in Algeria. For the nine months ended September 30, 2004, Anadarko's daily sales volumes increased slightly compared to the nine months ended September 30, 2003. The increase was primarily due to higher volumes in Algeria due to the timing of cargo liftings and the expansion of production facilities and infrastructure, partially offset by lower sales volumes in the United States due to natural production declines, primarily in areas targeted for divestiture.

Natural Gas Sales Volumes and Average Prices
	Three Months Ended							Nine Months Ended
		September 30						September 30
		2004			2003			2004			2003
United States (Bcf)			132			136			378			378
MMcf/d			1,428			1,481			1,382			1,383
Price per Mcf	$		4.96	$		4.48	$		5.01	$		4.41
Canada (Bcf)			35			33			108			103
MMcf/d			385			357			392			379
Price per Mcf	$		4.81	$		4.65	$		5.03	$		4.83
Total (Bcf)			167			169			486			481
MMcf/d			1,813			1,838			1,774			1,762
Price per Mcf	$		4.93	$		4.51	$		5.01	$		4.50
Bcf - billion cubic feet
MMcf/d - million cubic feet per day

       The Company's daily natural gas sales volumes for the third quarter of 2004 were down slightly compared to the third quarter of 2003. For the first nine months of 2004, the Company's daily natural gas sales volumes were up slightly compared to the same period of 2003. The changes were primarily due to higher volumes associated with successful drilling in Texas, Louisiana and Canada, offset by natural production declines in the United States primarily in areas targeted for divestiture. 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, 2004 increased 9% and 11%, respectively, compared to the same periods in 2003. These higher prices include commodity price hedges on 32% and 36% of natural gas sales volumes during the three and nine months ended September 30, 2004, respectively, that reduced the Company's exposure to low prices and limited participation in higher prices. As of September 30, 2004, the Company has hedged about 33% of its anticipated natural gas wellhead sales volumes for the remainder of 2004. SeeDerivative Instruments 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
		2004			2003			2004			2003
United States (MMBbls)			8			8			24			26
MBbls/d			92			97			88			96
Price per barrel	$		31.83	$		26.34	$		30.94	$		26.45
Canada (MMBbls)			1			2			4			5
MBbls/d			14			17			14			17
Price per barrel	$		38.86	$		26.43	$		35.63	$		27.56
Algeria (MMBbls)			6			5			18			14
MBbls/d			63			51			64			52
Price per barrel	$		38.37	$		27.66	$		34.21	$		28.06
Other International (MMBbls)			2			2			6			5
MBbls/d			17			24			21			19
Price per barrel	$		30.20	$		23.68	$		27.06	$		22.94
Total (MMBbls)			17			17			52			50
MBbls/d			186			189			187			184
Price per barrel	$		34.42	$		26.36	$		31.98	$		26.64
MMBbls - million barrels
MBbls/d - thousand barrels per day

       Anadarko's daily crude oil and condensate sales volumes for the third quarter of 2004 were down 2% compared to the third quarter of 2003 primarily due to slightly lower volumes from onshore United States, Canada and Qatar, partially offset by higher volumes in Algeria and offshore United States due to production startup at the Marco Polo deepwater platform. For the nine months ended September 30, 2004, daily crude oil and condensate sales volumes were up 2% compared to the same period of 2003 primarily due to higher daily volumes in Algeria partially offset by lower volumes in Texas and Louisiana. Production of oil is not usually affected by seasonal swings in demand.

       Anadarko's average realized crude oil prices for the three and nine months ended September 30, 2004 increased 31% and 20%, respectively, compared to the same periods of 2003. These higher prices include commodity price hedges on 36% of crude oil and condensate sales volumes during the three and nine months ended September 30, 2004 that reduced the Company's exposure to low prices and limited participation in higher prices. As of September 30, 2004, the Company has hedged about 37% of its anticipated oil and condensate sales volumes for the remainder of 2004. SeeDerivative Instruments 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
		2004			2003			2004			2003
Total (MMBbls)			4			4			12			12
MBbls/d			46			46			45			44
Price per barrel	$		29.16	$		20.36	$		25.90	$		21.10

       The Company's daily NGLs sales volumes for the third quarter of 2004 were flat compared to the same period of 2003. For the nine months ended September 30, 2004, the Company's daily NGLs sales volumes increased slightly compared to the same period of 2003. During the third quarter of 2004, average NGLs prices increased 43% compared to the same period of 2003. For the nine months ended September 30, 2004, average NGLs prices increased 23% compared to the same period of 2003. NGLs production is dependent on natural gas prices and the economics of processing the natural gas to extract NGLs.

