Anadarko Petroleum 10Q 2004 Q2 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 June 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 June 30, 2004 is shown below:


Title of Class	Number of Shares Outstanding

Common Stock, par value $0.10 per share	250,212,962

TABLE OF CONTENTS


			Page
PART I

	Item 1.	Financial Statements

		Consolidated Statements of Income for the Three and Six Months Ended June 30, 2004 and 2003	-

		Consolidated Balance Sheets as of June 30, 2004 and December 31, 2003	-

		Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2004 and 2003	-

		Consolidated Statements of Cash Flows for the Six Months Ended June 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.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities	-

	Item 4.	Submission of Matters to a Vote of Security Holders	-

	Item 6.	Exhibits and Reports on Form 8-K	-

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		Three Months Ended							Six Months Ended
		June 30							June 30

millions except per share amounts		2004				2003			2004			2003

Revenues
Gas sales	$		843		$		697	$		1,615	$		1,403
Oil and condensate sales			503				434			1,054			879
Natural gas liquids sales			93				85			196			170
Other sales			4				33			38			52

Total			1,443				1,249			2,903			2,504


Costs and Expenses
Direct operating			163				151			321			287
Transportation and cost of product			59				53			116			93
Administrative and general			92				86			171			174
Depreciation, depletion and amortization			357				323			705			613
Other taxes			85				71			166			146
Impairments related to oil and gas properties			-				13			9			18

Total			756				697			1,488			1,331


Operating Income			687				552			1,415			1,173

Interest Expense and Other (Income) Expense
Interest expense			66				68			129			128
Other (income) expense			(4	)			12			56			(27	)

Total			62				80			185			101


Income Before Income Taxes			625				472			1,230			1,072

Income Tax Expense			219				170			431			398


Net Income Before Cumulative Effect of Change
in Accounting Principle	$		406		$		302	$		799	$		674


Preferred Stock Dividends			1				1			2			2


Net Income Available to Common Stockholders Before
Cumulative Effect of Change in Accounting Principle	$		405		$		301	$		797	$		672


Cumulative Effect of Change in Accounting Principle			-				-			-			47


Net Income Available to Common Stockholders	$		405		$		301	$		797	$		719


Per Common Share
Net income - before change in accounting principle - basic	$		1.60		$		1.21	$		3.16	$		2.70
Net income - before change in accounting principle - diluted	$		1.59		$		1.20	$		3.14	$		2.65

Change in accounting principle - basic	$		-		$		-	$		-	$		0.19
Change in accounting principle - diluted	$		-		$		-	$		-	$		0.18

Net income - basic	$		1.60		$		1.21	$		3.16	$		2.89
Net income - diluted	$		1.59		$		1.20	$		3.14	$		2.83

Dividends	$		0.14		$		0.10	$		0.28	$		0.20

Average Number of Common Shares Outstanding - Basic			252				250			252			249

Average Number of Common Shares Outstanding - Diluted			254				252			254			255


See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,				December 31,
millions	2004				2003

ASSETS
Current Assets
Cash and cash equivalents	$		309		$		62
Accounts receivable, net of allowance:
Customers			959				778
Others			290				326
Other current assets			158				158


Total			1,716				1,324


Properties and Equipment
Original cost (includes unproved properties of $1,767 and $2,524
as of June 30, 2004 and December 31, 2003, respectively)			27,609				26,367
Less accumulated depreciation, depletion and amortization			9,543				8,971


Net properties and equipment - based on the full cost method
of accounting for oil and gas properties			18,066				17,396


Other Assets			443				437


Goodwill			1,378				1,389


Total Assets	$		21,603		$		20,546



LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable		$	1,309			$	1,222
Accrued expenses			567				493
Current portion, notes and debentures			168				-


Total			2,044				1,715


Long-term Debt			4,895				5,058


Other Long-term Liabilities
Deferred income taxes			4,437				4,252
Other			1,076				922


Total			5,513				5,174


Stockholders' Equity
Preferred stock, par value $1.00 per share
(2.0 million shares authorized, 0.1 million shares issued
as of June 30, 2004 and December 31, 2003)			89				89
Common stock, par value $0.10 per share
(450.0 million shares authorized, 259.3 million and 258.2 million shares
issued as of June 30, 2004 and December 31, 2003, respectively)			26				26
Paid-in capital			5,565				5,500
Retained earnings			3,925				3,199
Treasury stock (5.8 million and 3.2 million shares as of June 30, 2004 and
December 31, 2003, respectively)			(317	)			(166	)
Deferred compensation and ESOP (1.3 million and 1.6 million shares
as of June 30, 2004 and December 31, 2003, respectively)			(49	)			(69	)
Executives and Directors Benefits Trust, at market value
(2.0 million shares as of June 30, 2004 and December 31, 2003)			(117	)			(102	)
Accumulated other comprehensive income (loss):
Unrealized loss on derivative instruments			(144	)			(120	)
Foreign currency translation adjustments			231				300
Minimum pension liability			(58	)			(58	)

Total			29				122


Total			9,151				8,599


Commitments and Contingencies			-				-


Total Liabilities and Stockholders' Equity		$	21,603			$	20,546

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended									Six Months Ended
	June 30										June 30

millions		2004				2003					2004				2003


Net Income Available to Common Stockholders	$		405		$		301		$			797		$		719

Add: Preferred Stock Dividends			1				1					2				2


Net Income Available to Common Stockholders
Before Preferred Stock Dividends			406				302					799				721


Other Comprehensive Income (Loss), Net of Income Taxes
Unrealized gain (loss) on derivative instruments:
Unrealized loss during the period¹			(34	)			(73	)				(115	)			(152	)
Reclassification adjustment for loss included in net
income²			47				27					91				49

