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, 2002
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 _____

The number of shares outstanding of the Company's common stock as of July 31, 2002 is shown below:


Title of Class	Number of Shares Outstanding

Common Stock, par value $0.10 per share	248,514,438

TABLE OF CONTENTS

			Page
PART I

	Item 1.	Financial Statements

		Consolidated Statement of Income for the Three and Six Months Ended June 30, 2002 and June 30, 2001	3

		Consolidated Balance Sheet as of June 30, 2002 and December 31, 2001	4

		Consolidated Statement of Comprehensive Income for the Three and Six Months Ended June 30, 2002 and June 30, 2001	6

		Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2002 and June 30, 2001	7

		Notes to Consolidated Financial Statements	8

	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38

PART II

	Item 1.	Legal Proceedings	45

	Item 4.	Submission of Matters to a Vote of Security Holders	45

	Item 5.	Other Information	45

	Item 6.	Exhibits and Reports on Form 8-K	46

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Unaudited)
			Three Months Ended								Six Months Ended
			June 30								June 30
millions except per share amounts			2002				2001				2002			2001
Revenues
Gas sales		$		480		$		825		$		833	$		1,939
Oil and condensate sales				418				375				768			736
Natural gas liquids sales				55				71				97			144
Marketing sales				770				950				1,377			2,408
Minerals and other				15				17				36			20
Total				1,738				2,238				3,111			5,247

Costs and Expenses
Marketing purchases				752				931				1,348			2,364
Operating expenses				184				193				354			350
Administrative and general				77				64				149			113
Depreciation, depletion and amortization				274				320				541			594
Other taxes				62				66				118			149
Impairments related to oil and gas properties				25				8				33			15
Amortization of goodwill				--				19				--			36
Total				1,374				1,601				2,543			3,621

Operating Income				364				637				568			1,626

Other (Income) Expense
Merger expenses				--				17				--			27
Interest expense				48				25				97			47
Other (income) expense				(21	)			(4	)			2			(100	)
Total				27				38				99			(26	)

Income Before Income Taxes				337				599				469			1,652

Income Taxes
Income taxes				96				228				139			617
Effect of change in Canadian income tax rate				--				(31	)			--			(31	)
Total				96				197				139			586

Net Income Before Cumulative Effect of Change
	in Accounting Principle	$		241		$		402		$		330	$		1,066

Preferred Stock Dividends				2				1				3			4

Net Income Available to Common Stockholders Before
	Cumulative Effect of Change in Accounting Principle	$		239		$		401		$		327	$		1,062

Cumulative Effect of Change in Accounting Principle				--				--				--			5

Net Income Available to Common Stockholders		$		239		$		401		$		327	$		1,057

Per Common Share
Net income - before change in accounting principle - basic		$		0.96		$		1.60		$		1.32	$		4.24
Net income - before change in accounting principle - diluted		$		0.93		$		1.50		$		1.27	$		4.01
Change in accounting principle - basic		$		--		$		--		$		--	$		(0.02	)
Change in accounting principle - diluted		$		--		$		--		$		--	$		(0.02	)
Net income - basic		$		0.96		$		1.60		$		1.32	$		4.22
Net income - diluted		$		0.93		$		1.50		$		1.27	$		3.99
Dividends		$		0.075		$		0.05		$		0.15	$		0.10

Average Number of Common Shares Outstanding - Basic				248				251				248			251
Average Number of Common Shares Outstanding - Diluted				259				268				261			266

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEET
(Unaudited)

			June 30,			December 31,
millions			2002			2001
ASSETS
Current Assets
Cash and cash equivalents		$		45	$		37
Accounts receivable, net of allowance:
	Customers			629			532
	Others			270			486
Other current assets				132			146

Total				1,076			1,201

Properties and Equipment
Original cost (includes unproved properties of $3,590 and $3,573
	as of June 30, 2002 and December 31, 2001, respectively)			21,583			20,088
Less accumulated depreciation, depletion and amortization				7,085			6,451

Net properties and equipment - based on the full cost method
	of accounting for oil and gas properties			14,498			13,637

Other Assets				494			503

Goodwill				1,443			1,430

		$		17,511	$		16,771

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEET (continued)
(Unaudited)

			June 30,				December 31,
millions except share amounts			2002				2001
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable		$		943		$		1,132
Accrued expenses				296				257
Current portion, notes and debentures				300				412

Total				1,539				1,801

Long-term Debt				5,241				4,638

Other Long-term Liabilities
Deferred income taxes				3,518				3,451
Other				523				516

Total				4,041				3,967

Stockholders' Equity
Preferred stock, par value $1.00 per share
	(2.0 million shares authorized, 0.1 million shares
	issued as of June 30, 2002 and December 31, 2001)			101				103
Common stock, par value $0.10 per share
	(450.0 million shares authorized, 254.4 million and 254.1 million shares
	issued as of June 30, 2002 and December 31, 2001, respectively)			25				25
Paid-in capital				5,333				5,336
Retained earnings				1,567				1,276
Treasury stock
	(3.2 million and 2.2 million shares as of June 30, 2002
	and December 31, 2001, respectively)			(166	)			(116	)
Deferred compensation and ESOP (0.7 million and 0.9 million shares
	as of June 30, 2002 and December 31, 2001, respectively)			(75	)			(96	)
Executives and Directors Benefits Trust, at market value
	(2.0 million shares as of June 30, 2002 and December 31, 2001)			(98	)			(114	)
Accumulated other comprehensive income (loss):
	Unrealized loss on derivatives			(9	)			--
	Foreign currency translation adjustments			27				(46	)
	Minimum pension liability			(15	)			(3	)
	Total			3				(49	)

Total				6,690				6,365

Commitments and Contingencies				--				--

		$		17,511		$		16,771

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Unaudited)

				Three Months Ended								Six Months Ended
				June 30								June 30
millions				2002				2001				2002				2001

Net Income Available to Common Stockholders			$		239		$		401		$		327		$		1,057

Other Comprehensive Income (Loss), net of income taxes
Unrealized gain (loss) on derivatives:
	Cumulative effect of accounting change (1)				--				--				--				(5	)
	Reclassification of cumulative effect of accounting change
		included in net income (2)			--				--				--				3
	Unrealized gain (loss) during the period (3)				5				21				(14	)			18
	Reclassification for gains included in net income (4)				6				--				5				--
	Total unrealized gain (loss) on derivatives				11				21				(9	)			16

Foreign currency translation adjustments					75				19				73				19

Minimum pension liability adjustment (5)					--				--				(12	)			(3	)

Total					86				40				52				32

Comprehensive Income			$		325		$		441		$		379		$		1,089

(1) net of income tax benefit (expense) of:			$		--		$		--		$		--		$		3
(2) net of income tax benefit (expense) of:					--				--				--				(1	)
(3) net of income tax benefit (expense) of:					(2	)			(13	)			9				(10	)
(4) net of income tax benefit (expense) of:					(4	)			--				(3	)			--
(5) net of income tax benefit (expense) of:					--				--				7				1

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
				Six Months Ended
				June 30
millions				2002				2001
Cash Flow from Operating Activities
Net income before cumulative effect of change in accounting principle			$		330		$		1,066
Adjustments to reconcile net income before cumulative effect of change
	in accounting principle to net cash provided by operating activities:
		Depreciation, depletion and amortization			548				594
		Amortization of goodwill			--				36
		Non-cash merger expenses			--				7
		Interest expense - zero coupon debentures			6				6
		Deferred income taxes			53				415
		Impairments related to oil and gas properties			33				15
		Other non-cash items			(10	)			27
					960				2,166
Decrease in accounts receivable					95				369
Decrease in accounts payable and accrued expenses					(108	)			(377	)
Other items - net					14				(108	)

Net cash provided by operating activities					961				2,050

Cash Flow from Investing Activities
Additions to properties and equipment					(1,364	)			(1,514	)
Acquisition costs, net of cash acquired					(17	)			(821	)
Sales and retirements of properties and equipment					63				3

Net cash used in investing activities					(1,318	)			(2,332	)

Cash Flow from Financing Activities
Additions to debt					1,100				2,418
Retirements of debt					(615	)			(1,950	)
Decrease in accounts payable, banks					(51	)			(16	)
Dividends paid					(39	)			(29	)
Retirement of preferred stock					(2	)			(73	)
Purchase of treasury stock					(50	)			--
Issuance of common stock and stock put options					22				32

Net cash provided by financing activities					365				382

Effect of Exchange Rate Changes on Cash					--				1

Net Increase in Cash and Cash Equivalents					8				101

Cash and Cash Equivalents at Beginning of Period					37				199

Cash and Cash Equivalents at End of Period			$		45		$		300

See accompanying notes to consolidated financial statements.

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of 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 principal subsidiaries of Anadarko are: RME Petroleum Company; RME Holding Company (RME); Anadarko Canada Energy Ltd.; Anadarko Canada Corporation; RME Land Corp.; and, Anadarko Algeria Company, LLC. Certain amounts for the prior year have been reclassified to conform to the current presentation.

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, 2002 and December 31, 2001, the results of operations for the three and six months ended June 30, 2002 and 2001 and cash flows for the six months ended June 30, 2002 and 2001. In preparing financial statements, Management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to litigation, environmental liabilities, income taxes and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Derivative Financial Instruments In 2001, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, which provides guidance for accounting for derivative instruments and hedging activities. The change was effective January 2001 and the related cumulative adjustment to net income was a decrease of $8 million ($5 million after taxes or $0.02 per share) and the cumulative adjustment to accumulated other comprehensive income was a decrease of $8 million ($5 million after taxes).

Derivative financial 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. Under this statement, all derivatives are carried on the balance sheet at fair value. Realized gains/losses and option premiums are recognized in the statement of income when the underlying physical gas and oil production is sold. Accordingly, realized derivative gains/losses are generally offset by similar changes in the realized prices of the underlying physical gas and oil production. Realized derivative gains/losses are reflected in the average sales price of the physical gas and oil production. Accounting for unrealized gains/losses is dependent on whether the derivative financial instruments have been designated and qualify as part of a hedging relationship. Derivative financial instruments may be designated as a hedge of exposure to changes in fair values, cash flows or foreign currencies, if certai n conditions are met. Unrealized gains/losses on derivative financial instruments that do not meet the conditions to qualify for hedge accounting are recognized currently in earnings.

If the hedged exposure is to changes in fair value, the gains/losses on the derivative financial instrument, as well as the offsetting losses/gains on the hedged item, are recognized currently in earnings. Consequently, if gains/losses on the derivative financial instrument and the related hedge item do not completely offset, the difference (i.e., ineffective portion of the hedge) is recognized currently in earnings.

If the hedged exposure is a cash flow exposure, the effective portion of the gains/losses on the derivative financial 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/losses from the derivative financial 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. Effective July 2001, the Company implemented Derivatives Implementation Group Issue G20, "Cash Flow Hedges: Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash Flow Hedge," which provides guidance for assessing the effectiveness on total changes in an option's cash flows rather than only on changes in the option's intrinsic value. Time value changes were previously being recognized in current earnings si nce the Company excluded time value changes from its assessment of hedge effectiveness. If the hedged exposure is a foreign currency exposure, the accounting is similar to the accounting for fair value and cash flow hedges.

Derivative financial instruments, as well as physical delivery purchase and sale contracts, utilized in the Company's energy trading activities and in the management of price risk associated with the Company's firm transportation keep-whole commitment are accounted for under the mark-to-market accounting method pursuant to Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." Under this method, the derivatives and physical delivery contracts are revalued in each accounting period and premiums and unrealized gains/losses are recorded in the statement of income and carried as assets or liabilities on the balance sheet.

The Company's derivative financial instruments associated with the marketing and trading activities 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. See Note 6.

Earnings Per Share The Company's basic earnings per share (EPS) amounts have been computed based on the average number of shares of common stock outstanding for the period. Diluted EPS amounts include the effect of the Company's outstanding stock options and performance-based stock awards under the treasury stock method 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 later.