Costs and Expenses
	Three Months Ended							Nine Months Ended
		September 30						September 30
millions		2004			2003			2004			2003
Direct operating	$		177	$		158	$		498	$		445
Transportation and cost of product			67			49			183			142
Administrative and general			98			108			269			282
Depreciation, depletion and amortization			387			341			1,092			954
Other taxes			86			70			252			216
Impairments related to oil and gas properties			-			74			9			92
Total	$		815	$		800	$		2,303	$		2,131

       During the third quarter of 2004, Anadarko's costs and expenses increased 2% compared to the third quarter of 2003 due to the following factors:

- Direct operating expense was up 12%. The third quarter of 2004 includes $11 million in severance and other costs related to 2004 divestitures and a $9 million increase in offshore United States operating expenses primarily due to production beginning from the Marco Polo platform.

- Transportation and cost of product expense increased 37%. The third quarter of 2004 includes a $10 million increase in marketing transportation expense and a $7 million increase in oil and gas transportation expense primarily due to higher transportation rates.

- Administrative and general (A&G) expense decreased 9%. The third quarter of 2004 includes $9 million in severance and other costs related to 2004 divestitures and reorganization efforts. The third quarter of 2003 includes $33 million in restructuring costs related to the cost reduction plan implemented in July 2003. Excluding the costs associated with 2004 divestitures and reorganization and the 2003 restructuring costs, A&G expense increased 19% due to an increase in employee benefits expenses, an increase in litigation costs and a slight increase in contract labor costs.

- Depreciation, depletion and amortization (DD&A) expense increased 13%. DD&A expense increases include about $47 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) and a $3 million increase in depreciation of general properties and asset retirement obligation accretion expense, partially offset by a decrease of $4 million related to lower production volumes.

- Other taxes increased 23% primarily due to higher commodity prices in 2004.

- Impairments of oil and gas properties in 2003 were due to a $68 million ceiling test impairment for Qatar as a result of lower future production estimates and a $6 million impairment related to other international activities.

       For the nine months ended September 30, 2004, Anadarko's costs and expenses increased 8% compared to the same period of 2003 due to the following factors:

- Direct operating expense was up 12%. The nine months ended September 30, 2004 include $11 million in severance and other costs related to 2004 divestiture and reorganization efforts. Excluding these costs, direct operating expenses in the United States increased $27 million primarily due to higher enhanced oil recovery activity in the western states, production beginning in mid-2004 at the Marco Polo platform and the acquisition of producing properties in mid-2003 in the Gulf of Mexico. Direct operating expenses increased $9 million in Canada due to higher Canadian exchange rates and $6 million in Algeria primarily due to higher volumes.

- Transportation and cost of product expense increased 29%. The nine months ended September 30, 2004 include a $22 million increase in oil and gas transportation expense and a $22 million increase in marketing transportation expense primarily due to higher transportation rates and slightly higher volumes.

- A&G expense decreased 5%. The first nine months of 2004 include $19 million in severance and other costs related to 2004 divestitures and reorganization efforts. The first nine months of 2003 include $33 million in restructuring costs related to the cost reduction plan implemented in July 2003. Excluding the costs associated with 2004 divestitures and reorganization and the 2003 restructuring costs, A&G expense was essentially flat.

- DD&A expense increased 14%. DD&A expense increases include about $110 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), $15 million related to higher production volumes and $13 million due to asset retirement obligation accretion expense and higher depreciation of general properties.

- Other taxes increased 17% primarily due to higher commodity prices in 2004.

- Impairments of oil and gas properties in 2004 were related to international activities. Impairments in 2003 were due to a $68 million ceiling test impairment for Qatar as a result of lower future production estimates and $24 million related to other international activities.