Total unrealized gain (loss) on derivative instruments			13				(46	)				(24	)			(103	)
Foreign currency translation adjustments³			(42	)			108					(69	)			235


Total			(29	)			62					(93	)			132


Comprehensive Income	$		377		$		364		$			706		$		853


1net of income tax benefit of:	$		18		$		44		$			65		$		89
2net of income tax expense of:			(27	)			(16	)				(53	)			(28	)
3net of income tax benefit (expense) of:			9				(52	)				13				(52	)

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

		Six Months Ended
		June 30

millions		2004				2003

Cash Flow from Operating Activities
Net income before cumulative effect of change in accounting principle	$		799		$		674
Adjustments to reconcile net income before cumulative effect of change
in accounting principle to net cash provided by operating activities:
Depreciation, depletion and amortization			705				613
Deferred income taxes			248				263
Impairments related to oil and gas properties			9				18
Other noncash items			72				-

			1,833				1,568
Increase in accounts receivable			(158	)			(64	)
Increase (decrease) in accounts payable and accrued expenses			158				(4	)
Other items- net			(68	)			(85	)


Net cash provided by operating activities			1,765				1,415


Cash Flow from Investing Activities
Additions to properties and equipment			(1,473	)			(1,524	)
Sales and retirements of properties and equipment			1				41


Net cash used in investing activities			(1,472	)			(1,483	)


Cash Flow from Financing Activities
Additions to debt			6				601
Retirements of debt			(1	)			(458	)
Increase (decrease) in accounts payable, banks			(30	)			45
Sale of future hard minerals royalty revenues			158				-
Dividends paid			(73	)			(51	)
Purchase of treasury stock			(151	)			-
Retirement of preferred stock			-				(12	)
Issuance of common stock			44				34


Net cash provided by (used in) financing activities			(47	)			159


Effect of Exchange Rate Changes on Cash			1				3


Net Increase in Cash and Cash Equivalents			247				94

Cash and Cash Equivalents at Beginning of Period			62				34


Cash and Cash Equivalents at End of Period	$		309		$		128

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 June 30, 2004 and December 31, 2003, the results of operations for the three and six months ended June 30, 2004 and 2003 and cash flows for the six months ended June 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 uses derivative instruments for its energy marketing and trading business and to manage foreign currency risk and commodity price risk associated with its equity oil and gas production and 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 7.

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 10.

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 July 2004, the FASB issued proposed FASB Staff Position (FSP) FAS 142-b, "Application of FASB Statement No. 142, Goodwill and Other Intangible Assets to Oil and Gas Producing Entities." This proposed FSP confirms the Staff's position 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 that are within the scope of SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." Anadarko classifies the cost of oil and gas drilling and mineral rights as properties and equipment, which is consistent with SFAS No. 19 and proposed FSP FAS 142-b.

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							Six Months Ended
		June 30						June 30

millions except per share amounts		2004			2003			2004			2003

Net income available to common stockholders, as reported		$	405		$	301		$	797			$	719
Add: Stock-based employee compensation expense included
in income, after income taxes			4			2			7				5
Deduct: Total stock-based employee compensation expense
determined under the fair value method, after income taxes			(5	)		(5	)		(10	)			(16	)

Pro forma net income available to common stockholders		$	404		$	298		$	794			$	708


Basic EPS - as reported		$	1.60		$	1.21		$	3.16			$	2.89
Basic EPS - pro forma		$	1.60		$	1.19		$	3.15			$	2.84

Diluted EPS - as reported		$	1.59		$	1.20		$	3.14			$	2.83
Diluted EPS - pro forma		$	1.59		$	1.18		$	3.12			$	2.79

3. 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, "Accounting for Asset Retirement Obligations," 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 depreciation, depletion and amortization (DD&A) 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:

millions
Carrying amount of asset retirement obligations as of January 1, 2004	$	477
Liabilities incurred		12
Liabilities settled		(26	)
Accretion expense		16
Revisions in estimated liabilities		2
Impact of foreign currency exchange rate changes		(4	)

Carrying amount of asset retirement obligations as of June 30, 2004	$	477

4. 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:

	June 30,		December 31,
millions	2004		2003

Materials and supplies	$	76	$	77
Natural gas		29		29
Crude oil and NGLs		21		19


Total	$	126	$	125

5. Properties and Equipment

Oil and gas properties include costs of $1.8 and $2.5 billion at June 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 June 30, 2004 and December 31, 2003, the Company's investment in countries where proved reserves have not been established was $81 million and $76 million, respectively. During the second quarter of 2003, the Company made provisions for impairments of oil and gas properties of $13 million related to international activities. For the first six months of 2004 and 2003, the Company made provisions for impairments of oil and gas properties of $9 million and $1 8 million, respectively, related to international activities.

Total interest costs incurred during the second quarter of 2004 and 2003 were $88 million and $98 million, respectively. Of these amounts, the Company capitalized $22 million and $30 million during the second quarter of 2004 and 2003, respectively, as part of the cost of oil and gas properties. Total interest costs incurred during the first six months of 2004 and 2003 were $176 million and $192 million, respectively. Of these amounts, the Company capitalized $47 million and $64 million during the first six 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 $45 million capitalized during the second quarters of 2004 and 2003. For the first six months of 2004 and 2003, the Company capitalized internal costs related to exploration and development activities of $86 million and $97 million, respectively.

