QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

ANADARKO PETROLEUM CORPORATION
17001 Northchase Drive, Houston, Texas 77060-2141
(281) 875-1101

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject tosuch filing requirements for the past 90 days.Yes X No _____

The number of shares outstanding of the Company's common stock as of ~~April 30,~~July 31, 2001 is shown below:

ANADARKO PETROLEUM CORPORATION	ANADARKO PETROLEUM CORPORATION									ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF INCOME	CONSOLIDATED STATEMENT OF INCOME									CONSOLIDATED STATEMENT OF INCOME
(Unaudited)	(Unaudited)									(Unaudited)
			Three Months Ended									Three Months Ended							Six Months Ended
			March 31									June 30							June 30
millions except per share amounts	millions except per share amounts		2001				2000			millions except per share amounts		2001				2000			2001			2000
Revenues	Revenues									Revenues
Gas sales	Gas sales	$		1,114		$		109		Gas sales	$		825		$		156	$	1,939		$		265
Oil and condensate sales	Oil and condensate sales			361				118		Oil and condensate sales			375				93		736				211
Natural gas liquids sales	Natural gas liquids sales			73				42		Natural gas liquids sales			71				38		144				80
Marketing sales	Marketing sales			1,500				391		Marketing sales			976				460		2,476				851
Minerals and other	Minerals and other			3				1		Minerals and other			17				1		20				2
Total	Total			3,051				661		Total			2,264				748		5,315				1,409

Costs and Expenses	Costs and Expenses									Costs and Expenses
Marketing purchases and transportation	Marketing purchases and transportation			1,475				380		Marketing purchases and transportation			957				446		2,432				826
Operating expenses	Operating expenses			157				61		Operating expenses			193				62		350				123
Administrative and general	Administrative and general			49				30		Administrative and general			64				30		113				60
Depreciation, depletion and amortization	Depreciation, depletion and amortization			274				59		Depreciation, depletion and amortization			320				60		594				119
Other taxes	Other taxes			83				12		Other taxes			66				13		149				25
Impairments related to international properties	Impairments related to international properties			7				--		Impairments related to international properties			8				--		15				--
Amortization of goodwill	Amortization of goodwill			17				--		Amortization of goodwill			19				--		36				--
Total	Total			2,062				542		Total							611		3,689				1,153

Operating Income	Operating Income			989				119		Operating Income			637				137		1,626				256

Other (Income) Expense	Other (Income) Expense									Other (Income) Expense
Merger expenses	Merger expenses			10				--		Merger expenses			17				--		27				--
Interest expense	Interest expense			22				21		Interest expense			25				20		47				41
Other (income) expense				(96	)			--
Other income										Other income			(4	)			--		(100	)			--
Total	Total			(64	)			21		Total			38				20		(26	)			41

Income Before Income Taxes	Income Before Income Taxes			1,053				98		Income Before Income Taxes			599				117		1,652				215

Income Taxes	Income Taxes			389				47		Income Taxes
Income taxes										Income taxes			228				50		617				98
Effect of change in Canadian income tax rate										Effect of change in Canadian income tax rate			(31	)			--		(31	)			--
Total										Total			197				50		586				98

Net Income Before Cumulative Effect of Change	Net Income Before Cumulative Effect of Change									Net Income Before Cumulative Effect of Change
	in Accounting Principle	$		664		$		51		in Accounting Principle	$		402		$		67	$	1,066		$		117

Preferred Stock Dividends	Preferred Stock Dividends			3				3		Preferred Stock Dividends			1				3		4				5

Net Income Available to Common Stockholders Before	Net Income Available to Common Stockholders Before									Net Income Available to Common Stockholders Before
	Cumulative Effect of Change in Accounting Principle	$		661		$		48		Cumulative Effect of Change in Accounting Principle	$		401		$		64	$	1,062		$		112

Cumulative Effect of Change in Accounting Principle	Cumulative Effect of Change in Accounting Principle			5				17		Cumulative Effect of Change in Accounting Principle			--				--		5				17

Net Income Available to Common Stockholders	Net Income Available to Common Stockholders	$		656		$		31		Net Income Available to Common Stockholders	$		401		$		64	$	1,057		$		95

Per Common Share	Per Common Share									Per Common Share
Net income - before change in accounting principle - basic	Net income - before change in accounting principle - basic	$		2.64		$		0.37		Net income - before change in accounting principle - basic	$		1.60		$		0.50	$	4.24		$		0.87
Net income - before change in accounting principle - diluted	Net income - before change in accounting principle - diluted	$		2.52		$		0.37		Net income - before change in accounting principle - diluted	$		1.50		$		0.48	$	4.01		$		0.84

Change in accounting principle - basic	Change in accounting principle - basic	$		(0.02	)	$		(0.13	)	Change in accounting principle - basic	$		--		$		--	$	(0.02	)	$		(0.13	)
Change in accounting principle - diluted	Change in accounting principle - diluted	$		(0.02	)	$		(0.13	)	Change in accounting principle - diluted	$		--		$		--	$	(0.02	)	$		(0.13	)

Net income - basic	Net income - basic	$		2.62		$		0.24		Net income - basic	$		1.60		$		0.50	$	4.22		$		0.74
Net income - diluted	Net income - diluted	$		2.50		$		0.24		Net income - diluted	$		1.50		$		0.48	$	3.99		$		0.72

Dividends	Dividends	$		0.05		$		0.05		Dividends	$		0.05		$		0.05	$	0.10		$		0.10

Average Number of Common Shares Outstanding - Basic	Average Number of Common Shares Outstanding - Basic			250				128		Average Number of Common Shares Outstanding - Basic			251				128		251				128
Average Number of Common Shares Outstanding - Diluted	Average Number of Common Shares Outstanding - Diluted			263				131		Average Number of Common Shares Outstanding - Diluted			268				138		266				135

~~Item 1. Financial Statements(continued)~~ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEET (continued)
(Unaudited)

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

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 terms "Anadarko" and "Company" refer to Anadarko Petroleum Corporation and its subsidiaries. The principal subsidiaries of Anadarko are: RME Petroleum Company; Anadarko Canada Corporation; and, Anadarko Algeria Company LLC. Certain amounts for the prior year have been reclassified to conform to the current presentation.

Change in Accounting Principles 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 adjustment to net income was a decrease of $8 million ($5 million after taxes, or $0.02 per share) and the adjustment to accumulated other comprehensive income was a decrease of $8 million ($5 million after taxes).

During 2000, the Company changed its method of accounting for the carrying value of foreign crude oil inventories from market to cost. This change was made as a result of a change in position on the carrying value of inventories communicated by the Securities and Exchange Commission (SEC). The change was effective January 2000 and the related adjustment to foreign crude oil inventories was a decrease of $19 million ($17 million after taxes, or $0.13 per share). ~~First quarter~~The three and six months ended June 30, 2000 results have been restated to reflect this accounting change.

Derivative Financial Instruments ~~Effective January~~In 2001, 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~~exposu re to changes in fair values, cash flows, or foreign currencies, if certain conditions are met. If the hedged exposure is a fair value exposure, the gains/losses on the derivative financial instrument, as well as the offsetting losses/gains on the hedged item, isare 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 ~~hedge~~the cash flow hedges' effectiveness are recognized currently in other (income) expense. If the hedged exposure is a foreign currency exposure, the accounting is similar to the accounting for fair value and cash flow hedges. Unrealized gains/losses on derivative financial instruments that do not meet the conditions to qualify for hedge accounting are recognized currently in earnings.

Realized gains and losses resulting from the Company's interest rate swap agreements are included in interest expense on a current basis. The swap agreements effectively convert a portion of the Company's fixed interest rate debt to variable interest rate debt. The Company's interest rate swap agreements do not qualify for hedge accounting. Therefore, unrealized gains/losses are recognized currently in earnings and are reflected in other (income) expense. At June 30, 2001, the Company did not have any outstanding interest rate swaps.

New Accounting Principles In July 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated or completed after June 30, 2001. SFAS No. 141 also specifies criteria that intangible assets acquired in a purchase method business combination must meet to be recognized and reported apart from goodwill. The adoption of SFAS No. 141 as of July 1, 2001 had no impact on the Company's financial statements.

SFAS No. 142 requires that goodwill no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142. Any goodwill and any intangible asset determined to have an indefinite useful life that are acquired in a purchase business combination completed after June 30, 2001 will not be amortized, but will be evaluated for impairment in accordance with the appropriate existing accounting literature. Goodwill and intangible assets acquired in business combinations completed before July 1, 2001 will continue to be amortized prior to the adoption of SFAS No. 142.

~~ANADARKO PETROLEUM CORPORATION~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~
~~(Unaudited)~~
Implementation of SFAS No. 142 is required as of January 1, 2002. Because of the extensive effort needed to comply with adopting SFAS No. 142, the impact of adoption on the Company's financial statements has not been determined, including whether any transitional impairment losses will be required to be recognized as the effect of a change in accounting principle. As of January 1, 2002, the Company expects to have unamortized goodwill in the amount of $1.4 billion, which will be subject to the transition provisions of SFAS No. 142. Amortization expense related to goodwill was $36 million and $31 million for the six months ended June 30, 2001 and the year ended December 31, 2000, respectively.

2. Merger and ~~Acquisition~~Acquisitions On July 14, 2000, the Company merged with Union Pacific Resources Group Inc., subsequently renamed RME Holding Company (RME). Each share of common stock of RME issued and outstanding was converted into 0.455 shares of Anadarko common stock. The merger was treated as a tax-free reorganization and accounted for as a purchase business combination under generally accepted accounting principles. Under this method of accounting, the Company's historical operating results for periods prior to the merger are the same as Anadarko's historical operating results. At the date of the merger, the assets and liabilities of Anadarko remain based upon their historical costs, and the assets and liabilities of RME were recorded at their estimated fair market values.

Merger costs of ~~$10~~$14 million were expensed in the ~~first~~second quarter of 2001 related to the RME merger. These relate primarily to transition, integration, hiring and relocation costs ($78 million), retention bonuses ($4 million) and vesting of restricted stock and stock options ($32 million) issued in conjunction with the merger. For the six months ended June 30, 2001, merger costs of $24 million were expensed related to the RME merger. These relate primarily to transition, integration, hiring and relocation costs ($15 million), vesting of restricted stock and stock options ($5 million) and retention bonuses ($4 million).

~~During~~For the ~~first quarter~~six months ended June 30, 2001, ~~121~~157 RME employees actually separated and were paid pursuant to the severance plans and 2328 RME employees were relocated to Houston.

The majority of the remaining accrued liability balance included in capitalized merger costs is expected to be spent in 2001. The following table summarizes the activity in the accrued liability account for the ~~three~~six months ended ~~March 31,~~June 30, 2001:

millions
Capitalized merger costs at December 31, 2000	$	26
Capitalized merger costs as of January 1, 2001				$	26
Cash payments		(12	)		(14	)
Capitalized merger costs at March 31, 2001	$	14

Capitalized merger costs as of June 30, 2001				$	12

The pro forma results for 2000 are a result of combining the three and six months income ~~statement~~statements of Anadarko with the three and six months income ~~statement~~statements of RME adjusted for 1) certain costs that RME had expensed under the successful efforts method of accounting that are capitalized under the full cost method of accounting; 2) depreciation, depletion and amortization expense of RME calculated in accordance with the full cost method of accounting applied to the adjusted basis of the properties acquired using the purchase method of accounting; 3) decreases to interest expense for the capitalization of interest on significant investments in unevaluated properties and major development projects and partly offset by the revaluation of RME debt under the purchase method of accounting, including the elimination of historical debt issuance amortization costs; 4) issuance of Anadarko common stock and stock options pursuant to the merger agreement, and 5) the related income tax effects of ~~these~~thes e adjustments based on the applicable statutory tax rates. It should be noted that the pro forma results do not include any merger expenses.

The following table presents the unaudited pro forma results of the Company ~~for the three months ended March 31, 2000~~ as though the merger had occurred on January 1, 2000. Pro forma results are not necessarily indicative of actual results.

~~ANADARKO PETROLEUM CORPORATION~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~
~~(Unaudited)~~

On March 16, 2001, Anadarko acquired Canadian based Berkley Petroleum ~~Corporation~~Corp. (Berkley) for C$11.40 per share for an aggregate equity value of US$779 million plus the assumption of approximately US$236 million in debt. Merger costs of $3 million were expensed for the three and six months ended June 30, 2001 related to the Berkley acquisition. This acquisition was accounted for under the purchase method of accounting.