Interest Expense and Other (Income) Expense

	Three Months Ended											Nine Months Ended
			September 30									September 30
millions			2004					2003				2004				2003
Interest Expense
Interest expense		$		88			$		89		$		264		$		273
Premium and related expenses for early retirement of debt				63					-				63				8
Capitalized interest				(20	)				(30	)			(67	)			(94	)
Net interest expense				131					59				260				187
Other (Income) Expense
Operating lease settlement				-					-				63				-
Firm transportation keep-whole contract valuation				6					8				3				(10	)
Foreign currency exchange gains				(3	)				(1	)			(5	)			(15	)
Ineffectiveness of derivative financial instruments				5					(6	)			2				(3	)
Other				8					1				9				3
Total other (income) expense				16					2				72				(25	)
Total		$		147		$			61		$		332		$		162

Interest Expense     Anadarko's interest expense for the three and nine months ended September 30, 2004 included $63 million of premiums and related expenses for the 2004 early retirement of debt. An additional $40 million in premiums and related expenses associated with the October 2004 retirement of debt will be reflected in fourth quarter 2004 operating results. SeeDebt. Excluding the debt retirement expenses, interest expense decreased slightly during the three and nine months ended September 30, 2004, compared to the same periods of 2003 due to slightly lower average outstanding debt. Capitalized interest decreased by 33% and 29%, respectively, compared to the same periods of 2003. The decreases were primarily due to lower capitalized costs that qualify for interest capitalization.

Other (Income) Expense     For the third quarter of 2004, the Company had other expense of $16 million compared to other expense of $2 million for the same period of 2003. The unfavorable change of $14 million was primarily due to an $11 million unfavorable change for ineffectiveness of derivative financial instruments and a $7 million increase in other expenses primarily related to environmental remediation expense, partially offset by a $2 million favorable increase related to the effect of higher market values for firm transportation subject to the keep-whole agreement and a $2 million favorable change in foreign currency exchange gains.

       For the nine months ended September 30, 2004, the Company had other expense of $72 million compared to other income of $25 million for the same period of 2003. The unfavorable change of $97 million was primarily due to a $63 million loss in the first quarter of 2004 related to an operating lease settlement for the Corpus Christi West Plant Refinery, a $13 million unfavorable change related to the effect of lower market values for firm transportation subject to the keep-whole agreement, a $10 million unfavorable change primarily due to a decrease in Canadian foreign currency exchange gains, a $5 million unfavorable change for ineffectiveness of derivative financial instruments and a $6 million increase in other expenses primarily related to environmental remediation expense. For additional information seeNote 17 - Contingencies of theNotes to Consolidated Financial Statement s under Item 1 of this Form 10-Q andDerivative InstrumentsandForeign Currency Risk under Item 3 of this Form 10-Q.

Income Tax Expense
	Three Months Ended									Nine Months Ended
		September 30								September 30
millions		2004				2003				2004				2003
Income tax expense	$		199		$		203		$		630		$		601
Effective tax rate			33	%			42	%			34	%			39	%

      For the three months ended September 30, 2004, income tax expense was essentially flat compared to the same period of 2003. For the nine months ended September 30, 2004, income tax expense increased 5% compared to the same period of 2003. The increase was primarily due to higher income before income taxes, partially offset by the effect of the reduction in the Alberta provincial tax rate during 2004, credits and other items. The effective tax rates for the three and nine months ended in 2004 decreased from the same periods in 2003 primarily due to increased utilization of credits, a reduction in the Canadian income tax rates and other items. For the three and nine months ended in 2004, variances from the 35% statutory rate are caused by income taxes related to foreign activities including the reduction in the Alberta provincial tax rate, state income taxes, credits and other items.

      Current tax expense related to the estimated taxable gains from the 2004 divestitures was recorded during the third quarter of 2004 with a corresponding reduction to deferred tax expense. As a result, total income taxes and the effective tax rate for the three and nine months ended September 30, 2004 were not impacted by the anticipated divestitures.

Operating Results

Exploration and Development Activities     During the third quarter of 2004, Anadarko participated in a total of 204 wells, including 175 gas wells, 24 oil wells and 5 dry holes. This compares to a total of 289 wells, including 180 gas wells, 99 oil wells and 10 dry holes during the third quarter of 2003.

      For the first nine months of 2004, Anadarko participated in a total of 810 wells, including 599 gas wells, 180 oil wells and 31 dry holes. This compares to a total of 866 wells, including 562 gas wells, 261 oil wells and 43 dry holes during the first nine months of 2003.

