ANADARKO PETROLEUM CORP - 10-Q 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, 2003
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 to such 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 July 31, 2003 is shown below:


Title of Class	Number of Shares Outstanding

Common Stock, par value $0.10 per share	249,532,968

TABLE OF CONTENTS

			Page
PART I

	Item 1.	Financial Statements

		Consolidated Statements of Income for the Three and Six Months Ended June 30, 2003 and 2002	--

		Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002	--

		Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2003 and 2002	--

		Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002	--

		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 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	2003		2002			2003		2002
Revenues
Gas sales	$	720	$	497		$	1,428	$	865
Oil and condensate sales		439		422			884		775
Natural gas liquids sales		85		56			170		99
Other sales		33		27			52		53
Total		1,277		1,002			2,534		1,792

Costs and Expenses
Operating expenses		204		200			380		383
Administrative and general		86		77			174		149
Depreciation, depletion and amortization		323		274			613		541
Other taxes		71		62			146		118
Impairments related to oil and gas properties		13		25			18		33
Total		697		638			1,331		1,224

Operating Income		580		364			1,203		568

Other (Income) Expense
Interest expense		68		48			128		97
Other (income) expense		40		(21	)		3		2
Total		108		27			131		99

Income Before Income Taxes		472		337			1,072		469

Income Tax Expense		170		96			398		139

Net Income Before Cumulative Effect of Change
in Accounting Principle	$	302	$	241		$	674	$	330

Preferred Stock Dividends		1		2			2		3

Net Income Available to Common Stockholders Before
Cumulative Effect of Change in Accounting Principle	$	301	$	239		$	672	$	327

Cumulative Effect of Change in Accounting Principle		--		--			47		--

Net Income Available to Common Stockholders	$	301	$	239		$	719	$	327

Per Common Share
Net income - before change in accounting principle - basic	$	1.21	$	0.96		$	2.70	$	1.32
Net income - before change in accounting principle - diluted	$	1.20	$	0.93		$	2.65	$	1.27

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

Net income - basic	$	1.21	$	0.96		$	2.89	$	1.32
Net income - diluted	$	1.20	$	0.93		$	2.83	$	1.27

Dividends	$	0.10	$	0.075		$	0.20	$	0.15

Average Number of Common Shares Outstanding - Basic		250		248			249		248
Average Number of Common Shares Outstanding - Diluted		252		259			255		261

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)

		June 30,				December 31,
millions		2003				2002
ASSETS
Current Assets
Cash and cash equivalents	$		128			$		34
Accounts receivable, net of allowance:
Customers			883					673
Others			317					435
Other current assets			166					138

Total			1,494					1,280

Properties and Equipment
Original cost (includes unproved properties of $3,031 and $3,085
as of June 30, 2003 and December 31, 2002, respectively)			24,932					22,595
Less accumulated depreciation, depletion and amortization			8,173					7,497

Net properties and equipment - based on the full cost method
of accounting for oil and gas properties			16,759					15,098

Other Assets			468					436

Goodwill			1,472					1,434

Total Assets	$		20,193			$		18,248



LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable		$		1,243			$	1,050
Accrued expenses				562				511
Current portion, notes and debentures				445				300

Total				2,250				1,861

Long-term Debt				5,171				5,171

Other Long-term Liabilities
Deferred income taxes				4,001				3,633
Other				964				611

Total				4,965				4,244

Stockholders' Equity
Preferred stock, par value $1.00 per share
(2.0 million shares authorized, 0.1 million shares
issued as of June 30, 2003 and December 31, 2002)				89				101
Common stock, par value $0.10 per share
(450.0 million shares authorized, 255.3 million and 254.6 million shares
issued as of June 30, 2003 and December 31, 2002, respectively)				26				25
Paid-in capital				5,363				5,347
Retained earnings				2,691				2,021
Treasury stock (3.2 million shares as of June 30, 2003 and December 31, 2002)				(166	)			(166	)
Deferred compensation and ESOP (0.5 million and 0.7 million shares
as of June 30, 2003 and December 31, 2002, respectively)				(40	)			(63	)
Executives and Directors Benefits Trust, at market value
(2.0 million shares as of June 30, 2003 and December 31, 2002)				(90	)			(95	)
Accumulated other comprehensive income (loss):
Unrealized loss on derivative instruments				(188	)			(85	)
Foreign currency translation adjustments				198				(37	)
Minimum pension liability				(76	)			(76	)
Total				(66	)			(198	)

Total				7,807				6,972

Commitments and Contingencies				--				--

Total Liabilities and Stockholders' Equity		$		20,193			$	18,248

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	2003			2002			2003			2002

Net Income Available to Common Stockholders	$	301		$	239		$	719		$	327

Add: Preferred Stock Dividends		1			2			2			3

Net Income Available to Common Stockholders
Before Preferred Stock Dividends		302			241			721			330

Other Comprehensive Income (Loss), Net of Taxes
Unrealized gain (loss) on derivative instruments:
Unrealized gain (loss) during the period¹		(73	)		5			(152	)		(14	)
Reclassification adjustment for loss included in net
income²		27			6			49			5
Total unrealized gain (loss) on derivative instruments		(46	)		11			(103	)		(9	)
Foreign currency translation adjustments³		108			75			235			73
Minimum pension liability⁴		--			--			--			(12	)

Total		62			86			132			52

Comprehensive Income	$	364		$	327		$	853		$	382

^{1net of income tax benefit (expense) of:}	$	44		$	(2	)	$	89		$	9
^{2net of income tax expense of:}		(16	)		(4	)		(28	)		(3	)
^{3net of income tax expense of:}		(52	)		--			(52	)		--
^{4net of income tax benefit of:}		--			--			--			7

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

		Six Months Ended
		June 30
millions		2003				2002
Cash Flow from Operating Activities
Net income before cumulative effect of change in accounting principle	$		674		$		330
Adjustments to reconcile net income before cumulative effect of change
in accounting principle to net cash provided by operating activities:
Depreciation, depletion and amortization			619				548
Interest expense - zero coupon debentures			4				6
Deferred income taxes			263				53
Impairments related to oil and gas properties			18				33
Other non-cash items			(10	)			(10	)
			1,568				960
(Increase) decrease in accounts receivable			(64	)			95
Decrease in accounts payable and accrued expenses			(4	)			(108	)
Other items - net			(85	)			14

Net cash provided by operating activities			1,415				961

Cash Flow from Investing Activities
Additions to properties and equipment			(1,524	)			(1,364	)
Acquisition costs, net of cash acquired			--				(17	)
Sales and retirements of properties and equipment			41				63

Net cash used in investing activities			(1,483	)			(1,318	)

Cash Flow from Financing Activities
Additions to debt			601				1,100
Retirements of debt			(458	)			(615	)
Increase (decrease) in accounts payable, banks			45				(51	)
Dividends paid			(51	)			(39	)
Retirement of preferred stock			(12	)			(2	)
Purchase of treasury stock			--				(50	)
Issuance of common stock and common stock put options			34				22

Net cash provided by financing activities			159				365

Effect of Exchange Rate Changes on Cash			3				--

Net Increase in Cash and Cash Equivalents			94				8

Cash and Cash Equivalents at Beginning of Period			34				37

Cash and Cash Equivalents at End of Period	$		128		$		45

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, 2003 and December 31, 2002, the results of operations for the three and six months ended June 30, 2003 and 2002 and cash flows for the six months ended June 30, 2003 and 2002. 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.

Changes in Accounting Principles In 2003, the Company adopted Statement of Financial Accounting Standards (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 in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. See Note 3.

In 2003, the Company adopted the fair value method of accounting for stock-based employee compensation using the prospective method described in SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure." See Note 2.

Beginning with the second quarter of 2003, the Company included derivative contracts that qualify as cash flow hedges in the ceiling test calculation in accordance with a revision to Staff Accounting Bulletin Topic 12, "Oil and Gas Producing Activities."

Derivative Instruments Derivative instruments utilized to manage or reduce commodity price risk related to the Company's equity production are accounted for under the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." Under this statement, all derivative contracts that are not normal sales contracts are carried on the balance sheet at fair value. Realized gains and losses are recognized in sales when the underlying physical gas and oil production is sold. Accordingly, realized derivative gains and losses are generally offset by similar changes in the realized value of the underlying physical gas and oil production. Realized derivative gains and losses are reflected in the average sales price of the physical gas and oil production.

Accounting for unrealized gains and losses 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. Unrealized gains and losses on derivative instruments that do not meet the conditions to qualify for hedge accounting are recognized currently in other (income) expense.

If the hedged exposure is a cash flow exposure, the effective portion of the gains and losses on the derivative instrument is reported as a component of accumulated other comprehensive income and reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The ineffective portion of the gains and losses from the derivative instrument, if any, as well as any amounts excluded from the assessment of the cash flow hedges' effectiveness are recognized currently in other (income) expense.

