Exhibit 99

ANADARKO PETROLEUM CORPORATION

INDEX

CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm		2
Statements of Income, Three Years Ended December 31, 2005		3
Balance Sheets, December 31, 2005 and 2004		4
Statements of Stockholders’ Equity, Three Years Ended December 31, 2005		5
Statements of Comprehensive Income, Three Years Ended December 31, 2005		6
Statements of Cash Flows, Three Years Ended December 31, 2005		7
Notes to Consolidated Financial Statements		8
Supplemental Information on Oil and Gas Exploration and Production Activities		42

1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Anadarko Petroleum Corporation:

      We have audited the accompanying consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, stockholders’ equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

      We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Anadarko Petroleum Corporation’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 2, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

March 2, 2006, except as to the first paragraph

        of Note 11 and Note 22, which are as of

        September 5, 2006

2

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31
	2005			2004		2003
millions except per share amounts
Revenues
Gas sales	$	2,968		$	2,583	$	2,183
Oil and condensate sales		2,703			2,022		1,621
Natural gas liquids sales		437			439		348
Other sales		79			80		94
Total		6,187			5,124		4,246
Costs and Expenses
Direct operating		437			522		467
Transportation and cost of product		275			216		166
General and administrative		393			373		370
Depreciation, depletion and amortization		1,111			1,132		1,033
Other taxes		358			292		277
Impairments		78			72		103
Total		2,652			2,607		2,416
Operating Income		3,535			2,517		1,830
Interest Expense and Other (Income) Expense
Interest expense		206			358		274
Other (income) expense		(76	)		59		(20	)
Total		130			417		254
Income from Continuing Operations Before Income Taxes		3,405			2,100		1,576
Income Tax Expense		1,332			799		684
Income from Continuing Operations		2,073			1,301		892
Income from Discontinued Operations, net of taxes		398			305		353
Net Income Before Cumulative Effect of Change in Accounting Principle		2,471		$	1,606	$	1,245
Preferred Stock Dividends		5			5		5
Net Income Available to Common Stockholders Before Cumulative Effect of Change in Accounting Principle	$	2,466		$	1,601	$	1,240
Cumulative Effect of Change in Accounting Principle		—			—		47
Net Income Available to Common Stockholders	$	2,466		$	1,601	$	1,287
Per Common Share
Income from Continuing Operations — basic	$	4.40		$	2.60	$	1.78
Income from Continuing Operations — diluted	$	4.36		$	2.58	$	1.76
Income from Discontinued Operations, net of taxes — basic	$	0.85		$	0.61	$	0.71
Income from Discontinued Operations, net of taxes — diluted	$	0.84		$	0.60	$	0.70
Net Income Before Cumulative Effect of Change in Accounting Principle — basic	$	5.24		$	3.21	$	2.49
Net Income Before Cumulative Effect of Change in Accounting Principle — diluted	$	5.19		$	3.18	$	2.45
Cumulative Effect of Change in Accounting Principle — basic	$	—		$	—	$	0.09
Cumulative Effect of Change in Accounting Principle — diluted	$	—		$	—	$	0.09
Net Income Available to Common Stockholders — basic	$	5.24		$	3.21	$	2.58
Net Income Available to Common Stockholders — diluted	$	5.19		$	3.18	$	2.55
Dividends	$	0.36		$	0.28	$	0.22
Average Number of Common Shares Outstanding — Basic		470			499		499
Average Number of Common Shares Outstanding — Diluted		475			503		507

See accompanying notes to consolidated financial statements.

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

		December 31
		2005			2004
millions
ASSETS
Current Assets
Cash and cash equivalents		$	561		$	348
Accounts receivable, net of allowance:
	Customers		1,109			862
	Others		562			292
Other current assets			207			153
Current assets held for sale			477			847
Total			2,916			2,502
Properties and Equipment
Original cost (includes unproved properties of $1,198 and $1,465 as of December 31, 2005 and 2004, respectively)			23,130			20,482
Less accumulated depreciation, depletion and amortization			7,935			6,919
Net properties and equipment — based on the full cost method of accounting for oil and gas properties			15,195			13,563
Other Assets			561			422
Goodwill			1,089			1,202
Long-Term Assets Held for Sale			2,827			2,503
Total Assets		$	22,588		$	20,192
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable		$	1,485		$	1,240
Accrued expenses			499			348
Current debt			80			169
Current liabilities associated with assets held for sale			339			236
Total			2,403			1,993
Long-term Debt			3,547			3,621
Other Long-term Liabilities
Deferred income taxes			3,993			3,628
Other			819			783
Long-term liabilities associated with assets held for sale			775			882
Total			5,587			5,293
Stockholders’ Equity
Preferred stock, par value $1.00 per share
	(2.0 million shares authorized, 0.1 million shares issued as of December 31, 2005 and 2004)		89			89
Common stock, par value $0.10 per share
	(450.0 million shares authorized, 266.3 million and 262.2 million shares issued as of December 31, 2005 and 2004, respectively)		27			26
Paid-in capital			6,063			5,741
Retained earnings			6,957			4,661
Treasury stock (34.4 million and 23.5 million shares as of December 31, 2005 and 2004, respectively)			(2,423	)		(1,476	)
Employee Stock Ownership Plan (0.1 million shares as of December 31, 2004)			—			(7	)
Executives and Directors Benefits Trust, at market value (2.0 million shares as of December 31, 2005 and 2004)			(189	)		(130	)
Accumulated other comprehensive income (loss):
	Unrealized loss on derivative instruments		(5	)		(23	)
	Foreign currency translation adjustments		549			482
	Minimum pension liability		(17	)		(78	)
	Total		527			381
Total			11,051			9,285
Commitments and Contingencies			—			—
Total Liabilities and Stockholders’ Equity		$	22,588		$	20,192