Proved Reserves     The Company has previously disclosed that less than 6% of total worldwide proved reserves are located in offshore fields in which reserve booking is supported by conclusive formation tests rather than actual production tests (flow tests). In April 2004, the Securities and Exchange Commission (SEC) notified the Company that it does not object to classifying reserves as proved undeveloped in the deepwater Gulf of Mexico without a flow test, if they are fully supported by each of the following sources of information: open-hole logs, core samples, seismic surveys and wire line sampling. All of Anadarko's reserves in the deepwater Gulf of Mexico are supported by each of these four data sources or a flow test.

Marketing Strategies

Overview     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, maximizing 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. Therefore, even though the Company sells significant volumes to major purchasers, the Company believes other purchasers would be willing to buy the Company's natural gas, crude oil, condensate and NGLs at comparable market prices.

       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 in turn enhance the value of 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. Essentially all of the Company's trading transactions have a term of less than one year and most are less than three months. SeeDerivative Instruments 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.

Marketing and Trading Contracts     The following tables provide additional information regarding the Company's marketing and trading portfolio of physical and derivative contracts and the firm transportation keep-whole agreement and related derivatives as of September 30, 2004. The Company records income or loss on these activities using mark-to-market accounting.

				Firm
	Marketing			Transportation
millions	and Trading			Keep-Whole			Total
Fair value of contracts outstanding as of
December 31, 2003 - assets (liabilities)	$	6		$	(76	)	$	(70	)
Contracts realized or otherwise settled during 2004		(4	)		16			12
Fair value of new contracts when entered into during 2004		1			-			1
Other changes in fair value		(3	)		(3	)		(6	)
Fair value of contracts outstanding as of
September 30, 2004 - assets (liabilities)	$	-		$	(63	)	$	(63	)

		Fair Value of Contracts as of September 30, 2004
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	$		-		$		(1	)	$		1		$	-	$	-
Prices based on models and other valuation
methods			-				-				-			-		-
Firm Transportation Keep-Whole
Prices actively quoted	$		(25	)	$		-		$		-		$	-	$	(25	)
Prices based on models and other valuation
methods			-				(29	)			(9	)		-		(38	)
Total
Prices actively quoted	$		(25	)	$		(1	)	$		1		$	-	$	(25	)
Prices based on models and other valuation
methods			-				(29	)			(9	)		-		(38	)

Capital Resources and Liquidity

General     Anadarko's cash flow from operating activities during the nine months ended September 30, 2004 was $2.8 billion compared to $2.3 billion for the same period of 2003. The increase in 2004 cash flow is attributed primarily to higher commodity prices and slightly higher sales volumes, partially offset by higher expenses. 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 the past. As divestitures are made pursuant to the refocused strategy, any related decrease in sales volumes is 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 replacem ent and the level of costs and expenses required for continued operations. The Company's goals include continuing to find oil and gas reserves at competitive prices, managing commodity price risk and keeping operating costs at efficient levels.

Sale of Future Hard Minerals Royalty Revenues     In the second quarter of 2004, the Company entered into an agreement whereby it sold a portion of its future royalties associated with existing coal and trona leases to a third party for $158 million, net of transaction costs. The Company conveyed a limited-term nonparticipating royalty interest which was carved out of the Company's royalty interests that entitles the third party to receive up to $229 million in future coal and trona royalty revenue over an 11-year period. Additionally, the third party is entitled to receive 5% of the aggregate royalties earned during the first ten years of the agreement that exceed $400 million. The Company retains 100% of the aggregate royalty payment receipts between $229 million and $400 million during the term of the agreement and 95% of the aggregate royalty payment receipts that are in excess of $400 million during the first ten years of the agreement. For additional information seeNote 9 - Sale of Future Hard Minerals Royalty Revenues of theNotes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Capital Expenditures     The Company funded its capital investment programs for the first nine months of 2004 and 2003 primarily through cash flow. The following table shows the Company's capital expenditures by category.

			Nine Months Ended
			September 30
millions			2004			2003
Development		$		1,630	$		1,169
Exploration				312			396
Property acquisitions
	Development			5			209
	Exploration			57			103
Capitalized interest and internal costs related to exploration
and development activities				194			236
Total oil and gas				2,198			2,113
Gathering and other				56			52
Total*		$		2,254	$		2,165
* Excludes asset retirement costs and includes actual asset retirement expenditures.