On June 25, 2001, Anadarko announced it had entered into an agreement to acquire Canadian based Gulfstream Resources Canada Limited for C$2.65 per share. The total value of this proposed acquisition is approximately US$137 million and is expected to close in the third quarter of 2001.

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

		March 31,			December 31,			June 30,			December 31,
millions		2001			2000			2001			2000
Materials and supplies	$		46	$		44	$		58	$		44
Foreign crude oil			19			20			22			20
Natural gas			11			15			14			15
Total	$		76	$		79	$		94	$		79

4. Properties and Equipment Oil and gas properties include costs of ~~$3.4~~$3.7 billion and $2.9 billion at ~~March 31,~~June 30, 2001 and December 31, 2000, respectively, which were excluded from capitalized costs being amortized. These amounts represent costs associated with unevaluated properties and major development projects.

~~ANADARKO PETROLEUM CORPORATION~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~
~~(Unaudited)~~

At ~~March 31,~~June 30, 2001, ~~$466 million of notes payable to banks, $100~~$98 million of 8 1/4% Notes due 2001 and ~~$100~~$650 million of Zero Yield Puttable Contingent Debt Securities (ZYP-CODES) due 2021 were classified as short-term debt. At December 31, 2000, notes payable to banks were classified as long-term debt in accordance with SFAS No. 6, "Classification of Short-term Obligations Expected to be Refinanced", under the terms of Anadarko's Bank Credit Agreements.

In February 2001, Anadarko, Anadarko Capital Trust I, Anadarko Capital Trust II and Anadarko Capital Trust III filed a shelf registration statement with the SEC that permits the issuance of up to $1 billion in debt securities, preferred stock, depositary shares, common stock, warrants, purchase price adjustments and purchase units. In addition, the Trusts may issue preferred securities. 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 March 2001, Anadarko issued $650 million of ZYP-CODES due 2021 to qualified institutional buyers under Rule ~~144~~144A and non-U.S. persons under Regulation S. The debt securities were priced with a zero coupon, zero yield to maturity and a conversion premium of 38%. The proceeds from the debt securities were used initially to finance costs associated with the acquisition of Berkley. Holders of the ZYP-CODES may require Anadarko to purchase all or a portion of their ZYP-CODES on March 13th of 2002, 2004, 2006, 2011, or 2016, at $1,000 per ZYP-CODES. Anadarko will pay the purchase price in cash, except that with respect to the ZYP-CODES that may be put to Anadarko for purchase on March 13, 2002, Anadarko may choose to pay the purchase price for those ZYP-CODES in cash, common stock or a combination of cash and common stock. Due to the Company's ability and intent to purchase these ZYP-CODES with cash and common stock, $550 million of the ZYP-CODES were classified as long-term debt at March 31, 2001. The remaining $100 million were classified as short-term debt.

In April 2001, Anadarko Finance Company, a wholly owned finance subsidiary of Anadarko, issued $1.3 billion in notes as part of the Company's financial restructuring plan following the Berkley acquisition. This issuance was made up of $400 million of 6 3/4% Notes due 2011 and $900 million of 7 1/2% Notes due 2031. In May 2001, Anadarko Finance Company issued an additional $550 million of 6 3/4% Notes due 2011, bringing the 6 3/4% Notes to an aggregate total of $950 million. The notes are fully and unconditionally guaranteed by Anadarko. The notes were issued as part of an exchange of securities for other Anadarko debt and preferred stock. ~~In addition,~~The intercompany debt resulting from these transactions is of a long-term investment nature; therefore, foreign currency translation gains and losses are recorded as ~~part~~a component of ~~the restructuring plan, the Company made an equity contribution to Anadarko Canada Corporation and reduced outstanding debt by $200 million.~~

6. 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 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. These instruments may include futures, swaps and options.

Anadarko also enters into commodity derivative financial instruments (options, futures and swaps) for trading purposes with the objective of generating profits on or from exposure to shifts or changes in the market price of natural gas and crude oil. Commodity derivative financial instruments also provide methods to meet customer's pricing requirements while achieving a price structure consistent with the Company's overall pricing strategy. In addition, the Company had swap agreements in place to lock in mark-to-market gains of its firm transportation keep-whole commitment with Duke Energy Field Services, Inc.

Cash Flow Hedges At ~~March 31,~~June 30, 2001, 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. Other income for the ~~quarter~~three and six months ended ~~March 31,~~June 30, 2001, included $9$18 million and $27 million, respectively of net unrealized derivative gains. This amount represents the sum of a) the amount of hedge ineffectiveness arising from differences between the New York Mercantile Exchange WTI-based hedging instruments and the crude oil posting-based hedged items and b)gains primarily due to the change in the time value of the option contracts that was excluded from the assessment of hedge effectiveness.

Approximately $2$18 million of net ~~losses~~gains in accumulated other comprehensive income balance as of ~~March 31,~~June 30, 2001 are expected to be reclassified into gas and oil sales during the remainder of 2001.

~~ANADARKO PETROLEUM CORPORATION~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~
~~(Unaudited)~~

As of ~~March 31,~~June 30, 2001, the Company has option contracts to hedge its exposure to the variability in future cash flows associated with sales of equity oil production that extend through December 2001 and associated with sales of gas production that extend through December 2005. Swap agreements to hedge the Company's exposure to the variability in future cash flows associated with sales of equity oil production extend through December 2002.

Fair Value Hedge The Company also had a swap agreement in place to convert a gas contract from a fixed price to a market sensitive price. ~~Other~~Operating income for the ~~quarter~~three and six months ended ~~March 31,~~June 30, 2001 includes ~~$0.3~~$1 million of net losses. This amount represents the ineffective portion of this swap agreement.

Interest Rate Swaps In 1999, Anadarko entered into a 29.5 year swap agreement with a notional value of $200 million whereby the Company received a fixed interest rate and paid a floating interest rate indexed to the 3-month London Interbank Offered Rate (LIBOR). The swap agreement was cancelled onin March ~~15, 2001.~~2001 at no cost to the

Company. During 1996, Anadarko entered into a 10-year swap agreement with a notional value of $100 million whereby the Company received a fixed interest rate and paid a floating interest rate indexed to the 3-month LIBOR. This agreement was terminated onin April ~~19,~~ 2001 at no cost to the Company. These agreements were entered into to offset a portion of the effect of the Company's fixed rate long-term debt. The one remaining interest rate swap at March 31, 2001 does not qualify for hedge accounting, therefore, changes in the fair value, based upon market quotes from a commercial bank, are recorded to other income.

7. Preferred Stock For the first ~~quarter~~and second quarters of 2001 and 2000, dividends of $13.65 per share (equivalent to $1.365 per Depositary Share) were paid to holders of preferred stock. In April 2001, Anadarko repurchased $85 million of preferred stock as part of the exchange of securities under the restructuring plan discussed inNote 5.

8. Common Stock Under the most restrictive provisions of the Company's credit agreements, which limit the payment of dividends, retained earnings were not restricted as to the payment of dividends at ~~March 31,~~June 30, 2001 and December 31, 2000.

The Company's basic earnings per share (EPS) amounts have been computed based on the average number of common shares outstanding. Diluted EPS amounts include the effect of the Company's outstanding stock options under the treasury stock method, ~~and~~ the net effect of the assumed conversion of the convertible debentures and ZYP-CODES.

Three Months Ended

Three Months Ended

March 31, 2001

March 31, 2000

millions except

Per Share

Per Share

per share amounts
Income
Shares
Amount
Income
Shares
Amount
Basic EPS

Income available to common

  stockholders before change in

  accounting principle
$
661

250

$
2.64

$
48

128

$
0.37

Effect of convertible debentures

  and ZYP-CODES
2

10

--

2

Effect of dilutive stock options and

  performance-based stock awards
--

  3

--

  1

Diluted EPS

Income available to common

  stockholders plus assumed conversion
$
663

263

$
2.52

$
48

131

$
0.37

~~ANADARKO PETROLEUM CORPORATION~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~
~~(Unaudited)~~

For the three and six months ended ~~March 31,~~June 30, 2001, ~~and 2000,~~ options for ~~0.1~~0.2 million ~~and 3.2 million~~ shares ~~respectively,~~ of common stock and 2 million put options were excluded from the diluted EPS calculation because ~~the options'~~their exercise price was greater than the average market price of common stock for the period.

In July 2001, the Board of Directors authorized the Company to purchase as much as $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. Through July 2001, Anadarko has written a series of put options for the purchase of a total of 4 million shares of Anadarko common stock with a notional amount of about $200 million. Put options for 1 million shares expired unexercised in July 2001. The remaining put options will expire between September 2001 and January 2002. The outstanding put options permit a net-share settlement at the Company's option and do not result in a put option liability on the consolidated balance sheet. During the second quarter of 2001, premiums of $5 million were received related to these put options and recorded as an increase to paid-in capital. In addition, premiums of $6 million were received in July 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:

10. Segment Information The following table illustrates information related to Anadarko's ~~reportable~~ business segments:

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

~~ANADARKO PETROLEUM CORPORATION~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~
~~(Unaudited)~~

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, which the Company 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, six Superfund sites (five Federal and one State) are included in the Superfund Reserve. Liabilities associated with the Superfund sites continue to evolve due to unexpected lawsuits and agency actions.

~~ANADARKO PETROLEUM CORPORATION~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~
~~(Unaudited)~~

Mineral Reservation Litigation In August 1994, the surface owners (McCormick, et al.) of portions of five sections of Colorado land that are subject to mineral reservations made by the Company's predecessor in title brought suit against the Company in State District Court, Weld County, Colorado, to quiet title to minerals, including oil (in some of the lands) and natural gas. On June 23, 1997, the State District Court granted the Company's Motion for Summary Judgment, holding as a matter of law that the mineral reservations at issue were unambiguous and included all valuable non-surface substances, including oil and gas. The Colorado Court of Appeals affirmed the decision of the State District Court in granting the Company's Motion for Summary Judgment on December 10, 1998 and then denied the surface owners' Motion for Rehearing. The surface owners then filed a Petition for Writ with the Colorado Supreme Court, which was granted in September 1999. The Colorado Supreme Court has affirmed the lower court's decisions in favor of the Company bringing this matter to a successful conclusion.

Royalty Litigation During September of 2000, the Company was named as a defendant in a case styledU.S. of America ex rel. Harold E. Wright v. AGIP Company, et al. (the "Gas Qui Tam case") filed in the U.S. District Court for the Eastern District of Texas, Lufkin Division. This lawsuit generally alleges that the Company and 118 other defendants improperly measured and otherwise undervalued natural gas in connection with a payment of royalties on production from federal and Indian lands. The case has been transferred to the U.S. District Court, Multi-District Litigation Docket pending in Wyoming. Based on the Company's present understanding of the various governmental and False Claims Act proceedings described above, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. However, if the Company is found to have violated the Civil False Claims Act, the Company could be subject to a ~~variety~~varie ty 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 has been asserted. The Company is of the opinion that the amount of damages at risk is substantially less than the amount demanded by the class action counsel and the Company intends to vigorously assert its defenses. The Company is currently appealing the class certification order. A decision on the class certification is expected during the ~~second~~third quarter of 2001.

~~A group of royalty owners in the State of Oklahoma surrounding the Beaver County Gathering System allege five separate claims against the defendants including RME. This matter styled~~~~Galen Bridenstine v. Kaiser Francis Oil Company, et al.~~ (including RME) has been certified as a class action. The plaintiffs contend that gathering, compression and dehydration fees deducted by the defendants from royalty payments were in violation of the Oklahoma Check Stub Statute and were improper. This matter has now been settled.

~~ANADARKO PETROLEUM CORPORATION~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~
~~(Unaudited)~~

A class action lawsuit entitledGilbert 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. This matter is now set for trial on October 29, 2001.

Wyoming Tax Litigation RME has filed suit in the First District Court, Laramie, Wyoming, against the State of Wyoming, et al. alleging that the revaluation by the Department of Revenue of crude oil production sales for the years 1989 through 1995 is inappropriate. The Department of Revenue has valued the crude oil sales based upon the Cushing, Oklahoma price as opposed to the actual sales price collected from RME. The Department seeks to void the initial sales transaction as an unlawful affiliate sale that does not reflect true market price. RME seeks a declaratory judgment in court that the sale made to RME is a true sale reflective of market value at the wellhead and thus the initial amounts paid to the Department of Revenue were correct. The amount in controversy in this matter is approximately $8 million. The Company is currently unable to predict the final outcome of this matter.