See accompanying notes to consolidated financial statements.

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Years Ended December 31
	2005			2004			2003
millions
Preferred Stock
Balance at beginning of year	$	89		$	89		$	101
Preferred stock repurchased		—			—			(12	)
Balance at end of year		89			89			89
Common Stock
Balance at beginning of year		26			26			25
Common stock issued		1			—			1
Balance at end of year		27			26			26
Paid-in Capital
Balance at beginning of year		5,741			5,453			5,326
Common stock issued		263			260			120
Revaluation to market for Executives and Directors Benefits Trust		59			28			7
Balance at end of year		6,063			5,741			5,453
Retained Earnings
Balance at beginning of year		4,661			3,199			2,021
Net income		2,471			1,606			1,292
Dividends paid — preferred		(5	)		(5	)		(5	)
Dividends paid — common		(170	)		(139	)		(109	)
Balance at end of year		6,957			4,661			3,199
Treasury Stock
Balance at beginning of year		(1,476	)		(166	)		(166	)
Purchase of treasury stock		(947	)		(1,310	)		—
Balance at end of year		(2,423	)		(1,476	)		(166	)
Employee Stock Ownership Plan
Balance at beginning of year		(7	)		(22	)		(42	)
Release of shares		7			15			20
Balance at end of year		—			(7	)		(22	)
Executives and Directors Benefits Trust
Balance at beginning of year		(130	)		(102	)		(95	)
Revaluation to market		(59	)		(28	)		(7	)
Balance at end of year		(189	)		(130	)		(102	)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of year		381			122			(198	)
Unrealized gain (loss) on derivative instruments		18			97			(35	)
Foreign currency translation adjustments		67			182			337
Minimum pension liability adjustments		61			(20	)		18
Balance at end of year		527			381			122
Total Stockholders’ Equity	$	11,051		$	9,285		$	8,599

See accompanying notes to consolidated financial statements.

5

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

		Years Ended December 31
		2005			2004			2003
millions
Net Income Available to Common Stockholders		$	2,466		$	1,601		$	1,287
Add: Preferred stock dividends			5			5			5
Net Income Available to Common Stockholders Before Preferred Stock Dividends			2,471			1,606			1,292
Other Comprehensive Income (Loss), Net of Income Taxes
Unrealized gains (losses) on derivative instruments:
	Unrealized losses during the period1		(126	)		(165	)		(154	)
	Reclassification adjustment for loss included in net income2		144			262			119
	Total unrealized gains (losses) on derivative instruments		18			97			(35	)
Foreign currency translation adjustments3			67			182			337
Minimum pension liability adjustments4			61			(20	)		18
Total			146			259			320
Comprehensive Income		$	2,617		$	1,865		$	1,612

1net of income tax benefit of:	$	73		$	96		$	91
2net of income tax expense of:		(82	)		(153	)		(67	)
3net of income tax expense of:		(9	)		(22	)		(59	)
4net of income tax benefit (expense) of:		(35	)		11			(11	)

See accompanying notes to consolidated financial statements.