Derivative instruments, including both physical delivery and financially-settled purchase and sale contracts, utilized in the Company's energy trading activities are accounted for under the mark-to-market accounting method pursuant to SFAS No. 133. Under this method, the derivatives are revalued in each accounting period and unrealized gains and losses are recorded in the statement of income and carried as assets or liabilities on the balance sheet. The Company's firm transportation keep-whole agreement and the derivative financial instruments used in the management of the price risk associated with the keep-whole agreement are also accounted for under the mark-to-market accounting method pursuant to SFAS No. 133.

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 with 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. See Note 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 and outstanding put options under the reverse 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 or the date of issuance, if including such potential common shares is dilutive. See Note 9.

New Accounting Principles and Recent Developments Financial Accounting Standards Board Interpretation (FIN) No. 46, "Consolidation of Variable Interest Entities," was issued in January 2003. FIN No. 46 addresses consolidation by business enterprises of variable interest entities. It applies immediately to variable interest entities created after January 31, 2003. For entities created prior to this date, FIN No. 46 is effective for the third quarter 2003. During the second quarter of 2003, two of the Company's corporate office buildings located in The Woodlands, Texas, were acquired by a wholly-owned subsidiary of a major financial institution from the special purpose entities that had leased the buildings to the Company. The new lessor is not a variable interest entity. See Note 13. The Company does not expect the adoption of FIN No. 46 to have a material impact on the financial statements.

SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," was issued in April 2003. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities that fall within the scope of SFAS No. 133. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, with certain exceptions, and for hedging relationships designated after June 30, 2003. The Company does not expect the adoption of SFAS No. 149 to have any impact on the financial statements.

The Securities and Exchange Commission (SEC) suggests that oil and gas drilling rights acquired should be classified as an intangible asset pursuant to SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." However, the SEC is not requiring oil and gas producing companies to apply this classification or the disclosure requirements of intangible assets. Anadarko classifies the cost of oil and gas mineral rights as properties and equipment and believes that this is consistent with oil and gas accounting and industry practice. The Financial Accounting Standards Board has been asked to address this issue. If the SEC prevails on this issue, Anadarko would reclassify these costs from properties and equipment to intangible assets on the balance sheet. There would be no effect on the statement of income or cash flows.

2. Stock-Based Compensation SFAS No. 123, "Accounting for Stock-Based Compensation," defines a fair value method of accounting for an employee stock option or similar equity instrument. SFAS No. 123 allows an entity to continue measuring compensation costs for these instruments using Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." In 2003, the Company voluntarily changed to the fair value method of accounting for stock-based employee compensation for all grants after January 1, 2003 using the prospective method described in SFAS No. 148. Anadarko applies APB No. 25 for prior grants whereby no compensation expense is recognized for stock options granted with an exercise price equal to the market value of Anadarko 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 net income and EPS would have been as shown in the pro forma amounts below:

	Three Months Ended						Six Months Ended
	June 30						June 30
millions except per share amounts	2003			2002			2003			2002
Net income available before effect of change
in accounting principle as reported	$	301		$	239		$	672		$	327
Add: Stock-based employee compensation expense included
in net income, after taxes		2			2			5			5
Deduct: Total stock-based employee compensation expense
determined under the fair value method, after taxes		(5	)		(9	)		(10	)		(20	)
Pro forma net income before change in accounting principle	$	298		$	232		$	667		$	312

Basic EPS - as reported before change in accounting principle	$	1.21		$	0.96		$	2.70		$	1.32
Basic EPS - pro forma before change in accounting principle	$	1.19		$	0.93		$	2.68		$	1.26

Diluted EPS - as reported before change in accounting principle	$	1.20		$	0.93		$	2.65		$	1.27
Diluted EPS - pro forma before change in accounting principle	$	1.18		$	0.91		$	2.63		$	1.21

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, which requires the fair value of a liability for an asset retirement obligation to be recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The change was effective January 2003, and the related cumulative adjustment to net income was an increase of $47 million ($74 million before taxes) or $0.18 per share (diluted). Additionally, the Company recorded an asset retirement obligation liability of $278 million and an increase to net properties and equipment and other assets of $352 million. The application of SFAS No. 143 did not have a material impact on the Company's depreciation, depletion and amortization expense, net income or net income per share for the three and six months ended June 30, 2003. The re was no impact on the Company's cash flow as a result of adopting SFAS No. 143.

The following table provides a rollforward of the asset retirement obligations for the current year:

millions
Carrying amount of asset retirement obligations as of January 1, 2003	$	278
Liabilities incurred during 2003		84
Liabilities settled during 2003		(9	)
Accretion expense		8
Revisions in estimated cash flows		13
Carrying amount of asset retirement obligations as of June 30, 2003	$	374

The following table shows the effect of the implementation on the Company's net income and EPS as if SFAS No. 143 had been in effect in prior periods. There was no material effect on reported amounts for the three and six months ended June 30, 2002.

		Years Ended December 31
millions except per share amounts		2002			2001				2000			1999			1998
Actual
Net income (loss) available before effect of
change in accounting principle	$		825	$		(183	)	$		813	$		32	$		(49	)
Basic EPS - before change in accounting principle	$		3.32	$		(0.73	)	$		4.42	$		0.25	$		(0.41	)
Diluted EPS - before change in accounting principle	$		3.21	$		(0.73	)	$		4.25	$		0.25	$		(0.41	)

Pro forma amounts assuming SFAS No. 143 was
applied retroactively
Net income (loss) available before effect of
change in accounting principle	$		826	$		(178	)	$		812	$		33	$		(48	)
Basic EPS - before change in accounting principle	$		3.32	$		(0.71	)	$		4.41	$		0.26	$		(0.40	)
Diluted EPS - before change in accounting principle	$		3.21	$		(0.71	)	$		4.24	$		0.26	$		(0.40	)

Carrying amount of asset retirement obligation Beginning of year	$	251		$	208		$	48		$	44		$	36
End of year	$	278		$	251		$	208		$	48		$	44

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	2003		2002
Materials and supplies	$	83	$	75
Natural gas		27		16
Crude oil		14		15
NGLs		1		--
Total	$	125	$	106

5. Properties and Equipment Oil and gas properties include costs of $3.0 billion and $3.1 billion at June 30, 2003 and December 31, 2002, respectively, which were excluded from capitalized costs being amortized. These amounts represent costs associated with unevaluated properties and major development projects. At June 30, 2003 and December 31, 2002, the Company's investment in countries where reserves have not been established was $73 million and $63 million, respectively.

Total interest costs incurred during the second quarter of 2003 and 2002 were $98 million and $89 million, respectively. Of these amounts, the Company capitalized $30 million and $41 million during the second quarter of 2003 and 2002, respectively. Total interest costs incurred during the first six months of 2003 and 2002 were $192 million and $176 million, respectively. Of these amounts, the Company capitalized $64 million and $79 million during the first six months of 2003 and 2002, respectively. Capitalized interest is included as part of the cost of oil and gas properties. 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.

In addition to capitalized interest, the Company also capitalized internal costs of $45 million and $57 million during the second quarter of 2003 and 2002, respectively. For the first six months of 2003 and 2002, the Company capitalized internal costs of $97 million and $100 million, respectively. These internal costs were directly related to exploration and development activities and are included as part of the cost of oil and gas properties.

6. Debt A summary of debt follows:

		June 30, 2003				December 31, 2002
millions		Principal		Carrying Value		Principal		Carrying Value
Notes Payable, Banks		$	100	$	100	$	44	$	44
Commercial Paper			375		375		181		181
Long-term Portion of Capital Lease			6		6		7		7
6 3/4% Notes due 2003			--		--		73		73
5 7/8% Notes due 2003			83		83		83		83
6.5% Notes due 2005			170		167		170		166
7.375% Debentures due 2006			88		88		88		87
7% Notes due 2006			174		171		174		171
5 3/8% Notes due 2007			650		647		650		647
3.25% Notes due 2008			350		349		--		--
6.75% Notes due 2008			116		111		116		111
7.8% Debentures due 2008			11		11		11		11
7.3% Notes due 2009			85		83		85		83
6 3/4% Notes due 2011			950		910		950		912
6 1/8% Notes due 2012			400		395		400		395
5% Notes due 2012			300		297		300		297
7.05% Debentures due 2018			114		105		114		105
Zero Coupon Convertible
	Debentures due 2020		--		--		380		380
Zero Yield Puttable Contingent
	Debt Securities due 2021		30		30		30		30
7.5% Debentures due 2026			112		106		112		106
7% Debentures due 2027			54		54		54		54
6.625% Debentures due 2028			17		17		17		17
7.15% Debentures due 2028			235		212		235		212
7.20% Debentures due 2029			135		135		135		135
7.95% Debentures due 2029			117		117		117		117
7 1/2% Notes due 2031			900		862		900		862
7.73% Debentures due 2096			61		61		61		61
7.5% Debentures due 2096			83		75		83		75
7 1/4% Debentures due 2096			49		49		49		49
Total debt		$	5,765		5,616	$	5,619		5,471
Less current portion					445				300
Total long-term debt				$	5,171			$	5,171

At June 30, 2003, $588 million of notes, debentures and securities will mature or may be put to Anadarko within the next twelve months. In accordance with SFAS No. 6, "Classification of Short-term Obligations Expected to be Refinanced," $143 million of this amount is classified as long-term debt, since Anadarko has the intent and ability to refinance this debt under the terms of Anadarko's Bank Credit Agreements.