New Accounting Principles SFAS No. 143, "Accounting for Asset Retirement Obligations," requires the fair value of a liability for an asset retirement obligation to be recorded in the period in which it is incurred along with a corresponding increase in the carrying amount of the related long-lived asset and will be effective for the Company in January 2003. The Company is evaluating the impact of SFAS No. 143.

SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13 and Technical Corrections," was issued in April 2002. SFAS No. 145 provides guidance for income statement classification of gains and losses on extinguishment of debt and accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 145 will be effective for the Company in January 2003. The Company is evaluating the impact of SFAS No. 145 and does not expect adoption to materially affect the consolidated financial statements.

SFAS No. 146, "Accounting for Exit or Disposal Activities," was issued in June 2002. SFAS No. 146 addresses significant issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance set forth in EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity." SFAS No. 146 will be effective for the Company in January 2003. The Company is evaluating the impact of SFAS No. 146.

EITF Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10," was issued in June 2002. EITF Issue No. 02-3 addresses certain issues related to energy trading activities, including (a) gross versus net presentation in the income statement, (b) whether the initial fair value of an energy trading contract can be other than the price at which it was exchanged, and (c) additional disclosure requirements for energy trading activities. EITF Issue No. 02-3 will be effective for the Company in the third quarter of 2002. The Company is evaluating the impact of EITF Issue No. 02-3 and expects adoption to result in the presentation of net marketing margins in revenues, rather than marketing revenues, which were offset by marketing purchases in costs a nd expenses.

2. Goodwill SFAS No. 142, "Goodwill and Other Intangible Assets," requires discontinuing amortization of goodwill after 2001 and requires that goodwill be tested for impairment. The impairment test requires allocating goodwill and all other assets and liabilities to business levels referred to as reporting units. The fair value of each reporting unit that has goodwill is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value (including goodwill), then a second test is performed to determine the amount of the impairment.

If the second test is necessary, the fair value of the reporting unit's individual assets and liabilities is deducted from the fair value of the reporting unit. This difference represents the implied fair value of goodwill, which is compared to the book value of the reporting unit's goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the amount of the impairment.

The goodwill impairment test is performed annually, and also at interim dates upon the occurrence of significant events. Significant events include: a significant adverse change in legal factors or business climate; an adverse action or assessment by a regulator; a more-likely-than-not expectation that a reporting unit or significant portion of a reporting unit will be sold; significant adverse trends in current and future oil and gas prices; nationalization of any of the Company's oil and gas properties; or, significant increases in a reporting unit's carrying value relative to its fair value. The initial goodwill impairment test is required to be performed using an effective date of January 1, 2002.

In January 2002, the Company discontinued the amortization of goodwill in accordance with SFAS No. 142. The transitional goodwill impairment test as of January 1, 2002 was performed and no goodwill impairment was indicated. The following tables show the effect of the elimination of amortization of goodwill on the Company's net income and net income per share as if SFAS No. 142 had been in effect in prior periods.

		Three Months Ended						Six Months Ended
		June 30						June 30
millions except per share amounts		2002			2001			2002			2001
Net income	$		239	$		401	$		327	$		1,057
Add: Goodwill amortization			--			19			--			36
Adjusted net income	$		239	$		420	$		327	$		1,093

Earnings per share - basic	$		0.96	$		1.60	$		1.32	$		4.22
Goodwill amortization per share - basic			--			0.08			--			0.14
Adjusted earnings per share - basic	$		0.96	$		1.68	$		1.32	$		4.36

Earnings per share - diluted	$		0.93	$		1.50	$		1.27	$		3.99
Goodwill amortization per share - diluted			--			0.07			--			0.14
Adjusted earnings per share - diluted	$		0.93	$		1.57	$		1.27	$		4.13

		Years Ended December 31
millions except per share amounts		1997			1998				1999			2000			2001
Net income (loss)	$		107	$		(49	)	$		32	$		796	$		(188	)
Add: Goodwill amortization			--			--				--			31			73
Adjusted net income (loss)	$		107	$		(49	)	$		32	$		827	$		(115	)

Earnings (loss) per share - basic	$		0.90	$		(0.41	)	$		0.25	$		4.32	$		(0.75	)
Goodwill amortization per share - basic			--			--				--			0.17			0.29
Adjusted earnings (loss) per share - basic	$		0.90	$		(0.41	)	$		0.25	$		4.49	$		(0.46	)

Earnings (loss) per share - diluted	$		0.89	$		(0.41	)	$		0.25	$		4.16	$		(0.75	)
Goodwill amortization per share - diluted			--			--				--			0.16			0.29
Adjusted earnings (loss) per share - diluted	$		0.89	$		(0.41	)	$		0.25	$		4.32	$		(0.46	)

The change in goodwill since December 31, 2001 is due primarily to foreign currency remeasurements. Future changes in goodwill may result from, among other things, foreign currency remeasurement, changes in deferred income tax liabilities related to acquisitions, divestitures, impairments or future acquisitions. The Company is continuing to evaluate the deferred income tax liabilities of RME to determine the reasonableness of the balance as of the merger date. Any adjustment of deferred income tax liabilities of RME as of the merger date will have no effect on net income or cash flow because there will be a corresponding adjustment to goodwill.

3. Inventories The major classes of inventories, which are included in other current assets, are as follows:

		June 30,			December 31,
millions		2002			2001
Materials and supplies	$		78	$		61
Crude oil			12			22
Natural gas			12			18
Total	$		102	$		101

4. Properties and Equipment Oil and gas properties include costs of $3.6 billion at June 30, 2002 and December 31, 2001, which were excluded from capitalized costs being amortized. These amounts represent costs associated with unevaluated properties and major development projects. At June 30, 2002 and December 31, 2001, the Company's investment in countries where reserves have not been established was $54 million and $53 million, respectively.

Total interest costs incurred during the second quarter of 2002 and 2001 were $89 million and $75 million, respectively. Of these amounts, the Company capitalized $41 million and $50 million during the second quarter of 2002 and 2001, respectively. Total interest costs incurred during the first six months of 2002 and 2001 were $176 million and $148 million, respectively. Of these amounts, the Company capitalized $79 million and $101 million during the first six months of 2002 and 2001, 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 that are under active evaluation.

In addition to capitalized interest, the Company also capitalized internal costs of $57 million and $47 million during the second quarter of 2002 and 2001, respectively. For the first six months of 2002 and 2001, the Company capitalized internal costs of $100 million and $83 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.

5. Debt A summary of debt follows:

		June 30, 2002				December 31, 2001
millions		Principal		Carrying Value		Principal		Carrying Value
Notes Payable, Banks		$	207	$	207	$	228	$	228
Commercial Paper			308		308		226		226
Long-term Portion of Capital Lease			8		8		9		9
6.8% Debentures due 2002			88		88		88		88
6 3/4% Notes due 2003			73		73		73		73
5 7/8% Notes due 2003			83		83		83		83
6.5% Notes due 2005			170		165		170		164
7.375% Debentures due 2006			88		87		88		87
7% Notes due 2006			174		170		174		170
5 3/8% Notes due 2007			650		647		--		--
6.75% Notes due 2008			116		111		116		110
7.8% Debentures due 2008			11		11		11		11
7.3% Notes due 2009			85		82		85		82
6 3/4% Notes due 2011			950		910		950		910
6 1/8% Notes due 2012			400		395		--		--
7.05% Debentures due 2018			114		105		114		105
Zero Coupon Convertible
	Debentures due 2020		373		373		367		367
Zero Yield Puttable Contingent
	Debt Securities due 2021		30		30		650		650
7.5% Debentures due 2026			112		106		112		105
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 1/4% Debentures due 2096			49		49		49		49
7.5% Debentures due 2096			83		75		83		75
Total debt		$	5,691		5,541	$	5,195		5,050
Less current portion					300				412
Total long-term debt				$	5,241			$	4,638

At June 30, 2002, $1.05 billion 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," $750 million of this amount is classified as long-term debt, under the terms of Anadarko's Bank Credit Agreements. The remaining $300 million is classified as current liabilities. At December 31, 2001, $1.16 billion of notes, debentures and securities would mature or could be put to Anadarko within the next twelve months. In accordance with SFAS No. 6, $750 million of this amount was classified as long-term debt, under the terms of Anadarko's Bank Credit Agreements. The remaining $412 million was classified as current liabilities.

In March 2001, Anadarko issued $650 million of ZYP-CODES due 2021. Holders of the ZYP-CODES have the right to require Anadarko to purchase all or a portion of their ZYP-CODES in March 2002, 2004, 2006, 2011 or 2016, at $1,000 per ZYP-CODES. In March 2002, ZYP-CODES in the amount of $620 million were put to the Company for repayment and were paid in cash.

In February 2002, the Company issued $650 million principal amount of 5 3/8% Notes due 2007. In March 2002, the Company issued $400 million principal amount of 6 1/8% Notes due 2012. The net proceeds from these issuances were used to reduce floating rate debt and to fund a portion of the ZYP-CODES put to the Company for repayment in March 2002.

In April 2002, Anadarko filed a shelf registration statement with the Securities and Exchange Commission that permits the issuance of up to $1 billion in debt securities, preferred stock, preferred securities, depositary shares, common stock, warrants, purchase contracts and purchase units, once effective. Net proceeds, terms and pricing of the offerings of securities issued under the shelf registration statement will be determined at the time of the offerings.

6. Financial Instruments

Commodity Derivative Financial Instruments The Company is exposed to price risk from changing commodity prices. Management believes it is prudent to 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. These instruments may include futures, swaps and options. Most of the instruments entered into by the Company have a term of less than one year. As of June 30, 2002, the Company had outstanding derivative financial instruments that hedged 11% of the Company's natural gas production and 19% of its crude oil production, which is expected to be produced during the second half of 2002. In July 2002, the Company hedged an additio nal 16% of its crude oil production for the second half of 2002.

Anadarko also enters into commodity derivative financial instruments (options, futures and swaps) for trading purposes with the objective of generating profits from exposure to changes in the market price of natural gas and crude oil. Commodity derivative financial instruments also provide a way to meet customers' pricing requirements while achieving a price structure consistent with the Company's overall pricing strategy. In addition, the Company uses swap agreements 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 oil and gas sales at major industry trading locations; e.g., Henry Hub, Louisiana for gas and Cushing, Oklahoma for oil. Settlements of futures contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the International Petroleum Exchange and have nominal credit risk. Swap agreements are generally used to fix or float the price of oil and gas at the Company's market locations. Swap agreements are also used to fix the price differential between the price of gas at Henry Hub and various other market locations. Swap agreements expose the Company to credit risk to the extent the counterparty is unable to meet its monthly settlement commitment. The Company carefully monitors the creditworthiness of each counterparty. In addition, the Company routinely exercises its contractual right to net realized gains against realized losses in settling with its swap counterparties. Options are generally used to fix a floo r and/or a ceiling price (a "collar") for the Company's expected future oil and gas sales. The Company buys/sells options through exchanges as well as in the over the counter market.

Cash Flow Hedges At June 30, 2002, the Company had option and swap contracts in place to fix floor and/or ceiling prices on a portion of expected future sales of equity gas and oil production. As of June 30, 2002, the Company had a net unrealized loss of $11 million before taxes (gains of $7 million and losses of $18 million), or $7 million after taxes, on derivative commodity instruments entered into to hedge equity production recorded in accumulated other comprehensive income compared to a net unrealized gain of $7 million before taxes (gains of $9 million and losses of $2 million), or $4 million after taxes at December 31, 2001. Other income for the three months ended June 30, 2002 and 2001 included $3 million and $18 million of net gains, respectively, and for the six months ended June 30, 2002 and 2001 included $8 million of net losses and $27 million of net gains, respectively, primarily due to the ineffective portion of the hedge and the change i n the time value of the option contracts, that was excluded from the assessment of hedge effectiveness.

As of June 30, 2002 and December 31, 2001, the Company had the following volumes under derivative contracts related to its oil and gas producing activities (non-trading activity). The difference between the fair values in the table and the unrealized gain (loss) before income taxes recognized in accumulated other comprehensive income is due to premiums and ineffectiveness.

