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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

ANADARKO PETROLEUM CORPORATION
1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046
(832) 636-1000

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

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

See accompanying notes to consolidated financial statements.

See accompanying notes to consolidated financial statements.

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

See accompanying notes to consolidated financial statements.

See accompanying notes to consolidated financial statements.

See accompanying notes to consolidated financial statements.

General     Anadarko Petroleum Corporation is engaged in the exploration, development, production and marketing of natural gas, crude oil, condensate and natural gas liquids (NGLs). The Company also engages in the hard minerals business through non-operated joint ventures and royalty arrangements in several coal, trona (natural soda ash) and industrial mineral mines. The terms "Anadarko" and "Company" refer to Anadarko Petroleum Corporation and its subsidiaries. The principal subsidiaries of Anadarko are: Anadarko E&P Company LP; Anadarko Holding Company (Anadarko Holding); Anadarko Canada Energy Ltd.; Anadarko Canada Corporation; Anadarko Land Corp.; and, Anadarko Algeria Company, LLC. Certain amounts for the prior periods have been reclassified to conform to the current presentation.

The information, as furnished herein, reflects all normal recurring adjustments that are, in the opinion of Management, necessary for a fair statement of financial position as of September 30, 2002 and December 31, 2001, the results of operations for the three and nine months ended September 30, 2002 and 2001 and cash flows for the nine months ended September 30, 2002 and 2001. In preparing financial statements, Management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, Management reviews its estimates, including those related to litigation, environmental liabilities, income taxes and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Changes in Accounting Principles     In the third quarter of 2002, the Company adopted Emerging Issues Task Force (EITF) Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts." In accordance with the implementation of EITF Issue No. 02-3, marketing sales and purchases for prior periods have been reclassified to show net marketing margins as revenues. The marketing margins related to the Company's equity production are included in gas sales, oil and condensate sales and natural gas liquids sales and are reflected in commodity prices. The marketing margin related to purchases of third-party commodities is included in other sales. This reclassification has no effect on reported net income or cash flow.

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

As of the end of October 2002, the Company has outstanding derivative financial instruments and fixed price physical delivery sales contracts that hedged 11% of the Company's natural gas production and 37% of its crude oil production, which is expected to be produced during the remainder of 2002. In addition, as of the end of October 2002, the Company has outstanding derivative financial instruments and fixed price physical delivery sales contracts that hedged 30% of the Company's natural gas production and 30% of its crude oil production, which is expected to be produced during 2003 and 22% of the Company's natural gas production and 3% of its crude oil production, which is expected to be produced during 2004.

Derivative financial instruments utilized to manage or reduce commodity price risk related to the Company's equity production are accounted for under the provisions of SFAS No. 133. Under this statement, all derivatives are carried on the balance sheet at fair value. Realized gains/losses and option premiums are recognized in the statement of income when the underlying physical gas and oil production is sold. Accordingly, realized derivative gains/losses are generally offset by similar changes in the realized prices of the underlying physical gas and oil production. Realized derivative gains/losses are reflected in the average sales price of the physical gas and oil production. Accounting for unrealized gains/losses is dependent on whether the derivative financial instruments have been designated and qualify as part of a hedging relationship. Derivative financial instruments may be designated as a hedge of exposure to changes in fair values, cash flows or foreign currencies, if certain con ditions are met. Unrealized gains/losses on derivative financial instruments that do not meet the conditions to qualify for hedge accounting are recognized currently in earnings.

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

If the hedged exposure is a cash flow exposure, the effective portion of the gains/losses on the derivative financial instrument is reported as a component of accumulated other comprehensive income and reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The ineffective portion of the gains/losses from the derivative financial instrument, if any, as well as any amounts excluded from the assessment of the cash flow hedges' effectiveness are recognized currently in other (income) expense. Effective July 2001, the Company implemented Derivatives Implementation Group Issue G20, "Cash Flow Hedges: Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash Flow Hedge," which provides guidance for assessing the effectiveness on total changes in an option's cash flows rather than only on changes in the option's intrinsic value. Time value changes were previously being recognized in current earnings since the C ompany excluded time value changes from its assessment of hedge effectiveness. If the hedged exposure is a foreign currency exposure, the accounting is similar to the accounting for fair value and cash flow hedges.

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

The Company's derivative financial instruments associated with the marketing and trading activities are generally either exchange traded or valued by reference to a commodity that is traded in a liquid market. Valuation is determined by reference to readily available public data. Option valuations are based on the Black-Scholes option pricing model and verified against third-party quotations. The fair value of the short-term portion of the firm transportation keep-whole agreement is calculated with quoted natural gas basis prices, while the fair value of the long-term portion is estimated based on historical natural gas basis prices. See Note 6.