In April 2003, Anadarko redeemed for cash its callable Zero Coupon Convertible Debentures due 2020. Anadarko funded the $384 million redemption with available credit facilities that carry a lower effective interest rate. Anadarko paid $556.46 per debenture, reflecting the issue price plus accrued interest at 3.5%.

In May 2003, the Company issued $350 million principal amount of 3.25% Notes due 2008. The net proceeds from this issuance were used to reduce floating interest rate debt that was incurred in April 2003 to redeem the Zero Coupon Convertible Debentures due 2020.

7. Financial Instruments

Commodity 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 commodity 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 options, futures and swaps.

The Company also enters into commodity derivative financial instruments (options, futures and swaps) and physical delivery and purchase and sale contracts for trading purposes with the objective of generating profits from exposure to changes in the market price of natural gas and crude oil. These derivative 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 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 gas and oil 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 the Company's expected future oil and gas sales. Settlements of futures contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the International Petroleum Exchange and have nominal credit risk. Swap, over the counter traded option and physical delivery agreements expose the Company to credit risk to the extent t he counter-party is unable to meet its settlement commitment. The Company monitors the creditworthiness of each counter-party. In addition, the Company routinely exercises its contractual right to net realized gains against realized losses in settling with its swap and option counter-parties.

Cash Flow Hedges At June 30, 2003 and December 31, 2002, 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 gas and oil production. The fixed price physical delivery contracts are excluded from hedge accounting treatment under the normal purchase, 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 are as follows:

	June 30,			December 31,
millions	2003			2002
Fair value - Asset (Liability)
Current	$	(279	)	$	(115	)
Non-current		(82	)		(39	)
Total	$	(361	)	$	(154	)

Accumulated other comprehensive income (loss) before tax	$	(300	)	$	(128	)

Accumulated other comprehensive income (loss) after tax	$	(189	)	$	(81	)

The difference between the fair values and the unrealized gain (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 $152 million ($96 million after taxes) of net losses in the accumulated other comprehensive income balance as of June 30, 2003 are expected to be reclassified into oil and gas sales during 2003 as the hedged transactions occur. During the three and six months ended June 30, 2003, unrealized pre-tax losses of $17 million and $13 million, respectively, were reclassified from accumulated other comprehensive income to other (income) expense due to the discontinuance of hedge accounting for certain cash flow hedges of previously anticipated oil and gas production that will not occur. These hedges have been re-designated to other forecasted production.

As of June 30, 2003, the Company had the following cash flow hedges through 2005 related to its gas and oil producing activities (non-trading activities). There are no significant cash flow hedges beyond 2005.


	Third			Fourth
	Quarter			Quarter					Annual
		2003			2003				2004				2005
Natural Gas

Three-Way Collars (thousand MMBtu/d)		399				399				269			19
NYMEX price per MMBtu
Floor sold price	$	2.91		$		2.91		$		2.67		$	2.20
Floor purchased price	$	3.97		$		3.97		$		3.65		$	3.00
Ceiling sold price	$	5.01		$		5.01		$		5.30		$	4.83


Two-Way Collars (thousand MMBtu/d)		61				61				44			26
NYMEX price per MMBtu
Floor purchased price	$	4.79		$		4.79		$		4.29		$	3.76
Ceiling sold price	$	8.73		$		8.73		$		6.43		$	5.65

Fixed Price (thousand MMBtu/d)		498				495				259			33
NYMEX price per MMBtu	$	4.29		$		4.28		$		3.72		$	3.00

Total (thousand MMBtu/d)		958				955				572			78

Basis Swaps (thousand MMBtu/d)		695				695				138			20
Price per MMBtu	$	(0.21	)	$		(0.21	)	$		(0.06	)	$	(0.09	)


Crude Oil

Three-Way Collars (MBbls/d)		53				53				20			--
NYMEX price per barrel
Floor sold price	$	18.62		$		18.62		$		18.00		$	--
Floor purchased price	$	23.81		$		23.81		$		22.00		$	--
Ceiling sold price	$	27.39		$		27.39		$		28.07		$	--


Two-Way Collars (MBbls/d)		4				4				3			2
NYMEX price per barrel
Floor purchased price	$	25.00		$		25.00		$		22.00		$	22.00
Ceiling sold price	$	28.29		$		28.29		$		26.32		$	26.32

Fixed Price (MBbls/d)		14				14				8			--
NYMEX price per barrel	$	25.39		$		25.39		$		23.09		$	--

Total (MBbls/d)		71				71				31			2

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 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. These contracts 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 portfolio (both physical delivery and financially settled contracts) as of June 30, 2003 and December 31, 2002 are as follows:

	June 30,		December 31,
millions	2003		2002
Fair value - Asset (Liability)
Current	$	5	$	(5	)
Non-current		2		--
Total	$	7	$	(5	)

Firm Transportation Keep-Whole Agreement Anadarko Holding Company (Anadarko Holding) was a party to several long-term firm gas transportation agreements that supported its gas marketing program within its gathering, processing and marketing (GPM) business segment, which was sold in 1999 to Duke. Most of the GPM's long-term firm transportation contracts were transferred to Duke in the GPM disposition. One contract was retained, but is managed and operated by Duke. Anadarko is not responsible for the operations of the contracts and does not utilize the associated transportation assets to transport the Company's natural gas. As part of the GPM disposition, Anadarko Holding agreed to pay Duke if transportation market values fall below the fixed contract transportation rates, while Duke will pay Anadarko Holding if the transportation market values exceed the contract transportation rates (keep-whole agreement). This keep-whole agreement will be in effect until the earlier of each contrac t's expiration date or February 2009. The Company may periodically use derivative instruments to reduce its exposure under the Duke keep-whole agreement to potential decreases in future transportation market values. While derivatives are intended to reduce the Company's exposure to declines in transportation market rates, they also limit the potential to benefit from market price increases. Due to decreased liquidity, the use of derivative instruments to manage this risk is generally limited to the forward twelve months. Net (payments to) or receipts from Duke for the three months ended June 30, 2003 and 2002 were $14 million and $(2) million, respectively, and for the six months ended June 30, 2003 and 2002 net (payments to) or receipts from Duke were $24 million and $(12) 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 with 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 twelve months are not reliable indicators of fair value due to decreasing liquidity. Accordingly, the fair value of the long-term portion is estimated based on historical natural gas basis prices, discounted at 10% per year. Management also periodically evaluates the supply and demand factors (such as expected drilling activity, anticipated pipeline construction projects, expected changes in demand at pipeline delivery points, etc.) that may impact the future market value of the firm transportation capacity to determine if the estimated fair value should be adjusted. The Company recognized other expense of $17 million and other income of $16 million for the three month s ended June 30, 2003 and 2002, respectively, and other income of $18 million and $10 million for the six months ended June 30, 2003 and 2002, respectively, related to the keep-whole agreement and associated derivative instruments. As of June 30, 2003 and December 31, 2002, accounts payable included $20 million and $5 million and other long-term liabilities included $58 million and $68 million, respectively, 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, 2003 are as follows:

millions		Undiscounted			Discounted

2003	$		11	$		11
2004			23			21
2005			20			17
2006			19			14
2007			14			10
Later years			9			5
Total	$		96	$		78

As of June 30, 2003 and December 31, 2002, the Company had no material volumes of natural gas hedges under derivative financial instruments related to the firm transportation keep-whole agreement.

8. Preferred Stock For the first and second quarters of 2003 and 2002, dividends of $13.65 per share (equivalent to $1.365 per Depositary Share) were paid to holders of preferred stock. During the first quarter of 2003, the Company repurchased $12 million of preferred stock.

9. Common Stock The Company's credit agreements allow for a maximum capitalization ratio of 60% debt, exclusive of the effect of any non-cash writedowns. While there is no specific restriction on paying dividends, under the maximum debt capitalization ratio retained earnings were not restricted as to the payment of dividends at June 30, 2003 and December 31, 2002.

The reconciliation between basic and diluted EPS is as follows:

		Three Months Ended							Three Months Ended
		June 30, 2003							June 30, 2002
						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		$	301		250	$	1.21	$		239		248	$	0.96
Effect of convertible debentures
and ZYP-CODES			1		1					2		9
Effect of dilutive stock options and
performance-based stock awards			--		1					--		2
Diluted EPS
Net income available before change
in accounting principle plus
assumed conversion		$	302		252	$	1.20	$		241		259	$	0.93

		Six Months Ended							Six Months Ended
		June 30, 2003							June 30, 2002
						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		$	672		249	$	2.70	$		327		248	$	1.32
Effect of convertible debentures
and ZYP-CODES			3		5					4		11
Effect of dilutive stock options and
performance-based stock awards			--		1					--		2
Diluted EPS
Net income available before change
in accounting principle plus
assumed conversion		$	675		255	$	2.65	$		331		261	$	1.27

For 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. For the three and six months ended June 30, 2002, options for 1.4 million average shares 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.