June 30, 2002

							Net Fair Value
	Production						Asset (Liability)
	Period	Instrument Type**	Volumes		Average Price		millions

Natural Gas			(million MMBtu)		($ per MMBtu)

	2002	2-way collar*		20	3.71-4.24	$		7
	2002	3-way collar*		3	2.20-3.00-4.83			--
	2003	2-way collar*		2	3.00-5.00			--
	2003	3-way collar*		7	2.20-3.00-4.83			(1	)
	2004	2-way collar*		2	3.00-5.00			--
	2004	3-way collar*		7	2.20-3.00-4.83			(2	)
	2005	2-way collar*		2	3.00-5.00			--
	2005	3-way collar*		7	2.20-3.00-4.83			(2	)
	2002	Calls sold		5	3.72			--
	2002	Calls purchased		3	3.58			--
	2003	Calls sold		7	3.31			(3	)
	2003	Calls purchased		10	3.47			3
	2004	Calls sold		1	3.06			--
	2004	Calls purchased		1	3.06			--
		Total				$		2

Crude Oil			(MMBbls)		($ per barrel)

	2002	Swaps*		2	24.28	$		(1	)
	2002	2-way collar*		1	22.30-23.32			(2	)
	2002	3-way collar*		3	17.89-21.94-28.04			(3	)
	2003	Swaps*		1	23.80			--
	2003	2-way collar*		1	22.30-23.32			(1	)
	2003	3-way collar*		4	17.00-21.00-26.33			(4	)
		Total				$		(11	)

December 31, 2001

								Net Fair Value
	Production							Asset (Liability)
	Period		Instrument Type**	Volumes		Average Price		millions

Natural Gas				(million MMBtu)		($ per MMBtu)

	2002		2-way collar*		2	3.00-5.00	$		1
	2002		3-way collar*		7	2.20-3.00-4.83			2
	2003		2-way collar*		2	3.00-5.00			1
	2003		3-way collar*		7	2.20-3.00-4.83			1
	2004		2-way collar*		2	3.00-5.00			1
	2004		3-way collar*		7	2.20-3.00-4.83			1
	2005		2-way collar*		2	3.00-5.00			1
	2005		3-way collar*		7	2.20-3.00-4.83			1
	2002		Calls sold		10	3.66			2
	2002		Calls purchased		5	3.50			--
	2003		Calls sold		7	3.18			(2	)
	2003		Calls purchased		10	4.12			2
	2004		Calls sold		1	2.95			--
	2004		Calls purchased		1	2.95			--
			Total				$		11

Crude Oil				(MMBbls)		($ per barrel)

	2002		Swaps*		1	25.56	$		2
	2002		3-way collar*		3	19.11-23.33-30.51			6
			Total				$		8


MMBtu - million British thermal units
MMBbls - million barrels

*		Qualifies for hedge accounting.
**		A "2-way collar" is a combination of options, a sold call and purchased put. The purchased put establishes a minimum price (the "floor") and the sold call establishes a maximum price (the "ceiling") the Company will receive for the volumes under contract. A "3-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 "ceiling") the Company will receive for the volumes under contract.

Trading Activity As of June 30, 2002 and December 31, 2001, the Company had the following volumes under derivative contracts related to its trading activity:

June 30, 2002

							Net Fair Value
	Production						Asset (Liability)
	Period	Instrument Type	Volumes	Average Price			millions

Natural Gas			(million MMBtu)	($ per MMBtu)

	2002	Futures sold	18		3.32	$		1
	2002	Futures purchased	20		3.33			--
	2002	Swaps	42		3.35			(1	)
	2002	Calls sold	13		3.75			--
	2002	Calls purchased	4		4.04			--
	2002	Puts sold	2		3.84			(1	)
	2002	Puts purchased	6		2.84			--
	2003	Futures sold	5		3.47			(3	)
	2003	Futures purchased	6		3.53			2
	2003	Swaps	45		3.68			3
	2003	Calls purchased	3		4.40			1
	2004	Futures sold	1		3.84			--
	2004	Swaps	1		4.02			--
	2005	Swaps	1		4.05			--
	2006	Swaps	1		3.99			--
		Total				$		2

Crude Oil			(MMBbls)	($ per barrel)

	2002	Futures sold	3		24.79	$		(1	)
	2002	Futures purchased	3		25.03			--
	2002	Puts sold	1		23.56			--
		Total				$		(1	)

December 31, 2001

							Net Fair Value
	Production						Asset (Liability)
	Period	Instrument Type	Volumes	Average Price			millions

Natural Gas			(million MMBtu)	($ per MMBtu)

	2002	Futures sold	24		3.34	$		18
	2002	Futures purchased	22		3.50			(21	)
	2002	Swaps	72		3.20			(42	)
	2002	Calls sold	8		3.07			1
	2002	Calls purchased	13		4.09			1
	2002	Puts sold	8		3.25			(7	)
	2002	Puts purchased	1		2.58			--
	2003	Futures sold	1		3.51			--
	2003	Futures purchased	1		3.36			--
	2003	Swaps	12		3.12			--
		Total				$		(50	)

Crude Oil			(MMBbls)	($ per barrel)

	2002	Futures sold	3		19.80	$		(1	)
	2002	Futures purchased	1		20.05			2
	2002	Swaps	1		21.77			--
	2002	Calls sold	1		29.50			--
		Total				$		1

Firm Transportation Keep-Whole Agreement RME 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 firm long-term 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, RME agreed to pay Duke if transportation market values fall below the fixed contract transportation rates, while Duke will pay RME if the transportation market values exceed the contract transportation rates (keep-whole agreement). Transportation contracts transferred to Duke in the GPM disposition and the contract not transferred, all of which are included in the keep-whole agreement with Duke, relate to various pipelines. 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 financial instruments to manage the price risk associated with this agreement. This keep-whole agreement and any oil and gas derivative financial instruments are accounted for on a mark-to-market basis. The Company recognized other income of $16 million and other expense of $42 million for the three months ended June 30, 2002 and 2001, respectively, and other income of $10 million and $98 million for the six months ended June 30, 2002 and 2001, respectively, related to the keep-whole agreement and associated derivative financial instruments. As of June 30, 2002 and December 31, 2001, other current assets included $4 million and $25 million, accounts payable included $10 million and $27 million and other long-term liabilities included $75 million and $80 million, respectiv ely, related to the keep-whole agreement and associated derivative financial instruments.

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.

Anticipated discounted and undiscounted liabilities (assets) for the firm transportation keep-whole commitment at June 30, 2002 are as follows:

millions		Undiscounted				Discounted

2002	$		(16	)	$		(16	)
2003			23				22
2004			27				23
2005			20				15
2006			19				13
Later years			24				14
Total	$		97		$		71

As of June 30, 2002 and December 31, 2001, the Company had the following volumes of natural gas under derivative contracts related to the firm transportation keep-whole agreement:

Net Fair Value

Production

Volumes

Average Price

Asset (Liability)

Period

Instrument Type

(million MMBtu)

($ per MMBtu)

millions

June 30, 2002

2002

Swaps

2.25

(10

)

December 31, 2001

2002

Swaps

8.42

Represents 11% of the Company's total volumetric exposure under the keep-whole agreement for the remainder of 2002.

Represents 2% of the Company's total volumetric exposure under the keep-whole agreement for 2002.

7. Preferred Stock For the first and second quarters of 2002 and 2001, dividends of $13.65 per share (equivalent to $1.365 per Depositary Share) were paid to holders of preferred stock. During the second quarter of 2002, the Company repurchased $2 million of preferred stock.

8. 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, 2002 and December 31, 2001.

The reconciliation between basic and diluted EPS is as follows:

		Three Months Ended							Three Months Ended
millions except per share amounts		June 30, 2002							June 30, 2001
						Per Share							Per Share
	Income			Shares		Amount		Income			Shares		Amount
Basic EPS
Net income available to common
stockholders before change in
accounting principle	$		239		248	$	0.96	$		401		251	$	1.60
Effect of convertible debentures
and ZYP-CODES			2		9					2		14
Effect of dilutive stock options and
performance-based stock awards			--		2					--		3
Diluted EPS
Net income available to common
stockholders plus assumed conversion	$		241		259	$	0.93	$		403		268	$	1.50


		Six Months Ended							Six Months Ended
millions except per share amounts		June 30, 2002							June 30, 2001
						Per Share							Per Share
	Income			Shares		Amount		Income			Shares		Amount
Basic EPS
Net income available to common
stockholders before change in
accounting principle	$		327		248	$	1.32	$		1,062		251	$	4.24
Effect of convertible debentures
and ZYP-CODES			4		11					4		12
Effect of dilutive stock options and
performance-based stock awards			--		2					--		3
Diluted EPS
Net income available to common
stockholders plus assumed conversion	$		331		261	$	1.27	$		1,066		266	$	4.01

For the three and six months ended June 30, 2002, options for 1.4 million 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, 2001, options for 0.2 million 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 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. For the three and six months ended June 30, 2001, put options for 2 million shares of common stock were excluded from the diluted EPS calculation because the put options' exercise price was less than the average market price of common stock for the periods.

In 2001, the Board of Directors authorized the Company to purchase up to $1 billion in shares of Anadarko common stock. The share purchases may be made from time to time, depending on market conditions. Shares may be purchased either in the open market or through privately negotiated transactions. The repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. During 2001, the Company purchased 2.2 million shares of common stock for $116 million. In January 2002, the Company purchased an additional 1 million shares of common stock for $50 million.

To enhance the share repurchase program, Anadarko has sold put options to independent third parties. These put options entitle the holder to sell shares of Anadarko common stock to the Company on certain dates at specified prices. During 2001, Anadarko sold put options for the purchase of a total of 5 million shares of Anadarko common stock with a notional amount of $240 million. A put option for 1 million shares was exercised and put options for 2 million shares expired unexercised in 2001. In January 2002, the Company entered into an additional put option for 1 million shares of Anadarko common stock with a notional amount of $46 million and received a $3 million premium. In July 2002, this put option was extended and the Company received an additional $3 million premium. Put options for an additional 2 million shares expired unexercised in 2002. The remaining put option for 1 million shares will expire in October 2002, if not exercised. The put options permit a net-share settlement at the Company's option and did not result in a liability on the consolidated balance sheet as of June 30, 2002 or December 31, 2001.

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

		Six Months Ended
		June 30
millions		2002			2001
Interest	$		76	$		45
Income taxes	$		38	$		194

10. Segment Information The following table illustrates information related to Anadarko's business segments. The segment shown as All Other includes smaller operating units, corporate activities, financing activities and inter-company eliminations.

		Oil and Gas
		Exploration							All
millions		and Production		Marketing			Minerals		Other			Total
Three Months Ended June 30, 2002
Revenues		$	751	$	972		$	9	$	6		$	1,738
Intersegment revenues			202		2			--		(204	)		--
	Total revenues		953		974			9		(198	)		1,738
Income (loss) before income taxes		$	421	$	19		$	8	$	(111	)	$	337

Three Months Ended June 30, 2001
Revenues		$	783	$	1,437		$	12	$	6		$	2,238
Intersegment revenues			488		2			--		(490	)		--
	Total revenues		1,271		1,439			12		(484	)		2,238
Income (loss) before income taxes		$	693	$	(39	)	$	11	$	(66	)	$	599

		Oil and Gas
		Exploration						All
millions		and Production		Marketing		Minerals		Other			Total
Six Months Ended June 30, 2002
Revenues		$	1,359	$	1,716	$	22	$	14		$	3,111
Intersegment revenues			339		4		--		(343	)		--
	Total revenues		1,698		1,720		22		(329	)		3,111
Income (loss) before income taxes		$	676	$	5	$	19	$	(231	)	$	469
Net properties and equipment		$	12,632	$	248	$	1,204	$	414		$	14,498
Goodwill		$	1,443	$	--	$	--	$	--		$	1,443

Six Months Ended June 30, 2001
Revenues		$	1,847	$	3,379	$	23	$	(2	)	$	5,247
Intersegment revenues			972		13		--		(985	)		--
	Total revenues		2,819		3,392		23		(987	)		5,247
Income (loss) before income taxes		$	1,725	$	115	$	21	$	(209	)	$	1,652
Net properties and equipment		$	13,340	$	197	$	1,209	$	318		$	15,064
Goodwill		$	1,415	$	--	$	--	$	--		$	1,415

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

			Three Months Ended								Six Months Ended
			June 30								June 30
millions			2002				2001				2002				2001
Firm transportation keep-whole contract valuation (See Note 6)		$		(16	)	$		42		$		(10	)	$		(98	)
Foreign currency exchange *				(9	)			(35	)			(10	)			17
Corporate hedge ineffectiveness and change in time value				(3	)			(18	)			8				(27	)
Other				7				7				14				8
Total		$		(21	)	$		(4	)	$		2		$		(100	)

*	The three and six months ended June 30, 2002, excludes $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.