6

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

			Years Ended December 31
			2005			2004			2003
millions
Cash Flow from Operating Activities
Net income before cumulative effect of change in accounting principle			$	2,471		$	1,606		$	1,245
Less income from discontinued operations, net of taxes				398			305			353
Adjustments to reconcile net income provided by operating activities:
	Depreciation, depletion and amortization			1,111			1,132			1,033
	Deferred income taxes			480			201			429
	Impairments			78			72			103
	Other noncash items			(33	)		69			52
	Changes in assets and liabilities:
		(Increase) decrease in accounts receivable		(515	)		(274	)		69
		Increase (decrease) in accounts payable and accrued expenses		357			323			(94	)
		Other items — net		(49	)		(81	)		(58	)
Cash provided by operating activities — continuing operations				3,502			2,743			2,426
Cash provided by operating activities — discontinued operations				644			464			617
Net cash provided by operating activities				4,146			3,207			3,043
Cash Flow from Investing Activities
Additions to properties and equipment				(2,918	)		(2,486	)		(2,274	)
Acquisition costs, net of cash acquired				—			(46	)		—
Sales of properties and equipment and other assets				160			2,087			106
Cash used in investing activities — continuing operations				(2,758	)		(445	)		(2,168	)
Cash (used in) provided by investing activities — discontinued operations				(495	)		408			(466	)
Net cash used in investing activities				(3,253	)		(37	)		(2,634	)
Cash Flow from Financing Activities
Additions to debt				4			18			356
Retirements of debt				(170	)		(1,188	)		(732	)
Increase (decrease) in accounts payable, banks				86			(43	)		51
Sale of future hard minerals royalty revenues				—			158			—
Dividends paid				(175	)		(144	)		(114	)
Purchase of treasury stock				(947	)		(1,310	)		—
Retirement of preferred stock				—			—			(12	)
Issuance of common stock				168			194			100
Cash used in financing activities — continuing operations				(1,034	)		(2,315	)		(351	)
Cash provided by (used in) financing activities — discontinued operations				3			(46	)		(40	)
Net cash used in financing activities				(1,031	)		(2,361	)		(391	)
Effect of Exchange Rate Changes on Cash
Discontinued operations				3			3			10
Net (Decrease) Increase in Cash and Cash Equivalents				(135	)		812			28
Cash and Cash Equivalents at Beginning of Period				874			62			34
Cash and Cash Equivalents at End of Period			$	739		$	874		$	62

See accompanying notes to consolidated financial statements.

7

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

1.  Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production and marketing of natural gas, crude oil, condensate and natural gas liquids (NGLs). The Company also engages in the hard minerals business through non-operated joint ventures and royalty arrangements in several coal, trona (natural soda ash) and industrial mineral mines. The terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its subsidiaries.

Discontinued Operations  Certain amounts have been reclassified to present the Company’s Canadian oil and gas business (Canadian operations) as discontinued operations. Unless otherwise indicated, information presented in the notes to the financial statements relates only to Anadarko’s continuing operations. Information related to discontinued operations is included in Note 22 and in some instances, where appropriate, is included as a separate disclosure within the individual footnotes.

Principles of Consolidation and Use of Estimates  The consolidated financial statements include the accounts of Anadarko and its subsidiaries. All significant intercompany transactions have been eliminated. The Company accounts for investments in affiliated companies (generally 20% to 50% owned) using the equity method of accounting. The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. Certain amounts for prior periods have been reclassified to conform to the current presentation. 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, fair values 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  Statement of Financial Accounting Standards (SFAS) No. 153, “Exchanges of Nonmonetary Assets,” requires the use of fair value measurement for exchanges of nonmonetary assets. The statement was effective for the Company beginning in the third quarter 2005 and applied prospectively for any nonmonetary exchanges occurring after the effective date. The adoption of SFAS No. 153 did not have a material impact on the Company’s financial statements.

      In September 2005, the Emerging Issues Task Force (EITF) concluded in Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” that purchases and sales of inventory with the same party in the same line of business should be accounted for as nonmonetary exchanges, if entered into in contemplation of one another. Anadarko presents purchase and sale activities related to its marketing and trading activities on a net basis in the income statement. The conclusion reached on EITF Issue No. 04-13 did not have an impact on the Company’s consolidated financial statements.

      Financial Accounting Standards Board (FASB) Staff Position (FSP) FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” provides guidance on the application of SFAS No. 109, “Accounting for Income Taxes,” to the tax deduction on qualified production as provided for in the American Jobs Creation Act of 2004 (Jobs Act). FSP FAS 109-1 provides that the deduction should be treated as a special deduction under the provisions of SFAS No. 109. The adoption of FSP FAS 109-1 did not have a material impact on the consolidated financial statements.

      FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004,” provides guidance on the application of SFAS No. 109 to the special one-time dividends received deduction on the repatriation of certain undistributed foreign earnings to a U.S. taxpayer as provided for in the Jobs Act. In 2005, Anadarko’s Chief Executive Officer and Board of Directors approved a domestic reinvestment plan for a $500 million repatriation of foreign earnings under the Jobs Act. The $26 million tax effect of this repatriation was recorded as current tax expense in 2005.

8

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

1.  Summary of Significant Accounting Policies (Continued)

      In 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires the fair value of a liability for an asset retirement obligation to be recorded in the period incurred and a corresponding increase in the carrying amount of the related long-lived asset. See Note 9.