6. Debt

A summary of debt follows:

	June 30, 2004					December 31, 2003

millions	Principal		Carrying Value			Principal		Carrying Value


Total debt	$	5,201		$	5,063	$	5,202	$	5,058
Less current portion					168				-

Total long-term debt				$	4,895			$	5,058

7. 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 to losses 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 June 30, 2004 and December 31, 2003, the Company had option contracts, swap contracts and fixed price physical delivery contracts in place to hedge a portion of 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 meet the qualifications and mark-to-market accounting is applied to those that do not qualify for hedge accounting. The fair values and the accumulated other comprehensive income balances applicable to the derivative financial instruments (excluding the physical delivery sales contracts) are as follows:

		June 30,			December 31,
millions		2004				2003

Fair Value - Asset (Liability)
Current	$		(254	)	$		(232	)
Noncurrent			(16	)			(10	)

Total	$		(270	)	$		(242	)


Accumulated other comprehensive loss before income taxes	$		(227	)	$		(193	)

Accumulated other comprehensive loss after income taxes	$		(144	)	$		(122	)

The difference between the fair values 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. Approximately $209 million ($133 million after income taxes) of net losses in the accumulated other comprehensive income balance as of June 30, 2004 is expected to be reclassified into gas and oil sales during 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 (non-trading activities) as of June 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.

		Third			Fourth
		Quarter			Quarter			Annual
		2004			2004				2005

Natural Gas

Three-Way Collars (thousand MMBtu/d)		269			269				129
NYMEX price per MMBtu
Floor sold price	$	2.67		$	2.67		$		3.74
Floor purchased price	$	3.65		$	3.65		$		4.71
Ceiling sold price	$	5.30		$	5.30		$		8.64

Two-Way Collars (thousand MMBtu/d)		44			44				26
NYMEX price per MMBtu
Floor purchased price	$	4.29		$	4.29		$		3.76
Ceiling sold price	$	6.43		$	6.43		$		5.65

Fixed Price (thousand MMBtu/d)		264			245				33
NYMEX price per MMBtu	$	3.87		$	3.83		$		3.46

Total (thousand MMBtu/d)		577			558				188

Basis Swaps (thousand MMBtu/d)		202			183				103
Price per MMBtu	$	(0.13	)	$	(0.12	)	$		(0.19	)


Crude Oil

Three-Way Collars (MBbls/d)		38			38				20
NYMEX price per barrel
Floor sold price	$	20.13		$	20.13		$		27.00
Floor purchased price	$	24.61		$	24.61		$		32.00
Ceiling sold price	$	30.00		$	30.00		$		44.05

Two-Way Collars (MBbls/d)		3			3				2
NYMEX price per barrel
Floor purchased price	$	22.00		$	22.00		$		22.00
Ceiling sold price	$	26.32		$	26.32		$		26.32

Fixed Price (MBbls/d)		26			26				-
NYMEX price per barrel	$	27.22		$	27.22		$		-

Total (MBbls/d)		67			67				22


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 purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) 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 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 sold call establishes a maximum price the Company will receive for the volumes under contract. 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 fair values of the Company's marketing and trading derivative financial instruments as of June 30, 2004 and December 31, 2003 are as follows:

		June 30,		December 31,
millions		2004		2003

Fair Value - Asset (Liability)
Current	$		42	$	33
Noncurrent			5		4

Total	$		47	$	37

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 June 30, 2004 and 2003 were $(6) million and $14 million, respectively, and net (payments to) receipts from Duke for the six months ended June 30, 2004 and 2003 were $(12) million and $24 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 income of $5 million and ot her expense of $17 million for the quarter ended June 30, 2004 and 2003, respectively, and other income of $3 million and $18 million for the six months ended June 30, 2004 and 2003, respectively, related to the keep-whole agreement and associated derivative instruments. As of June 30, 2004, accounts payable included $20 million and other long-term liabilities included $41 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 June 30, 2004 are as follows:

millions		Undiscounted			Discounted

2004	$		11	$		11
2005			18			17
2006			19			15
2007			14			11
2008			9			6
2009			1			1

Total	$		72	$		61

As of June 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.

8. 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. Under the terms of the agreement, 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 also 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 thir d party relies solely on the royalty payments 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.

The $158 million in proceeds 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 second quarter 2004, the Company amortized $4 million 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

9. Preferred Stock

For the first and second 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.

10. Common Stock

The reconciliation between basic and diluted EPS is as follows:

		Three Months Ended							Three Months Ended
		June 30, 2004							June 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		$	405		252	$	1.60	$		301		250	$	1.21

Effect of convertible debentures
and ZYP-CODES			-		-					1		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		$	405		254	$	1.59	$		302		252	$	1.20

		Six Months Ended							Six Months Ended
		June 30, 2004							June 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		$	797		252	$	3.16	$		672		249	$	2.70

Effect of convertible debentures
and ZYP-CODES			-		-					3		5
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		$	797		254	$	3.14	$		675		255	$	2.65

For the three and six months ended June 30, 2004, options for 1.1 million and 1.2 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 six months ended June 30, 2003, options for 8.8 million and 8.9 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. The Company intends to purchase the majority of the authorized amount in shares within the next 12 months. 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 second quarter of 2004, the Company purchased 2.6 million shares of common stock for $150 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 June 30, 2004 and December 31, 2003.