CITGO Litigation CITGO Petroleum Corporation's 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 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 ("the 1995 Settlement Agreement") to allocate, on an interim basis, each parties' 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~~th is liability in order to work out a joint defense agreement in the major lawsuits. Arbitration will resume upon request of either CITGO or RME. In conjunction with this matter, RME is suing Continental Insurance for denial of coverage for claims related to this dispute. Negotiations and discussions with CITGO and legal actions against Continental Insurance continue.

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 ~~$36~~$37 million (before taxes) as of ~~March 31,~~June 30, 2001. 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

~~ANADARKO PETROLEUM CORPORATION~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~
~~(Unaudited)~~

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~~sho uld be responsible for refunds attributable to the time period before August 1, 1985.

The Company has reached a settlement agreement with PanEnergy that requires the Company to pay ~~$14~~$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 agreement is contingent upon FERC approval. The settlement agreement ~~is to be~~was filed with the FERC ~~by May 15,~~on June 22, 2001. The FERC is expected to approve the settlement agreement within 60 days of the date that the settlement agreement is filed with the FERC. 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 the ~~first quarter of~~six months ended June 30, 2001, included a ~~$14~~$15 million charge (before income taxes) related to the settlement agreement.

Anadarko's net income for 1997 included a $2 million charge (before income taxes) related to the Kansas ad valorem tax refunds. This charge reflects all principal and interest which may be due at the conclusion of all regulatory proceedings and litigation to parties other than PanEnergy. The Company is currently unable to predict the final outcome of this matter and no provision for liability (excluding amounts recorded in 1993, 1994, 1997 and 2001) has been made in the accompanying financial statements.

13. The information, as furnished herein, reflects all normal recurring adjustments that are, in the opinion of management, necessary to a fair statement of financial position as of ~~March 31,~~June 30, 2001 and December 31, 2000, ~~and for~~ the results of operations for the three and six months ended June 30, 2001 and 2000 and cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2001 and 2000.

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

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company's operations, economic performance and financial condition. These forward looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, and those statements preceded by, followed by or that otherwise include the words "believes", "expects", "anticipates", "intends", "estimates", "projects", "target", "goal", "plans", "objective", "should" or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward looking statements contained in the Private Securities Litigation Reform Act of 1995. ~~Such~~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 Additional Factors Affecting Business in the Management's Discussion and Analysis of Financial Condition and Results of Operations included in the Company's 2000 Annual Report on Form 10-K.

Net Income Anadarko's net income available to common stockholders in the ~~first~~second quarter of 2001 totaled ~~$656~~$401 million, or ~~$2.50~~$1.50 per share (diluted) compared to net income of ~~$31~~$64 million, or 2448 cents per share (diluted) for the ~~first~~second quarter of 2000. ~~First quarter~~For the six-month period ended June 30, 2001, Anadarko's net income available to common stockholders ~~before the cumulative effect of change in accounting principle~~ was ~~$661~~$1,057 million, or ~~$2.52~~$3.99 per share (diluted). ~~For~~By comparison, for the ~~first quarter of~~six months ended June 30, 2000, Anadarko's net income available to common stockholders ~~before the cumulative effect of change in accounting principle~~ was ~~$48~~$95 million, or 3772 cents per share (diluted). Anadarko's results for 2001 include the effect of the merger with Union Pacific Resources Group Inc., subsequently renamed RME Holding Company (RME), which closed in July 2000, and the acquisition of Berkley Petroleum ~~Corporation~~Corp. (Berkley), which closed ~~mid-March~~in March 2001.

~~Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)~~

Revenues Revenues for the ~~first~~second quarter of 2001 ~~were up 362%~~increased 203% to ~~$3,051~~$2,264 million compared to revenues of ~~$661~~$748 million for the same period of 2000. For the six months ended June 30, 2001, revenues were $5,315 million, an increase of 277%, compared to $1,409 million for the same period of 2000. The increase in revenues for both periods is primarily due to significantly higher ~~production~~sales volumes and natural gas prices.

Costs and Expenses Costs and expenses during the ~~first~~second quarter of 2001 increased ~~280%~~166% compared to the ~~first~~second quarter of 2000. The increase in 2001 is primarily due to:

1)	Marketing ~~gas and oil~~ purchases and transportation increased ~~288%.~~115% primarily due to the increase in sales volumes.
2)	Operating expenses, depreciation, depletion and amortization expense and other taxes increased ~~289%~~329% primarily due to the increase in ~~production~~sales volumes associated with the RME merger.
3)	Administrative and general expenses increased ~~63%~~113% primarily due to the Company's expanded workforce resulting ~~primarily~~ from the RME merger.
4)	Impairments related to international properties ~~increased $7 million.~~in the North Atlantic were $8 million in 2001.
5)	Amortization of goodwill was $19 million related to the RME merger and the Berkley acquisition.

For the six-month period ended June 30, 2001 costs and expenses increased 220% compared to the same period of 2000. The increase in 2001 is primarily due to:

1)	Marketing purchases and transportation increased ~~$17~~194% primarily due to the increase in sales volumes.
2)	Operating expenses, depreciation, depletion and amortization expense and other taxes increased 309% primarily due to the increase in sales volumes associated with the RME merger.
3)	Administrative and general expenses increased 88% primarily due to the Company's expanded workforce resulting from the RME merger.
4)	Impairments related to international properties in the North Atlantic and Ghana were $15 million in 2001.
5)	Amortization of goodwill was $36 million related to the RME merger and the Berkley acquisition.

Merger Expenses ~~During~~For the ~~first quarter of~~three and six months ended June 30, 2001, merger costs of ~~$10~~$14 million and $24 million, respectively, were expensed related to the RME merger. ~~These~~For the quarter ended June 30, 2001, these costs relate primarily to transition, integration, hiring and relocation costs ($78 million), retention bonuses ($4 million) and vesting of restricted stock and stock options ($32 million).

~~Item 2. Management's Discussion~~ For the six months ended June 30, 2001, these costs relate primarily to transition, integration, hiring and ~~Analysis~~relocation costs ($15 million), vesting of ~~Financial Condition~~restricted stock and ~~Results~~stock options ($5 million) and retention bonuses ($4 million). For the three and six months ended June 30, 2001, merger costs of ~~Operations (continued)~~

Interest Expense For the ~~first~~second quarter of 2001, Anadarko's interest expense increased 5%25% to ~~$22~~$25 million compared to ~~$21~~$20 million for the second quarter of 2000. For the first ~~quarter~~six months of 2001, interest expense was $47 million, an increase of 15% compared to $41 million for the same period of 2000. The increase in interest expense in 2001 is primarily due to higher levels of long-term debt in 2001 compared to 2000 as a result of the RME merger and the Berkley acquisition, partially offset by higher capitalized interest in 2001.

Other ~~(Income) Expense~~Income Other ~~(income) expense~~income for the ~~first~~second quarter 2001 increased ~~$96~~$4 million compared to the same period of 2000 due primarily to ~~$140~~$35 million of foreign currency exchange gains and $18 million of income related to corporate hedges, partially offset by $42 million in other expense related to the effect of lower value for firm transportation subject to a keep-whole agreement and $7 million in other expenses.

For the six months ended June 30, 2001, other income increased $100 million compared to the same period of 2000 due primarily to $98 million in other income related to the effect of significantly higher value for firm transportation subject to a keep-whole agreement and $9$27 million of income related to corporate hedges, partially offset by ~~$52~~$17 million of foreign currency exchange ~~losses.~~losses and $8 million in other expenses.

Income Taxes For the second quarter of 2001, income taxes increased 294% to $197 million compared to $50 million for the second quarter of 2000. For the first six months of 2001, income taxes were $586 million, an increase of 498% compared to $98 million for the same period of 2000. The increases are due to the significant increase in earnings, partially offset by a decrease in income taxes of $31 million during the second quarter of 2001 related to a deferred tax adjustment resulting from the 2% decrease in Canada's tax rate.

During the ~~first~~second quarter of 2001, Anadarko sold 4752 million barrels of oil equivalent (BOE), up ~~236%~~271% from 14 million BOE in the second quarter of 2000. During the first ~~quarter~~six months of 2001, Anadarko sold 99 million BOE, up 267% from 27 million BOE for the same period of 2000. The increased volumes are a result of the merger with RME and from the Company's operations in the Gulf of Mexico, Alaska and Texas.

~~Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)~~

The following table shows the Company's sales volumes and average wellhead prices for the three and six months ended ~~March 31,~~June 30, 2001 and 2000:

		Three Months Ended								Three Months Ended								Six Months Ended
		March 31								June 30								June 30
		2001				2000				2001				2000				2001				2000
Natural gas
United States (Bcf)			139				44				151				49				290				93
MMcf/d			1,548				486				1,651				536				1,600				511
Price per Mcf	$		6.86		$		2.46		$		4.43		$		3.20		$		5.60		$		2.84
Canada * (Bcf)			24				--				33				--				57				--
MMcf/d			269				--				362				--				316				--
Price per Mcf	$		6.50				--		$		4.82				--		$		5.53				--
Other International * (Bcf)			1				--				--				--				1				--
MMcf/d			5				--				5				--				5				--
Price per Mcf	$		1.03				--		$		1.24				--		$		1.13				--
Total (Bcf)			164				44				184				49				348				93
MMcf/d			1,822				486				2,018				536				1,921				511
Price per Mcf	$		6.79		$		2.46		$		4.49		$		3.20		$		5.58		$		2.84

Crude oil and condensate
United States (MMBbls)			8				2				9				1				16				4
MBbls/d			89				20				96				21				92				21
Price per barrel	$		25.44		$		24.83		$		24.61		$		26.29		$		25.00		$		25.57
Canada * (MMBbls)			3				--				3				--				6				--
MBbls/d			31				--				36				--				34				--
Price per barrel	$		16.56				--		$		18.84				--		$		17.79				--
Algeria (MMBbls)			2				2				2				2				4				4
MBbls/d			25				29				17				17				21				23
Price per barrel	$		25.12		$		27.30		$		25.58		$		27.23		$		25.30		$		27.27
*Other International (MMBbls)**			4				--				4				--				8				--
MBbls/d			41				--				43				--				42				--
Price per barrel	$		14.87				--		$		14.68				--		$		14.77				--
Total (MMBbls)			17				4				18				3				34				8
MBbls/d			186				49				192				38				189				44
Price per barrel	$		21.59		$		26.28		$		21.38		$		26.71		$		21.48		$		26.47

Natural gas liquids
Total (MMBbls)			3				2				4				2				7				4
MBbls/d			36				22				42				21				39				22
Price per barrel	$		22.54		$		20.73		$		18.81		$		20.10		$		20.52		$		20.43

Barrels of oil equivalent (MMBOE)
United States				34				12				37				12				71				23
Canada *				7				--				9				--				16				--
Algeria				2				2				2				2				4				4
Other International *				4				--				4				--				8				--
Total				47				14				52				14				99				27

Bcf - billion cubic feet
MMBbls - million barrels
MBbls/d - thousand barrels per day
Mcf - thousand cubic feet
MMcf/d - million cubic feet per day
MMBOE - million barrels of oil equivalent

*In July 2000, Anadarko acquired production in Canada and other international areas as a result of the merger with RME.

~~Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)~~

Natural Gas Natural gas sales volumes in the ~~first~~second quarter of 2001 ~~averaged 1,822~~were 2,018 MMcf/d, an increase of ~~275%~~276% over the ~~486~~536 MMcf/d in the same period last year. Natural gas prices at the wellhead averaged ~~$6.79~~$4.49 per ~~thousand cubic feet (Mcf)~~Mcf during the ~~first~~second quarter of 2001 compared to ~~an average of $2.46~~$3.20 per Mcf in the ~~first~~second quarter of 2000.

In the first six months of 2001, Anadarko's natural gas production was 1,921 MMcf/d, up 276% from 511 MMcf/d in the same period of 2000. The wellhead price for natural gas in the first half of 2001 averaged $5.58 per Mcf, compared to $2.84 per Mcf in the same period last year.