For the three and six months ended June 30, 2002, a put option for 1.0 million shares of common stock was excluded from the diluted EPS calculation because the put option's exercise price was less than the average market price of common stock for the periods.

10. Statements of Cash Flows Supplemental Information The amounts of cash paid (received) for interest (net of amounts capitalized) and income taxes are as follows:

		Six Months Ended
		June 30
millions		2003			2002
Interest	$		114	$		76
Income taxes	$		72	$		(50	)

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

		Oil and Gas		Marketing				Intercompany
		Exploration		And				Eliminations
millions		and Production		Trading		Minerals		and All Other			Total
Three Months Ended June 30:
2003
Revenues		$	710	$	41	$	8	$	518		$	1,277
Intersegment revenues			514		4		--		(518	)		--
	Total revenues		1,224		45		8		--			1,277
Impairments related to oil and gas properties			13		--		--		--			13
Income (loss) before income taxes		$	630	$	1	$	6	$	(165	)	$	472

2002
Revenues		$	639	$	34	$	9	$	320		$	1,002
Intersegment revenues			317		2		--		(319	)		--
	Total revenues		956		36		9		1			1,002
Impairments related to oil and gas properties			25		--		--		--			25
Income (loss) before income taxes		$	424	$	19	$	8	$	(114	)	$	337

Six Months Ended June 30:
2003
Revenues		$	1,475	$	55	$	17	$	987		$	2,534
Intersegment revenues			982		8		--		(990	)		--
	Total revenues		2,457		63		17		(3	)		2,534
Impairments related to oil and gas properties			18		--		--		--			18
Income (loss) before income taxes		$	1,344	$	15	$	14	$	(301	)	$	1,072
Net properties and equipment		$	14,867	$	257	$	1,200	$	435		$	16,759
Goodwill		$	1,472	$	--	$	--	$	--		$	1,472

2002
Revenues		$	1,152	$	58	$	22	$	560		$	1,792
Intersegment revenues			552		4		--		(556	)		--
	Total revenues		1,704		62		22		4			1,792
Impairments related to oil and gas properties			33		--		--		--			33
Income (loss) before income taxes		$	682	$	5	$	19	$	(237	)	$	469
Net properties and equipment		$	12,632	$	248	$	1,204	$	414		$	14,498
Goodwill		$	1,443	$	--	$	--	$	--		$	1,443

12. Other (Income) Expense Other (income) expense consists of the following:

		Three Months Ended						Six Months Ended
		June 30						June 30
millions		2003			2002			2003			2002
Unrealized (gain) loss on derivative financial instruments		$	29		$	(3	)	$	33		$	8
Firm transportation keep-whole contract valuation (See Note 7)			17			(16	)		(18	)		(10	)
Foreign currency exchange *			(6	)		(9	)		(14	)		(10	)
Gas sales contracts - accretion of discount			2			2			4			4
Other			(2	)		5			(2	)		10
Total		$	40		$	(21	)	$	3		$	2

*	The three and six months ended June 30, 2003 exclude zero and $8 million, respectively, in transaction losses related to remeasurement of the Venezuela deferred tax liability. The three and six months ended June 30, 2002 exclude $26 million and $33 million, respectively, in transaction gains related primarily to remeasurement of the Venezuela deferred tax liability, which is included in income tax expense.

13. Commitments

Financial Operating Leases During the second quarter of 2003, two of the Company's corporate office buildings located in The Woodlands, Texas, were acquired by a wholly-owned subsidiary of a major financial institution from the special purpose entities that had leased the buildings to the Company. The original leases were amended and restated, and, other than the extension of the period of the lease, the terms of the replacement lease between the Company and the real estate development company were essentially unchanged. The total amount funded under the new lease was approximately $214 million. The Company is not required to consolidate the lease in the financial statements and has accounted for this arrangement as an operating lease.

The lease term is seven years and the monthly lease payments are based on the London interbank borrowing rate applied against the lease balance. The lease contains various covenants including covenants regarding the Company's financial condition. Default under the lease, including violation of these covenants, could require the Company to purchase the facilities for a specified amount, which approximates the lessor's original cost of $214 million. As of June 30, 2003, the Company was in compliance with these covenants.

At the end of the lease term, the Company has an option to either purchase the facilities for the purchase option amount of the lease balance plus any outstanding lease payments or assist the lessor in the sale of the properties. The Company has provided a residual value guarantee for any deficiency of up to $187 million if the properties are sold for less than the lease balance. In addition, the Company is entitled to any proceeds from a sale of the properties in excess of the lease balance.

The Company has recorded an $8 million guarantee liability and corresponding prepaid rent asset at June 30, 2003 related to its residual value guarantee on the corporate office buildings. If the Company determines that it is probable that the expected fair value of the property at the end of the lease term will be less than the lease balance, the liability will be adjusted accordingly. Currently, Management does not believe it is probable that the fair market value of the properties will be less than the lease balance at the end of the lease term.

Production Platform In 2002, the Company signed an agreement under which a floating production platform for its Marco Polo discovery in Green Canyon Block 608 of the Gulf of Mexico will be installed. The other party to the agreement will construct and own the platform and production facilities that upon completion, expected in late 2003, will be operated by Anadarko. The agreement provides that Anadarko dedicate its production from Green Canyon Block 608 and 11 other Green Canyon blocks to the production facilities. The agreement requires a monthly demand charge of slightly over $2 million for five years beginning at the time of project completion and a processing fee based upon production throughput. The agreement does not contain any purchase options, purchase obligations or value guarantees.

14. 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 and benzene while working at a refinery in Corpus Christi, Texas, which Anadarko Holding sold 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 During September 2000, the Company was named as a defendant in a case styled U.S. of America ex rel. Harold E. Wright v. AGIP Company, et al. (the "Gas Qui Tam case") filed in the U.S. District Court for the Eastern District of Texas, Lufkin Division. This lawsuit generally alleges that the Company and 118 other defendants improperly measured and otherwise undervalued natural gas in connection with a payment of royalties on production from federal and Indian lands. The case has been transferred to the U.S. District Court, Multi-District Litigation Docket pending in Wyoming. Based on the Company's present understanding of the various governmental and False Claims Act proceedings described above, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. However, if the Company is found to have violated the Civil False Claims Act, the Company could be subject to a variety of sanctions, including trebl e damages and substantial monetary fines. Motions to dismiss on the grounds that plaintiffs did not provide new information for the government to file suit upon were filed in January 2003. The defendants expected a hearing in the third quarter of 2003; however, the Wyoming federal judge has suggested that the case be remanded back to the Texas federal court, which will delay the proceedings.

A group of royalty owners purporting to represent Anadarko Holding's gas royalty owners in Texas (Neinast, et al.) was granted class action certification 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 $100 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. 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 C ompany is vigorously contesting this new petition.

A class action lawsuit entitled Gilbert H. Coulter, et al. v. Anadarko Petroleum Corporation has been certified in the 26th Judicial District Court, Stevens County, Kansas. In this action, the royalty owners contend that royalty was underpaid as a result of the deduction for certain post-production costs in the calculation of royalty. The Company believes that its method of calculating royalty was proper, and thus plaintiffs' claims are without merit. This case was certified as a class action in August 2000 and was tried in February 2002. It is uncertain at this time when the trial court will render its ruling.

A royalty owner action styled Texas Osage 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 Anadarko Holding (formerly UPRG, Inc.) failed to properly pay royalties due Texas Osage. In addition, the plaintiff contends that Anadarko Holding failed to comply with express and implied provisions of various leases between April 1993 and the present. The Company is vigorously contesting the claims and believes royalties were properly paid based upon prices received in sales made to third-party purchasers or at sales prices comparable to third-party sales. The plaintiff served expert reports in the third quarter of 2003, which calculate the plaintiff's royalty damages in a range between $2 million and $5 million. The plaintiff also claims additional damages with regard to certain specific land issues that are not material. Trial of this ma tter currently is set for October 2003; however, the Company expects that the court will postpone the trial until an undetermined future date.

CITGO Litigation CITGO Petroleum Corporation's (CITGO) claims arise out of an Asset Purchase and Contribution Agreement in 1987 whereby Anadarko Holding's predecessor sold a refinery located in Corpus Christi, Texas, to CITGO's predecessor. After the sale of the refinery, numerous individuals living near the refinery sued CITGO (the Neighborhood Litigation) thereby implicating the Asset Purchase and Contribution Agreement indemnity provision. CITGO and Anadarko Holding eventually entered into a settlement agreement to allocate, on an interim basis, each party's liability for defense and liability cost in that and related litigation. That agreement provides that once the Neighborhood Litigation and certain related claims are resolved, then the parties will determine their final indemnity obligations to each other through binding arbitration. At the present time, Anadarko Holding and CITGO have agreed to defer arbitrating the allocation of responsibility for this liability in order to focus their efforts on a global settlement. Arbitration will resume upon request of either CITGO or Anadarko Holding. Negotiations and discussions with CITGO continue. Anadarko Holding has offered to settle all outstanding issues for approximately $4 million and a liability for this amount has been accrued.