12. Commitments

Synthetic Leases In November 1999, Anadarko entered into a build-to-suit lease arrangement for its corporate office building in The Woodlands, Texas. The development and acquisition of the property was financed by a special purpose entity (SPE) sponsored by a financial institution. The amount funded was $165 million. The SPE is not consolidated in the Company's financial statements and, based on the initial terms of the agreement, the Company has accounted for this arrangement as an operating lease in accordance with SFAS No. 13, "Accounting for Leases."

The initial lease term is five years, with up to seven one-year renewal options. Monthly lease payments are based on the London interbank borrowing rate applied against the lease balance and began in mid-2002. 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 facility for a specified amount, which approximates the lessor's original cost ($165 million). As of June 30, 2002, the Company was in compliance with these covenants.

At the end of the lease term, the Company has an option to either purchase the facility for the purchase option amount of the lease balance plus any outstanding lease payments or to assist the SPE in the sale of the property. The Company has provided a residual value guarantee for any deficiency if the property is sold for less than the sale option amount ($139 million at June 30, 2002). In addition, the Company is entitled to any proceeds from a sale of the property in excess of the purchase option amount.

In December 2000, the Company entered into a lease arrangement for an office building in The Woodlands, Texas. The acquisition of the property was financed by an SPE sponsored by a financial institution. The amount funded was $48 million. The SPE is not consolidated in the Company's financial statements and the Company has accounted for this arrangement as an operating lease in accordance with SFAS No. 13.

The initial lease term is five years. Monthly lease payments, which began in 2001, are based on the London interbank borrowing rate applied against the $48 million 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 facility for a specified amount, which approximates the lessor's original cost ($48 million). As of June 30, 2002, the Company was in compliance with these covenants.

At the end of the lease term, the Company has an option to either purchase the facility for the purchase option amount of $48 million plus any outstanding lease payments or to assist the SPE in the sale of the property. The Company has provided a residual value guarantee for any deficiency if the property is sold for less than the sale option amount ($39 million at June 30, 2002). In addition, the Company is entitled to any proceeds from a sale of the property in excess of the purchase option amount.

If for either of these leases, 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 purchase option amount, the Company will accrue the expected loss on a straight line basis over the remaining lease term. Currently, management does not believe it is probable that the fair market value of either of these properties will be less than the purchase option amount at the end of the lease term.

Production Platform In April 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 2004, 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. Anadarko will be entitled to 25% of the net after tax cash proceeds from these facilities after payout, as defined, is attained. The agreement does not contain any purchase options, purchase obligations or value guarantees.

13. 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 RME 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.

Superfund Presently, five Superfund sites (four Federal and one State) are included in the Superfund Reserve.


	Operating Industries, Inc. (Federal) - The former municipal industrial landfill, located in Monterey Park, California, was operational between 1948 and 1984. RME was noticed as a Potentially Responsible Party (PRP) in June 1986 for its Wilmington Production Field's and Wilmington Refinery's contributions. One settlement and consent decree with the Environmental Protection Agency (EPA) was finalized in the second quarter of 2002 and the Company fulfilled its obligations by payment of $4.3 million. The Company believes its share of the remaining consent decree will be about $0.8 million.

	Ekotek (Federal) - The facility in Salt Lake City, Utah operated as a refinery from 1953 until 1978, at which time it was converted to a hazardous waste storage/treatment and petroleum recycling facility. The Utah Department of Environmental Quality issued multiple Notices of Violation to the facility in 1988, resulting in the facility's closing. Bear Creek Uranium Company, an affiliate of RME, was named as a PRP for its contributions of used/waste oils. Remediation of the Ekotek site is nearing completion and no additional funding requests are expected.

	Casmalia (Federal) - The Casmalia facility, located in Santa Barbara County, California, is a former Resource Conservation and Recovery Act hazardous waste disposal site. RME was noticed as a PRP in March 1993. RME's waste contribution is attributed to the Wilmington Refinery. Negotiations with the EPA are ongoing. The Company believes its share of the costs will be about $0.1 million.

	Geothermal Inc. (State) - The site, located in Middletown, California, was permitted as a Class II surface impoundment facility for geothermal wastes. Sludge from drilling operations and power plant wastes generated at the Geysers Geothermal Field between 1976 and 1987 were transported to the facility for treatment/disposal. The waste material was placed in evaporation ponds and allowed to dry. The resultant solids were buried onsite. Site remediation began in 1984. Anadarko was noticed as a PRP in December 1993. Several remedial methods are currently being evaluated to determine the most effective for addressing site groundwater impacts. The Company believes its share of the costs will be about $0.1 million.

	PCB Treatment, Inc. (Federal) - The PCB treatment/disposal site, located in Kansas City, Kansas and Kansas City, Missouri, operated from 1982 until 1986 when regulatory violations forced its closure. RME was noticed as a PRP in October 1998 for contributions attributed to Wilmington Refinery operations. PCB impacts are currently limited to the facility structures and surrounding soils. Remedial alternatives are under review. The Company believes its share of the costs will be about $0.1 million.

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 cou ld be subject to a variety of sanctions, including treble damages and substantial monetary fines.

A group of royalty owners purporting to represent RME'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 most recently 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.

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 that its gas was marketable in the condition produced, and thus plaintiffs' claims are without merit. This case was certified as a class action in August 2000 and was tried in February 2002. A decision from the trial court is expected by the end of 2002.

Citgo Litigation CITGO Petroleum Corporation's (CITGO) claims arise out of an Asset Purchase and Contribution Agreement dated March 17, 1987 whereby RME'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 RME 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, RME 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 RME. In conjunction with this matter, RME sued Continental Insurance for denial of coverage for claims related to this dispute. RME and Continental Insurance settled the insurance coverage litigation which resulted in Continental Insurance paying RME for the claims. Negotiations and discussions with CITGO continue.

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 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 f or refunds attributable to the time period before August 1, 1985.

The Company reached a settlement agreement with PanEnergy that required the Company to pay $15 million for settlement in full of all matters relating to the refunds of Kansas ad valorem tax reimbursements collected by the Company as first seller from August 1, 1985 through 1988. The settlement agreement was approved by the FERC and paid by Anadarko during 2001. The settlement agreement does not have any impact on the outstanding dispute between the Company and PanEnergy in connection with the refunds that relate to the Cimmaron River System. Anadarko's net income for 2001 included a $15 million charge (before taxes) related to the settlement agreement. Discussions with the Kansas Corporation Commission and PanEnergy to reach a settlement of the Cimmaron River System dispute are ongoing. At this time, it is estimated that a resolution may be reached in the second half of 2002, that may result in a payment by the Company of about $7 million. Accordingly, a provision for $7 million was charge d against income in 2001.

Other Litigation The Company has a reserve of $1 million for Kansas ad valorem tax refunds of RME. This amount reflects all principal and interest that 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 RME 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 co nclusion 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 is unable at this time to determine the fair market rental value or the fair market sales value of the West Plant, but will at least annually evaluate the potential effect of the obligation.

Guarantees Anadarko is guarantor for certain obligations of its wholly-owned and consolidated subsidiaries, which are included in the consolidated financial statements and notes. In addition, the Company is guarantor for specific financial obligations of two trona mining affiliates. The investments in these entities, which are not consolidated subsidiaries, are accounted for using the equity method. The Company has guaranteed a portion of certain Industrial Revenue Bonds, amounts due under a revolving credit agreement and letters of credit required for environmental surety bonds. The amount the Company would be obligated to pay should the affiliates default on these obligations would be up to $7 million for environmental surety bonds and $23 million for debt.

Other In connection with a sale of properties, the Company has agreed to indemnify the purchaser for the use of certain currency remeasurement losses claimed by the Company in previously filed tax returns, which are currently being evaluated by the taxing authorities. The Company believes it is probable that these losses will be disallowed and will have to be settled with the purchaser in cash. The Company has a $22 million liability recorded for the contingency.

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

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company's operations, economic performance and financial condition. These forward looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, and those statements preceded by, followed by or that otherwise include the words "believes", "expects", "anticipates", "intends", "estimates", "projects", "target", "goal", "plans", "objective", "should" or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward looking statements contained in the Private Securities Litigation Reform Act of 1995. S uch statements are subject to various risks and uncertainties, and actual results could differ materially from those expressed or implied by such statements due to a number of factors in addition to those discussed elsewhere in this Form 10-Q and in the Company's other public filings, press releases and discussions with Company management. Anadarko undertakes no obligation to publicly update or revise any forward looking statements. See "Regulatory Matters and Additional Factors Affecting Business" and "Critical Accounting Policies" in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in the Company's 2001 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				2002				2001				2002			2001

Revenues			$		1,738		$		2,238		$		3,111	$		5,247
Costs and expenses					1,374				1,601				2,543			3,621
Merger expenses					--				17				--			27
Interest expense					48				25				97			47
Other (income) expense					(21	)			(4	)			2			(100	)
Income taxes					96				197				139			586
Net income available to common stockholders before
	cumulative effect of change in accounting principle		$		239		$		401		$		327	$		1,062
Net income available to common stockholders			$		239		$		401		$		327	$		1,057
Earnings per share - before cumulative effect
		of change in accounting principle - basic	$		0.96		$		1.60		$		1.32	$		4.24
Earnings per share - before cumulative effect
		of change in accounting principle - diluted	$		0.93		$		1.50		$		1.27	$		4.01
Earnings per share - basic			$		0.96		$		1.60		$		1.32	$		4.22
Earnings per share - diluted			$		0.93		$		1.50		$		1.27	$		3.99

Net Income Anadarko's net income available to common stockholders in the second quarter of 2002 totaled $239 million or $0.93 per share (diluted) compared to net income of $401 million or $1.50 per share (diluted) for the second quarter of 2001. For the six-month period ended June 30, 2002, Anadarko's net income available to common stockholders was $327 million, or $1.27 per share (diluted). By comparison, for the six months ended June 30, 2001, Anadarko's net income available to common stockholders was $1.06 billion or $3.99 per share (diluted).

In January 2002, the Company discontinued the amortization of goodwill in accordance with Statement of Financial Accounting Standards (SFAS) No. 142, "Goodwill and Other Intangible Assets." Stated without amortization of goodwill, net income available to common stockholders for the three and six months ended June 30, 2001 would have been $420 million or $1.57 per share (diluted) and $1.09 billion or $4.13 per share (diluted), respectively.

Revenues

		Three Months Ended						Six Months Ended
		June 30						June 30
millions		2002			2001			2002			2001

Gas sales	$		480	$		825	$		833	$		1,939
Oil and condensate sales			418			375			768			736
Natural gas liquids sales			55			71			97			144
Marketing sales			770			950			1,377			2,408
Minerals and other			15			17			36			20
Total	$		1,738	$		2,238	$		3,111	$		5,247

Total revenues for the second quarter 2002 decreased $500 million or 22% compared to the second quarter 2001. Natural gas, crude oil and condensate and natural gas liquids (NGLs) revenues for the second quarter of 2002 decreased $318 million or 25% due primarily to a significant decrease in natural gas prices and a decrease in natural gas volumes, partially offset by higher crude oil volumes and prices. Marketing sales for the second quarter of 2002 decreased $180 million or 19% due primarily to decreases in commodity prices and is offset by a decrease in marketing purchases of $179 million.