      In 2003, the Company adopted the fair value method of accounting for stock-based employee compensation using the prospective method described in SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” The disclosure provisions of SFAS No. 148 were adopted in 2002. See Note 2.

      In 2003, the Company adopted SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” that requires additional disclosures about plan assets, obligations, cash flows and net periodic benefit cost of pension plans and other postretirement benefit plans. See Note 20.

Properties and Equipment  The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (SEC). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

      Operating fees received related to the properties in which the Company owns an interest are netted against expenses. Fees received in excess of costs incurred are recorded as a reduction to the full cost pool.

Costs Excluded  Properties and equipment include costs that are excluded from costs being depreciated or amortized. Oil and gas costs excluded represent investments in unproved properties and major development projects in which the Company owns a direct interest. These unproved property costs include nonproducing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. Anadarko excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (DD&A) pool) or a charge is made against earnings for those international operations where a reserve base has not yet been established. For international operations where a reserve base has not yet been established, an impairment requiring a charge to earnings may be indicated through evaluation of drilling results, relinquishing drilling rights or other information. Costs excluded for oil and gas properties are generally classified and evaluated as significant or individually insignificant properties.

      Significant properties, primarily comprised of costs associated with domestic offshore blocks, Alaska, the Land Grant and other international areas, are individually evaluated each quarter by the Company’s exploration and engineering staff. Nonproducing leases and geological and geophysical costs are transferred to the DD&A pool based on the progress of the Company’s exploration program. Exploration drilling costs are transferred to the DD&A pool upon the determination of whether proved reserves can be assigned to the properties, which is generally based on drilling results. The Company has a 10- to 12-year exploration and evaluation program for the Land Grant acreage. Costs are transferred to the DD&A pool as they are evaluated. The Land Grant’s mineral interests (both working and royalty interests) are owned by the Company in perpetuity.

      Insignificant properties are comprised primarily of costs associated with onshore properties in the United States. Nonproducing leases, along with related geological and geophysical costs, are transferred to the DD&A pool over a three- to five-year period based on the lease term. Exploration costs are transferred to the DD&A pool upon the determination of whether proved reserves can be assigned to the properties.

      Other costs excluded from depreciation represent major construction projects that are in progress.

Depreciation, Depletion and Amortization  The depreciable base for oil and gas properties includes the sum of capitalized costs net of accumulated DD&A, estimated future development costs and asset retirement costs not

9

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

1.  Summary of Significant Accounting Policies (Continued)

accrued in oil and gas properties, less costs excluded from amortization and salvage. The depreciable base of oil and gas properties and mineral investments are amortized using the unit-of-production method. All other properties are stated at original cost and depreciated using the straight-line method over the useful life of the assets, which ranges from three to 40 years. Properties and equipment carrying values do not purport to represent replacement or market values.

Capitalized Interest  Interest is capitalized as part of the historical cost of acquiring assets. Oil and gas investments in unproved properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready for service. Capitalized interest is calculated by multiplying the Company’s weighted-average interest rate on debt by the amount of qualifying costs. Capitalized interest cannot exceed gross interest expense. As oil and gas costs excluded are transferred to the DD&A pool, the associated capitalized interest is also transferred to the DD&A pool. As major construction projects are completed, the associated capitalized interest is amortized over the useful life of the asset with the underlying cost of the asset.

Ceiling Test  Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated DD&A and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, generally using prices in effect at the end of the period held flat for the life of production and including the effect of derivative instruments that qualify as cash flow hedges, 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 and reflected as additional accumulated DD&A. For cash flow hedge effect information, see Supplemental Information on Oil and Gas Exploration and Production Activities — Discounted Future Net Cash Flows.

Revenues  The Company recognizes sales revenues based on the amount of gas, oil, condensate and NGLs sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline or a tanker lifting has occurred. The Company follows the sales method of accounting for gas imbalances. If the Company’s excess sales of production volumes for a well exceed the estimated remaining recoverable reserves of the well, a liability is recorded. No receivables are recorded for those wells on which the Company has taken less than its ownership share of production.

      The Company enters into buy/sell arrangements for a portion of its crude oil production. Under these arrangements, barrels are sold at prevailing market prices at a location and in a simultaneous transaction with the same third party, barrels are re-purchased at a different location at the market prices prevailing at that location. The barrels are then sold at prevailing market prices at the re-purchase location. These arrangements are often a requirement of private transporters. In these transactions, the re-purchase price is more than the original sales price with the difference representing a transportation fee. Other buy/sell arrangements are entered to move the ultimate sales point of the Company’s production to a more liquid location and thereby avoid potential marketing fees and deductions from the market price in the field. In these transactions, the sales price in the field and the re-purchase price are each at prevailing market prices for the respective location. Anadarko uses these buy/sell arrangements in its marketing and trading activities and, as such, reports these transactions in the income statement on a net basis.