Kansas Ad Valorem Tax

General The Natural Gas Policy Act of 1978 allowed a "severance, production or similar" tax to be included as an add-on, over and above the maximum lawful price charged for natural gas. Based on the Federal Energy Regulatory Commission (FERC) ruling that the Kansas ad valorem tax was such a tax, the Company collected the Kansas ad valorem tax.

Background of PanEnergy Litigation FERC's ruling regarding the ability of producers to collect the Kansas ad valorem tax was appealed to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The Court held in June 1988 that FERC failed to provide a reasoned basis for its findings and remanded the case to FERC.

Ultimately, the D.C. Circuit issued a decision on August 2, 1996 ruling that producers must refund all Kansas ad valorem taxes collected relating to production since October 1983. The Company filed a petition for writ of certiorari with the Supreme Court. That petition was denied on May 12, 1997.

PanEnergy Litigation On May 13, 1997, the Company filed a lawsuit in the Federal District Court for the Southern District of Texas against PanEnergy seeking declaration that pursuant to prior agreements Anadarko is not required to issue refunds to PanEnergy for the principal amount of $14 million (before taxes) and, if the petition for adjustment is denied in its entirety by FERC with respect to PanEnergy refunds, interest in an amount of $38 million (before taxes). The Company also sought from PanEnergy the return of the $1 million (before taxes) charged against income in 1993 and 1994. In October 2000, the U.S. Magistrate issued recommendations concerning motions for summary judgment previously filed by both parties. In essence, the Magistrate's recommendation finds that the Company should be responsible for refunds attributable to the time period following August 1, 1985 while Duke Energy (as the successor company to Anadarko Production Company) should be responsible for refunds attributable to the time period before August 1, 1985.

In 2001, the Company paid $15 million for settlement of the liability for Kansas ad valorem tax reimbursements for the interstate portion of this matter. The remaining dispute between the Company and PanEnergy is attributable to the Cimmaron River System (CRS). The Company filed a settlement agreement, which has been approved, in the CRS matter during January 2003. The Company paid approximately $5 million under the CRS settlement agreement during the second quarter of 2003. Anadarko's net income for 2001 included a $20 million charge (before taxes) related to these settlement agreements.

Other Litigation The Company has a reserve of about $2 million for Kansas ad valorem tax refunds. This amount reflects all principal and interest which may be due at the conclusion of all regulatory proceedings and litigation to parties other than PanEnergy.

Lease Agreement The Company, through one of its affiliates, is a party to a lease agreement (base lease) for the leveraged lease financing of the Corpus Christi West Plant Refinery (West Plant) with an initial term expiring December 31, 2003, and successive renewal periods lasting through January 31, 2011. At the conclusion of the initial term of the base lease, any renewal period or January 31, 2011, the Company has the right to purchase the West Plant at the fair market sales value. In connection with the sale by Anadarko Holding of its refining business in 1987 and 1989, the West Plant was subleased to CITGO with sublease payments during the initial term equal to the Company's base lease payments and during any renewal period equal to the lesser of the base lease rental, which will be tied to the annual fair market rental value, or a specified maximum amount. Additionally, CITGO has the option under the sublease to purchase the West Plant from the Company at the conclusion of the initial term or any renewal term at the fair market sales value, or on January 31, 2011 at a nominal price. If the fair market rental value of the base lease during any renewal term exceeds CITGO's maximum obligation under the sublease, or if CITGO purchases the West Plant on January 31, 2011 and the fair market sales value of the West Plant is greater than the purchase amount specified in the sublease, the Company will be obligated to pay the excess amounts.

The Company and the lessor are currently in the process of determining the current fair market rental and fair market sales value of the West Plant and expect the current determination will be completed by year-end 2003. Based on the information currently available, no liability has been recognized as of June 30, 2003.

Guarantees Anadarko is guarantor for certain obligations of its wholly-owned and consolidated subsidiaries, which are included in the consolidated financial statements and notes. The Company also has made residual value guarantees in connection with aircraft operating leases for any deficiency if the aircraft are sold for less than the maximum lessee risk amount of approximately $15 million. No liability has been recorded related to these guarantees.

The Company is guarantor for specific financial obligations of a trona mining affiliate. The investment in this entity, which is not a consolidated subsidiary, is accounted for using the equity method. The Company has guaranteed a portion of amounts due under a revolving credit agreement and various letters of credit used to secure Industrial Revenue Bonds and environmental surety bonds. The Company's guarantee under the revolving credit agreement expires in 2005 coinciding with the maturity of that agreement. Expiration dates of the Company's guarantees under the letters of credit securing the Industrial Revenue Bonds and environmental surety bonds range from 2003 to 2004; however, it is the intent of the Company to renew these letters of credit and the related guarantees until the maturity dates of the obligations which range from 2004 to 2018. The amounts the Company would be obligated to pay should the affiliate default on these obligations would be up to $15 million for the revolving credit agreement, $8 million for environmental surety bonds and $15 million for the Industrial Revenue Bonds. No liability has been recognized for these guarantees.

In connection with its various acquisitions, the Company routinely indemnifies the former officers and directors of acquired companies in respect to acts or omissions occurring prior to the effective date of the acquisition. The Company also agrees to maintain directors' and officers' liability insurance on these individuals with respect to acts or omissions occurring prior to the acquisition, generally for a period of six years. No liability has been recognized for these indemnifications.

The Company also provides certain indemnifications in relation to dispositions of assets. These indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. In connection with a sale of properties in 2001, the Company indemnified the purchaser for the use of certain currency remeasurement losses utilized by the Company in previously filed tax returns. These losses have been disallowed by the taxing authorities. The Company has filed a lawsuit seeking relief. The Company believes it is probable that these losses will have to be settled with the purchaser in cash. The Company has a $22 million liability recorded for the contingency.

15. Subsequent Event

On July 31, 2003, Anadarko announced a cost reduction plan that is expected to reduce overhead costs from the Company's annual cost structure, which includes cuts in personnel and corporate expenses. One time costs associated with these cost reductions are expected to be approximately $40 million ($25 million after taxes.) These costs will be charged to income as specific liabilities are incurred. It is estimated that $35 million ($22 million after taxes) will be reflected in third quarter 2003 results.

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

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company's operations, economic performance and financial condition. These forward looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, and those statements preceded by, followed by or that otherwise include the words "believes", "expects", "anticipates", "intends", "estimates", "projects", "target", "goal", "plans", "objective", "should" or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward looking statements contained in the Private Securities Litigation Reform Act of 1995. 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" in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in the Company's 2002 Annual Report on Form 10-K.
Financial Results

Selected Financial Data

	Three Months Ended					Six Months Ended
	June 30					June 30
millions except per share amounts	2003		2002			2003		2002

Revenues	$	1,277	$	1,002		$	2,534	$	1,792
Costs and expenses	$	697	$	638		$	1,331	$	1,224
Interest expense	$	68	$	48		$	128	$	97
Other (income) expense	$	40	$	(21	)	$	3	$	2
Income tax expense	$	170	$	96		$	398	$	139
Net income available to common stockholders before
cumulative effect of change in accounting principle	$	301	$	239		$	672	$	327
Cumulative effect of change in accounting principle		--		--			47		--
Net income available to common stockholders	$	301	$	239		$	719	$	327
Earnings per share - before cumulative effect
of change in accounting principle - basic	$	1.21	$	0.96		$	2.70	$	1.32
Earnings per share - before cumulative effect
of change in accounting principle - diluted	$	1.20	$	0.93		$	2.65	$	1.27
Cumulative effect of change in accounting principle
per share - basic	$	--	$	--		$	0.19	$	--
Cumulative effect of change in accounting principle
per share - diluted	$	--	$	--		$	0.18	$	--
Earnings per share - basic	$	1.21	$	0.96		$	2.89	$	1.32
Earnings per share - diluted	$	1.20	$	0.93		$	2.83	$	1.27

Net Income In the second quarter of 2003, Anadarko reported net income available to common stockholders of $301 million, or $1.20 per share (diluted) compared to net income available to common stockholders of $239 million, or $0.93 per share (diluted) for the second quarter of 2002. For the six-month period ended June 30, 2003, Anadarko's net income available to common stockholders was $719 million, or $2.83 per share (diluted). For the six months ended June 30, 2003, net income available to common stockholders before the cumulative effect of change in accounting principle was $672 million, or $2.65 per share (diluted). By comparison, for the six months ended June 30, 2002, Anadarko's net income available to common stockholders was $327 million, or $1.27 per share (diluted).

In 2003, the Company adopted Statement of Financial Accounting Standards (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 in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The change was effective January 2003 and the related cumulative adjustment to net income was an increase of $47 million after taxes, or $0.18 per share (diluted). The application of SFAS No. 143 did not have a material impact on the Company's depreciation, depletion and amortization (DD&A) rate. There was no impact on the Company's cash flow as a result of adopting SFAS No. 143.