For the six months ended June 30, 2002, total revenues decreased $2.14 billion or 41% compared to the six months ended June 30, 2001. Natural gas, crude oil and condensate and NGLs revenues for the six-month period ended June 30, 2002 decreased $1.12 billion or 40% due primarily to a significant decrease in natural gas prices, as well as decreases in natural gas volumes and crude oil, condensate and NGLs prices, partially offset by higher crude oil volumes. Marketing sales for the six months ended June 30, 2002 decreased $1.03 billion or 43% due primarily to decreases in commodity prices and is partially offset by a decrease in marketing purchases of $1.02 billion.

Analysis of Oil and Gas Sales Volumes

		Three Months Ended				Six Months Ended
		June 30				June 30
		2002		2001		2002		2001
Barrels of Oil Equivalent (MMBOE)
	United States		34		37		66		71
	Canada		8		9		18		16
	Algeria		6		2		11		4
	Other International		2		4		4		8
	Total		50		52		99		99

Barrels of Oil Equivalent per Day (MBOE/d)
	United States		365		411		368		395
	Canada		98		98		98		89
	Algeria		61		17		60		21
	Other International		22		44		23		43
	Total		546		570		549		548

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

During the second quarter of 2002, Anadarko sold 50 MMBOE, a decrease of 2 MMBOE or 4% compared to sales of 52 MMBOE in the second quarter of 2001. The decrease in volumes during the second quarter of 2002 was due primarily to a decrease of 3 MMBOE from operations in the United States, primarily offshore, a decrease of 2 MMBOE related to the disposition of operations in Guatemala and Argentina in 2001 and a decrease of 1 MMBOE in Canada. These decreases were partially offset by an increase of 4 MMBOE in Algeria due primarily to the expansion of production facilities.

For the six months ended June 30, 2002, Anadarko sold 99 MMBOE, essentially flat compared to sales for the same period of 2001. During 2002, volumes from operations in Algeria increased 7 MMBOE due to the expansion of production facilities and volumes from operations in Canada increased 2 MMBOE due to the Berkley Petroleum Corp. (Berkley) acquisition in 2001. These increases were offset by a decrease of 5 MMBOE in the United States, primarily offshore and in east Texas, and a decrease of 4 MMBOE related to the disposition of operations in Guatemala and Argentina in 2001. Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs marketing strategies to help manage production and sales volumes and mitigate the effect of price volatility, which is likely to continue in the future. See Derivative Financial 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
			2002				2001			2002				2001

United States (Bcf)				131				151			261				290
	MMcf/d			1,435				1,651			1,446				1,600
	Price per Mcf before hedge	$		3.00		$		4.41	$		2.56		$		5.57
	Effect of hedge per Mcf			(0.08	)			0.02			(0.03	)			0.03
	Price per Mcf	$		2.92		$		4.43	$		2.53		$		5.60

Canada (Bcf)				32				33			64				57
	MMcf/d			356				362			352				316
	Price per Mcf before hedge	$		2.87		$		4.70	$		2.54		$		5.66
	Effect of hedge per Mcf *			0.17				0.12			0.16				(0.13	)
	Price per Mcf	$		3.04		$		4.82	$		2.70		$		5.53

Other International (Bcf)				--				--			--				1
	MMcf/d			--				5			--				5
	Price per Mcf	$		--		$		1.24	$		--		$		1.13

Total (Bcf)				163				184			325				348
	MMcf/d			1,791				2,018			1,798				1,921
	Price per Mcf before hedge	$		2.97		$		4.46	$		2.56		$		5.57
	Effect of hedge per Mcf *			(0.03	)			0.03			--				0.01
	Price per Mcf	$		2.94		$		4.49	$		2.56		$		5.58


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

*	Includes the effect of financial derivative instruments as well as fixed price physical delivery sales contracts.

The Company's natural gas sales volumes for the second quarter 2002 were down 21 Bcf or 11% compared to the second quarter of 2001. The decrease in volumes is due primarily to a decrease in the Company's sales volumes within the United States, primarily central Texas and offshore, as a result of reduced spending for development drilling, a strategy the Company adopted in the third quarter of 2001 in response to lower commodity prices.

For the first six months of 2002, natural gas sales volumes were down 23 Bcf or 7% compared to the same period of 2001. The decrease in volumes is due primarily to a decrease in the Company's sales volumes within the United States, primarily central Texas and offshore, partially offset by an increase in volumes from Canada due to the Berkley acquisition in 2001. Production of natural gas is generally not directly affected by seasonal swings in demand. However, the Company may decide during periods of low commodity prices to decrease development activity, which can result in lower production volumes.

The Company's average wellhead gas price for the three and six months ended June 30, 2002 decreased 35% and 54%, respectively, from the same periods of 2001. The decrease in prices during 2002 was attributed to a severe decline in natural gas demand as a result of high prices in early 2001, a national economic downturn and mild summer weather in 2001. The Company has hedged 11% of its remaining forecasted 2002 natural gas wellhead sales volumes as of June 30, 2002. As a result, the remaining future natural gas volumes are subject to continued volatility based on fluctuations in market prices.

Crude Oil and Condensate Sales Volumes and Average Prices

			Three Months Ended							Six Months Ended
			June 30							June 30
			2002				2001			2002				2001

United States (MMBbls)				8				9			16				16
	MBbls/d			85				96			88				92
	Price per barrel before hedge	$		23.68		$		24.38	$		21.16		$		24.92
	Effect of hedge per barrel			(0.43	)			0.23			(0.09	)			0.08
	Price per barrel	$		23.25		$		24.61	$		21.07		$		25.00

Canada (MMBbls)				3				3			7				6
	MBbls/d			37				36			37				34
	Price per barrel before hedge	$		20.00		$		14.47	$		17.96		$		13.44
	Effect of hedge per barrel *			(0.78	)			4.37			(0.41	)			4.35
	Price per barrel	$		19.22		$		18.84	$		17.55		$		17.79

Algeria (MMBbls)				6				2			11				4
	MBbls/d			61				17			60				21
	Price per barrel	$		23.49		$		25.58	$		21.84		$		25.30

Other International (MMBbls)				2				4			4				8
	MBbls/d			22				43			23				42
	Price per barrel	$		21.21		$		14.68	$		18.19		$		14.77

Total (MMBbls)				19				18			38				34
	MBbls/d			205				192			208				189
	Price per barrel before hedge	$		22.70		$		20.45	$		20.46		$		20.67
	Effect of hedge per barrel*			(0.32	)			0.93			(0.11	)			0.81
	Price per barrel	$		22.38		$		21.38	$		20.35		$		21.48


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

*	Includes the effect of financial derivative instruments as well as fixed price physical delivery sales contracts.

Anadarko's crude oil and condensate sales volumes for the second quarter of 2002 increased 1 MMBbls or 6% compared to the second quarter of 2001. The increase in crude oil and condensate sales volumes was due primarily to an increase of approximately 4 MMBbls from operations in Algeria primarily related to the expansion of production facilities, partially offset by a decrease of 2 MMBbls related to the sale of producing properties in Guatemala and Argentina during 2001 and a decrease of 1 MMBbls related to operations in the United States, primarily offshore.

Crude oil and condensate sales volumes for the six months ended June 30, 2002 increased 4 MMBbls or 12% compared to the six months ended June 30, 2001. The increase in crude oil and condensate sales volumes was due primarily to an increase of approximately 7 MMBbls from operations in Algeria primarily due to the expansion of production facilities and an increase of 1 MMBbls from Canada due to the Berkley acquisition, partially offset by a decrease of 4 MMBbls related to the sale of producing properties in Guatemala and Argentina. Production of oil usually is not affected by seasonal swings in demand or in market prices.

Anadarko's average realized crude oil prices for the three and six months ended June 30, 2002 increased 5% and decreased 5%, respectively, compared to the same periods of 2001. The decrease in crude oil prices during the first six months of 2002 is attributed primarily to a modest increase in supply and very slow growth in demand due to a worldwide economic downturn and a sharp decline in jet fuel consumption. As of the end of July 2002, the Company has hedged 35% of its anticipated oil and condensate sales volumes for the second half of 2002. As a result, the remaining 65% of oil and condensate volumes for the second half of 2002 are subject to continued volatility based on fluctuations in market prices.

Natural Gas Liquids Sales Volumes and Average Prices

			Three Months Ended						Six Months Ended
			June 30						June 30
			2002			2001			2002			2001

Total (MMBbls)				4			4			7			7
	MBbls/d			42			42			41			39
	Price per barrel	$		14.34	$		18.81	$		13.02	$		20.52

The Company's NGLs sales volumes for the three and six months ended June 30, 2002 were flat compared to the same periods of 2001. During the three and six months ended June 30, 2002, average NGLs prices declined 24% and 37%, respectively, compared to the same periods of 2001. High levels of NGLs inventories in the United States during the first half of 2002, coupled with lower demand for NGLs by the petrochemical industry, have caused NGLs prices to decline.

Costs and Expenses

		Three Months Ended						Six Months Ended
		June 30						June 30
millions		2002			2001			2002			2001

Marketing purchases	$		752	$		931	$		1,348	$		2,364
Operating expenses			184			193			354			350
Administrative and general			77			64			149			113
Depreciation, depletion and amortization			274			320			541			594
Other taxes			62			66			118			149
Impairments related to oil and gas properties			25			8			33			15
Amortization of goodwill			--			19			--			36
Total	$		1,374	$		1,601	$		2,543	$		3,621

During the second quarter of 2002, Anadarko's costs and expenses decreased $227 million or 14% compared to the second quarter of 2001 due to the following factors:
--	Marketing purchases decreased $179 million (19%) due primarily to decreases in prices for gas and oil volumes purchased from third parties.
--	Operating expenses decreased $9 million (5%) primarily due to a decrease in downstream expenses.
--	Administrative and general expenses increased $13 million (20%) primarily due to increases in benefits and salaries expenses associated with the Company's workforce. Salaries expense included $2 million for amortization of restricted stock issued in connection with previous mergers.
--	Depreciation, depletion and amortization (DD&A) expense decreased $46 million (14%). The decrease is due primarily to a lower DD&A rate for oil and gas properties in 2002 as a result of ceiling test impairments in the third quarter of 2001 and a decrease related to lower production volumes in 2002.
--	Other taxes decreased $4 million (6%) primarily due to a decrease in production taxes related to the significantly lower commodity prices and lower production volumes in 2002.
--	Impairments of oil and gas properties were primarily due to unsuccessful exploration and development activities in Congo and Oman in 2002 and the United Kingdom in 2001.
--	Amortization of goodwill decreased $19 million due to discontinuing amortization of goodwill in 2002 in accordance with SFAS No. 142.

For the six-month period ended June 30, 2002, costs and expenses decreased $1.08 billion or 30% compared to the same period of 2001 due to the following factors:
--	Marketing purchases decreased $1.02 billion (43%) due primarily to decreases in prices for gas and oil volumes purchased from third parties.
--	Operating expenses increased $4 million (1%) primarily due to an increase in oil field service costs, partially offset by a decrease in downstream expenses.
--	Administrative and general expenses increased $36 million (32%) primarily due to increases in benefits and salaries expenses associated with the Company's workforce. Salaries expense included $4 million for amortization of restricted stock issued in connection with previous mergers.
--	DD&A expense decreased $53 million (9%). The decrease is due primarily to a lower DD&A rate for oil and gas properties in 2002 as a result of ceiling test impairments in the third quarter of 2001.
--	Other taxes decreased $31 million (21%) primarily due to a decrease in production taxes related to the significantly lower commodity prices in 2002.
--	Impairments of oil and gas properties were primarily due to unsuccessful exploration and development activities in Congo, Oman and Australia in 2002 and the United Kingdom and Ghana in 2001.
--	Amortization of goodwill decreased $36 million due to discontinuing amortization of goodwill in 2002 in accordance with SFAS No. 142.

Merger Expenses

For the three and six months ended June 30, 2001, merger costs of $17 million and $27 million, respectively, were expensed related to mergers and acquisitions that took place in 2000 and 2001. These costs related primarily to transition, integration, hiring and relocation costs, vesting of restricted stock and stock options, and retention bonuses. Any continuing expenses related to these acquisitions are minimal and are included in administrative and general expenses in 2002.