Crude Oil, Condensate and Natural Gas Liquids Total sales volumes of crude oil and condensate in the ~~first~~second quarter 2001 ~~averaged 186~~were 192 MBbls/d, up ~~280%~~405% from 4938 MBbls/d in the ~~first~~second quarter of 2000. Oil prices in the ~~first~~second quarter of 2001 averaged ~~$21.59~~$21.38 per barrel compared to ~~$26.28~~$26.71 per barrel in the second quarter last year.

Anadarko's production of crude oil and condensate for the half of 2001 averaged 189 MBbls/d, up 330% from 44 MBbls/d in the comparable 2000 period. Anadarko's average oil price for the first ~~quarter~~six months of 2001 was $21.48 per barrel compared with $26.47 per barrel in the same period last year. The decrease in oil prices is due primarily to the Company's significant increase in international heavy oil sales volumes that sell for less at the wellhead.

Sales volumes of natural gas liquids (NGLs) during the second quarter of 2001 ~~averaged 36~~were 42 MBbls/d, up ~~64%~~100% from 2221 MBbls/d in the ~~first~~second quarter of 2000. Prices during the ~~first~~second quarter of 2001 for Anadarko's NGLs averaged ~~$22.54~~$18.81 per barrel compared to ~~$20.73~~$20.10 per barrel in the ~~first~~second quarter last year.

Anadarko's NGLs volumes during the first six months of 2001 were 39 MBbls/d, an increase of 77% over the 22 MBbls/d in the same period of 2000. The average price per barrel for NGLs for the first half of 2001 was $20.52 per barrel compared with $20.43 per barrel a year earlier.

During the first ~~three~~six months of 2001, Anadarko's capital spending (including capitalized interest and overhead) was ~~$658~~$1,514 million compared to ~~$184~~$451 million infor the ~~first quarter~~same period of 2000.

In February 2001, Anadarko, Anadarko Capital Trust I, Anadarko Capital Trust II and Anadarko Capital Trust III 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, depositary shares, common stock, warrants, purchase price adjustments and purchase units. In addition, the Trusts may issue preferred securities. 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 March 2001, Anadarko issued $650 million of Zero Yield Puttable Contingent Debt Securities (ZYP-CODES) due 2021 to qualified institutional buyers under Rule ~~144~~144A and non-U.S. persons under Regulation S. The debt securities were priced with a zero coupon, zero yield to maturity and a conversion premium of 38%. The proceeds from the debt securities were used initially to finance costs associated with the acquisition of Berkley. Holders of the ZYP-CODES may require Anadarko to purchase all or a portion of their ZYP-CODES on March 13th of 2002, 2004, 2006, 2011, or 2016, at $1,000 per ZYP-CODES. Anadarko will pay the purchase price in cash, except that with respect to the ZYP-CODES that may be put to Anadarko for purchase on March 13, 2002, Anadarko may choose to pay the purchase price for those ZYP-CODES in cash, common stock or a combination of cash and common stock. Due to the Company's ability and intent to purchase these ZYP-CODES with cash and common stock, $550 million of the ZYP-CODES were classified as long-term debt at March 31, 2001. The remaining $100 million were classified as short-term debt.

In April 2001, Anadarko Finance Company, a wholly owned finance subsidiary of Anadarko, issued $1.3 billion in notes as part of the Company's financial restructuring plan following the Berkley acquisition. This issuance was made up of $400 million of 6 3/4% Notes due 2011 and $900 million of 7 1/2% Notes due 2031. In May 2001, Anadarko Finance Company issued an additional $550 million of 6 3/4% Notes due 2011, bringing the 6 3/4% Notes to an aggregate total of $950 million. The notes are fully and unconditionally guaranteed by Anadarko. The notes were issued as part of an exchange of securities for other Anadarko debt and preferred stock. ~~In addition, as part of the restructuring plan, the Company made an equity contribution to Anadarko Canada Corporation and reduced outstanding debt by $200 million.~~

In April 2001, Anadarko repurchased $85 million of preferred stock as part of the exchange of securities discussed above.

The Company believes that cash flows and existing or available credit facilities will provide the majority of funds to meet its capital and operating requirements for 2001. The Company will continue to evaluate funding alternatives, including property sales and additional borrowings, to secure other funds for capital development. At this time, Anadarko has no plans to issue common stock other than through its Dividend Reinvestment and Stock Purchase Plan.

~~Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)~~

During the ~~first~~second quarter of 2001, Anadarko participated in a total of ~~243~~328 wells, including ~~176~~222 gas wells, 5793 oil wells and 1013 dry holes. This compares to a total of ~~119~~97 wells, including 7356 gas wells, 4237 oil wells and 4 dry holes during the ~~first~~second quarter of 2000.

For the first six months of 2001, Anadarko participated in a total of 571 wells, including 398 gas wells, 150 oil wells and 23 dry holes. This compares to a total of 216 wells, including 129 gas wells, 79 oil wells and 8 dry holes during the first six months of 2000.

Development Average gas production from Anadarko's ~~largest onshore gas field~~Bossier play, located in Texas and Louisiana, during the ~~first~~second quarter was ~~322 MMcf/d of gas (gross) and 236~~269 MMcf/d of gas (net). The Company currently has 30 rigs in operation throughout the Bossier play (26 in East Texas and 4 in Northwest Louisiana). Anadarko continued to strengthen its leasehold position by adding more than 44,000 gross acres during, up 12% from the first quarter ~~2001, bringing~~of 2001. In the Texas portion of the play, a total ~~acreage~~of 40 wells were completed in the ~~play to more than 295,000 acres (gross).~~

second quarter giving the Company 369 gas wells, primarily located in Freestone County, Texas.

Some of the more significant development well completions during the ~~first~~second quarter of 2001, including Anadarko's working interest (WI), include:

·- Thigpen ~~A-4(16.0~~A-14(21.6 MMcf/d of gas), Dew field, 100% WI

·- Stephens A-10(20.8 MMcf/d of gas), Dew field, 99% WI

- Stephens A-8(20.7 MMcf/d of gas), Dew field, 99% WI

- Adams A-7(13.5 MMcf/d of gas), Dew field, 75% WI

- Moody A-2(10.2 MMcf/d of gas), Dew field, 100% WI

- Burgher ~~C-8(15.5~~G-8(13.7 MMcf/d of gas), Dowdy Ranch field, 100% WI

· ~~Thigpen A-5(15.5 MMcf/d of gas), Dew field~~

· ~~Blair A-7(20.6 MMcf/d of gas), Dew field~~

· ~~Thigpen A-9(11.8 MMcf/d of gas), Dew field~~

·- Burgher ~~D-11(12.7~~G-6(10.4 MMcf/d of gas), Dowdy Ranch field, 100% WI

·- Burgher ~~D-12(13.8~~A-6 (8.4 MMcf/d of gas), Dowdy Ranch field, 100% WI

· ~~Thigpen A-13(9.9~~- Evans A-6(8.9 MMcf/d of gas), ~~Dew~~Dowdy Ranch field, 100% WI

- Evans A-7(8.8 MMcf/d of gas), Dowdy Ranch field, 100% WI

- Reagan C-2(5.4 MMcf/d of gas), Reagan Ranch field, 100% WI

- Eubanks Trust No. 8(5.4 MMcf/d of gas), Mimms field, 100% WI

During the second quarter, Anadarko ~~owns a~~maintained its 100% ~~working interest in each of these~~success rate for field development and extension wells ~~except the Blair A-7 in which it owns an 80% working interest.~~

~~Anadarko also holds acreage~~ in the Vernon field ofin Jackson Parish, Louisiana, where the Company is developing other intervals in addition to the Bossier formation. During the first quarter, the Company reported results from 3 wells completed in the Lower Cotton Valley formation.Louisiana. The ~~Davis Brothers E-3 Alt.~~Jones 10-1 well (98% WI) tested ~~4.5~~12.5 MMcf/d of gas, the ~~Simonton 16 No. 1~~Robert Cone 12-1 well (100% WI) produced ~~4.8~~6 MMcf/d of gas and the ~~Fisher 15-1~~Davis Bros K-2 well (98% WI) tested ~~8.5~~6.5 MMcf/d of gas. The Vernon field is producing about 45 MMcf/d of gas from a total of 31 wells.

~~Besides an extensive~~Exploration In addition to field development ~~effort in the Bossier play,~~and infill drilling, Anadarko also maintains an active ~~exploratory drilling~~exploration program to discover new Bossier fields. In 2001, the Company has drilled 6 exploration wells in East Texas, 5 of which ~~included the first quarter completion of the Hodges~~are discoveries or field extensions and another 5 wells are currently drilling.

The Anderson Trust A-1 well ~~in Leon County, Texas.~~(100% WI), located north of Dowdy Ranch, has opened up additional exploitation potential. The ~~wildcat~~ well ~~which tested 5.2~~flowed at an unstimulated rate of 6.7 MMcf/d of gas from the Bossier sands. The Louetta Parker A-1 well (100% WI) was drilled 4 miles to the east of Dowdy Ranch field, deeper in the basin. The well encountered substantial net pay in the Moore interval and is ~~on trend with~~currently testing.

Ten wells have now been drilled in the ~~Company's~~ Bald Prairie area confirming the exploration and ~~Bear Grass fields, where Anadarko has completed 29 producing wells. The Company owns a 96% working interest in~~development potential for the ~~Hodges A-1 well and is planning additional drilling to offset the discovery.~~

Asmost southern part of ~~an ongoing program to add value to its~~the Bossier ~~reserves, Anadarko made some significant improvements to its gas gathering facilities in the~~ play. During the ~~first~~second quarter, the Company completed a project to tie the Dew, Buffalo and Dowdy Ranch central gathering facilities together. The project allows the Company to more efficiently direct compression to where it is needed most. Altogether, Anadarko's gas gathering equipment can handle about 450Mischer D-1 well (100% WI) tested at 3.3 MMcf/d of ~~gas. Also during~~gas from a step-out location 2.5 miles northeast of the ~~first quarter,~~field discovery well. The Mischer A-1 well (100% WI) extended the ~~Company began construction of a fourth central gathering~~Bald Prairie field 1.5 miles to the southeast and ~~compression facility~~is waiting on completion. Three delineation wells are being completed and 4 rigs are drilling in the Bald Prairie field. ~~Start-up of that facility is set for June 2001.~~

Hugoton Embayment During the first quarter, Anadarko launched a program utilizing 3-D seismic data to identify deeper drilling prospects in the Youngren East field of Stevens County, Kansas. Initial successes from the project include the Cavner A-6 well, which tested 1.2 MMcf/d of gas after being completed in the Lower Morrow formation at a depth of 5,800 feet. The Cavner A-7 well, which was completed in the St. Louis formation, tested 473 thousand cubic feet per day (Mcf/d) of gas and 482 barrels of oil per day (BOPD). The Company owns a 100% working interest in each well.

~~Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)~~

Also in Stevens County, Anadarko completed the HJV Cornell University A-1 well, located in the South Cimarron River field. The well tested 1.7 MMcf/d of gas and is part of Anadarko's continuing Hugoton joint venture project.

Anadarko completed its second Toronto formation well in the Forgan NW field during the first quarter. The Adams O-1 well tested 311 Mcf/d of gas and 155 BOPD. The Company has a 100% working interest in the well, which is located in Beaver County, Oklahoma.

Central Texas ~~In the Giddings field, Anadarko's ongoing program of horizontal re-entry~~Anadarko continues its drilling success across multiple pay zones in existing wells continues to post strong results. The latest success is the Fife Unit No. 2 well in Washington County, Texas, in which Anadarko owns a 100% working interest. The well, which initially flowed 51 MMcf/d of gas with flowing tubing pressure of 1,510 psi, confirms the nearby Becker No. 1 well that reached peak production of more than 50 MMcf/d of gas.

The Fife Unit No. 2 and Becker No. 1 wells are located in the Georgetown formation. Re-entry successes for the Buda formation include the Cannon-Chance well, which was completed in March and is producing 250 BOPD and 4.5 MMcf/d, and the recently completed Patterson-Clark well, which is producing 300 BOPD and 5.4 MMcf/d.