      Marketing margins related to the Company’s equity production, realized gains and losses on derivative instruments that receive cash flow hedge accounting treatment, unrealized gains and losses attributable to ineffectiveness of derivative instruments that receive cash flow hedge accounting treatment, and unrealized gains and losses on derivative instruments that were undertaken to manage the price risk of the Company’s production that do not receive cash flow hedge accounting treatment are included in gas sales, oil and condensate sales and NGLs sales. The marketing margin related to purchases of third-party commodities is included in other sales.

10

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

1.  Summary of Significant Accounting Policies (Continued)

Derivative Instruments  The majority of the derivative instruments utilized by Anadarko are in conjunction with its marketing and trading activities or to manage the price risk attributable to the Company’s expected oil and gas production. Anadarko also periodically utilizes derivatives to manage its exposure associated with the firm transportation keep-whole agreement, foreign currency exchange rates and interest rates. All derivatives, other than those that meet the normal purchases and sales exception, are carried on the balance sheet at fair value.

      Anadarko prefers to apply hedge accounting for derivatives utilized to manage price risk associated with the Company’s oil and gas production, foreign currency exchange rate risk and interest rate risk. However, some of these derivatives do not qualify for hedge accounting. In these instances, unrealized gains and losses are recognized currently in earnings. For those derivatives that qualify for hedge accounting, Anadarko formally documents the hedging relationship including the risk management objective and strategy for undertaking the hedge. Each hedge is also assessed for effectiveness quarterly. Under hedge accounting, the derivatives may be designated as a hedge of exposure to changes in fair values, cash flows or foreign currencies. If the hedge relates to the exposure of fair value changes to a recognized asset or liability or an unrecognized firm commitment, the unrealized gains and losses on the derivative and the unrealized gains and losses on the hedged item are both recognized currently in earnings. If the hedge relates to exposure of variability in the cash flow of a forecasted transaction, the effective portion of the unrealized gains and losses on the derivative is reported as a component of accumulated other comprehensive income and reclassified into earnings in the same period the hedged transaction is recorded. The ineffective portion of unrealized gains and losses attributable to cash flow hedges, if any, is recognized currently in gas sales and oil and condensate sales. Hedge ineffectiveness is that portion of the derivative’s unrealized gains and losses that exceed the hedged item’s unrealized gains and losses. In those instances where it becomes probable that a hedged forecasted transaction will not occur, the unrealized gain or loss is reclassified from accumulated other comprehensive income to earnings in the current period. Accounting for unrealized gains and losses attributable to foreign currency hedges that qualify for hedge accounting is dependent on whether the hedge is a fair value or a cash flow hedge.

      Unrealized gains and losses attributable to derivative instruments used in the Company’s marketing and trading activities (including both physical delivery and financially settled purchase and sale contracts), the firm transportation keep-whole agreement and derivatives used to manage the exposure of the keep-whole agreement are recognized currently in earnings. The marketing and trading unrealized gains and losses that are attributable to the Company’s production are recorded to gas sales and oil and condensate sales. The marketing and trading unrealized gains and losses that are attributable to third-party production are recorded to other sales. The gains and losses attributable to the firm transportation keep-whole agreement and associated derivatives are recorded to other (income) expense.

      The Company’s derivative instruments are either exchange traded or transacted in an over-the-counter market. Valuation is determined by reference to readily available public data. Option valuations are based on the Black-Scholes option pricing model and verified against third-party quotations. The fair value of the short-term portion of the firm transportation keep-whole agreement is calculated based on quoted natural gas basis differentials, while the fair value of the long-term portion is estimated based on an internally developed model that utilizes historical natural gas basis differentials. See Note 7.

Inventories  Materials and supplies and commodity inventories are stated at the lower of average cost or market and removed at carrying value.

Goodwill  Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in previous mergers and acquisitions. The Company assesses the carrying amount of goodwill by testing the goodwill for impairment annually and upon certain events. 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 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 the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Anadarko’s goodwill relates to its oil and gas reporting unit.

11

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

1.  Summary of Significant Accounting Policies (Continued)

      Goodwill impairment tests were performed annually as well as upon the Company’s property divestitures in 2004, and no goodwill impairments were indicated. The change in goodwill in 2005 was primarily due to the adjustment of deferred income tax liabilities related to previous acquisitions. Goodwill of $107 million was allocated to the Canadian operations and has been included in Long-Term Assets Held for Sale on the consolidated balance sheet. Future changes in goodwill may result from, among other things, changes in foreign currency exchange rates, changes in deferred income tax liabilities related to previous acquisitions, divestitures, impairments or future acquisitions. See Note 18.