       During the nine months ended September 30, 2004, Anadarko's capital spending increased 4% compared to the same period of 2003. 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. The acquisitions in 2004 primarily relate to exploratory non-producing leases and the acquisitions in 2003 primarily relate to the acquisition of producing properties in the Gulf of Mexico and exploratory non-producing leases.

Debt     At September 30, 2004 and December 31, 2003, Anadarko's total debt was $4.5 billion and $5.1 billion, respectively. During the third quarter of 2004, Anadarko made cash tender offers in order to acquire $1.2 billion aggregate principal amount of its outstanding debt. In September and October 2004, $750 million and $455 million principal amount, respectively, of debt was purchased by the Company. The Company used proceeds from asset divestitures, bridge loans, commercial paper and cash to fund the debt reductions.

       The Company also terminated its existing revolving credit agreement and entered into a $750 million, five-year Revolving Credit Agreement with a syndicate of 20 U.S. and Canadian lenders in September 2004. Under the terms of the agreement, the Company can, under certain conditions, request an increase up to a total commitment level of $1.25 billion. The facility has a maximum 60% debt to capital covenant (not affected by noncash charges); however, there are not any material adverse change covenants in the agreement. The agreement terminates in August 2009. As of September 30, 2004, the Company had no outstanding borrowings under this agreement.

Common Stock Repurchase Plan     In June 2004, in conjunction with the refocused strategy, the Company announced a stock buyback program to purchase up to $2 billion in shares of common stock and that it intends to purchase the majority of the authorized amount within a year. Shares may be repurchased either in the open market or through privately negotiated transactions. It is the Company's intent to purchase the shares as targeted divestiture proceeds and excess cash flow are realized and as debt less cash (net debt) per barrel of oil equivalent targets are achieved and maintained. During the nine months ended September 30, 2004, Anadarko purchased 7.6 million shares of common stock for $458 million under the program. During October 2004, Anadarko purchased an additional 1.4 million shares of common stock for $94 million under the program.

Dividends     In the first nine months of 2004 and 2003, Anadarko paid $106 million and $74 million, respectively, in dividends to its common stockholders (14 cents per share in the first, second and third quarters of 2004 and 10 cents per share in the first, second and third quarters of 2003). Anadarko has paid a dividend to its common stockholders continuously since becoming an independent company in 1986. For the nine months ended September 30, 2004 and 2003, 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, 2004, Anadarko's capitalization ratio was 32% debt. Under the maximum debt capitalization ratio, retained earnings were not restricted as to the payment of dividends at September 30, 2004. The amount of future common stock dividends will depend on earnings, financial conditions, capital requirements and other factors, and will be determined by the Board of Directors on a quarterly basis.

Outlook     The Company expects 2004 capital spending to range between $2.8 billion and $3.0 billion. Cash flow from operating activities in 2004 is expected to be sufficient to fund capital spending. Additional borrowings are not anticipated in 2004. The Company's 2004 capital spending noted above was determined at an investment level that is less than cash flow using recent New York Mercantile Exchange prices. The Company expects steady funding of the capital program regardless of oil and gas price volatility. Anadarko's refocused strategy is designed to enable a capital program that is self-funding at mid-cycle oil and gas prices. When prices exceed mid-cycle levels, as is currently the case, the excess cash would be systematically used to build additional balance sheet strength through debt reductions, returned to shareholders through stock repurchases, and otherwise be made available for reinvestment in other strategic options. Alternatively, when pric es are below the Company's mid-cycle targets, Anadarko could draw upon its strengthened debt capacity to fund a steady level of activity.