Central Texas. Overall, Anadarko holds 750,000 net acres and operates more than 1,200 wells in the Giddings ~~area.~~field. This gives the Company ~~significant~~ potential to exploit opportunities through horizontal ~~re-entries.~~drilling. Currently, Anadarko has 1011 rigs operating throughout its Central Texas play. ~~Of the 77 development wells planned for 2001, two-thirds will be re-entries of existing wells.~~ Anadarko's net volumes in Central Texas ~~have increased to~~are over 220 MMcf/d of gas and ~~14,700~~13,900 barrels of oil per day (BOPD) in the second quarter.

Georgetown Play Anadarko completed 2 more horizontal wells in the second quarter in the Georgetown play in Washington County, Texas. The Graham #1 well (100% WI) initially flowed 50 MMcf/d of gas and is just west of the Becker #1 well, which has cumulative production of about 8 Bcf since it went on production in August 2000. The Barney #2 well (100% WI) was completed during the second quarter and had peak production of 52 MMcf/d of gas. Current production from the Company's 4 Georgetown wells is about 75 MMcf/d of gas.

Buda and Austin Chalk Play During the second quarter, 22 wells were completed as part of the Company's redevelopment program of the Buda and Austin Chalk formations. From the Buda formation, the Polar Bear Unit #1 well (99% WI) tested at 750 BOPD and 0.4 MMcf/d of gas, the Cannon-Chance #1RE well (100% WI) tested 4.6 MMcf/d of gas and 250 BOPD and the Reveille #5RE well (50% WI) tested 7.0 MMcf/d of gas and 300 BOPD. From the Austin Chalk formation, the Sarah Beth #1RE well (50% WI) tested 3.3 MMcf/d of gas and 250 BOPD.

Glen Rose Play The Wash-McAdams 3 HR well (63% WI), located in the Mossey Grove field in Walker County, Texas, tested at over 6 MMcf/d of gas from the Glen Rose formations.

~~Carthage~~ Texas/Louisiana Development of the Kent Bayou field in Terrebonne Parish, Louisiana, continued in the second quarter. The Continental Land and Fur (CLF) #5 well encountered 24 net feet of downthrown pay which tested at 2 MMcf/d of gas and 2,500 barrels of condensate per day (BCPD). The CLF #6 well, a development well in the main fault block, was spud in June. With the facility upgrade finished in June, and 4 wells completed and on-line, the field reached a production rate of 73 MMcf/d of gas and 14,700 BCPD. Anadarko owns a 67% WI in the Kent Bayou field.

A total of 1611 wells were completed in the Carthage area during the ~~first~~second quarter as Anadarko's ongoing ~~four-rig~~4-rig infill drilling program ~~continues.~~continued. The wells ~~which~~ targeted the tight gas sand formations of the Cotton Valley ~~interval, added production of almost 20 MMcf/d (gross).~~interval. In addition, 7 workover rigs are being used to complete the newly drilled wells and perform additional workovers on older wells. Net ~~volumes from the more than 900 Anadarko-operated and non-operated wells currently producing in the area total about 115~~production volume averaged 125 MMcf/d of gas ~~up from 103 MMcf/d~~and 3,000 BCPD in the ~~fourth quarter of 2000. Net oil and natural gas liquids production during that same time period increased from 5,000 BOPD to 6,300 BOPD.~~

Permian Basin Anadarko's waterflood program initiated last year in the Snyder field of Howard County, Texas, continued at a brisk pace in the first quarter of 2001. Some of the more notable completions include 4 B.S. Snyder "A" wells. The No. 100, No. 116, No. 2884 and No. 2899 wells tested at a combined initial rate of 695 BOPD. The Company has a 100% working interest in each of these wells.

Noteworthy projects from Eddy County, New Mexico during the first quarter included an acid stimulation of the Baish Federal No. 5 well, which increased production from 180 BOPD to 450 BOPD. Anadarko has a 100% working interest in the North Shugart field producer. In addition, the Baish Federal No. 12 well tested 1 MMcf/d of gas after being completed in the Morrow formation. The Company owns an 88% working interest in the North Shugart/Bone Spring field well.

~~At the Company's TXL North Unit in Ector County, Texas, 5 wells were completed during the first~~second quarter. The No. 875, No. 877 and No. 878 wells tested at a combined rate of 365 BOPD from the Clearfork and Tubb intervals. Combined production from the No. 872 and No. 873 wells was 140 BOPD from the Tubb formation. Anadarko owns an 80% working interest in each of these wells.

Rocky Mountains ~~During the first quarter,~~This year, Anadarko ~~unveiled its plans to more than double~~has doubled exploration and development ~~spending~~drilling activity in the Rocky Mountain area. The capital spending budget for the area ~~to over~~is about $130 million, ~~in 2001. The increased budget will~~which should allow the Company ~~to take full advantage of its strong acreage position and unlock the potential of this underexplored area. Anadarko plans~~ to drill more than 20 new exploratory and 130 development wells throughout Wyoming, Colorado and Utah in 2001. In addition, the Company ~~will~~expects to gather several hundred square miles of new 3-D seismic ~~data.~~data and add to its existing land base.

~~Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)~~

~~Utah~~ Coalbed Methane ~~Gas production from coalbed~~Coalbed methane (CBM) is becoming an increasingly important core play for Anadarko, which is reflected by the Company's strong acreage position in key areas of Utah and Wyoming. ~~First quarter highlights included first~~Anadarko currently has 3 operated CBM projects in various stages of development and has interests in 7 other CBM projects.

The Drunkards Wash project, located in Utah, has current gross production of 14 MMcf/d of gas ~~sales~~ from the ~~completion of~~ 35 new producing wells and 2 saltwater disposal wells in the Drunkard's Wash field of Carbon and Emery counties in Utah, which were drilled in late 2000. Production from this new field is over 10 MMcf/d of gas. Production growth continues in the nearby Helper field where 20CBM wells drilled in late 2000 ~~are now on-line~~and production is expected to double over the next several years. The de-watering continues at the Helper field and total field production ~~is 28~~now exceeds 32 MMcf/d.d of gas (gross). Production from this area is anticipated to increase substantially by 2002 as the wells mature and ~~another 37~~more wells are drilled this year. Construction is already underway on a new central production facility, which will add capacity of 20 MMcf/d of gas. The Company has a 100% WI in both of these fields.

~~Wyoming Coalbed Methane~~ Anadarko is also involved in multiple ~~coalbed methane~~CBM projects throughout Wyoming, including the Powder River ~~basin. In the Powder River basin, the most active coalbed methane play~~Basin. The County Line project (50% WI), located in Johnson County, Wyoming, is in the ~~United States,~~initial stage of development with 85 producing wells drilled to date. Initial production began in August 2001 from the ~~Company has had 2 to 4 active rigs in operation drilling 70 gross (35 net)~~first 16 wells. Completion and facilities work will ~~be completed in the second quarter with gas sales targeted for the third quarter 2001.~~

Wyoming ~~With 60 net wells planned for development, the~~The Greater Wamsutter area represents ~~the~~a focal point of Anadarko's natural gas program in Wyoming. ~~Activity in~~During the ~~first~~second quarter, ~~included~~ the ~~completion~~Red Desert 17-1 well (100% WI), a step-out southwest of ~~the Chambers Federal No. 3-24 well located in Carbon County, Wyoming.~~Wamsutter field was drilled. The well tested ~~1.4~~at 2.4 MMcf/d of gas and 28 ~~barrels of condensate per day (BCPD)~~BCPD from the Almond ~~formation.~~and Lewis formations. The ~~Company owns a 54% working interest~~17-1 well was followed by 4 additional wells in the ~~well. In Sweetwater County, Wyoming, Anadarko recompleted the Shelby 1-27~~second quarter. The UPRC #5-27 well (45% WI), located in the ~~Lewis formation. Production, which was added to~~Siberia Ridge field, tested from the ~~previously drilled~~ Almond ~~interval, increased from 185 Mcf/d of gas to 1.2~~formation at 2.4 MMcf/d of gas and ~~25 BCPD.~~42 BOPD. Anadarko ~~owns~~is also participating with a ~~100% working interest in the well. Another Sweetwater County recompletion involving the Akron No. 2-33 well was carried out during the first quarter. The well tested 1.1 MMcf/d of gas~~typical 25% WI and ~~10 BCPD from the Lewis formation. The Company has a 100% working interest in the well. Additionally, Anadarko has an average 25% working~~33% net revenue interest in a program to drill 150 ~~to 200 (gross) non-operated~~outside operated wells ~~for~~in 2001.

OnIn the ~~exploration side,~~Brady field, the Company ~~plans to spend more than $11 million for conventional natural gas drilling and the acquisition of new leases that will focus on 3 core plays in Utah and Wyoming~~drilled two successful wells. The Brady #46F well (50% WI) was completed in the ~~sands of the Greater Green River basin, the deep Paleozoic reservoirs and the prolific Overthrust/Subthrust plays.~~

~~Central Oklahoma In Garvin County, Oklahoma, the Carson "B" No. 1 well was completed during the first quarter~~Frontier formation and tested ~~170 BOPD and 140 Mcf/~~at 6.1 MMcf/d of gas. ~~Anadarko owns a 100% working interest~~An average well in the field produces only about 1 MMcf/d of gas. The Jacknife #11 well ~~which is located in the Rush Creek field. This is one of the 50 wells planned for the area in 2001.~~

Gulf Coast Delineation of the Kent Bayou field in Terrebonne Parish, Louisiana, continued in the first quarter with the spudding of the Continental Land and Fur No. 5 well. Three of the 4 wells completed so far are on-line and producing about 45(56% WI) tested at 1.1 MMcf/d of gas ~~and 10,000 BOPD. Production~~ from the ~~No. 3~~Blair formation.

Hugoton Embayment Anadarko continues to be active in one of its oldest operations areas. Two significant wells were completed in Southwest Kansas during the second quarter. In Morton County, the McClure D-5 well ~~has been suspended while upgrades are made to existing processing facilities. Work began in the first quarter to construct a second oil sales line which will help increase capacity to about 80~~(98% WI) tested at 486 BOPD and 0.7 MMcf/d of gas ~~and 15,000 BOPD. Completion is expected~~after being completed in the ~~second quarter of 2001. Anadarko owns a 66.7% working interest~~Morrow St. Louis formation in the ~~Kent Bayou~~Cimarron Bend East field.

In The HJV Mangels A-1 well (100% WI), in the ~~Brookeland~~Cimarron Gap field, ~~of Jasper County, Texas, Anadarko completed the N. Hilton-350 No. 1 well, which~~ tested 94.7 MMcf/d of gas ~~and 328 BOPD. Anadarko owns a 100% working interest in~~from the ~~well which~~Morrow formation and is part of Anadarko's continuing ~~Austin Chalk program.~~Hugoton project.

InCentral Oklahoma During the ~~first~~second quarter, ~~2001, Anadarko began its natural gas exploration joint venture on more than 3 million acres~~10 wells were completed in the ~~Brooks Range Foothills region~~Golden Trend play. The play is located in Grady, Garvin, and McClain Counties of ~~Alaska's North Slope.~~Oklahoma and is targeting several different formations including the deeper Sycamore, Woodford, Hunton, Viola and Bromide.

California At the East Lost Hills field (24% WI), the ELH #3R well encountered no hydrocarbons from the targeted Temblor interval and the well was temporarily abandoned pending further analysis. The ~~joint venture program will include several seismic surveys this year.~~

Anadarko is also participating in a multi-well program delineating satellite discoveries in the Colville River Unit and a multi-well program in the National Petroleum Reserve - Alaska, offsetting last year's drilling program.