11. Statements of Cash Flows Supplemental Information

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

		Six Months Ended
		June 30

millions		2004			2003

Interest	$		125	$		114
Income taxes	$		13	$		72

12. 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 June 30:
2004

Revenues		$	696	$		30		$		7		$	710		$		1,443
Intersegment revenues			730			4				-			(734	)			-

Total revenues			1,426			34				7			(24	)			1,443

Income (loss) before income taxes		$	803	$		(4	)	$		6		$	(180	)	$		625


2003

Revenues		$	682	$		41		$		8		$	518		$		1,249
Intersegment revenues			514			4				-			(518	)			-

Total revenues			1,196			45				8			-				1,249

Impairments related to oil and gas properties			13			-				-			-				13

Income (loss) before income taxes		$	602	$		1		$		6		$	(137	)	$		472


Six Months Ended June 30:
2004

Revenues		$	1,430	$		79		$		21		$	1,373		$		2,903
Intersegment revenues			1,393			7				-			(1,400	)			-

Total revenues			2,823			86				21			(27	)			2,903

Impairments related to oil and gas properties			9			-				-			-				9

Income (loss) before income taxes		$	1,576	$		7		$		18		$	(371	)	$		1,230

Net properties and equipment		$	16,236	$		268		$		1,197		$	365		$		18,066

Goodwill		$	1,378	$		-		$		-		$	-		$		1,378


2003

Revenues		$	1,445	$		55		$		17		$	987		$		2,504
Intersegment revenues			982			8				-			(990	)			-

Total revenues			2,427			63				17			(3	)			2,504

Impairments related to oil and gas properties			18			-				-			-				18

Income (loss) before income taxes		$	1,314	$		15		$		14		$	(271	)	$		1,072

Net properties and equipment		$	14,867	$		257		$		1,200		$	435		$		16,759

Goodwill		$	1,472	$		-		$		-		$	-		$		1,472

13. Other (Income) Expense

Other (income) expense consists of the following:

	Three Months Ended									Six Months Ended
			June 30								June 30

millions			2004				2003				2004				2003

Operating lease settlement		$		-		$		-		$		63		$		-
Firm transportation keep-whole contract valuation				(5	)			17				(3	)			(18	)
Foreign currency exchange (gains) losses				1				(6	)			(2	)			(14	)
Ineffectiveness of derivative financial instruments				3				1				(3	)			3
Other				(3	)			-				1				2

Total		$		(4	)	$		12		$		56		$		(27	)

The operating lease settlement in 2004 relates to the Corpus Christi West Plant Refinery (West Plant). SeeNote 16. Foreign currency exchange (gains) losses for the three and six months ended June 30, 2004, exclude zero and $6 million, respectively, in transaction gains related primarily to remeasurement of the Venezuelan deferred tax liability. For the three and six months ended June 30, 2003, foreign currency exchange (gains) losses exclude zero and $8 million, respectively, in transaction losses related primarily to remeasurement of the Venezuelan deferred tax liability. These amounts are included in income tax expense.

14. Commitments

The future minimum lease obligations for the Company's operating leases increased to $421 million at June 30, 2004 from $398 million at December 31, 2003 primarily due to the operating lease settlement. SeeNote 16.

15. 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 six months ended June 30, 2004, the Company made contributions of $70 million to funded pension plans, $35 million to unfunded pension plans and $5 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 $6 million to funded pension plans, $4 million to unfunded pension plans and $4 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 supersedes FSP FAS 106-1 once FSP FAS 106-2 becomes effective in the third quarter of 2004. The Company believes that its other postretireme nt benefit plan benefits are actuarially equivalent to Medicare Part D and that it will be eligible for the federal subsidy for sponsors under the Act. The effect of the Act will be recognized on a prospective basis beginning in the third quarter of 2004. The Company does not expect adoption of FSP FAS 106-2 to materially affect the 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
	June 30						June 30

millions	2004			2003			2004		2003

Components of net periodic benefit cost
Service cost	$	6		$	5		$	3	$	2
Interest cost		8			9			2		2
Expected return on plan assets		(8	)		(8	)		-		-
Amortization values and deferrals		3			4			1		1

Net periodic benefit cost	$	9		$	10		$	6	$	5

	Pension Benefits						Other Benefits

	Six Months Ended						Six Months Ended
	June 30						June 30

millions	2004			2003			2004		2003

Components of net periodic benefit cost
Service cost	$	12		$	10		$	6	$	4
Interest cost		16			17			4		4
Expected return on plan assets		(16	)		(15	)		-		-
Amortization values and deferrals		6			7			2		1

Net periodic benefit cost	$	18		$	19		$	12	$	9

16. 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. H owever, 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 currently are scheduled for August 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. filed in January 1997 in the 335th District Court of Lee County, Texas became active during the first quarter of 2003. 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 three and six months ended June 30, 2004 include before tax charges of $23 million and $27 million, respectively, 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. 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, which the Company believes will result in a nominal purchase price. 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 Company 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 currently estimates the purchase price to be $12.5 million less than the agreed upon maximum purchase price. Since the agreed upon rental rates exceed the capped sublease payments from CITGO and the Company's estimated purchase price exceeds CITGO's specified purchase price in 2011, the Company recorded a liability of $63 million in the first quarter of 2004. This amount represents 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.

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 s afe harbor for forward looking statements contained in the Private Securities Litigation Reform Act of 1995. Such 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 will involve 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 current oil and gas production, with after-tax proceeds expected to exceed $2.5 billion. The Company intends to use 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 retained properties will be separated into two broad categories and managed to serve different roles within the overall portfolio. "Foundation" assets will be 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 proved reserves and between 115 and 125 thousand barrels of oil equivalent per day (MBOE/d) of production volumes. Most of the identified properties to be divested are located in the shallow waters of the Gulf of Mexico, Western Canadian Sedimentary Basin and the Mid-Continent region of the United States. The majority of the planned asset sales are expected to close by year-end, with the rest expected to be accomplished by the end of the first quarter of 2005.

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.