Interest Expense

		Three Months Ended								Six Months Ended
		June 30								June 30
millions		2002				2001				2002				2001

Gross interest expense	$		89		$		75		$		176		$		148
Capitalized interest			(41	)			(50	)			(79	)			(101	)
Net interest expense	$		48		$		25		$		97		$		47

Gross interest expense for the three and six months ended June 30, 2002 increased 19% compared to the same periods of 2001. The increase is due to higher average debt outstanding in 2002 compared to 2001 primarily because of acquisitions in 2001 and capital spending. See Capital Resources and Liquidity and Outlook on Liquidity.

For the three and six months ended June 30, 2002, capitalized interest decreased by 18% and 22%, respectively, compared to the same periods of 2001. 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		2002				2001				2002				2001

Firm transportation keep-whole contract valuation	$		(16	)	$		42		$		(10	)	$		(98	)
Foreign currency exchange			(9	)			(35	)			(10	)			17
Corporate hedge ineffectiveness and change in time value			(3	)			(18	)			8				(27	)
Other			7				7				14				8
Total	$		(21	)	$		(4	)	$		2		$		(100	)

Other income in the second quarter of 2002 increased $17 million compared to the same period of 2001 due primarily to a $58 million increase related to the effect of significantly higher market values for firm transportation subject to a keep-whole agreement, partially offset by a $26 million decrease in foreign currency exchange gains primarily due to the restructuring of Canadian debt and changes in the Canadian exchange rate and a $15 million decrease related to corporate hedges.

For the six months ended June 30, 2002, other income decreased $102 million compared to the same period of 2001 due primarily to a $88 million decrease related to the effect of significantly lower market values for firm transportation subject to a keep-whole agreement and a $35 million decrease related to corporate hedges, partially offset by a $27 million decrease in foreign currency exchange losses primarily due to the restructuring of Canadian debt and changes in the Canadian exchange rate. See Derivative Financial Instruments and Foreign Currency Risk under Item 3 of this Form 10-Q.

Income Taxes

		Three Months Ended							Six Months Ended
		June 30							June 30
millions		2002			2001				2002			2001

Income taxes	$		96	$		228		$		139	$		617
Effect of change in Canadian income tax rate			--			(31	)			--			(31	)
Total	$		96	$		197		$		139	$		586

For the second quarter of 2002, income taxes decreased $101 million or 51% compared to the second quarter of 2001. For the first six months of 2002, income taxes decreased $447 million or 76% compared to the same period of 2001. The net effective tax rate for the second quarter of 2002 was 28% compared to 33% for the same period of 2001 and the net effective tax rate for the first six months of 2002 was 30% compared to 35% for the same period of 2001. The decrease in the net effective tax rate for the three and six months ended June 30, 2002 was due to a benefit of $26 million and $33 million, respectively, primarily related to remeasurement of Venezuela deferred tax liabilities. During the second quarter of 2001, income taxes included a decrease of $31 million related to a deferred tax adjustment resulting from the 2% decrease in Canada's corporate income tax rate from 45% to 43%. Excluding these items, the decrease in income taxes is due primarily to the decrease in earnings before inc ome taxes.

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 has several large 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 through Anadarko Energy Services Company (AES), Anadarko, Anadarko Canada Corporation and RME Holding Company (RME). AES markets the Company's production to creditworthy customers at competitive prices, maximizing netbacks while managing credit exposure. The market knowledge gained is valuable to the corporate decision making process. AES purchases some physical volumes for resale primarily from partners and producers near our own production, which gives the Company operating and marketing flexibility to reduce risk s and maximize netbacks.

Third-party purchases allow the Company to aggregate larger volumes of gas and attract larger, creditworthy customers, which in turn enhances the value of the Company's production. AES 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. AES 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. Included in this strategy is the use of leased natural gas storage facilities and various derivative financial 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 has no round-trip trades or 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 Financial Instruments under Item 3 of this Form 10-Q.

During 2002, all segments of the natural gas market have experienced increased scrutiny on their financial condition, liquidity and credit. This has been reflected in rating agency credit downgrades of many merchant energy trading companies. In 2002, Anadarko has not experienced any material financial losses associated with credit deterioration of third-party gas purchasers; however, in certain situations the Company has changed its sales terms to require some counterparties to pay in advance or post letters of credit for gas purchases. Given the increased credit demands on gas sales, during 2002 the Company reduced its third-party gas purchases and sales in an effort to minimize future risk of possible losses associated with counterparty defaults.

Marketing Contracts The following schedules 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, 2002. The Company records income or loss on these activities using the mark-to-market method. During the three and six months ended June 30, 2002, the use of mark-to-market accounting compared to historical cost accounting resulted in additional non-cash income of $9 million and reduced non-cash income of $18 million, respectively, before taxes, related to the marketing and trading activities and resulted in additional non-cash income related to the firm transportation keep-whole agreement of $17 million and zero, respectively, before taxes. During the three and six months ended June 30, 2001, the use of mark-to-market accounting compared to historical cost accounting resulted in additional non-cash inc ome of $3 million and $20 million, respectively, before taxes, related to the marketing and trading activities and reduced non-cash income of $85 million and $5 million, respectively, before taxes, related to the firm transportation keep-whole agreement.

						Firm
		Marketing				Transportation
millions		and Trading				Keep-whole				Total

Fair value of contracts outstanding at December 31, 2001	$		17		$		(82	)	$		(65	)
Contracts realized or otherwise settled during 2002			6				(9	)			(3	)
Fair value of new contracts when entered into during 2002			2				--				2
Other changes in fair value			(26	)			10				(16	)
Fair value of contracts outstanding at June 30, 2002	$		(1	)	$		(81	)	$		(82	)

				Fair Value of Contracts at June 30, 2002
Assets (Liabilities)				Matures				Matures				Matures				Matures
millions				2002				2003-2004				2005-2006				Thereafter				Total

Marketing and Trading
	Prices actively quoted		$		(1	)	$		--		$		--		$		--		$		(1	)
	Prices based on models and other valuation
		methods			--				--				--				--				--

Firm Transportation Keep-whole
	Prices actively quoted		$		13		$		(7	)	$		--		$		--		$		6
	Prices based on models and other valuation
		methods			(7	)			(37	)			(28	)			(15	)			(87	)

Total
	Prices actively quoted		$		12		$		(7	)	$		--		$		--		$		5
	Prices based on models and other valuation
		methods			(7	)			(37	)			(28	)			(15	)			(87	)

Capital Resources and Liquidity
Capital Expenditures*

			Six Months Ended
			June 30
millions			2002			2001

Development		$		581	$		742
Exploration				584			471
Acquisitions of producing properties				1			45
Gathering and other				19			72
Capitalized interest and exploration and development costs				179			184
Total		$		1,364	$		1,514

*	Excludes corporate acquisitions.

During the first six months of 2002, Anadarko's capital spending was $1.36 billion, a decrease of 10% compared to the same period of 2001. This decrease is primarily due to a $161 million decrease in development and a $53 million decrease in gathering and other spending, partially offset by a $113 million increase in exploration spending. The shift in spending from development to exploration activities reflects the Company's decision to focus on increasing its inventory of drilling prospects by identifying new reserves through increased exploration, rather than growing production through development during the current down cycle for energy prices. The increase in exploration activity relates primarily to the higher level of activity in the Gulf of Mexico and Alaska.

The Company's original capital expenditure budget for 2002 was set at $2.0 billion. In July 2002, the Company increased the capital expenditure budget 10% to $2.2 billion.

Debt As of June 30, 2002, Anadarko's total debt was $5.54 billion. This compares to total debt of $5.05 billion at December 31, 2001. Due to activities in progress at the beginning of 2002 and the seasonal nature of drilling activity in Alaska and Canada, a disproportionate amount of the 2002 capital expenditure budget was spent in the first half of 2002 and, as a result, total debt increased $0.49 billion.

In April 2002, Anadarko filed a shelf registration statement with the Securities and Exchange Commission (SEC) that permits the issuance of up to $1 billion in debt securities, preferred stock, preferred securities, depositary shares, common stock, warrants, purchase contracts and purchase units, once effective. Net proceeds, terms and pricing of the offerings of securities issued under the shelf registration statement will be determined at the time of the offerings.

In February 2002, the Company issued $650 million principal amount of 5 3/8% Notes due 2007. In March 2002, the Company issued $400 million principal amount of 6 1/8% Notes due 2012. The net proceeds from these issuances were used to reduce floating rate debt and to fund a portion of the Zero Yield Puttable Contingent Debt Securities (ZYP-CODES) put to the Company for repayment in March 2002.

Common Stock Purchase Program In 2001, the Board of Directors authorized the Company to purchase up to $1 billion in shares of Anadarko common stock. The share purchases may be made from time to time, depending on market conditions. Shares may be purchased either in the open market or through privately negotiated transactions. The repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time.

To enhance the share repurchase program, Anadarko has sold put options to independent third parties. These put options entitle the holder to sell shares of Anadarko common stock to the Company on certain dates at specified prices. During 2001, Anadarko sold put options for the purchase of a total of 5 million shares of Anadarko common stock with a notional amount of $240 million. A put option for 1 million shares was exercised and put options for 2 million shares expired unexercised in 2001. In January 2002, the Company entered into an additional put option for 1 million shares of Anadarko common stock with a notional amount of $46 million and received a $3 million premium. In July 2002, this put option was extended, and the Company received an additional $3 million premium. Put options for an additional 2 million shares expired unexercised in 2002. The remaining put option for 1 million shares will expire in October 2002, if not exercised. The put options permit a net-share settlement at the Company's option and did not result in a liability on the consolidated balance sheet as of June 30, 2002 or December 31, 2001.

The following table summarizes purchases under the stock purchase program and the effect of the related put option premiums on the repurchase price.

						Six Months
						Ended
		Annual				June 30,				Total
millions except per share amounts		2001				2002				Program

Shares repurchased			2.2				1.0				3.2
Total paid for shares repurchased	$		116		$		50		$		166
Put premiums settled			(7	)			(7	)			(14	)
Total repurchase price	$		109		$		43		$		152

Average repurchase price per share	$		49.41		$		43.04		$		47.42

Obligations and Commitments

Production Platform In April 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 2004, 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. Anadarko will be entitled to 25% of the net after tax cash proceeds from these facilities after payout, as defined, is attained. The agreement does not contain any purchase options, purchase obligations or value guarantees.

Outlook on Liquidity

Anadarko's net cash from operating activities during the six months ended June 30, 2002 was $1.0 billion compared to $2.1 billion for the same period in 2001. The decrease in cash flow is attributed primarily to a significant decrease in natural gas prices, as well as decreases in natural gas volumes and crude oil, condensate and NGLs prices. Cash flow from operations will vary depending upon, among other things, actual commodity prices received throughout the year.

Anadarko believes that operating cash flow and existing or available credit facilities will be adequate to meet its capital and operating requirements for 2002. However, due to activities in progress at the beginning of 2002 and the seasonal nature of drilling activity in Alaska and Canada, a disproportionate amount of the 2002 capital expenditure budget was spent in the first six months of the year. As a result, there was an increase in debt in the first half of the year that the Company expects to reduce in the second half of 2002. If prices do not increase as expected later in the year, the Company may have higher borrowing levels at December 31, 2002. Reduced fourth quarter activity in 2002 relative to 2001 could lead to higher working capital requirements and also result in additional borrowing. The Company has a three-year stock buyback program to purchase up to $1 billion in shares of Anadarko common stock. Potential stock repurchases for 2002 are not included in the announced capi tal expenditure budget and could require additional borrowing.

The Company's credit agreements allow for a maximum capitalization ratio of 60% debt, exclusive of the effect of any non-cash write-downs. As of June 30, 2002, Anadarko's capitalization ratio was 45% 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, 2002. 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.

As a result of the announced asset sales (see Divestitures) and recent decisions not to process gas for natural gas liquids recovery in the east Texas Carthage plant and part of the Rockies due to current processing economics, Anadarko is reducing its volume guidance for 2002 from 199 MMBOE to 196 MMBOE. This reduction in estimated volumes is expected to have very little impact on our financial results for 2002.