~~The Alpine field, in which Anadarko holds a 22% interest,~~Company is currently ~~producing in excess of 80,000 (gross) BOPD from 17 producing wells.~~

~~Item 2. Management's Discussion~~drilling the ELH #4 well and ~~Analysis of Financial Condition and Results of Operations (continued)~~

Anadarko participated in the OCS Federal Lease Sale No. 178 held in March 2001 and was the apparent high bidder for 23 tracts covering 120,000 acres in the Gulf of Mexico. The blocks, which represent an investment of $32 million for Anadarko, include 7 on the Outer Continental Shelf in shallow water and 16 in deepwater. The sale results strengthen the Company's holdings, particularly in the sub-salt play in deepwater areas. Anadarko currently holds a total of 353 leases in theNet production from Anadarko's Gulf of Mexico ~~- 58~~properties in the ~~deepwater and 150 in the sub-salt play.~~

Sub-salt Development work was completed at the Tanzanite field (Eugene Island 346) during the first quarter. The 2 wells are currently producing at about 20,000 BOPD and 120 MMcf/d of gas. Cumulative production from Tanzanite during the firstsecond quarter was about 1.4 MMBbls of oil and 4.2 Bcf of gas. At the Hickory field (Grand Isle 110/111/116), Anadarko has completed 3 wells, which are producing, and is in the process of completing the fourth well. Presently, Hickory is producing approximately 170averaged 373 MMcf/d of gas and ~~13,400 BCPD. For~~29,000 BOPD, an increase of 29% from the first quarter ~~the Hickory field produced a total~~ of ~~5 Bcf of gas and almost 300,000 barrels of condensate. Anadarko owns a 100% working interest in the Tanzanite field and a 50% working interest in the Hickory field.~~

Drilling is now under way on 3 additional sub-salt projects, including Tarantula (South Timbalier 308), Taurus (Green Canyon 134) and the Mahogany A-11 well, which is targeting deeper horizons below the main producing interval. In all, the Company plans to drill 7 sub-salt wildcats in 2001.

Conventional Shallow water projects on the Outer Continental Shelf represent an important piece of Anadarko's plans to increase offshore ~~volumes~~production volumes. During the second quarter of 2001, 3 discoveries were made. The Ship Shoal 216 #C-23 well (55% WI) encountered about 106 net feet of pay in 5 intervals. The well is already on production at 20 MMcf/d of gas. The South Marsh Island 280 #6 well (50% WI) encountered about 267 net feet of pay in 7 pay sands. The Company is currently drilling the #7 well (50% WI) to ~~an average~~accelerate development of ~~73,000 BOE per day~~the discovery and to test deeper objectives. The Ship Shoal 190 #5 well (100% WI) encountered about 80 feet of net pay in 6 sands and came on production in July 2001.

Several development completions were made during the second quarter of 2001. ~~For~~The Ship Shoal 126 #A1 well (58% WI) was recompleted and came on-line at 11 MMcf/d of gas and 1,000 BCPD. The Ship Shoal 190 #3 well (100% WI) flowed 10.7 MMcf/d of gas and 1,200 BCPD from the ~~year, the Company plans to drill 20 development and 10 exploratory wells in and around older existing fields.~~

Deepwater ~~During the first quarter, drilling was completed on the first of 8 deepwater wells planned for 2001. The LaSalle prospect, located~~Drilling is underway at ~~East Breaks Block 558 in 3,385 feet of water, encountered pay. Results are being evaluated. Anadarko is operator of the project and has a 33% working interest.~~

Eiger Sanction (100% WI), a deepwater prospect ~~was spud~~which spudded in ~~April.~~April 2001. The well, is located on ~~the~~ Mississippi Canyon Block 667 in 2,950 feet of water, is currently drilling below 12,000 feet and ~~is expected to be drilled to~~has a targeted depth of 29,000 feet. Mississippi Canyon Block 667 is adjacent to Anadarko's earlier deepwater Gomez discovery.

Sub-salt A sub-salt well drilled in the second quarter of 2001 is an apparent commercial discovery. The Tarantula prospect (South Timbalier 308) encountered about 170 feet of net pay. The well has been suspended and the Company is currently updating its technical interpretations with further drilling planned this year. The Company has a 100% WI in the well.

~~Monet,~~The Taurus prospect, located on Green Canyon 134 (100% WI), was plugged and abandoned.

At the North Garnet field, the East Cameron 347 #2 well (100% WI) was completed in the PL1-10 sand and tested at 1,100 BOPD and 2 MMcf/d of gas. This was the Company's first "smart" completion, which will allow the well to be recompleted later in its life without the use of a ~~non-operated~~rig or wireline. This technology will be important in developing future deepwater ~~prospect in which~~fields. A subsea tie-back was installed to the Company's East Cameron 359 A platform.

Development work at the Hickory field (Grand Isle 110/111/116) was completed during the second quarter. All 4 wells are now on-line and producing about 240 MMcf/d of gas and 15,000 BCPD. The Tanzanite field (Eugene Island 346) is producing at about 85 MMcf/d of gas and 13,000 BOPD. Anadarko has a ~~33% working interest,~~50% WI in Hickory and a 100% WI in Tanzanite.

Anadarko and its partner announced first discoveries in the National Petroleum Reserve-Alaska. During the past two winters drilling seasons, 5 wells and a sidetrack, which targeted the Alpine producing horizon, encountered oil or gas and condensate. These wells are the Spark #1, Spark #1A, Moose's Tooth C, Lookout #1, Rendezvous A and Rendezvous #2 (22% WI). A sixth well was ~~spud~~a dry hole. The Spark #1A well tested 1,550 BCPD and 26.5 MMcf/d of gas. The Rendezvous well tested at an unstimulated rate of 360 BCPD and 6.6 MMcf/d of gas. The other wells have been suspended and further drilling is planned for next year.

The Alpine field (22% WI) is currently producing at a record rate of 96,000 BOPD. In July 2001, Alpine set a field production record by producing more than 100,000 BOPD during a single day. Anadarko and its partner are currently considering a number of oilfield development scenarios that reflect the higher than expected production rates from Alpine and the discovery and delineation of the satellite fields.

In July 2001, Anadarko and its partner announced the discovery of a satellite oil field (22% WI) near the Alpine field. It was discovered in April 2000 with the Nanuq #2 exploration well, which tested at a rate of 1,750 barrels per day of 40-degree API gravity crude and 1.2 MMcf/d of gas. A delineation well, the Nanuq CD1-229, was drilled from the Alpine field during the 2001 winter drilling season. The initial production test reported a rate of nearly 460 BOPD and 6.5 MMcf/d of gas from a horizontal completion. The Nanuq #3 delineation well was also drilled last winter and found pay in the Nanuq reservoir, extending the field limits. Nanuq is the second satellite field to be discovered near Alpine.

Anadarko and its partner were apparent high bidders on 36 of 43 bid tracts covering about 207,000 acres in the first North Slope Foothills Area-Wide Oil and Gas lease sale, which was held in May 2001. The ~~well is~~acres put up for lease are located onin the ~~Mississippi Canyon Block 561 in 6,300 feet~~southern part of ~~water~~the slope and ~~is expected to be drilled to a depth of 15,500 feet.~~

~~Evaluation continues at the Marco Polo discovery on Green Canyon 608. Detailed engineering and cost estimates~~ are ~~under way to help determine commerciality and the feasibility of additional drilling.~~

~~In mid-March, Anadarko completed its~~Since the purchase of ~~Canadian-based~~ Berkley ~~by acquiring 100%~~in March 2001, Anadarko increased capital spending 50% in Canada to almost $400 million to drill exploration wells and accelerate development of ~~Berkley's shares.~~recent discoveries. The shares tendered were purchased for C$11.40 per share for a total value of approximately US$779 million plus the assumption of US$236 million in debt. The purchase fast tracks Anadarko's Canadian natural gas program by offering excellent opportunities for both exploration and development in addition to those that the Company had been working. The Berkley acquisition increased Anadarko's ~~Canadian reserves by 42%, to 312 million BOE, 65% of which is natural gas.~~

~~The Berkley acquisition also increased the Company's~~ total acreage position in Canada ~~from 3 million~~ to 54.7 million net acres (4(3.5 million undeveloped 1and 1.2 million developed) ~~particularly~~. An additional 48,000 net acres were acquired during the second quarter.

During the second quarter of 2001, Anadarko had a 96% success rate in ~~Northeast British Columbia, the Alberta foothills~~Canada, drilling 159 wells, of which 29 were oil wells, 124 were gas wells and ~~the Northwest Territories. The Berkley acquisition should complement Anadarko's aggressive plans to drill 600 wells in western Canada during 2001.~~6 were dry holes. Activity ~~will be~~was focused primarily ~~on major operating areas~~ in the Alberta, British Columbia and Saskatchewan ~~where~~areas that have year-round access. Anadarko had 8 rigs active during the ~~Company plans~~second quarter and will increase activity to ~~apply new advances in exploration and drilling technologies.~~

~~Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)~~

~~During~~20 rigs during the 2000/2001 winter drilling season and into the first quarter of this year, Anadarko expanded its Jean Marie natural gas play in Northeast British Columbia, where the majority of its drilling activity has been focused. Anadarko increased its acreage position in the play by 80,000 acres in February 2001, to 167,600 net acres. The Company currently has 12 horizontal wells at various stages of completion, including 4 dual horizontal wells.

Six Jean Marie wells were recently put on production at a combined initial rate of 10 MMcf/d of gas. These wells tested at daily rates of between 2 MMcf/d and 4 MMcf/d of gas. Four of the 6 wells are scheduled to begin producing this summer ~~and the remaining 2 are expected to begin production next winter. The Company expects to conduct a summer drilling program in the Jean Marie play as well.~~

In ~~the Buckinghorse prospect area, also in Northeast British Columbia,~~southeast Saskatchewan, the Company drilled ~~2 successful exploration wells. The Green a-A55-A~~the Steelman 9-27 well (100% WI), which flowed at a choked-back rate of 4.3 MMcf/d of gas, and the 44-a well is flowing at a stabilized rate of 5.5 MMcf/d of gas. Anadarko owns a 100% working interest in both wells. Other high-impact exploration in Northeast British Columbia includes 1 well at the Conroy prospect and 1 well currently testing at Kobes.

~~In the southern Northwest Territories and Northeast British Columbia, development drilling in the Liard Maxhamish area resulted in 2 new gas completions~~605 BOPD from the ~~Mississippian Mattson formation~~Winnipegosis formation. The well has 3 horizontal laterals with ~~an initial gross production rate~~1,216 feet of 18 MMcf/d of gas. Anadarko holds working interests in the wells ranging from 33% to 50%. The Company also recompleted 2 gas wells in the Tatoo area. Preliminary production began in April 2001, at an initial gross production rate of 4 MMcf/d of gas.

In the Mackenzie Delta in the Northwest Territories, Anadarko expects to complete a 924-kilometer 2-D seismic survey in May. Anadarko and its partners have contracted a rig that could be used for drilling as early as next winter. The Company holds a 37.5% working interest.

In northern Alberta, 10 successful oil wells were drilled this winter in the Dawson area, each with initial production rates of between 250 BOPD and 1,000 BOPD. The Company has a 33-well drilling program planned for the remainder of this year, focusing on new pool wildcats and exploitation drilling opportunities identified from this winter's discoveries.

In the Wild River/Wild Hay area in northwestern Alberta, the Company is currently active with a two-rig natural gas development drilling program. Significant production growth is expected as numerous wells in this multi-pay area are completed throughout the year.

In the Larne area of northwestern Alberta, the Company participated in 2 successful exploratory Devonian Slave Point tests. Each well tested at rates between 1.5 to 4 MMcf/d of gas. First production began mid-April 2001. Anadarko holds a 50% working interest.

In the heavy oil area of eastern Alberta, Anadarko drilled a total of 17 development wells with a 100% success rate. The Company added 520 BOPD of new production as a result of winter drilling. In addition, a 330-square kilometer 3-D seismic program was completed in the heavy oil fields during March. Anadarko controls 80,000 net undeveloped acres in this area where recent outpost discoveries have been made on 2-D seismic. A summer drilling program is planned using 2 to 3 rigs.

horizontal length. In the Hatton shallow gas project in southwestern Saskatchewan, the Company ~~drilled 27~~completed 95 development wells during the ~~winter season, 15 of which are currently on production.~~second quarter. Net production from Hatton is ~~presently 70~~currently 72 MMcf/d of gas. More than ~~250~~75 wells ~~are~~remain to be drilled this year.

In the Wild Hay area of northwestern Alberta, Anadarko successfully drilled 4 gas wells in the second quarter. Most notable was the Cecilia 11-20 well (100% WI), which was dually completed in the Mannville and Cadomin formations with a combined test rate of 5 MMcf/d of gas. The success in this multi-play area should result in the expansion of the Company's gas processing plant to 56 MMcf/d of gas, up from 24 MMcf/d of gas.

In northern Alberta, 4 oil wells were drilled to the Slave Point formation in the Dawson area. The Dawson 16-7 well (60% WI) tested at 1,800 BOPD and the Dawson 8-8 (75% WI) produced about 950 BOPD. The Company has an active drilling program planned for the ~~summer~~remainder of this year that increases to 4 rigs and focuses on exploitation drilling ~~season.~~opportunities identified early this year.