Selected Data

		Three Months Ended							Six Months Ended
			June 30						June 30

millions except per share amounts			2004			2003			2004			2003


Financial Results
Revenues		$		1,443	$		1,249	$		2,903	$		2,504
Costs and expenses				756			697			1,488			1,331
Interest expense and other (income) expense				62			80			185			101
Income tax expense				219			170			431			398
Net income available to common stockholders before
	cumulative effect of change in accounting principle	$		405	$		301	$		797	$		672
Net income available to common stockholders		$		405	$		301	$		797	$		719
Earnings per share - before cumulative effect
	of change in accounting principle - diluted	$		1.59	$		1.20	$		3.14	$		2.65
Earnings per share - diluted		$		1.59	$		1.20	$		3.14	$		2.83

Operating Results
Sales volumes (MMBOE)				47			48			96			93

Capital Resources and Liquidity
Capital expenditures								$		1,483	$		1,524
Cash flow from operating activities								$		1,765	$		1,415

Financial Results

Net Income In the second quarter of 2004, Anadarko's net income was $405 million or $1.59 per share (diluted). This compares to net income of $301 million or $1.20 per share (diluted) for the second quarter of 2003. For the six months ended June 30, 2004, Anadarko's net income was $797 million, or $3.14 per share (diluted). This compares to net income before the cumulative effect of change in accounting principle of $672 million, or $2.65 per share (diluted) for the six months ended June 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 $719 million or $2.83 per share (diluted) for the first six months of 2003.

Revenues

	Three Months Ended							Six Months Ended
		June 30						June 30

millions		2004			2003			2004			2003


Gas sales	$		843	$		697	$		1,615	$		1,403
Oil and condensate sales			503			434			1,054			879
Natural gas liquids sales			93			85			196			170
Other sales			4			33			38			52

Total	$		1,443	$		1,249	$		2,903	$		2,504

Anadarko's total revenues for the three and six months ended June 30, 2004 increased 16% compared to the three and six months ended June 30, 2003 primarily due to higher commodity prices.

The impact of hedges and marketing activities resulted in lower realized prices of $0.28 per thousand cubic feet (Mcf) of gas and $3.19 per barrel of oil for the second quarter of 2004 compared to market prices, which decreased revenues $97 million. For the second quarter of 2003, the impact of hedges and marketing activities resulted in lower realized prices of $0.35 per Mcf of gas and $0.76 per barrel of oil compared to market prices, which decreased revenues $69 million. For the six months ended June 30, 2004, the impact of hedges and marketing activities resulted in lower realized prices of $0.20 per Mcf of gas and $2.36 per barrel of oil compared to market prices, which decreased revenues $144 million. For the six months ended June 30, 2003, the impact of hedges and marketing activities resulted in lower realized prices of $0.59 per Mcf of gas and $1.56 per barrel of oil compared to market prices, which decreased revenues $236 million.

Analysis of Sales Volumes

	Three Months Ended					Six Months Ended
		June 30				June 30

		2004		2003		2004		2003

Barrels of Oil Equivalent (MMBOE)
United States			33		33		65		65
Canada			7		8		15		15
Algeria			5		5		12		10
Other International			2		2		4		3

Total			47		48		96		93


Barrels of Oil Equivalent per Day (MBOE/d)
United States			355		367		355		358
Canada			81		84		82		84
Algeria			52		58		65		53
Other International			24		18		23		17

Total			512		527		525		512

During the second quarter of 2004, Anadarko's daily sales volumes decreased 3% compared to the second quarter of 2003 primarily due to lower production volumes offshore and in the western United States and lower sales volumes in Algeria due to the timing of cargo liftings. For the six months ended June 30, 2004, Anadarko's daily sales volumes increased 3% compared to the six months ended June 30, 2003 primarily due to higher volumes in Algeria due to the timing of cargo liftings and the expansion of production facilities and infrastructure.

Natural Gas Sales Volumes and Average Prices

	Three Months Ended							Six Months Ended
		June 30						June 30

		2004			2003			2004			2003


United States (Bcf)			126			122			247			241
MMcf/d			1,388			1,350			1,358			1,333
Price per Mcf	$		5.19	$		4.28	$		5.03	$		4.37

Canada (Bcf)			36			36			72			71
MMcf/d			398			391			396			390
Price per Mcf	$		5.16	$		4.80	$		5.14	$		4.91

Total (Bcf)			162			158			319			312
MMcf/d			1,786			1,741			1,754			1,723
Price per Mcf	$		5.19	$		4.40	$		5.06	$		4.50



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

The Company's daily natural gas sales volumes for the second quarter of 2004 were up 3% compared to the second quarter of 2003. For the first six months of 2004, the Company's daily natural gas sales volumes were up 2% compared to the same period of 2003. The increases for both periods were primarily due to successful drilling in Texas and Louisiana, partially offset by slightly lower volumes in the western United States. Production of natural gas is generally not directly affected by seasonal swings in demand.

The Company's average realized natural gas price for the three and six months ended June 30, 2004 increased 18% and 12%, respectively, compared to the same periods in 2003. These higher prices include commodity price hedges on 32% and 39% of natural gas sales volumes during the three and six months ended June 30, 2004, respectively, that reduced the Company's exposure to low prices and limited participation in higher prices. As of June 30, 2004, the Company has hedged about 31% 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							Six Months Ended
		June 30						June 30

		2004			2003			2004			2003


United States (MMBbls)			8			8			16			17
MBbls/d			84			97			86			94
Price per barrel	$		31.04	$		25.44	$		30.45	$		26.50

Canada (MMBbls)			1			2			3			3
MBbls/d			13			17			14			17
Price per barrel	$		36.12	$		27.15	$		33.99	$		28.12

Algeria (MMBbls)			5			5			12			10
MBbls/d			52			58			65			53
Price per barrel	$		33.46	$		25.36	$		32.20	$		28.25

Other International (MMBbls)			2			2			4			3
MBbls/d			24			18			23			17
Price per barrel	$		27.88	$		20.55	$		25.87	$		22.41

Total (MMBbls)			16			17			35			33
MBbls/d			173			190			188			181
Price per barrel	$		31.71	$		25.11	$		30.76	$		26.78



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

Anadarko's daily crude oil and condensate sales volumes for the second quarter of 2004 were down 9% compared to the second quarter of 2003 primarily due to lower volumes attributed to declines in south Louisiana and the Gulf of Mexico shelf and lower sales volumes in Algeria. For the six months ended June 30, 2004, daily crude oil and condensate sales volumes were up 4% compared to the same period of 2003 primarily due to the higher daily volumes in Algeria and Qatar, partially offset by lower daily volumes in Texas and Louisiana in the United States.Production of oil is not usually affected by seasonal swings in demand.