Exploration and Development Activities

During the second quarter of 2002, Anadarko participated in a total of 166 wells, including 95 gas wells, 62 oil wells and 9 dry holes. This compares to a total of 328 wells, including 222 gas wells, 93 oil wells and 13 dry holes during the second quarter of 2001.

For the first six months of 2002, Anadarko participated in a total of 522 wells, including 367 gas wells, 130 oil wells and 25 dry holes. This compares to a total of 571 wells, including 398 gas wells, 150 oil wells and 23 dry holes during the first six months of 2001. Following are highlights of second quarter 2002 activity:

-- In Canada, Anadarko made three new natural gas discoveries during the second quarter of 2002. In the Triassic in northeast British Columbia, two discovery wells were tested at 6.5 MMcf/d and 6.1 MMcf/d, respectively. These two wells, together with an offsetting development well also completed during the second quarter, were brought on production at a combined rate of 20 MMcf/d. Nine additional follow-up locations are planned. In the deep basin in northwest Alberta, Anadarko completed two wells in the Saddle Hills area, one of which tested at a rate of 6.5 MMcf/d.

-- In north Louisiana, the Company made a recent discovery at the Ansley prospect adjacent to the Vernon field. The Davis Brothers No. 11-1 well initially flowed at 8 MMcf/d. The Company is drilling three wells to confirm the discovery, as well as additional development drilling in the area. Anadarko holds 116,000 net acres in north Louisiana.

-- In east Texas, a new Bossier discovery at the Gregory A-1 well initially flowed at a rate of 8 MMcf/d. Three stepout wells are planned at Gregory, as well as further development drilling. Anadarko has exploration rights for 23,000 net acres in the area surrounding the discovery.

-- In Algeria, Anadarko was awarded exploration rights over Block 403c/e in Algeria's third licensing round. Anadarko will hold a 67% interest in the exploration phase of this venture. This increases Anadarko's gross acreage in the Berkine basin by 400,000 acres to 4 million acres. The 100 millionth barrel of oil was produced through the Hassi Berkine central processing facility in May 2002 and the Company announced plans to drill three new exploration wells in Algeria in the second half of 2002.

-- In Qatar, Anadarko acquired BP's interest in Blocks 12 and 13, including the Al Rayyan oilfield, and took over operatorship. When a field expansion and redevelopment program is complete in early 2003, gross oil production from Al Rayyan is expected to nearly triple to 35 MBbls/d.

-- In the Gulf of Mexico, the "I" platform at South Marsh Island Block 281 has been installed, and gas production from three discovery wells is expected to begin in early August 2002 at a rate of about 80 MMcf/d.

Divestitures

In August 2002, the Company announced a $320 million asset divestiture program planned for 2002. As part of the divestiture plan, Anadarko closed on the sales of selected non-core producing assets in south Texas and south Louisiana for $60 million during the second quarter. In addition, a wholly owned subsidiary, Anadarko Canada Corporation, has agreed to sell its heavy oil assets in eastern Alberta in several separate transactions for a total of about C$250 million (about U.S. $160 million). The Company also has identified another $100 million of properties it plans to put up for sale in the near future.

New Accounting Principles

SFAS No. 143 SFAS No. 143, "Accounting of Asset Retirement Obligations," requires the fair value of a liability for an asset retirement obligation to be recorded in the period in which it is incurred along with a corresponding increase in the carrying amount of the related long-lived asset and will be effective for the Company in January 2003. The Company is evaluating the impact of SFAS No. 143.

SFAS No. 145 SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13 and Technical Corrections," was issued in April 2002. SFAS No. 145 provides guidance for income statement classification of gains and losses on extinguishment of debt and accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 145 will be effective for the Company in January 2003. The Company is evaluating the impact of SFAS No. 145 and does not expect adoption to materially affect the consolidated financial statements.

SFAS No. 146 SFAS No. 146, "Accounting for Exit or Disposal Activities," was issued in June 2002. SFAS No. 146 addresses significant issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance set forth in Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity." SFAS No. 146 will be effective for the Company in January 2003. The Company is evaluating the impact of SFAS No. 146.

EITF Issue No. 02-3 EITF Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10," was issued in June 2002. EITF Issue No. 02-3 addresses certain issues related to energy trading activities, including (a) gross versus net presentation in the income statement, (b) whether the initial fair value of an energy trading contract can be other than the price at which it was exchanged, and (c) additional disclosure requirements for energy trading activities. EITF Issue No. 02-3 will be effective for the Company in the third quarter of 2002. The Company is evaluating the impact of EITF Issue No. 02-3 and expects adoption to result in the presentation of net marketing margins in revenues, rather than marketing reven ues, which were offset by marketing purchases in costs and expenses.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Derivative Financial Instruments Anadarko's derivative financial instruments currently are comprised of futures, swaps and options contracts. The volume of derivative financial 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.

Anadarko uses derivative financial instruments for various purposes and carefully monitors the credit worthiness of each counterparty. Derivative financial instruments utilized to manage or reduce commodity price risk related to the Company's equity production are accounted for under the provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." All derivatives are carried on the balance sheet at fair value. Realized gains/losses and option premiums are recognized in the statement of income when the underlying physical gas and oil production is sold. Accordingly, realized derivative gains/losses are generally offset by similar changes in the realized prices of the underlying physical gas and oil production. Realized derivative gains/losses are reflected in the average sales price of the physical gas and oil production.

Accounting for unrealized gains/losses is dependent on whether the derivative financial instruments have been designated and qualify as part of a hedging relationship. Derivative financial 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/losses on derivative financial instruments that do not meet the conditions to qualify for hedge accounting are recognized currently in earnings.

If the hedged exposure is a cash flow exposure, the effective portion of the gains/losses on the derivative financial 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/losses from the derivative financial 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. Effective July 2001, the Company implemented Derivatives Implementation Group Issue G20, "Cash Flow Hedges: Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash Flow Hedge," which provides guidance for assessing the effectiveness on total changes in an option's cash flows rather than only on changes in the option's intrinsic value. Time value changes were previously being recognized in current earnings since the C ompany excluded time value changes from its assessment of hedge effectiveness.

If the hedged exposure is a foreign currency exposure, the accounting is similar to the accounting for fair value and cash flow hedges.

As of June 30, 2002, the Company had a net unrealized loss of $11 million before taxes (gains of $7 million and losses of $18 million), or $7 million after taxes, on derivative commodity instruments entered into to hedge equity production recorded in accumulated other comprehensive income compared to a net unrealized gain of $7 million before taxes (gains of $9 million and losses of $2 million), or $4 million after taxes at December 31, 2001. Other income for the second quarter of 2002 and 2001, included $3 million and $18 million, respectively, of net gains related to derivative instruments designated as cash flow hedges. For the first six months of 2002 and 2001, other income included $8 million of net losses and $27 million of net gains, respectively, related to derivative instruments designated as cash flow hedges. These gains/losses were primarily due to the ineffective portion of the hedge and the change in the time value of the option contracts that was excluded from the assessmen t of hedge effectiveness. Based upon an analysis utilizing the actual derivative contractual volumes and assuming a 10% increase in commodity prices, the potential additional loss on these derivative commodity instruments would be approximately $25 million.

June 30, 2002

							Net Fair Value
	Production						Asset (Liability)
	Period	Instrument Type**	Volumes		Average Price		millions

Natural Gas			(million MMBtu)		($ per MMBtu)

	2002	2-way collar*		20	3.71-4.24	$		7
	2002	3-way collar*		3	2.20-3.00-4.83			--
	2003	2-way collar*		2	3.00-5.00			--
	2003	3-way collar*		7	2.20-3.00-4.83			(1	)
	2004	2-way collar*		2	3.00-5.00			--
	2004	3-way collar*		7	2.20-3.00-4.83			(2	)
	2005	2-way collar*		2	3.00-5.00			--
	2005	3-way collar*		7	2.20-3.00-4.83			(2	)
	2002	Calls sold		5	3.72			--
	2002	Calls purchased		3	3.58			--
	2003	Calls sold		7	3.31			(3	)
	2003	Calls purchased		10	3.47			3
	2004	Calls sold		1	3.06			--
	2004	Calls purchased		1	3.06			--
		Total				$		2

Crude Oil			(MMBbls)		($ per barrel)

	2002	Swaps*		2	24.28	$		(1	)
	2002	2-way collar*		1	22.30-23.32			(2	)
	2002	3-way collar*		3	17.89-21.94-28.04			(3	)
	2003	Swaps*		1	23.80			--
	2003	2-way collar*		1	22.30-23.32			(1	)
	2003	3-way collar*		4	17.00-21.00-26.33			(4	)
		Total				$		(11	)

December 31, 2001

								Net Fair Value
	Production							Asset (Liability)
	Period		Instrument Type**	Volumes		Average Price		millions

Natural Gas				(million MMBtu)		($ per MMBtu)

	2002		2-way collar*		2	3.00-5.00	$		1
	2002		3-way collar*		7	2.20-3.00-4.83			2
	2003		2-way collar*		2	3.00-5.00			1
	2003		3-way collar*		7	2.20-3.00-4.83			1
	2004		2-way collar*		2	3.00-5.00			1
	2004		3-way collar*		7	2.20-3.00-4.83			1
	2005		2-way collar*		2	3.00-5.00			1
	2005		3-way collar*		7	2.20-3.00-4.83			1
	2002		Calls sold		10	3.66			2
	2002		Calls purchased		5	3.50			--
	2003		Calls sold		7	3.18			(2	)
	2003		Calls purchased		10	4.12			2
	2004		Calls sold		1	2.95			--
	2004		Calls purchased		1	2.95			--
			Total				$		11

Crude Oil				(MMBbls)		($ per barrel)

	2002		Swaps*		1	25.56	$		2
	2002		3-way collar*		3	19.11-23.33-30.51			6
			Total				$		8


MMBtu - million British thermal units
MMBbls - million barrels

*		Qualifies for hedge accounting.
**		A "2-way collar" is a combination of options, a sold call and purchased put. The purchased put establishes a minimum price (the "floor") and the sold call establishes a maximum price (the "ceiling") the Company will receive for the volumes under contract. A "3-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 "ceiling") the Company will receive for the volumes under contract.

Derivative financial instruments utilized in the Company's energy trading activities and in the management of price risk associated with the Company's firm transportation keep-whole commitment are accounted for under the mark-to-market accounting method pursuant to Emerging Issues Task Force Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." Under this method, the derivatives and physical delivery contracts are revalued in each accounting period and premiums and unrealized gains/losses are immediately recorded in the statement of income and carried as assets or liabilities on the balance sheet. Anadarko's energy marketing and trading business is backed by the Company's substantial oil and gas production and reserves. In the United States and Canada, the Company purchases natural gas produced by other companies in those areas where the Company has substantial production volumes. Third-party purchases allow the Company to aggregate larger v olumes of gas and attract larger, more creditworthy customers, which in turn spreads the Company's relatively fixed overhead costs over more gas and can help reduce transportation costs. The Company does not engage in market making practices nor does it trade in any non-energy-related commodities. The marketing and trading business's risk position, most of the time, is a net short position. Excluding the firm transportation keep-whole agreement, essentially all of the Company's trading transactions have a term of less than one year and most are less than three months. The keep-whole agreement will be in effect until the earlier of each contract's expiration date or February 2009. As of June 30, 2002, the Company had a net unrealized gain of $1 million (gains of $33 million and losses of $32 million) on derivative commodity instruments entered into for trading purposes and a net unrealized loss of $2 million (gains of $21 million and losses of $23 million) on physical contracts entered into for trading purpos es. As of December 31, 2001, the Company had a net unrealized loss of $49 million (gains of $42 million and losses of $91 million) on derivative commodity instruments entered into for trading purposes. Losses on derivative commodity instruments were offset by a net unrealized gain of $66 million (gains of $82 million and losses of $16 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 loss on the derivative instruments would be increased by approximately $17 million.