Revenues

	Three Months Ended				Six Months Ended
	June 30				June 30
millions	2003		2002		2003		2002

Gas sales	$	720	$	497	$	1,428	$	865
Oil and condensate sales		439		422		884		775
Natural gas liquids sales		85		56		170		99
Other sales		33		27		52		53
Total	$	1,277	$	1,002	$	2,534	$	1,792

Total revenues for the second quarter 2003 increased $275 million or 27% compared to the second quarter of 2002. For the six months ended June 30, 2003, total revenues increased $742 million or 41% compared to the six months ended June 30, 2002. The increase in revenues is due primarily to significant increases in commodity prices, partially offset by a decrease in sales volumes.

Analysis of Oil and Gas Sales Volumes

		Three Months Ended				Six Months Ended
		June 30				June 30
		2003		2002		2003		2002
Barrels of Oil Equivalent (MMBOE)
	United States		33		34		65		66
	Canada		8		8		15		18
	Algeria		5		6		10		11
	Other International		2		2		3		4
	Total		48		50		93		99

Barrels of Oil Equivalent per Day (MBOE/d)
	United States		367		365		358		368
	Canada		84		98		84		98
	Algeria		58		61		53		60
	Other International		18		22		17		23
	Total		527		546		512		549

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

During the second quarter of 2003, Anadarko sold 48 MMBOE, a decrease of 2 MMBOE or 4% compared to sales of 50 MMBOE in the second quarter of 2002. For the six months ended June 30, 2003, Anadarko sold 93 MMBOE, a decrease of 6 MMBOE or 6% compared to sales of 99 MMBOE for the same period of 2002. The decreases in volumes during 2003 were due primarily to the 2002 divestiture of heavy oil properties in Canada, lower gas production in the Gulf of Mexico and slightly lower production in Algeria and other international areas.

Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs marketing strategies to help manage volumes, and mitigate the effect of price volatility which is likely to continue in the future. See Derivative Instruments under Item 3 of this Form 10-Q.

Natural Gas Sales Volumes and Average Prices

		Three Months Ended				Six Months Ended
		June 30				June 30
		2003		2002		2003		2002

United States (Bcf)			122		131		241		261
	MMcf/d		1,350		1,435		1,333		1,446
	Price per Mcf	$	4.46	$	3.02	$	4.48	$	2.63

Canada (Bcf)			36		32		71		64
	MMcf/d		391		356		390		352
	Price per Mcf	$	4.81	$	3.17	$	4.90	$	2.79

Total (Bcf)			158		163		312		325
	MMcf/d		1,741		1,791		1,723		1,798
	Price per Mcf	$	4.54	$	3.05	$	4.58	$	2.66


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

The Company's natural gas sales volumes for the second quarter 2003 were down 5 Bcf or 3% compared to the second quarter of 2002. For the first six months of 2003, natural gas sales volumes were down 13 Bcf or 4% compared to the same period of 2002. The decreases in volumes are due primarily to a decrease in the Company's sales volumes within the United States, primarily in the Gulf of Mexico, as a result of operational issues and natural production declines. This decrease is partially offset by increases in natural gas sales volumes in Canada due to successful exploration and development activities. 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, 2003 increased 49% and 72%, respectively, from the same periods of 2002. Strong demand in North American consumption due to colder weather and declining gas supply resulted in significantly higher North American gas prices. These higher prices were partially offset by commodity price hedges on 52% and 45% of natural gas sales volumes during the three and six months ended June 30, 2003, respectively, that reduced the Company's exposure to low prices and limited participation in higher prices. As of June 30, 2003, the Company has hedged 52% of its remaining expected 2003 natural gas wellhead sales volumes and about 30% of its expected natural gas wellhead sales volumes for 2004. See Derivative 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
		2003		2002		2003		2002

United States (MMBbls)			8		8		17		16
	MBbls/d		97		85		94		88
	Price per barrel	$	26.05	$	23.29	$	26.92	$	21.09

Canada (MMBbls)			2		3		3		7
	MBbls/d		17		37		17		37
	Price per barrel	$	27.04	$	20.21	$	27.22	$	18.17

Algeria (MMBbls)			5		6		10		11
	MBbls/d		58		61		53		60
	Price per barrel	$	25.36	$	23.48	$	28.25	$	22.08

Other International (MMBbls)			2		2		3		4
	MBbls/d		18		22		17		23
	Price per barrel	$	20.55	$	21.21	$	22.41	$	18.19

Total (MMBbls)			17		19		33		38
	MBbls/d		190		205		181		208
	Price per barrel	$	25.41	$	22.57	$	26.91	$	20.53


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

Anadarko's crude oil and condensate sales volumes for the second quarter of 2003 decreased 2 MMBbls or 11% compared to the second quarter of 2002. The decrease in crude oil and condensate volumes was due to a decrease of 1 MMBbls in Canada and a decrease of 1 MMBbls in Algeria. Crude oil and condensate sales volumes for the six months ended June 30, 2003 decreased 5 MMBbls or 13% compared to the six months ended June 30, 2002. The decrease in crude oil and condensate volumes was due to a decrease of 4 MMBbls in Canada, a decrease of 1 MMBbls in Algeria and a decrease of 1 MMBbls in other international areas related primarily to operations in Venezuela, partially offset by an increase of 1 MMBbls in the United States.

The decrease in Canada volumes is due largely to the sale of the Company's heavy oil assets in late 2002. The decrease in Algeria volumes is due primarily to the completion of cost recovery, whereby Anadarko was reimbursed for previous exploration spending with additional barrels of oil production. The decrease in Venezuela volumes is due primarily to the contract terms with the national oil company of Venezuela under which Anadarko earns a fee that is translated into barrels of oil based on current prices that results in lower oil volumes when prices increase. 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, 2003 increased 13% and 31%, respectively, compared to the same periods of 2002. The increase in crude oil prices during 2003 is attributed primarily to political unrest in the Middle East, the oil workers' strike in Venezuela, low oil inventory levels and increased demand. These higher prices were partially offset by commodity price hedges on 36% and 39% of crude oil and condensate sales volumes during the three and six months ended June 30, 2003, respectively, that reduced the Company's exposure to low prices and limited participation in higher prices. As of June 30, 2003, the Company has hedged 36% of its anticipated oil and condensate sales volumes for the remainder of 2003 and about 15% of its expected oil and condensate sales volumes for 2004. See Derivative 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
		2003		2002		2003		2002

Total (MMBbls)			4		4		8		7
	MBbls/d		47		42		44		41
	Price per barrel	$	20.09	$	14.43	$	21.49	$	13.17

The Company's natural gas liquids (NGLs) sales volumes for the three months ended June 30, 2003 were essentially flat compared to the same period of 2002. For the six months ended June 30, 2003, NGLs sales volumes increased 1 MMBbls or 14% compared to the same period of 2002. During the three and six months ended June 30, 2003, average NGLs prices increased 39% and 63%, respectively, compared to the same periods of 2002. The increase in NGLs prices is attributed to a comparable rise in natural gas prices coupled with historically lower levels of NGLs inventories in the United States. NGLs production is dependent on natural gas prices and the economics of processing the natural gas volumes to extract NGLs.

Costs and Expenses

	Three Months Ended				Six Months Ended
	June 30				June 30
millions	2003		2002		2003		2002

Operating expenses	$	204	$	200	$	380	$	383
Administrative and general		86		77		174		149
Depreciation, depletion and amortization		323		274		613		541
Other taxes		71		62		146		118
Impairments related to oil and gas properties		13		25		18		33
Total	$	697	$	638	$	1,331	$	1,224

During the second quarter of 2003, Anadarko's costs and expenses increased $59 million or 9% compared to the second quarter of 2002 due to the following factors:

--	Operating expenses increased $4 million (2%) primarily due to an increase in operating expenses related to oil and gas producing activities, partially offset by a decrease in costs associated with processing NGLs.
--	Administrative and general expenses increased $9 million (12%) primarily due to increases in salaries and benefits expenses associated with the Company's workforce.
--	DD&A expense increased $49 million (18%) primarily due to increases in the DD&A rates.
--	Other taxes increased $9 million (15%) primarily due to an increase in production taxes related to the significantly higher commodity prices received in 2003.
--	Impairments of oil and gas properties were primarily due to unsuccessful exploration activities in Australia, Gabon and Tunisia in 2003 and Congo and Oman in 2002.

For the six-month period ended June 30, 2003, costs and expenses increased $107 million or 9% compared to the same period of 2002 due to the following factors:

--	Operating expenses decreased $3 million (1%) primarily due to a decrease in costs associated with processing NGLs, partially offset by an increase in operating expenses related to oil and gas producing activities.
--	Administrative and general expenses increased $25 million (17%) primarily due to increases in salaries and benefits expenses associated with the Company's workforce.
--	DD&A expense increased $72 million (13%) primarily due to increases in the DD&A rates.
--	Other taxes increased $28 million (24%) primarily due to an increase in production taxes related to the significantly higher commodity prices received in 2003.
--	Impairments of oil and gas properties were primarily due to unsuccessful exploration activities in Australia, Tunisia and Gabon in 2003 and Congo, Oman and Australia in 2002.