Anadarko's average realized crude oil prices for the three and six months ended June 30, 2004 increased 26% and 15%, respectively, compared to the same periods of 2003. These higher prices include commodity price hedges on 39% and 36% of crude oil and condensate sales volumes during the three and six months ended June 30, 2004, respectively, that reduced the Company's exposure to low prices and limited participation in higher prices. As of June 30, 2004, the Company has hedged about 36% 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							Six Months Ended
		June 30						June 30

		2004			2003			2004			2003


Total (MMBbls)			4			4			8			8
MBbls/d			41			47			45			44
Price per barrel	$		25.18	$		20.09	$		24.22	$		21.49

The Company's daily NGLs sales volumes for the second quarter of 2004 decreased 13% compared to the same period of 2003. For the six months ended June 30, 2004, the Company's daily NGLs sales volumes increased 2% compared to the same period of 2003. During the second quarter of 2004, average NGLs prices increased 25% compared to the same period of 2003. For the six months ended June 30, 2004, average NGLs prices increased 13% 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							Six Months Ended
		June 30						June 30

millions		2004			2003			2004			2003


Direct operating	$		163	$		151	$		321	$		287
Transportation and cost of product			59			53			116			93
Administrative and general			92			86			171			174
Depreciation, depletion and amortization			357			323			705			613
Other taxes			85			71			166			146
Impairments related to oil and gas properties			-			13			9			18

Total	$		756	$		697	$		1,488	$		1,331

During the second quarter of 2004, Anadarko's costs and expenses increased 8% compared to the second quarter of 2003 due to the following factors:

-	Direct operating expense was up 8%. The second quarter of 2004 includes a $6 million increase in the western United States primarily due to higher enhanced oil recovery activity and an increase of $3 million in Canada, which includes the impact of the higher Canadian exchange rate.
-	Transportation and cost of product expense increased 11%. The second quarter of 2004 includes a $7 million increase in marketing transportation primarily due to higher transportation rates.
-	Administrative and general (A&G) expense increased 7%. The second quarter of 2004 includes $9 million in severance expense and other costs related to reorganization efforts.
-	Depreciation, depletion and amortization (DD&A) expense increased 11%. DD&A expense increases include about $35 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 $3 million due to asset retirement obligation accretion expense, partially offset by a decrease of $6 million related to lower production volumes.
-	Other taxes increased 20% primarily due to higher commodity prices in 2004.
-	Impairments of oil and gas properties in 2003 were related to international activities.

For the six months ended June 30, 2004, Anadarko's costs and expenses increased 12% compared to the same period of 2003 due to the following factors:

-	Direct operating expense was up 12%. The six months ended June 30, 2004 includes an $8 million increase in the western United States primarily due to higher enhanced oil recovery activity, an $8 million increase in Canada primarily due to the higher Canadian exchange rate, an increase of $7 million in Algeria and Qatar primarily due to higher volumes, and a $5 million increase in the Gulf of Mexico primarily due to the acquisition of producing properties in mid-2003.
-	Transportation and cost of product expense increased 25%. The six months ended June 30, 2004 include a $14 million increase in oil and gas transportation expense primarily due to higher transportation rates and higher volumes, and a $10 million increase in marketing transportation expense primarily due to higher transportation rates.
-	A&G expense decreased 2%. The first six months of 2004 include $10 million in severance expense and other costs related to reorganization efforts.
-	DD&A expense increased 15%. DD&A expense increases include about $65 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), $18 million related to higher production volumes and $6 million due to asset retirement obligation accretion expense.
-	Other taxes increased 14% primarily due to higher commodity prices in 2004.
-	Impairments of oil and gas properties were related to international activities.

Interest Expense and Other (Income) Expense

	Three Months Ended										Six Months Ended
		June 30										June 30

millions		2004					2003					2004				2003

Interest Expense
Gross interest expense		$	88			$		98		$			176		$		192
Capitalized interest			(22	)				(30	)				(47	)			(64	)

Net interest expense			66					68					129				128


Other (Income) Expense
Operating lease settlement			-					-					63				-
Firm transportation keep-whole contract valuation			(5	)				17					(3	)			(18	)
Foreign currency exchange (gains) losses			1					(6	)				(2	)			(14	)
Ineffectiveness of derivative financial instruments			3					1					(3	)			3
Other			(3	)				-					1				2

Total other (income) expense			(4	)				12					56				(27	)


Total		$	62		$			80		$			185		$		101

Interest Expense Anadarko's gross interest expense for the three and six months ended June 30, 2004 decreased 10% and 8%, respectively, compared to the same periods of 2003 primarily due to lower average outstanding debt during 2004. For the three and six months ended June 30, 2004, capitalized interest decreased by 27% 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 second quarter of 2004, the Company had other income of $4 million compared to other expense of $12 million for the same period of 2003. The favorable change of $16 million was primarily due to a $22 million favorable increase related to the effect of higher market values for firm transportation subject to the keep-whole agreement, partially offset by an unfavorable change of $7 million related to the impact of Canadian foreign currency exchange (gains) losses. For the six months ended June 30, 2004, the Company had other expense of $56 million compared to other income of $27 million for the same period of 2003. The unfavorable change of $83 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 (West Plant), a $15 million unfavorable change related to the effect of lower market values for firm transportation su bject to the keep-whole agreement, a $12 million unfavorable change primarily due to a decrease in Canadian foreign currency exchange gains, partially offset by a $6 million favorable change in (gains) losses for ineffectiveness of derivative financial instruments. For additional information seeNote 16 - Contingencies of theNotes to Consolidated Financial Statements under Item 1 of this Form 10-Q and Derivative InstrumentsandForeign Currency Risk under Item 3 of this Form 10-Q.