Legal Contingencies  The Company is subject to legal proceedings, claims and liabilities which arise in the ordinary course of its business. The Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as further information develops or circumstances change. See Note 21.

Environmental Contingencies  The Company accrues for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the time of the completion of the remediation feasibility study. These accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. See Note 21.

Income Taxes  The Company files various United States federal, state and foreign income tax returns. Deferred federal, state and foreign income taxes are provided on all significant temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.

Cash Equivalents  The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Stock-Based Compensation  Effective January 2003, the Company accounts for stock-based compensation under the fair value method. Under the fair value method, the Company records compensation expense over the vesting period using the straight-line method. The Company grants various types of stock-based awards including stock options, nonvested equity shares and performance-based equity units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Nonvested equity-share awards are valued using the market price on grant date. For performance-based stock awards, the fair value of the market condition portion of the award is measured using a Monte Carlo simulation and the performance condition portion of the award is measured at the market price of the Company’s common stock on the grant date. If the requisite service period is not satisfied, compensation expense is reversed. If the requisite service period is satisfied, expense is not adjusted unless the award contains a performance condition. If an award contains a performance condition, expense is recognized only for those shares that ultimately vest using the fair value per share measured at grant date. See Notes 2 and 11.

Earnings Per Share  The Company’s basic earnings per share (EPS) amounts have been computed based on the average number of shares of common stock outstanding for the period. Diluted EPS amounts include the effect of the Company’s outstanding stock options and performance-based stock awards under the treasury stock method if including such potential shares of common stock is dilutive. Diluted EPS amounts also include the net effect of the Company’s convertible debentures in 2003 and Zero Yield Puttable Contingent Debt Securities (ZYP-CODES) assuming the conversions occurred at the beginning of the year through the period outstanding, if including such potential common shares is dilutive. See Note 11.

New Accounting Principles  SFAS No. 123 (revised 2004), “Share-Based Payment,” requires the recognition of expense for the fair value of share-based payments. The statement is effective for the Company beginning January 1, 2006. The Company adopted the fair value method of accounting for share-based payments effective January 1, 2003, using the “modified prospective method” described in SFAS No. 148. For 2005, 2004 and 2003,

12

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

1.  Summary of Significant Accounting Policies (Continued)

the Company used the Black-Scholes option pricing model to estimate the value of stock options granted to employees. Anadarko expects to continue to use this acceptable option pricing model upon the required adoption of SFAS No. 123(R) on January 1, 2006. The Company does not anticipate that the adoption of SFAS No. 123(R) will have a material impact on its results of operations or its financial position. Certain amounts attributable to the benefits of tax deductions in excess of recognized compensation in the financial statements that have been previously reported in the statement of cash flow as operating activities — other items net — will be reported as financing activities since they relate to the issuance of common stock. These amounts were $53 million, $36 million and $1 million in 2005, 2004 and 2003, respectively.

2.  Stock-Based Compensation

      For share-based awards granted or modified after January 2003, the Company uses the fair value method of accounting for stock-based employee compensation expense. For share-based awards granted prior to 2003, Anadarko applies the intrinsic value method whereby no compensation expense is recognized for stock options granted with an exercise price equal to the market value of Anadarko common stock on the date of grant.

      All share and price per share information presented has been restated to give retroactive effect to the May 2006 two-for-one stock split which was effected in the form of a stock dividend. See Note 11. If compensation expense for all stock option grants had been determined using the fair value method, the Company’s pro forma net income and EPS would have been as shown below:

	2005			2004			2003
millions except per share amounts
Net income available to common stockholders, as reported	$	2,466		$	1,601		$	1,287
Add: Stock-based employee compensation expense included in income, after income taxes		20			14			12
Deduct: Total stock-based employee compensation expense determined under the fair value method, after income taxes		(21	)		(18	)		(30	)
Pro forma net income available to common stockholders	$	2,465		$	1,597		$	1,269
Basic EPS - as reported	$	5.24		$	3.21		$	2.58
Basic EPS - pro forma	$	5.24		$	3.20		$	2.54
Diluted EPS - as reported	$	5.19		$	3.18		$	2.55
Diluted EPS - pro forma	$	5.19		$	3.17		$	2.51

      The fair value of each option grant was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions:

	2005			2004			2003
Expected option life – years		5.4			5.2			5.3
Risk-free interest rate		4.5	%		3.5	%		3.3	%
Dividend yield		0.7	%		0.6	%		0.6	%
Volatility		29.6	%		33.6	%		40.4	%

3.  Divestitures

      Anadarko announced a refocused strategy in June 2004 that included the divestiture of certain properties. During 2004, the Company completed over $3 billion in pretax asset sales in the United States and Canada through a series of separate unrelated transactions with various third parties. The properties divested were primarily located in the shallow waters of the Gulf of Mexico, the Western Canadian Sedimentary basin and the mid-continent region of the United States.