Interest Expense

	Three Months Ended						Six Months Ended
	June 30						June 30
millions	2003			2002			2003			2002

Gross interest expense	$	98		$	89		$	192		$	176
Capitalized interest		(30	)		(41	)		(64	)		(79	)
Net interest expense	$	68		$	48		$	128		$	97

Gross interest expense for the three and six months ended June 30, 2003 increased 10% and 9%, respectively, compared to the same periods of 2002. The increase for both periods is due primarily to the expensing of debt issuance costs related to the Company redeeming the Zero Coupon Convertible Debentures due 2020 in the second quarter of 2003. The increase for the six months ended June 30, 2003 was also due to slightly higher interest rates caused by the redemption of the Zero Yield Puttable Contingent Debt Securities in March 2002, which were replaced with higher rate debt. See Capital Resources and Liquidity and Outlook on Liquidity.

For the three and six months ended June 30, 2003, capitalized interest decreased by 27% and 19%, respectively, compared to the same periods of 2002. The decreases are primarily due to a decrease in capitalized costs that qualify for interest capitalization.

Other (Income) Expense

	Three Months Ended						Six Months Ended
	June 30						June 30
millions	2003			2002			2003			2002

Unrealized (gain) loss on derivative financial instruments	$	29		$	(3	)	$	33		$	8
Firm transportation keep-whole contract valuation		17			(16	)		(18	)		(10	)
Foreign currency exchange		(6	)		(9	)		(14	)		(10	)
Gas sales contracts - accretion of discount		2			2			4			4
Other		(2	)		5			(2	)		10
Total	$	40		$	(21	)	$	3		$	2

Other expense in the second quarter of 2003 increased $61 million compared to the same period of 2002. The increase was due primarily to a $33 million increase related primarily to the effect of lower market values for firm transportation subject to a keep-whole agreement, a $32 million increase in unrealized losses on derivative instruments and a $3 million decrease in Canadian currency exchange gains, partially offset by a $7 million decrease in other losses. The $32 million increase in unrealized losses on derivative financial instruments is due to the reclassification of losses from other comprehensive income due to the discontinuance of hedge accounting for certain cash flow hedges of previously anticipated production that will not occur ($17 million), fair value changes of cash flow hedges that do not qualify for hedge accounting ($11 million) and cash flow hedge ineffectiveness ($4 million).

For the six months ended June 30, 2003, other expense increased $1 million compared to the same period of 2002 due primarily to a $25 million increase in unrealized losses on derivative instruments, mostly offset by an $8 million increase in income related primarily to the effect of higher market values for firm transportation subject to a keep-whole agreement, a $4 million increase in Canadian currency exchange gains and a $12 million decrease in other losses. The $25 million increase in unrealized (gains) losses on derivative financial instruments is due to fair value changes of cash flow hedges that do not qualify for hedge accounting ($17 million), the reclassification of losses from accumulated other comprehensive income due to the discontinuance of hedge accounting for certain cash flow hedges of previously anticipated production that will not occur ($13 million) and cash flow hedge ineffectiveness ($(5) million). See Derivative Instruments and Foreign Currency Risk under Item 3 of this Form 10-Q.

Income Tax Expense

	Three Months Ended				Six Months Ended
	June 30				June 30
millions	2003		2002		2003		2002

Income tax expense	$	170	$	96	$	398	$	139

For the second quarter of 2003, income taxes increased $74 million or 77% compared to the second quarter of 2002. For the first six months of 2003, income taxes increased $259 million or 186% compared to the same period of 2002. The increase in income taxes is due primarily to the increase in earnings before income taxes.

The effective tax rate for the second quarter of 2003 and 2002 was 36% and 28%, respectively. The effective tax rate for the first six months of 2003 and 2002 was 37% and 30%, respectively. The variances in the effective tax rate for the three and six months ended June 30, 2003 and 2002 from the statutory rate of 35% were due primarily to changes in income taxes related to foreign operations.

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 some 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 also conducts trading activities for the purpose of generating profits on or from exposure to changes in market prices of natural gas, crude oil, condensate and NGLs.

Included in this strategy is the use of leased natural gas storage facilities and various derivative instruments. 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. The Company's marketing function does not engage in round-trip trades or participate in any marketing-related partnerships. Essentially all of the Company's trading transactions have a term of less than one year and most are less than three months. See Derivative Instruments under Item 3 of this Form 10-Q.

During 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. In 2003, 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 counter-parties and changed its sales terms to require some counter-parties to pay in advance or post letters of credit for purchases.

Marketing 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, 2003. The Company records income or loss on these activities using the mark-to-market method.

				Firm
	Marketing			Transportation
millions	and Trading			Keep-whole			Total

Fair value of contracts outstanding as of December 31, 2002	$	(5	)	$	(73	)	$	(78	)
Contracts realized or otherwise settled during 2003		2			(23	)		(21	)
Fair value of new contracts when entered into during 2003		1			--			1
Other changes in fair value		9			18			27
Fair value of contracts outstanding as of June 30, 2003	$	7		$	(78	)	$	(71	)

		Fair Value of Contracts as of June 30, 2003

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	$		4		$	2		$	1		$	--		$	7
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			--			(36	)		(19	)		(3	)		(58	)

Total
Prices actively quoted	$		(16	)	$	2		$	1		$	--		$	(13	)
Prices based on models and other valuation
methods			--			(36	)		(19	)		(3	)		(58	)

Exploration and Development Activities

During the second quarter of 2003, Anadarko participated in a total of 319 wells, including 195 gas wells, 103 oil wells and 21 dry holes. This compares to a total of 166 wells, including 95 gas wells, 62 oil wells and 9 dry holes during the second quarter of 2002.

For the first six months of 2003, Anadarko participated in a total of 577 wells, including 382 gas wells, 162 oil wells and 33 dry holes. This compares to a total of 522 wells, including 367 gas wells, 130 oil wells and 25 dry holes during the first six months of 2002. Following are highlights of second quarter 2003 activity:

--	Onshore, the Company drilled a discovery well in the deep Woodbine play in Texas. The Blackstone Minerals A-249 well had encouraging shows of natural gas. Well testing is scheduled to begin in the third quarter. Anadarko holds a 100% working interest in this well.

--	Gross production from the Vernon play in North Louisiana increased from an average 120 MMcf/d in the first quarter to 180 MMcf/d currently following a step-up in development drilling. Eight Vernon wells with initial production of more than 10 MMcf/d each were completed during the quarter. In the Bossier play in East Texas, gross production increased from an average 245 MMcf/d in the first quarter to 300 MMcf/d currently.

--	Anadarko and its partners drilled another successful appraisal well at the K2 Gulf of Mexico deepwater discovery on Green Canyon Block 562. The Company also has an exploration well underway at Green Canyon Block 518 immediately north of the K2 field to test the possible northern extension of the K2 field. Anadarko holds a 100% working interest in this block.

--	Anadarko made its second natural gas discovery in the Eastern Gulf of Mexico at the deepwater Atlas prospect on Lloyd Ridge Block 50. The Company is finalizing plans to drill a delineation well at the Jubilee discovery later this year. Anadarko holds a 100% working interest in Atlas and Jubilee. In addition, Anadarko will drill a new exploration prospect in the area this year.

--	In the Gulf of Mexico, Anadarko acquired shelf properties from Amerada Hess with proved reserves of nearly 23 MMBOE for $225 million. The properties are expected to add 2.4 MMBOE to Anadarko's 2003 production volumes. Forecasted production for these properties has been hedged through 2007.

Capital Resources and Liquidity

Capital Expenditures*

		Six Months Ended
		June 30
millions		2003			2002

Development	$		749	$		581
Exploration			296			420
Acquisitions of oil and gas properties			280			165
Gathering and general			38			19
Capitalized interest and internal costs related to exploration
and development costs			161			179
Total	$		1,524	$		1,364

* Excludes corporate acquisitions.

During the first six months of 2003, Anadarko's capital spending was $1.5 billion, an increase of $160 million or 12% compared to the same period of 2002. This increase is primarily due to the acquisition of properties in the Gulf of Mexico purchased for approximately $225 million.

Debt As of June 30, 2003, Anadarko's total debt was $5.6 billion. This compares to total debt of $5.5 billion at December 31, 2002. The increase in debt was due primarily to the June 2003 acquisition of Gulf of Mexico properties, which were financed with available cash and credit facilities.

Outlook on Liquidity

Anadarko's net cash from operating activities during the six months ended June 30, 2003 was $1.4 billion compared to $1.0 billion for the same period in 2002. The increase in cash flow is attributed primarily to a significant increase in commodity prices. The Company's capital expenditure budget for 2003 is $2.7 billion. The increase of $0.4 billion from the original budget is expected to enable Anadarko to accelerate its exploration program in the Gulf of Mexico, Algeria and Canada, more aggressively develop key producing fields in Canada and East Texas, and includes the acquisition of oil and gas properties in the Gulf of Mexico.

On July 31, 2003, Anadarko announced a cost reduction plan that is expected to eliminate more than $100 million of overhead costs from the Company's annual cost structure, which includes cuts in personnel and corporate expenses. This cost reduction plan is expected to reduce costs and expenses by $60 million and capitalized overhead by $40 million. One time costs associated with these cost reductions are expected to be approximately $40 million ($25 million after taxes.) These costs will be charged to income as specific liabilities are incurred. It is estimated that $35 million ($22 million after taxes) will be reflected in third quarter 2003 results.