Income Tax Expense

	Three Months Ended									Six Months Ended
		June 30								June 30

millions		2004				2003				2004				2003


Income tax expense	$		219		$		170		$		431		$		398
Effective tax rate			35	%			36	%			35	%			37	%

For the three and six months ended June 30, 2004, income tax expense increased 29% and 8%, respectively, compared to the same periods of 2003. The increases were primarily due to higher income before income taxes in both periods, partially offset by the effect of the reduction in the Alberta provincial tax rate during the second quarter of 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, oil and gas credits and other items.

Operating Results

Exploration and Development Activities During the second quarter of 2004, Anadarko participated in a total of 318 wells, including 219 gas wells, 88 oil wells and 11 dry holes. This compares to a total of 319 wells, including 195 gas wells, 103 oil wells and 21 dry holes during the second quarter of 2003.

For the first six months of 2004, Anadarko participated in a total of 606 wells, including 424 gas wells, 156 oil wells and 26 dry holes. This compares to a total of 577 wells, including 382 gas wells, 162 oil wells and 33 dry holes during the first six months of 2003. Following are highlights of second quarter 2004 activity:

-	Anadarko expanded its Gulf of Mexico deepwater K2 North discovery with the No. 2 well that encountered 165 feet of net oil pay. The field is expected to begin production through the Marco Polo platform in 2005. Anadarko holds a 100% working interest in the field, which is located on Green Canyon Block 518.
-	In July 2004, Anadarko commenced production from three wells at its Marco Polo field located on Green Canyon Block 608 in the Gulf of Mexico. Anadarko has a 100% working interest and expects the field to reach peak production of 50 MBOE/d once all six wells are on line by early 2005.

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 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 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's marketing department actively manages sales of its oil and gas. 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 purchases physical 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 June 30, 2004. The Company records income or loss on these activities using the mark-to-market accounting method.

				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		(2	)		12			10
Other changes in fair value		4			3			7

Fair value of contracts outstanding as of
June 30, 2004 - assets (liabilities)	$	8		$	(61	)	$	(53	)

		Fair Value of Contracts as of June 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	$		5		$		2		$		1		$	-	$	8
Prices based on models and other valuation
methods			-				-				-			-		-

Firm Transportation Keep-Whole
Prices actively quoted	$		(20	)	$		-		$		-		$	-	$	(20	)
Prices based on models and other valuation
methods			-				(30	)			(11	)		-		(41	)

Total
Prices actively quoted	$		(15	)	$		2		$		1		$	-	$	(12	)
Prices based on models and other valuation
methods			-				(30	)			(11	)		-		(41	)

Capital Resources and Liquidity

General Anadarko's cash flow from operating activities during the six months ended June 30, 2004 was $1.8 billion compared to $1.4 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 replacement an d 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. Under the terms of the agreement, 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 also 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 8 - Sale of Future Hard Minerals Royalty Revenues of theNotes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Debt At June 30, 2004 and December 31, 2003, Anadarko's total debt was $5.1 billion.

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

		Six Months Ended
		June 30

millions		2004			2003


Development	$		1,045	$		749
Exploration			225			296
Acquisitions of oil and gas properties			45			280
Capitalized interest and internal costs related to exploration
and development activities			133			161

Total oil and gas			1,448			1,486
Gathering and other			35			38

Total*	$		1,483	$		1,524


* Excludes asset retirement costs and includes actual asset retirement expenditures.

During the six months ended June 30, 2004, Anadarko's capital spending decreased 3% 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 decrease in acquisitions of oil and gas properties is primarily due to the acquisition of properties in the Gulf of Mexico in 2003.

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. Shares may be repurchased either in the open market or through privately negotiated transactions. It is the Company's intent to purchase a majority of the authorized amount in shares within the next 12 months 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. For additional information seeChanges in Securities, Use of Proceeds and Issuer Purchases of Equity Securitiesunder Part II - Item 2 of this Form 10-Q.

Dividends In the first six months of 2004 and 2003, Anadarko paid $71 million and $49 million, respectively, in dividends to its common stockholders (14 cents per share in the first and second quarters of 2004 and 10 cents per share in the first and second quarters of 2003). Anadarko has paid a dividend to its common stockholders continuously since becoming an independent company in 1986. For the six months ended June 30, 2004 and 2003, Anadarko also paid $2 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 June 30, 2004, Anadarko's capitalization ratio was 36% debt. Under the maximum debt capitalization ratio, retained earnings were not restricted as to the payment of dividends at June 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 in 2004 is expected to be sufficient to fund capital spending and 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 prices are below the Company 's mid-cycle targets, Anadarko could draw upon its strengthened debt capacity to fund a steady level of activity.