13

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

3.  Divestitures (Continued)

      Under full cost accounting rules, gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The dispositions did not significantly alter the relationship between capitalized costs and proved reserves; therefore, the proceeds from these transactions were recognized as an adjustment of capitalized costs in the respective country cost centers.

4.  Inventories

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

	2005		2004
millions
Materials and supplies	$	90	$	66
Natural gas		18		12
Crude oil and NGLs		24		28
Total	$	132	$	106

      The above table excludes $49 million and $31 million as of December 31, 2005 and 2004, respectively, of inventories relating to our Canadian operations which are included in Current Assets Held for Sale.

5.  Properties and Equipment

      A summary of the original cost of properties and equipment by classification follows:

	2005		2004
millions
Oil and gas	$	20,886	$	18,324
Minerals		1,208		1,208
Marketing and trading		516		454
General		520		496
Total	$	23,130	$	20,482

      Oil and gas properties include costs of $1.2 billion and $1.5 billion at December 31, 2005 and 2004, respectively, which were excluded from capitalized costs being amortized. These amounts represent costs associated with unproved properties and major development projects in which the Company owns a direct interest. At December 31, 2005 and 2004, the Company’s investment in countries where proved reserves have not been established was $107 million and $116 million, respectively.

      During 2005, 2004 and 2003, the Company made provisions for impairments of oil and gas properties of $78 million, $72 million and $103 million, respectively. The impairments in 2005 include $35 million related to unsuccessful exploration activities in Tunisia, $30 million related to exploration activities at various international locations and $13 million related to the disposition of properties in Oman. The impairments in 2004 and 2003 included ceiling test impairments of oil and gas properties in Qatar of $62 million and $68 million, respectively, as a result of lower future production estimates and other international exploration activities.

      Total interest costs incurred during 2005, 2004 and 2003 were $266 million, $428 million and $366 million, respectively. Of these amounts, the Company capitalized $60 million, $70 million and $92 million during 2005, 2004 and 2003, respectively, as part of the cost of 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 on which exploration, development and construction activities are in progress.

      Properties and equipment include internal costs related to exploration, development and construction activities of $143 million, $144 million and $165 million capitalized during 2005, 2004 and 2003, respectively.

14

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

6.  Debt and Interest Expense

	2005				2004
	Principal		Carrying Value		Principal		Carrying Value
millions
Debt
6.5% Notes due 2005	$	—	$	—	$	170	$	169
7% Notes due 2006		51		50		51		50
53/8% Notes due 2007		142		142		142		142
3.25% Notes due 2008		350		350		350		349
6.75% Notes due 2008		47		46		47		45
7.3% Notes due 2009		52		51		52		51
63/4% Notes due 2011		950		917		950		913
61/8% Notes due 2012		170		168		170		168
5% Notes due 2012		82		81		82		81
7.05% Debentures due 2018		114		106		114		106
Zero Yield Puttable Contingent Debt Securities due 2021		30		30		30		30
7.5% Debentures due 2026		112		106		112		106
7% Debentures due 2027		54		54		54		54
6.625% Debentures due 2028		17		17		17		17
7.15% Debentures due 2028		235		213		235		213
7.20% Debentures due 2029		135		135		135		135
7.95% Debentures due 2029		117		117		117		117
71/2% Notes due 2031		900		862		900		862
7.73% Debentures due 2096		61		61		61		61
7.5% Debentures due 2096		78		72		78		72
71/4% Debentures due 2096		49		49		49		49
Total debt	$	3,746		3,627	$	3,916		3,790
Less current debt				80				169
Total long-term debt			$	3,547			$	3,621

      As of December 31, 2005, current debt represents $51 million principal amount of notes and debentures due in 2006 and $30 million principal amount of ZYP-CODES due 2021 that may be put to the Company in March 2006 at the option of the holders. None of the Company’s notes, debentures or securities contain ratings triggers accelerating the debt or requiring repayment. All of the Company’s debt is senior unsecured debt; therefore, all debt has equal priority with respect to the payment of both principal and interest.

      The unamortized debt discount of $119 million and $126 million as of December 31, 2005 and 2004, respectively, will be amortized over the terms of the debt issues.

      The Company has commercial paper programs that allow Anadarko to borrow funds, at rates as offered, by issuing notes to investors for terms of up to one year.