Earnings Per Share     The Company's basic earnings per share (EPS) amounts have been computed based on the average number of shares of common stock outstanding for the period. Diluted EPS amounts include the effect of the Company's outstanding stock options and performance-based stock awards under the treasury stock method and outstanding put options under the reverse treasury stock method, if including such equity instruments is dilutive. Diluted EPS amounts also include the net effect of the Company's convertible debentures and Zero Yield Puttable Contingent Debt Securities (ZYP-CODES) assuming the conversions occurred at the beginning of the year or the date of issuance, if including such potential common shares is dilutive.

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

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

SFAS No. 146, "Accounting for Exit or Disposal Activities," was issued in June 2002. SFAS No. 146 addresses significant issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance set forth in EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity." SFAS No. 146 will be effective for the Company in January 2003. The Company does not expect the adoption of SFAS No. 146 to materially affect the consolidated financial statements.

EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," was rescinded in October 2002. Accordingly, energy related contracts that are not accounted for pursuant to SFAS No. 133 will be accounted for as executory contracts and carried on an accrual basis, not fair value. For contracts existing on October 25, 2002, this consensus will be effective January 1, 2003. Contracts entered into after October 25, 2002 will be accounted for under SFAS No. 133. The Company is evaluating the impact of this rescission.

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

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

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

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

The change in goodwill since December 31, 2001 is due primarily to foreign currency remeasurements. Future changes in goodwill may result from, among other things, foreign currency remeasurement, changes in deferred income tax liabilities related to acquisitions, divestitures, impairments or future acquisitions.

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

4.  Properties and Equipment     Oil and gas properties include costs of $3.5 billion at September 30, 2002 and $3.6 billion at December 31, 2001, which were excluded from capitalized costs being amortized. These amounts represent costs associated with unevaluated properties and major development projects. At September 30, 2002 and December 31, 2001, the Company's investment in countries where reserves have not been established was $56 million and $53 million, respectively.

Total interest costs incurred during the third quarter of 2002 and 2001 were $91 million and $73 million, respectively. Of these amounts, the Company capitalized $42 million and $55 million during the third quarter of 2002 and 2001, respectively. Total interest costs incurred during the first nine months of 2002 and 2001 were $267 million and $222 million, respectively. Of these amounts, the Company capitalized $121 million and $157 million during the first nine months of 2002 and 2001, respectively. Capitalized interest is included as part of the cost of oil and gas properties. The interest rates for capitalization are based on the Company's weighted average cost of borrowings used to finance the expenditures applied to costs excluded that are under active evaluation.

In addition to capitalized interest, the Company also capitalized internal costs of $48 million and $43 million during the third quarter of 2002 and 2001, respectively. For the first nine months of 2002 and 2001, the Company capitalized internal costs of $148 million and $125 million, respectively. These internal costs were directly related to exploration and development activities and are included as part of the cost of oil and gas properties.

The Company limits, on a country-by-country basis, the capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, to the estimated future net cash flows from proved oil and gas reserves, generally using prices in effect at the end of the period held flat for the life of production, discounted at 10%, net of related tax effects, plus the cost of unevaluated properties and major development projects excluded from the costs being amortized. If capitalized costs exceed this limit, the excess is charged to expense.

As a result of low natural gas and oil prices at September 30, 2001, Anadarko's capitalized costs of oil and gas properties, primarily in the United States, Canada and Argentina, exceeded the ceiling limitation and the Company recorded a $2.5 billion ($1.6 billion after taxes) non-cash write-down in the third quarter of 2001. The pre-tax write-down is reflected as additional accumulated DD&A in the accompanying balance sheet.

5.  Debt     A summary of debt follows:

At September 30, 2002, $669 million of notes, debentures and securities will mature or may be put to Anadarko within the next twelve months. In accordance with SFAS No. 6, "Classification of Short-term Obligations Expected to be Refinanced," this amount is classified as long-term debt, since Anadarko has the intent and ability to refinance this debt under the terms of Anadarko's Bank Credit Agreements. At December 31, 2001, $1.16 billion of notes, debentures and securities would mature or could be put to Anadarko within the next twelve months. In accordance with SFAS No. 6, $750 million of this amount was classified as long-term debt, under the terms of Anadarko's Bank Credit Agreements. The remaining $412 million was classified as current liabilities.