Cash flow from operating activities in 2003 is expected to be about $3 billion. The Company plans to repay about $300 million in debt for the year. Cash flow from operating activities will vary depending upon, among other things, actual commodity prices received throughout the year. The Company intends to adjust capital expenditures to reflect changes in its cash flow from operations. The Company's cash flow and capital expenditure estimates for 2003 were based on prices below where oil and gas were trading in the second quarter of 2003. If higher prices are realized, the Company may expand the drilling program, make targeted acquisitions or further reduce debt. The Company has a stock buyback program to purchase up to $1 billion in shares of Anadarko common stock. Any stock repurchases for 2003 are not included in the announced capital expenditure budget and are not currently anticipated.

Both exchange and over-the-counter traded derivative instruments are subject to margin deposit requirements. Margin deposits are required of the Company whenever its unrealized losses with a counter-party exceed predetermined credit limits. Given the Company's sizable hedge position and price volatility, the Company may be required from time to time to advance cash to its counter-parties in order to satisfy these margin deposit requirements. During the first six months of 2003, the Company's margin deposit requirements ranged from zero to $125 million. The Company's margin deposit requirement was $12 million on June 30, 2003.

Anadarko believes that operating cash flow and existing or available credit facilities will be adequate to meet its capital and operating requirements for 2003. The Company funds its day-to-day operating expenses and capital expenditures from operating cash flows, supplemented as needed by short-term borrowings under commercial paper, money market loans or credit facility borrowings. To facilitate such borrowings, the Company has in place $750 million in committed credit facilities, which are supplemented by various non-committed credit lines that may be offered by certain banks from time to time at then-quoted rates. It is the Company's policy to limit commercial paper borrowing to levels that are fully back-stopped by unused balances from its committed credit facilities. The Company may choose to refinance certain portions of these short-term borrowings by issuing long-term debt in the public or private debt markets. To facilitate such financings, the Company may file shelf registrations in advance with the Securities and Exchange Commission. The Company continuously monitors its debt position and coordinates its capital expenditure program with expected cash flows and projected debt repayment schedules. The Company will continue to evaluate funding alternatives, including property sales and additional borrowing, to secure other funds for additional capital expenditures and stock repurchases. At this time, Anadarko has no plans to issue common stock other than through its Dividend Reinvestment and Stock Purchase Plan, through the exercise of stock options, or through the Company's Employee Savings Plan and Employee Stock Ownership Plan equity funded contributions.

The Company's credit agreements allow for a maximum capitalization ratio of 60% debt, exclusive of the effect of any non-cash writedowns. As of June 30, 2003, Anadarko's capitalization ratio was 42% debt. While there is no specific restriction on paying dividends, under the maximum debt capitalization ratio retained earnings were not restricted as to the payment of dividends at June 30, 2003. 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.

New Accounting Principles

For information on New Accounting Principles see Note 1 -- Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

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, see Note 1 - Summary of Significant Accounting Policies and Note 7 - Financial Instruments of the Notes 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 374 billion cubic feet of natural gas and 26 million barrels of crude oil as of June 30, 2003. As of June 30, 2003, the Company had a net unrealized loss of $361 million before taxes on these commodity derivative instruments. Based upon an analysis utilizing the actual derivative contractual volumes, a 10% increase in commodity prices would result in an additional loss on these commodity derivative instruments of approximately $207 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, 2003, the Company had a net unrealized gain of $24 million (gains of $57 million and losses of $33 million) on commodity derivative instruments entered into for trading purposes and a net unrealized loss of $17 million (gains of $18 million and losses of $35 million) on physical contracts entered into for trading purposes. Based upon an analysis utilizing the actual derivative contractual volumes and assuming a 10% decrease in underlying commodity prices, the potential additional loss on the derivative instruments would be approximately $21 million.

Firm Transportation Keep-Whole Agreement Anadarko Holding Company (Anadarko Holding) 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 (Duke). As part of the GPM disposition, Anadarko Holding agreed to pay Duke if transportation market values fall below the fixed contract transportation rates, while Duke will pay Anadarko Holding 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 th e forward twelve months. As of June 30, 2003, accounts payable included $20 million and other long-term liabilities included $58 million related to this agreement. As of December 31, 2002, accounts payable included $5 million and other long-term liabilities included $68 million related to this agreement. A 10% unfavorable change in prices on the short-term portion of the keep-whole agreement would result in an additional loss of $10 million. The future gain or loss from this agreement cannot be accurately predicted. For additional information related to the keep-whole agreement, see Note 7 -Financial Instruments of the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

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

Commodity Risk Crude oil prices continue to be affected by political developments worldwide, pricing decisions and production quotas of OPEC and the volatile trading patterns in the commodity futures markets. In addition, in OPEC countries in which Anadarko has production such as Algeria, Venezuela and Qatar, when the world oil market is weak, the Company may be subject to periods of decreased production due to government mandated cutbacks. Natural gas prices also continue to be highly volatile. In periods of sharply lower commodity prices, the Company may curtail production and capital spending projects, as well as delay or defer drilling wells in certain areas because of lower cash flows. Changes in crude oil and natural gas prices can impact the Company's determination of proved reserves and the Company's calculation of the standardized measure of discounted future net cash flows relating to oil and gas reserves. In addition, demand for oil and gas in the U.S. and worldwide may a ffect the Company's level of production.

Under the full cost method of accounting, a non-cash charge to earnings related to the carrying value of the Company's oil and gas properties on a country-by-country basis may be required when prices are low. Whether the Company will be required to take such a charge depends on the prices for crude oil and natural gas at the end of any quarter, as well as the effect of both capital expenditures and changes to proved reserves during that quarter. While this non-cash charge can give Anadarko a significant reported loss for the period, future expenses for depreciation, depletion and amortization will be reduced.

Interest Rate Risk Anadarko is also exposed to risk resulting from changes in interest rates as a result of the Company's variable and fixed interest 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.

At June 30, 2003 and December 31, 2002, a Canadian subsidiary had $99 million and $98 million, respectively, outstanding of fixed-rate notes and debentures denominated in U.S. dollars. The potential foreign currency remeasurement impact on earnings from a 10% increase in the June 30, 2003 Canadian exchange rate would be about $9 million based on the outstanding debt at June 30, 2003.

At June 30, 2003 and December 31, 2002, the Company's Latin American subsidiaries had foreign deferred tax liabilities denominated in the local currency equivalent totaling $38 million and $49 million, respectively. In conjunction with the sale of certain properties in 2001, the Company indemnified a purchaser for the use of local tax losses denominated in the local currency equivalent totaling $22 million. The potential foreign currency remeasurement impact on net earnings from a 10% increase in the June 30, 2003 Latin American exchange rates would be approximately $4 million.

Item 4. Controls and Procedures

Anadarko's Chief Executive Officer and Chief Financial Officer (Certifying Officers) 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 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 Certifying Officers have concluded that the Company's disclosure controls and procedures are effective as of June 30, 2003. In addition, there has been no significant change in the Company's internal control over financial reporting 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

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

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

(a)	On April 24, 2003 the Company held its Annual Stockholders' Meeting.

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

	Mr. Conrad P. Albert was re-elected with 212,623,114 votes for and 3,158,909 votes withheld. Mr. Robert J. Allison, Jr. was re-elected with 212,732,207 votes for and 3,049,716 votes withheld. Mr. John W. Poduska, Sr. was re-elected with 212,772,657 votes for and 3,009,266 votes withheld.

Item 6. Exhibits and Reports on Form 8-K

(a)	Exhibits

	Exhibits not incorporated by reference to a prior filing are designated by an (*) 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(e) to Form 10-Q	1-8968
			Corporation, as amended	for the quarter ended
				September 30, 2000

	(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

*10	(b)(i)		Termination Agreement and Release of All Claims

		*(ii)	Form of Amendment to Anadarko Petroleum
			Corporation Key Employee Change of Control
			Contract

		*(iii)	Form of Anadarko Petroleum Corporation 1998
			Director Stock Plan Stock Option Agreement

*12			Computation of Ratios of Earnings to Fixed
			Charges and Earnings to Combined Fixed
			Charges and Preferred Stock Dividends

*31			Rule 13a-14(a)/15d-14(a) Certifications

*32			Section 1350 Certifications

(b)	Reports on Form 8-K

	A report on Form 8-K dated April 25, 2003 was filed. The event was reported under Item 9 - Regulation FD Disclosure.

	A report on Form 8-K dated May 6, 2003 was filed. The event was reported under Item 5 - Other Events.

	A report on Form 8-K dated June 6, 2003 was filed. The event was reported under Item 9 - Regulation FD Disclosure.

	A report on Form 8-K dated June 10, 2003 was filed. The event was reported under Item 5 - Other Events.

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 11, 2003	By:	/s/ MICHAEL E. ROSE
		Michael E. Rose - Executive Vice President
		and Chief Financial Officer