The energy trading derivative contracts are primarily used to neutralize fixed price exposure in physical delivery agreements and to generate profit on or from exposure to changes in the market price of crude oil and natural gas. As of June 30, 2002 and December 31, 2001, the Company had the following volumes under derivative contracts related to its trading activity:

June 30, 2002

							Net Fair Value
	Production						Asset (Liability)
	Period	Instrument Type	Volumes	Average Price			millions

Natural Gas			(million MMBtu)	($ per MMBtu)

	2002	Futures sold	18		3.32	$		1
	2002	Futures purchased	20		3.33			--
	2002	Swaps	42		3.35			(1	)
	2002	Calls sold	13		3.75			--
	2002	Calls purchased	4		4.04			--
	2002	Puts sold	2		3.84			(1	)
	2002	Puts purchased	6		2.84			--
	2003	Futures sold	5		3.47			(3	)
	2003	Futures purchased	6		3.53			2
	2003	Swaps	45		3.68			3
	2003	Calls purchased	3		4.40			1
	2004	Futures sold	1		3.84			--
	2004	Swaps	1		4.02			--
	2005	Swaps	1		4.05			--
	2006	Swaps	1		3.99			--
		Total				$		2

Crude Oil			(MMBbls)	($ per barrel)

	2002	Futures sold	3		24.79	$		(1	)
	2002	Futures purchased	3		25.03			--
	2002	Puts sold	1		23.56			--
		Total				$		(1	)

December 31, 2001

							Net Fair Value
	Production						Asset (Liability)
	Period	Instrument Type	Volumes	Average Price			millions

Natural Gas			(million MMBtu)	($ per MMBtu)

	2002	Futures sold	24		3.34	$		18
	2002	Futures purchased	22		3.50			(21	)
	2002	Swaps	72		3.20			(42	)
	2002	Calls sold	8		3.07			1
	2002	Calls purchased	13		4.09			1
	2002	Puts sold	8		3.25			(7	)
	2002	Puts purchased	1		2.58			--
	2003	Futures sold	1		3.51			--
	2003	Futures purchased	1		3.36			--
	2003	Swaps	12		3.12			--
		Total				$		(50	)

Crude Oil			(MMBbls)	($ per barrel)

	2002	Futures sold	3		19.80	$		(1	)
	2002	Futures purchased	1		20.05			2
	2002	Swaps	1		21.77			--
	2002	Calls sold	1		29.50			--
		Total				$		1

RME Holding Company (RME) was a party to several long-term firm gas transportation agreements that supported its gas marketing program within its gathering, processing and marketing (GPM) business segment, which was sold in 1999 to Duke Energy Field Services, Inc. (Duke). Most of the GPM's firm long-term 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, RME agreed to pay Duke if transportation market values fall below the fixed contract transportation rates, while Duke will pay RME if the transportation market values exceed the contract transportation rates (keep-whole agreement). Net (payments to) or receipts from Duke for the three months ended June 30, 2002 and 2001 were $(2) million and $64 million, respe ctively. Net (payments to) or receipts from Duke for the six months ended June 30, 2002 and 2001 were $(12) million and $141 million, respectively. Transportation contracts transferred to Duke in the GPM disposition and the contract not transferred, all of which are included in the keep-whole agreement with Duke, relate to various pipelines. This keep-whole agreement is accounted for on a mark-to-market basis. This keep-whole agreement will be in effect until the earlier of each contract's expiration date or February 2009. During the second quarter of 2002 and 2001, the Company recognized other income of $16 million ($27 million gain from the agreement and $11 million loss from derivative financial instruments) and other expense of $42 million ($138 million loss from the agreement and $96 million gain from derivative financial instruments), respectively. During the first six months of 2002 and 2001, the Company recognized other income of $10 million ($24 million gain from the agreement and $14 million loss from derivative financial instruments) and $98 million ($46 million from the agreement and $52 million from derivative financial instruments), respectively. As of June 30, 2002, other current assets included $4 million and other long-term liabilities included $75 million related to this agreement. As of December 31, 2001, accounts payable included $27 million and other long-term liabilities included $80 million related to this agreement. The future gain or loss from this agreement cannot be accurately predicted.

Anticipated discounted and undiscounted liabilities (assets) for the firm transportation keep-whole commitment at June 30, 2002 are as follows:

millions		Undiscounted				Discounted

2002	$		(16	)	$		(16	)
2003			23				22
2004			27				23
2005			20				15
2006			19				13
Later years			24				14
Total	$		97		$		71

The Company may periodically use derivative financial instruments to reduce its exposure under the keep-whole agreement to potential decreases in future transportation market values. While the 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. For the three months ended June 30, 2002 and 2001, the Company recognized other expense of $11 million and other income of $96 million, respectively, on derivative financial instruments related to transportation rates. For the six months ended June 30, 2002 and 2001, the Company recognized other expense of $14 million and other income of $52 million, respectively, on derivative financial instruments related to transportation rates. At June 30, 2002 and December 31, 2001 accounts payable included $10 million and other current assets included $25 million, respectively, of unrealized gains and losses related to this agreement. Due to decreased liquidity, the use of derivative financial instruments to manage this risk is generally limited to the forward twelve months only.

As of June 30, 2002 and December 31, 2001, the Company had the following volumes of natural gas under derivative contracts related to the firm transportation keep-whole agreement:

Net Fair Value

Production

Volumes

Average Price

Asset (Liability)

Period

Instrument Type

(million MMBtu)

($ per MMBtu)

millions

June 30, 2002

2002

Swaps

2.25

(10

)

December 31, 2001

2002

Swaps

8.42

Represents 11% of the Company's total volumetric exposure under the keep-whole agreement for the remainder of 2002.

Represents 2% of the Company's total volumetric exposure under the keep-whole agreement for 2002.

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.

Common Stock Purchase Program In 2001, the Board of Directors authorized the Company to purchase up to $1 billion in shares of Anadarko common stock. For a description of the program, see Common Stock Purchase Program under Item 2 of this Form 10-Q.

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. In addition, in these subsidiaries, certain asset and liability balances are denominated in currencies other than the subsidiary's functional currency. These asset and liability balances are remeasured in the preparation of the subsidiary's financial statements using a combination of current and historical exchange rates, with any resulting remeasurement adjustments included in net income during the period.

At June 30, 2002 and December 31, 2001, a Canadian subsidiary had $187 million outstanding of fixed-rate notes and debentures denominated in U.S. dollars. During the second quarter of 2002 and 2001, the Company recognized $9 million and $17 million, respectively, of non-cash gains before taxes associated with the remeasurement of this debt. For the six months ended June 30, 2002 and 2001, the Company recognized $9 million of non-cash gains and $16 million of non-cash losses, respectively, before taxes associated with the remeasurement of this debt. The potential foreign currency remeasurement impact on earnings from a 10% increase in the June 30, 2002 Canadian exchange rate would be about $17 million based on the outstanding debt at June 30, 2002.

The Company periodically enters into foreign currency contracts to hedge specific currency exposures from commercial transactions. The Company has acquired foreign currency forward exchange contracts with maturities through October 2004 and recorded a $4 million liability representing the fair value of these contracts. These contracts were determined to be cash flow hedges of Anadarko Canada's future U.S. dollar denominated hydrocarbon sales. This liability will be recognized in earnings when the contracts are settled.

The following table summarizes the Company's open foreign currency positions at June 30, 2002 and December 31, 2001. Approximately $1 million and $3 million of the after tax unrealized loss was included in accumulated other comprehensive income as of June 30, 2002 and December 31, 2001, respectively.

		June 30,				December 31,
$ in millions, except foreign currency rates		2002				2001

Notional amount - US$	$		70		$		70
Forward rate			1.36				1.36
Market rate			1.49				1.58
Decrease in rate			(0.13	)			(0.22	)
Fair value - loss - C$	$		9		$		15
Fair value - loss - US$	$		6		$		10

At June 30, 2002 and December 31, 2001, the Company's Latin American subsidiaries had foreign deferred tax liabilities denominated in the local currency equivalent totaling $50 million and $78 million, respectively. During the second quarter of 2002, the Company recognized tax benefits primarily associated with remeasurement of these deferred tax liabilities of $26 million compared with $1 million for the same period of 2001. During the first six months of 2002 and 2001, the Company recognized tax benefits primarily associated with remeasurement of these deferred tax liabilities of $33 million and $2 million, respectively. In conjunction with the sale of Latin American 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% change in the June 30, 2002 Latin American exchange rates would be approximately $6 million .

Part II. OTHER INFORMATION
Item 1. Legal Proceedings

See Note 13 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 25, 2002 the Company held its Annual Stockholders' Meeting.

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

	Mr. Ronald Brown was re-elected with 210,255,916 votes for and 1,937,499 votes withheld. Mr. John R. Butler, Jr. was re-elected with 209,130,784 votes for and 3,062,631 votes withheld. Mr. Preston M. Geren III was re-elected with 210,271,222 votes for and 1,922,193 votes withheld. Mr. John R. Gordon was re-elected with 210,300,468 votes for and 1,892,947 votes withheld.

Item 5. Other Information

On August 14, 2002, the principal executive officer and the principal financial officer of Anadarko delivered their sworn written statements to the Securities and Exchange Commission as required by Commission Order No. 4-460. The sworn written statements of John N. Seitz, President and Chief Executive Officer, and Michael E. Rose, Executive Vice President and Chief Financial Officer were filed on a Form 8-K, dated August 14, 2002, as Exhibits 99.1 and 99.2.

On August 14, 2002, the chief executive officer and the chief financial officer of Anadarko signed the written certifications required under Section 906 of the Sarbanes-Oxley Act of 2002. The written certifications of John N. Seitz, President and Chief Executive Officer, and Michael E. Rose, Executive Vice President and Chief Financial Officer are included in this report as Exhibit 99.

In July 2002, Anadarko created two new committees for its Board of Directors and realigned several existing committees in an effort to augment the directors' advisory role to the Company. Under the new plan, Anadarko's Board of Directors will now have five standing committees.

The new Nominating and Corporate Governance Committee will be chaired by James L. Bryan. The members will be Conrad P. Albert, Larry Barcus, Preston M. Geren III and John R. Gordon. All members of the committee are outside directors. The primary responsibilities of this committee are to select and recommend director nominees and develop and recommend to the Board of Directors a set of corporate governance principles for the Company.

The new CEO Advisory Committee will be chaired by John R. Gordon. The members will be Robert J. Allison, Jr., John R. Butler, Jr. and John W. Poduska, Sr. All members of the committee are outside directors, except Mr. Allison. The primary responsibility of this committee is to provide Anadarko's Chief Executive Officer with strategic advice on the long-term direction of the Company and important management decisions.

Anadarko's Audit Committee is chaired by John R. Butler, Jr. The members are Conrad P. Albert, Larry Barcus and Ronald Brown. All members of the committee are outside directors. The primary responsibilities of the this committee are independent objective oversight of the Company's accounting functions and internal controls.

The Compensation and Benefits Committee is chaired by John W. Poduska, Sr. The members are James L. Bryan, Preston M. Geren III and John R. Gordon. All members of the committee are outside directors. The primary responsibilities of this committee are establishing and administrating director and executive compensation and benefit programs. The committee also has general oversight responsibilities for the Company's qualified benefit plans.

Anadarko's Executive Committee is chaired by Robert J. Allison, Jr. The members are Ronald Brown, James L. Bryan and John R. Butler, Jr. All members of the committee are outside directors, except Mr. Allison. The primary responsibility of the Executive Committee is to take action regarding the conduct of the business of the Company between Board meetings.

Effective May 23, 2002, George Lindahl III and Jeff D. Sandefer resigned as directors of Anadarko. Messrs. Lindahl and Sandefer joined Anadarko's Board of Directors following the Company's merger with Union Pacific Resources Group, Inc. in July 2000. That transition is now complete and they plan to devote full-time to their oil and gas investment company operations.

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		4.1 to Form 8-A dated		1-8968
		October 29, 1998, between Anadarko		October 30, 1998
		and The Chase Manhattan Bank

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

*99		Certification of Chief Executive Officer and
		Chief Financial Officer

(b)	Reports on Form 8-K

	There were no reports filed on Form 8-K during the three months ended June 30, 2002.

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 14, 2002	By:	/s/ MICHAEL E. ROSE
	Michael E. Rose - Executive Vice President
	and Chief Financial Officer