~~First quarter activity was highlighted by Anadarko's return to exploration in Algeria. For~~In the ~~past few years,~~Klua area of northeast British Columbia, the Company ~~has been focused on developing~~reactivated the ~~12 fields it has discovered~~Klua 97-J well (50% WI), which flowed at 8.8 MMcf/d of gas.

In the Mackenzie Delta in the ~~Sahara Desert. In March, the Company announced details regarding an amendment to the Production Sharing Agreement with Sonatrach signed by~~Northwest Territories, Anadarko and its partners LASMO and Maersk. The agreement will allow Anadarko to resume exploration of Blocks 404, 208 and 211 in areas outside of the exploitation license boundaries encompassing previous discoveries made by the Sonatrach/Anadarko association.

~~Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (continued)~~

These are the same blocks Anadarko began exploring in 1989 and the amendment will allow the Algerian exploration team to build on the knowledge gathered over the last several years. Under the terms of the three-phase exploration program, Anadarko and its partners will spend a minimum of $55 million. During the first 5 years, 400 square kilometers of 3-D seismic and 1,100acquired 926 kilometers of 2-D seismic ~~will be acquired~~data.

The scheduled 30-day shutdown of the central processing facility (CPF) on Block 404 was completed 6 days ahead of schedule. During the shutdown, statutory vessel inspections were performed and ~~processed;~~ the ~~results of previous seismic surveys will be reprocessed; and 6 exploration wells will be drilled. Seismic acquisition~~Stage II production facility for the HBNS field, which is expected to ~~begin this year, and exploration drilling will likely begin in 2002. Should the sixth- and seventh-year options be exercised, an additional exploration well will be drilled in each year.~~

~~Anadarko, LASMO and Maersk will finance 100% of the exploration investment and Sonatrach will participate 51%~~start up in the ~~development~~third quarter of 2001, was tied-in. The CPF is back up and exploitation phases of any discoveries. Where appropriate, existing facilities and infrastructure may be used to develop any discoveries, thereby reducing development costs and potentially accelerating firstproducing approximately 74,000 BOPD.

Construction continues on two other production trains at the CPF on Block 404. These trains will process oil ~~production.~~

~~Under the exploration phase of the original Production Sharing Agreement, Anadarko drilled 20 exploratory wells with a 70% success rate.~~

During the first quarter, Anadarko completed a number of oil producing wells in various areas of the Hassi Berkine (HBN) and Hassi Berkine South (HBNS) fields. The HBNS-30 encountered 84 feet of net pay in the main TAGI reservoir and was completed as an oil producer. In the south central portion of the HBNS field the HBNS-34 well was also completed as a Stage II oil producer after encountering 85 feet of net pay in the TAGI reservoir. Elsewhere in the HBNS field, Anadarko connected the HBNS-21 well to the water injection network and commenced operations. Also during the first quarter, production beganproduced from ~~the HBNS-18 and HBNS-35 wells after being connected to the oil gathering network. Combined production from the 2 wells is 13,500 BOPD.~~

~~On the western edge of~~ the HBN field ~~the HBN-8 well encountered 44 feet of net pay and was completed as an oil producer in the TAGI reservoir.~~

~~Three additional drilling rigs are being added to the development drilling program. The first of the 3 rigs has recently begun drilling operations.~~

~~Construction continues at Stage II facilities for HBNS, where production is expected to increase to 135,000 BOPD later this year. Construction is also continuing for the HBN~~ and the ~~Block 404~~ satellite ~~production facilities,~~fields around HBN-HBNS, both of which will be completed next year. AtThree production trains are also under construction at the Ourhoud ~~(ORD)~~ field ~~development continues, with construction of~~and first production is expected late next year.

Anadarko's successor exploration contract covering blocks 404, 211 and 208 was officially sanctioned by the ~~production facilities. Two drilling rigs~~Algerian government in June 2001. Plans are being ~~mobilized~~made to ~~carry out development~~begin exploration drilling ~~in the ORD field. Both rigs should begin drilling operations during May.~~

~~Progress continued in the first quarter on 2~~early next year. Two separate seismic acquisition ~~programs. The~~programs, a 3-D satellite survey on Block 404 ~~is 79% complete~~ and ~~the~~an EME 3-D survey on Block 208, were completed in the second quarter.

Middle East In June 2001, Anadarko announced that it had entered into an agreement to acquire Canadian based Gulfstream Resources Canada Limited (Gulfstream) for C$2.65 per share. The total value of the acquisition is ~~now complete.~~approximately US$137 million, subject to normal closing adjustments. Gulfstream is an international oil and gas exploration and production company with assets in Qatar, Oman and Madagascar.

Guatemala In July 2001, the Company sold 100% of its wholly owned subsidiary, Basic Resources International (Basic), for US$121 million. Basic produces and refines crude oil in Guatemala. Anadarko acquired Basic as part of the merger with RME in July 2000.

Business Combinations and Goodwill and Other Intangible Assets In July 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated or completed after June 30, 2001. SFAS No. 141 also specifies criteria that intangible assets acquired in a purchase method business combination must meet to be recognized and reported apart from goodwill. The adoption of SFAS No. 141 as of July 1, 2001 had no impact on the Company's financial statements.

Implementation of SFAS No. 142 is required as of January 1, 2002. Because of the extensive effort needed to comply with adopting SFAS No. 142, the impact of adoption on the Company's financial statements has not been determined, including whether any transitional impairment losses will be required to be recognized as the effect of a change in accounting principle. As of January 1, 2002, the Company expects to have unamortized goodwill in the amount of $1.4 billion, which will be subject to the transition provisions of SFAS No. 142. Amortization expense related to goodwill was $36 million and $31 million for the six months ended June 30, 2001 and the year ended December 31, 2000, respectively.

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

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 (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended. 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~~instru ments may be designated as a hedge of exposure to changes in fair values, cash flows, or foreign currencies, if certain conditions are met. If the hedged exposure is a fair value exposure, the gains/losses on the derivative financial instrument, as well as the offsetting losses/gains on the hedged item, shall be 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 shall be 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 ~~hedge~~the cash flow hedges' effectiveness are recognized currently in other (income) expense. Unrealized gains/losses on derivative financial instruments that do not meet the conditions to qualify for hedge accounting are recognized currently in earnings. The majority of the derivatives into which the Company enters have terms of less than 12 months. As of ~~March 31,~~June 30, 2001, the Company had a net unrealized ~~loss~~gain of ~~$10~~$24 million before taxes (gains of $1$29 million and losses of ~~$11~~$5 million), or $6$16 million after taxes, on derivative commodity instruments entered into to hedge equity production recorded in accumulated other comprehensive income. Other income for the ~~quarter~~three and six months ended ~~March 31,~~June 30, 2001, includes $9$18 million and $27 million, respectively, of net gains related to derivative instruments designated as cash flow ~~hedges and $0.3 million of net losses related to derivative instruments designated as fair value~~ hedges. These ~~amounts represents the sum of a) the amount of hedge ineffectiveness and b)~~gains are primarily due to the change in the time value of the option contracts that ~~was~~were excluded from the assessment of hedge effectiveness. Operating income for t he three and six months ended June 30, 2001, includes $1 million of net losses related to the ineffective portion of a swap agreement designated as a fair value hedge. 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 ~~$39~~$33 million.

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.~~method pursuant to Emerging Issues Task Force Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". Under this method, the derivatives are revalued in each accounting period and premium receipts/payments and unrealized gains/losses are immediately recorded in the statement of income and carried as current assets or liabilities on the balance sheet. The derivative contracts entered into for trading purposes are typically for terms of less than 12 months. As of ~~March 31,~~June 30, 2001 the Company had a net unrealized ~~gain~~loss of $7$47 million (gains of ~~$111~~$88 million and losses of ~~$104~~$135 million) on derivative commodity instruments entered into for trading purposes. Losses on derivative commodity instruments are offset by a net unrealized gain of $55 million (gains of $70 million and losses of $15 million) on physical contracts entered into for trading purposes. Based upon an analysis utilizing the actual derivative contractual volumes and assuming a 10% increase in underlying commodity prices, the potential ~~additional~~ loss on the derivative instruments would be decreased by approximately $1$12 million.

RME was a party to several long-term firm gas transportation agreements that supported the gas marketing program within the gathering, processing and marketing (GPM) business segment, which was sold in 1999 to Duke Energy Field Services, Inc. (Duke). Most of the GPM business segment'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 and Duke agreed RME will 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). ~~Payments~~Net payments from Duke in the ~~first quarter~~three and six months ended June 30, 2001 were ~~$78 million. Transportation~~$64 million and $141 million, respectively. Tran sportation 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

~~Item 3. Quantitative and Qualitative Disclosures About Market Risk(continued)~~

each contract's expiration date or March 2009. ~~Market rates for firm transportation (particularly those pipelines serving markets on the west coast) have increased significantly. As a result, the~~The Company recognized other expense of $138 million for the three months ended June 30, 2001 and other income of ~~$140~~$46 million ~~during~~for the ~~first quarter of~~six months ended June 30, 2001. As of ~~March 31,~~June 30, 2001, ~~Other Current Assets~~other current assets included ~~$140~~$19 million and other long-term liabilities included $85 million related to this agreement.

From time to time, the Company uses derivative financial instruments to reduce its exposure to potential decreases in future transportation market values. While the derivatives are intended to reduce the Company's exposure to declines in transportation market values, they also limit the potential to benefit from market value increases. ~~As of March 31,~~For the three and six months ended June 30, 2001, the Company ~~had an unrealized loss~~recognized other income of ~~$33~~$96 million and $52 million, respectively, on derivative financial instruments related to transportation rates. At June 30, 2001, other current assets included $81 million of unrealized gains related to this agreement. Based upon an analysis utilizing the actual derivative contractual volumes and assuming a 10% increase in underlying commodity prices, the potential additional loss would be approximately $6$3 million.

Stock Repurchase Program In July 2001, the Board of Directors authorized the Company to purchase as much as $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.

Interest Rate Risk Anadarko is also exposed to risk resulting from changes in interest rates as a result of the Company's variable and fixed interest rate debt. The Company has evaluated the potential effect that reasonably possible near term changes in interest rates may have on the fair value of the Company's various debt instruments.

Foreign Currency Risk The Company's Canadian subsidiary uses the Canadian dollar as its functional currency. The Company's Algerian subsidiary and the 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.

At ~~March 31,~~June 30, 2001, Anadarko Canada Corporation had ~~$650~~$190 million outstanding of fixed-rate notes and debentures denominated in U.S. ~~dollars and $789 million in intercompany debt.~~dollars. For the ~~period~~three and six months ended ~~March 31,~~June 30, 2001, the Company recognized a ~~$52~~$35 million pretax non-cash gain and $17 million pretax non-cash loss, respectively, associated with the remeasurement of ~~this debt.~~Anadarko Canada's U.S. denominated debt outstanding during the period. The potential foreign currency remeasurement impact on earnings from a 10% change in the ~~March 31,~~June 30, 2001 Canadian exchange rate would be about ~~$117~~$19 million based on the outstanding debt at ~~March 31,~~June 30, 2001.

The Company periodically enters into foreign currency contracts to hedge specific currency exposures from commercial transactions. The following table summarizes the Company's open foreign currency positions at ~~March 31,~~June 30, 2001:

U.S. $ in millions, except	Maturity Year
foreign currency rates	2004
					Maturity Year
U.S. $ in millions, except foreign currency rates					2004
Notional amount	$	70		$		70
Forward rate		1.36				1.36
Market rate		1.57				1.50
Decrease in rate	(0.21		)			(0.14	)
Fair value - gain (loss)	$	(15	)	$		(10	)

At ~~March 31,~~June 30, 2001, the Company's Latin American subsidiaries had foreign deferred tax liabilities denominated in the local currency equivalent totaling ~~$97~~$96 million. The potential foreign currency remeasurement impact on net earnings from a 10% change in the year-end Latin American exchange rates would be approximately $10 million.

SeeNote 12 of the Notes to Consolidated Financial Statements under Part I - Item 1 of this Form 10-Q.

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.