Recent Accounting Developments     In September 2004, the SEC issued Staff Accounting Bulletin (SAB) No. 106 regarding the application of SFAS No. 143 by oil and gas producing entities that follow the full cost accounting method. SAB No. 106, effective in the fourth quarter of 2004, states that after adoption of SFAS No. 143, the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the present value of estimated future net cash flows used for the full cost ceiling test calculation. Anadarko currently includes the future cash outflows associated with settling asset retirement obligations in the present value of estimated future net cash flows and reduces capitalized oil and gas costs by the asset retirement obligation accrued on the balance sheet. The Company does not expect the adoption of SAB No. 106 in the fourth quarter of 2004 to have any impact on Anadarko's fin ancial statements, nor does it expect adoption to have a material effect on the results of the ceiling test calculation.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Derivative Instruments     Anadarko's derivative instruments currently are comprised of futures, swaps and options contracts. The volume of derivative instruments utilized by the Company to hedge its market price risk and in its energy trading operation can vary during the year within the boundaries of its established risk management policy guidelines. 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 andNote 8 - Financial Instruments of theNotes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Derivative Instruments Held for Non-Trading Purposes     The Company had equity production hedges of 129 Bcf of natural gas and 23 MMBbls of crude oil as of September 30, 2004 (excluding physical delivery fixed price contracts). As of September 30, 2004, the Company had a net unrealized loss of $319 million on these derivative instruments. Utilizing the actual derivative contractual volumes, a 10% increase in commodity prices would result in an additional loss on these derivative instruments of approximately $118 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, 2004, the Company had a net unrealized gain of $61 million (gains of $62 million and losses of $1 million) on derivative financial instruments entered into for trading purposes and a net unrealized loss of $61 million (losses of $66 million and gains of $5 million) on derivative physical delivery contracts entered into for trading purposes. Utilizing the actual derivative contractual volumes and assuming a 10% increase in underlying commodity prices, the potential additional loss on the derivative instruments would be approximately $2 million.

Firm Transportation Keep-Whole Agreement     A companyAnadarko 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 Field Services, Inc. (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, 2004, accounts payable included $25 million and other long-term liabilities included $38 million related to this agreement. As of December 31, 2003, accounts payable included $27 million and other long-term liabilities included $49 million related to this agreement. A 10% unfavorable change in the September 30, 2004 prices on the short-term portion of the keep-whole agreement would result in an additional loss of $9 million. The future gain or loss from this agreement cannot be accurately predicted. For additional information related to the keep-whole agreement seeNote 8 - Financial Instruments of theNotes 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, seeMarketing 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 debt. The Company believes the potential effect that reasonably possible near term changes in interest rates may have on the fair value of the Company's various debt instruments is not material.

Foreign Currency Risk     The Company's Canadian oil and gas subsidiaries 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 re-measurement impact on earnings from a 10% increase in the September 30, 2004 Canadian exchange rate would be about $15 million based on the outstanding debt at September 30, 2004.

Item 4.  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, 2004. In addition, there has been no significant change in the Company's internal control over financial reporting during the quarter ended September 30, 2004 that has materially affected, or is reasonably likely to materially affect the Company's internal control over financial reporting.

PART II.   OTHER INFORMATION

Item 1.  Legal Proceedings

        SeeNote 17 - Contingencies of theNotes 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 2004.

					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		20,089	$	59.39		-
August		1,326,587	$	57.71		1,325,000
September		3,687,911	$	62.67		3,685,100
Third Quarter 2004		5,034,587	$	61.35		5,010,100		$	1,542,000,000

(1)	During the third quarter of 2004, 5,010,100 shares were repurchased under the Company's share repurchase programs. During the third quarter of 2004, 24,487 shares were related to restricted stock cancelled by the Company for the payment of withholding taxes due on restricted stock that vested under various employee restricted stock plans.
(2)	In June 2004, the Company announced a stock buyback program to purchase up to $2 billion in shares of common stock and that it is the Company's intent to purchase the majority of the authorized amount in shares within a year. However, the repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time.

Item 6.  Exhibits

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

Exhibit				Original Filed	File
Number			Description	Exhibit	Number
3	(a)		Restated Certificate of Incorporation	4(a) to Form S-3 dated	333-60496
			of Anadarko Petroleum Corporation,	May 9, 2001
			dated August 28, 1986
*	(b)		By-laws of Anadarko Petroleum
			Corporation, as amended
	(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	(b)(i)		Performance Share Agreement	10(b) to Form 10-Q	1-8968
				for quarter ended
				March 31, 2004
	*	(ii)	Anadarko Petroleum Corporation
			Deferred Compensation Plan
*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 5, 2004	By:	/s/ JAMES R. LARSON
		James R. Larson - Senior Vice President,
		Finance and Chief Financial Officer