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 7 - 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 143 Bcf of natural gas and 21 MMBbls of crude oil as of June 30, 2004 (excluding physical delivery fixed price contracts). As of June 30, 2004, the Company had a net unrealized loss of $270 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 $114 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 June 30, 2004, the Company had a net unrealized gain of $47 million (gains of $48 million and losses of $1 million) on derivative financial instruments entered into for trading purposes and a net unrealized loss of $39 million (losses of $47 million and gains of $8 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 $1 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 June 30, 2004, accounts payable included $20 million and other long-term liabilities included $41 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 June 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 7 - 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 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 June 30, 2004 Canadian exchange rate would be about $3 million based on the outstanding debt at June 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 June 30, 2004. In addition, there has been no significant change in the Company's internal control over financial reporting during the quarter ended June 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 16 - Contingencies of theNotes to Consolidated Financial Statements under Part I - Item 1 of this Form 10-Q.

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

The following table sets forth information with respect to repurchases by the Company of its shares of common stock during the first and second quarters 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)


January		41,820	$	51.11		-

February		3,643	$	50.57		-

March		2,607	$	51.80		-


First Quarter 2004		48,070	$	51.10		-		$	834,000,000


April		8,061	$	51.99		-

May		5,783	$	55.12		-

June		2,594,974	$	58.08		2,591,000


Second Quarter 2004		2,608,818	$	58.06		2,591,000		$	1,850,000,000

(1) During the first and second quarters of 2004, 49 shares and 2,591,164 shares, respectively, were repurchased under the Company's share repurchase programs. During the first and second quarters of 2004, 48,021 shares and 17,654 shares, respectively, 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) On July 23, 2001, the Company announced a stock buyback program to purchase up to $1 billion in shares of Anadarko common stock. As of March 31, 2004, the Company had repurchased $166 million of its common stock under this program. On June 9, 2004, the Company announced a replacement stock buyback program to purchase up to $2 billion in shares of common stock. It is the Company's intent to purchase the majority of the authorized amount in shares within the next 12 months. However, the repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time.

Item 4. Submission of Matters to a Vote of Security Holders

(a)	On May 6, 2004, the Company held its Annual Meeting of Stockholders.

(b)	Mr. James T. Hackett was elected and Messrs. Larry Barcus and James L. Bryan were re-elected as Class III directors to serve for a term of three years. Messrs. John R. Butler, Jr., Preston M. Geren III and John R. Gordon will continue to serve as Class I directors. Messrs. Conrad P. Albert, Robert J. Allison, Jr. and John W. Poduska, Sr. will continue to serve as Class II directors.

(c)	Mr. James T. Hackett was elected with 206,492,572 votes for and 3,874,376 votes withheld. Mr. Larry Barcus was re-elected with 204,137,838 votes for and 6,229,110 votes withheld. Mr. James L. Bryan was re-elected with 203,651,506 votes for and 6,715,442 votes withheld.

	The stockholders approved the performance criteria under and amendment to the Annual Incentive Bonus Plan (Incentive Plan). For each calendar year, the Compensation Committee establishes, in writing, the performance goals, the specific performance criteria and the performance target or range of targets to measure satisfaction of the performance goals. One or more of the following performance criteria will be used to establish the performance goals: (i) finding and development costs, (ii) production and operating costs, (iii) production, drilling and reserve growth results, (iv) attainment of cash flow and net income goals, (v) attainment of financial and operating return ratios or margins, (vi) attainment of corporate financial goals, (vii) mergers, divestitures and acquisitions results, (viii) attainment of regulatory, environmental and safety goals, and (ix) common stock price performance. The amendment to the Incentive Plan increased the maximum bonus amount that could be p aid to any individual for any calendar year under the Incentive Plan to $5 million. A total of 193,119,165 shares of common stock voted for the amendment, 15,573,222 shares of common stock voted against the amendment and 1,674,561 shares of common stock abstained.

	The stockholders ratified the appointment by the Audit Committee of KPMG LLP to audit the Company's financial statements for 2004. A total of 201,322,415 shares of common stock voted for the appointment, 7,718,536 shares of common stock voted against the appointment and 1,325,997 shares of common stock abstained.

	The stockholders rejected the Stockholder Proposal Regarding Climate Change. A shareholder of the Company requested the Board to prepare a report (at reasonable cost and omitting proprietary information) by September 1, 2004, explaining how the Company is responding to rising regulatory, competitive and public pressure to significantly reduce greenhouse gas (GHG) emissions. The Board of Directors and Management of the Company regularly review the risks facing Anadarko's business, including the environmental and regulatory matters associated with the Company's operations. The Company has formed a Climate Change Committee composed of employees representing disciplines across the Company to address GHG issues. Because the Company is actively addressing the issues raised in this proposal, the Board does not believe that creating the type of report requested by the proponents would help in the reduction of emissions or in the environmental performance of the Company. The Company b elieves that preparing the requested report will not create added value to the stockholders and will serve only to increase administrative burdens and costs. A total of 107,494,413 shares of common stock voted against the proposal, 49,180,149 shares of common stock voted for the proposal and 16,485,925 shares of common stock abstained.

Item 6. Exhibits and Reports on Form 8-K

(a)	Exhibits

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

Exhibit				Original Filed	File
Number			Description	Exhibit	Number


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

	(b)		By-laws of Anadarko Petroleum	3(b) to Form 10-K	1-8968
			Corporation, as amended	for year ended
				December 31, 2003

	(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)		Performance Share Agreement	10(b) to Form 10-Q	1-8968
				for quarter ended
				March 31, 2004

*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

(b)		Reports on Form 8-K

		A report on Form 8-K dated April 30, 2004 was furnished. The event was reported under Item 9 - Regulation FD Disclosure and Item 12 - Results of Operations and Financial Condition.

		A report on Form 8-K dated June 9, 2004 was furnished. The event was reported under Item 9 - Regulation FD Disclosure.

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)



August 4, 2004	By:	/s/ JAMES R. LARSON

		James R. Larson - Senior Vice President,
		Finance and Chief Financial Officer

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Anadarko Petroleum 10-Q2004 Q2 Quarterly report

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