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

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

In April 2002, Anadarko filed a shelf registration statement with the Securities and Exchange Commission that permits the issuance of up to $1 billion in debt securities, preferred stock, preferred securities, depositary shares, common stock, warrants, purchase contracts and purchase units. 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 September 2002, Anadarko issued $300 million principal amount of 5% Notes due 2012. The net proceeds from the issuance were used to reduce floating rate debt. These Notes were issued under the shelf registration statement filed in April 2002.

In October 2002, the Company entered into a 364-Day Revolving Credit Agreement. The agreement provides for $225 million principal amount and expires in 2003. Also in October 2002, Anadarko Canada Corporation, a wholly owned subsidiary of Anadarko, entered into a 364-Day Canadian Credit Agreement. The agreement provides for US$300 million principal amount and expires in 2003. The Canadian agreement is fully and unconditionally guaranteed by Anadarko. In addition, the Company has a Revolving Credit Agreement that provides for $225 million principal amount and expires in 2004.

Commodity Derivative Instruments     The Company is exposed to price risk from changing commodity prices. Management believes it is prudent to minimize the variability in cash flows on a portion of its oil and gas production. To meet this objective, the Company enters into various types of commodity derivative financial instruments to manage fluctuations in cash flows resulting from changing commodity prices. The Company also uses fixed price physical delivery sales contracts to accomplish this objective. The types of financial instruments utilized by the Company may include futures, swaps and options.

As of the end of October 2002, the Company has outstanding derivative financial instruments and fixed price physical delivery sales contracts that hedged 11% of the Company's natural gas production and 37% of its crude oil production, which is expected to be produced during the remainder of 2002. In addition, as of the end of October 2002, the Company has outstanding derivative financial instruments and fixed price physical delivery sales contracts that hedged 30% of the Company's natural gas production and 30% of its crude oil production, which is expected to be produced during 2003 and 22% of the Company's natural gas production and 3% of its crude oil production, which is expected to be produced during 2004.

Anadarko also enters into commodity derivative financial instruments (options, futures and swaps) for trading purposes with the objective of generating profits from exposure to changes in the market price of natural gas and crude oil. Commodity derivative financial instruments also provide a way to meet customers' pricing requirements while achieving a price structure consistent with the Company's overall pricing strategy. In addition, the Company uses swap agreements to reduce exposure to losses on its firm transportation keep-whole commitment with Duke Energy Field Services, Inc. (Duke). Essentially all of the derivatives used for trading purposes have a term of less than one year, with most having a term of less than three months.

Futures contracts are generally used to fix the price of expected future oil and gas sales at major industry trading locations; e.g., Henry Hub, Louisiana for gas and Cushing, Oklahoma for oil. Settlements of futures contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the International Petroleum Exchange and have nominal credit risk. Swap agreements are generally used to fix or float the price of oil and gas at the Company's market locations. Swap agreements are also used to fix the price differential between the price of gas at Henry Hub and various other market locations. Swap agreements expose the Company to credit risk to the extent the counterparty is unable to meet its monthly settlement commitment. The Company carefully monitors the creditworthiness of each counterparty. In addition, the Company routinely exercises its contractual right to net realized gains against realized losses in settling with its swap counterparties. Options are generally used to fix a floo r and/or a ceiling price (collar) for the Company's expected future oil and gas sales. The Company buys/sells options through exchanges as well as in the over the counter market.

Cash Flow Hedges     At September 30, 2002, the Company had option and swap contracts in place to fix floor and/or ceiling prices on a portion of expected future sales of equity gas and oil production. As of September 30, 2002, the Company had a net unrealized loss of $41 million before taxes (gains of $13 million and losses of $54 million), or $27 million after taxes, on derivative commodity instruments entered into to hedge equity production recorded in accumulated other comprehensive income compared to a net unrealized gain of $7 million before taxes (gains of $9 million and losses of $2 million), or $4 million after taxes at December 31, 2001. Other income for the three months ended September 30, 2002 and 2001 included $16 million and $1 million of net losses, respectively, and for the nine months ended September 30, 2002 and 2001 included $24 million of net losses and $26 million of net gains, respectively, primarily due to recognition of unrealized gai ns and losses on certain derivatives that did not qualify for hedge accounting and hedge ineffectiveness.

As of September 30, 2002 and December 31, 2001, the Company had the following volumes under derivative contracts related to its oil and gas producing activities (non-trading activity). The difference between the fair values in the table and the unrealized gain (loss) before income taxes recognized in accumulated other comprehensive income is due to premiums, recognition of unrealized gains and losses on certain derivatives that did not qualify for hedge accounting and hedge ineffectiveness.