Incorporated in the	Employer Identification
State of Delaware	No. 76-0146568


Title of Class	Number of Shares Outstanding

Common Stock, par value $0.10 per share	~~250,627,503~~250,764,764

			Page
PART I

	Item 1.	Financial Statements

		Consolidated ~~Statements~~Statement of Income for the Three and Six Months ~~Ended~~ ~~March 31,~~Ended June 30, 2001 and ~~March 31,~~June 30, 2000	3

		Consolidated Statement of Comprehensive Income for the Three ~~Months~~and ~~Ended March 31,~~Six Months ended June 30, 2001 and ~~March 31,~~June 30, 2000	4

		Consolidated Balance Sheet as of ~~March 31,~~June 30, 2001 and December 31, 2000	5

		Consolidated Statement of Cash Flows for the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2001 and ~~March 31,~~June 30, 2000	7

		Notes to Consolidated Financial Statements	8

	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	1819

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2930

PART II

	Item 1.	Legal Proceedings	3133

	Item 4.	Submission of Matters to a Vote of Security Holders	33

	Item 6.	Exhibits and Reports on Form 8-K	3133

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEET
(Unaudited)

		June 30,			December 31,
millions		2001			2000
ASSETS
Current Assets
Cash and cash equivalents	$		300	$		199
Accounts receivable, net of allowance			1,233			1,376
Other current assets			204			319

Total			1,737			1,894

Properties and Equipment
Original cost			18,487			15,843
Less accumulated depreciation, depletion and amortization			3,423			2,832

Net properties and equipment - based on the full cost
method of accounting for oil and gas properties			15,064			13,011

Other Assets			540			368

Goodwill			1,482			1,348
Less accumulated amortization			67			31

Goodwill, net of amortization			1,415			1,317

	$		18,756	$		16,590

		June 30,				December 31,
millions except share amounts		2001				2000
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$		1,104		$		1,256
Accrued expenses			349				420
Current portion, notes and debentures			748				--

Total			2,201				1,676

Long-term Debt			3,941				3,984

Other Long-term Liabilities
Deferred income taxes			4,177				3,633
Other			616				511

Total			4,793				4,144

Stockholders' Equity
Preferred stock, par value $1.00
(2.0 million shares authorized, 0.1 million and 0.2 million shares issued
as of June 30, 2001 and December 31, 2000, respectively)			115				200
Common stock, par value $0.10
(450.0 million shares authorized, 253.8 million and 253.3 million shares
issued as of June 30, 2001 and December 31, 2000, respectively)			25				25
Paid-in capital			5,313				5,303
Retained earnings (as of June 30, 2001, retained earnings
were not restricted as to the payment of dividends)			2,553				1,521
Deferred compensation and ESOP
(1.1 million shares as of June 30, 2001 and December 31, 2000)			(111	)			(121	)
Executives and Directors Benefits Trust, at market value
(2.0 million shares as of June 30, 2001 and December 31, 2000)			(109	)			(145	)
Accumulated other comprehensive income (loss)
Unrealized gain on derivatives			16				--
Foreign currency translation adjustments			22				3
Minimum pension liability			(3	)			--
Total			35				3

Total			7,821				6,786

Commitments and Contingencies			--				--

	$		18,756		$		16,590

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
				Six Months Ended
				June 30
millions				2001			2000
Cash Flow from Operating Activities
Net income before cumulative effect of change in accounting principle			$	1,066		$		117
Adjustments to reconcile net income before cumulative effect of change
	in accounting principle to net cash provided by operating activities:
		Depreciation, depletion and amortization		594				120
		Amortization of goodwill		36				--
		Non-cash merger expenses		7				--
		Interest expense - zero coupon debentures		6				4
		Deferred income taxes		415				62
		Impairments related to international properties		15				--
		Other non-cash items		27				--
				2,166				303
(Increase) decrease in accounts receivable				369				(129	)
Increase (decrease) in accounts payable and accrued expenses				(377	)			39
Other items - net				(108	)			(19	)

Net cash provided by operating activities				2,050				194

Cash Flow from Investing Activities
Additions to properties and equipment				(1,514	)			(451	)
Acquisition costs, net of cash acquired				(821	)			--
Sales and retirements of properties and equipment				3				(2	)

Net cash used in investing activities				(2,332	)			(453	)

Cash Flow from Financing Activities
Additions to debt				2,418				345
Retirements of debt				(1,950	)			(136	)
Decrease in accounts payable, banks				(16	)			--
Dividends paid				(29	)			(18	)
Retirement of preferred stock				(73	)			--
Issuance of common stock				32				28

Net cash provided by financing activities				382				219

Effect of Exchange Rate Changes on Cash				1				--

Net Increase (Decrease) in Cash and Cash Equivalents				101				(40	)

Cash and Cash Equivalents at Beginning of Period				199				45

Cash and Cash Equivalents at End of Period			$	300		$		5


millions except per share amounts
Revenues		$	1,546
Net income available to common stockholders before cumulative
	effect of change in accounting principle	$	164
Earnings per share - basic		$	0.68
Earnings per share - diluted		$	0.66

			Three Months Ended						Three Months Ended
			March 31, 2001						March 31, 2000
millions except						Per Share						Per Share
	per share amounts	Income			Shares	Amount		Income			Shares	Amount
Basic EPS
Income available to common
stockholders before change in
accounting principle		$		661	250	$	2.64	$		48	128	$	0.37
Effect of convertible debentures
and ZYP-CODES		2			10			--			2
Effect of dilutive stock options and
performance-based stock awards		--			3			--			1
Diluted EPS
Income available to common
stockholders plus assumed conversion		$		663	263	$	2.52	$		48	131	$	0.37

			Three Months Ended								Three Months Ended
			June 30, 2001								June 30, 2000
millions except								Per Share								Per Share
	per share amounts	Income				Shares		Amount		Income			Shares			Amount
Basic EPS
Income available to common
stockholders before change in
accounting principle		$			401		251	$	1.60	$		64			128	$	0.50
Effect of convertible debentures
and ZYP-CODES					2		14					2			8
Effect of dilutive stock options and
performance-based stock awards					--		3					--			2
Diluted EPS
Income available to common
stockholders plus assumed conversion		$			403		268	$	1.50	$		66			138	$	0.48

			Six Months Ended								Six Months Ended
			June 30, 2001								June 30, 2000
								Per Share								Per Share
		Income				Shares		Amount		Income				Shares		Amount
Basic EPS
Income available to common
stockholders before change in
accounting principle		$		1,062			251	$	4.24	$		112			128	$	0.87
Effect of convertible debentures
and ZYP-CODES				4			12					2			5
Effect of dilutive stock options and
performance-based stock awards				--			3					--			2
Diluted EPS
Income available to common
stockholders plus assumed conversion		$		1,066			266	$	4.01	$		114			135	$	0.84

		Oil and Gas
		Exploration						All
millions		and Production		Marketing		Minerals		Other			Total
Three Months Ended March 31:

2001
Revenues		$	1,163	$	1,885	$	11	$	(8	)	$	3,051
Intersegment revenues			385		182		--		(567	)		--
	Total revenues		1,548		2,067		11		(575	)		3,051
Income (loss) before income taxes		$	1,032	$	154	$	10	$	(143	)	$	1,053
Net properties and equipment		$	12,773	$	185	$	1,210	$	303		$	14,471

2000
Revenues		$	171	$	488	$	--	$	2		$	661
Intersegment revenues			97		14		--		(111	)		--
	Total revenues		268		502		--		(109	)		661
Income (loss) before income taxes		$	145	$	--	$	--	$	(47	)	$	98
Net properties and equipment		$	3,623	$	133	$	--	$	53		$	3,809


	Operating Industries, Inc. (Federal) - The former municipal industrial landfill (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 (approximately 50,500 barrels of E&P waste) and Wilmington Refinery's (approximately 23,500 barrels of liquid waste) contributions. The Company believes its share of the costs will be about $4 million, not including settlement of two pending lawsuits.

	Ekotek (Federal) - The facility (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, was named as a PRP for its contributions of approximately 117,000 gallons of used/waste oils. Remediation of the Ekotek site is nearing completion and no additional funding requests are expected.

	Casmalia (Federal) - The Casmalia facility (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. Environmental Protection Agency (EPA) has recently forwarded a request for payment in the amount of $22 million to the PRP group for reimbursement of previous remedial expenditures. Negotiations with EPA are ongoing. The Company believes its share of the costs will be about $100,000.

	Geothermal Inc. (State) - The site (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 $100,000.

	PCB Treatment, Inc. (Federal) - The PCB treatment/disposal site (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. Approximately 56,000 pounds of PCB contaminated materials were 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 $100,000.

(a)	Exhibits

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

Exhibit			Original Filed	File
Number		Description	Exhibit	Number

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

	(b)	By-laws of Anadarko Petroleum	3(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

	(c)	Amendment No. 1 to Rights Agreement,	2.4 to Form 8-K dated	1-8968
		dated as of April 2, 2000 between	April 2, 2000
		Anadarko and the Rights Agent


*12		Computation of Ratios of Earnings to Fixed	~~12(a) to Form S-3 dated~~	~~333-60496~~
		Charges and Earnings to Combined Fixed	~~May 9, 2001~~
		Charges and Preferred Stock Dividends

(b)	Reports on Form 8-K

	A report on Form 8-K dated ~~February 15,~~April 20, 2001 was filed in which the earliest event reported was ~~February 12,~~
	~~2001. This event was reported under Item 5 "Other Events" and Item 7(c), "Exhibits".~~

	~~A report on Form 8-K dated March 8, 2001 was filed in which the earliest event reported was March 8,~~April 19, 2001.
	This event was reported under Item 5 "Other Events" and Item 7(c), "Exhibits".

	A report on Form 8-K dated ~~March 9,~~June 25, 2001 was filed in which the earliest event reported was ~~February 1,~~June 25, 2001.
	This event was reported under Item 5 "Other Events" and Item 7(c), "Exhibits".

	ANADARKO PETROLEUM CORPORATION
	(Registrant)



~~May 14,~~

August 13, 2001	By: ~~/s/~~	/s/ MICHAEL E. ROSE ��
	Michael E. Rose - Executive Vice President,
	Finance and Chief Financial Officer

		March 31,			December 31,
millions		2001			2000
Notes Payable, Banks	$		466	$		199
Long-term Portion of Capital Lease			11			12
8 1/4% Notes due 2001			100			100
6.8% Debentures due 2002			248			247
6 3/4% Notes due 2003			100			100
5 7/8% Notes due 2003			100			100
6.5% Notes due 2005			192			192
7.375% Debentures due 2006			247			247
7% Notes due 2006			194			194
6.75% Notes due 2008			151			151
7.8% Debentures due 2008			150			150
7.3% Notes due 2009			156			156
7.05% Debentures due 2018			183			183
Zero Coupon Convertible
Debentures due 2020			358			355
Zero Yield Puttable Contingent
Debt Securities due 2021			650			--
7.5% Debentures due 2026			188			188
7% Debentures due 2027			100			100
6.625% Debentures due 2028			100			100
7.15% Debentures due 2028			334			334
7.20% Debentures due 2029			300			300
7.95% Debentures due 2029			239			238
7.73% Debentures due 2096			100			100
7 1/4% Debentures due 2096			100			100
7.5% Debentures due 2096			138			138
Total	$		4,905	$		3,984

		June 30,			December 31,
millions		2001			2000
Notes Payable, Banks	$		--	$		199
Long-term Portion of Capital Lease			11			12
8 1/4% Notes due 2001			98			100
6.8% Debentures due 2002			87			247
6 3/4% Notes due 2003			73			100
5 7/8% Notes due 2003			83			100
6.5% Notes due 2005			164			192
7.375% Debentures due 2006			92			247
7% Notes due 2006			169			194
6.75% Notes due 2008			110			151
7.8% Debentures due 2008			11			150
7.3% Notes due 2009			82			156
6 3/4% Notes due 2011			907			--
7.05% Debentures due 2018			105			183
Zero Coupon Convertible
Debentures due 2020			361			355
Zero Yield Puttable Contingent
Debt Securities due 2021			650			--
7.5% Debentures due 2026			105			188
7% Debentures due 2027			54			100
6.625% Debentures due 2028			17			100
7.15% Debentures due 2028			212			334
7.20% Debentures due 2029			135			300
7.95% Debentures due 2029			117			238
7 1/2% Notes due 2031			861			--
7.73% Debentures due 2096			61			100
7 1/4% Debentures due 2096			49			100
7.5% Debentures due 2096			75			138
Total	$		4,689	$		3,984