      In May 2005, the Company redeemed for cash $170 million principal amount of 6.5% Notes. In July, September and October 2004, Anadarko repurchased $1.2 billion aggregate principal amount of certain series of its outstanding debt. Premiums and related expenses for these early retirements of debt totaled $104 million and were recorded as interest expense. The Company used proceeds from asset divestitures to fund the debt reductions.

15

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

6.  Debt and Interest Expense (Continued)

      In September 2004, the Company entered into a $750 million, five-year Revolving Credit Agreement with a syndicate of 20 U.S. and Canadian lenders. Under the terms of the agreement, the Company can, under certain conditions, request an increase in the agreement up to a total available credit amount of $1.25 billion. The credit agreement has a maximum 60% debt to capital covenant (not affected by noncash charges), and there are no material adverse change covenants nor any ratings triggers in the agreement preventing funding or requiring repayment. The agreement terminates in August 2009. As of December 31, 2005, the Company had no outstanding borrowings under this agreement; however, outstanding letters of credit on the agreement have reduced the available credit amount by less than $1 million.

      In May 2003, the Company issued $350 million principal amount of 3.25% Notes due 2008. The net proceeds from this issuance were used to reduce floating rate debt that was incurred in April 2003 to redeem the Zero Coupon Convertible Debentures due 2020. In April 2003, Anadarko redeemed for cash its callable Zero Coupon Convertible Debentures due 2020. Anadarko funded the $384 million redemption with available credit facilities that carried a lower effective interest rate.

      At December 31, 2005 and 2004, a Canadian subsidiary had outstanding $50 million of fixed-rate notes and debentures denominated in U.S. dollars. During 2005, 2004 and 2003, the Company recognized gains of $2 million, $4 million and $20 million, respectively, before income taxes associated with the foreign currency remeasurement of this debt.

      In April and May 2001, Anadarko Finance Company, a wholly owned finance subsidiary of Anadarko, issued a total of $1.9 billion in notes. The intercompany debt resulting from these transactions is of a long-term investment nature; therefore, net foreign currency translation gains of $63 million, $138 million and $376 million for 2005, 2004 and 2003, respectively, were recorded as a component of other comprehensive income.

	2005			2004			2003
millions
Interest Expense
Gross interest expense	$	266		$	328		$	358
Premium and related expenses for early retirement of debt		—			100			8
Capitalized interest		(60	)		(70	)		(92	)
Net interest expense	$	206		$	358		$	274

      Total sinking fund and installment payments related to debt for the five years ending December 31, 2010 are shown below.

millions
2006	$	81
2007		142
2008		397
2009		52
2010		—

      The above table excludes $50 million related to discontinued operations.

16

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

7.  Financial Instruments

      The following information provides the carrying value and estimated fair value of the Company’s financial instruments:

		Carrying
		Amount			Fair Value
millions
2005
Cash and cash equivalents		$	561		$	561
Total debt			3,627			4,213
Derivative instruments (including firm transportation keep-whole agreement)
	Asset		93			93
	Liability		(134	)		(134	)
2004
Cash and cash equivalents		$	348		$	348
Total debt			3,790			4,472
Derivative instruments (including firm transportation keep-whole agreement)
	Asset		43			43
	Liability		(159	)		(159	)

Cash and Cash Equivalents  The carrying amount reported on the balance sheet approximates fair value.

Debt  The fair value of debt at December 31, 2005 and 2004 is the value the Company would have to pay to retire the debt, including any premium or discount to the debt holder for the differential between stated interest rate and year-end market rate. The fair values are based on quoted market prices and, where such quotes were not available, on the average rate in effect at year-end.

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

      Anadarko also enters into derivative financial instruments (futures, swaps and options) and physical delivery contracts for trading purposes with the objective of generating profits from exposure to changes in the market price of natural gas and crude oil. Derivative financial instruments are also used to meet customers’ pricing requirements while achieving a price structure consistent with the Company’s overall pricing strategy. In addition, the Company may use options and swaps to reduce exposure on its firm transportation keep-whole commitment with Duke Energy Corporation (Duke).

      Futures contracts are generally used to fix the price of expected future gas sales and oil sales at major industry trading locations; e.g., Henry Hub, Louisiana for gas and Cushing, Oklahoma for oil. Swap agreements are generally used to fix or float the price of oil and gas at major trading locations. Basis swaps are used to fix or float the price differential between the price of gas at Henry Hub and various other market locations. Physical delivery purchase and sale agreements require the receipt or delivery of physical product at a specified location and price. The pricing can be fixed or market-based. Options are generally used to fix a floor and a ceiling price (collar) for expected future gas sales and oil sales. Settlements of futures contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the International Petroleum Exchange and have nominal credit risk. Swap, over-the-counter traded option and physical delivery agreements expose the Company to credit risk to

17

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

7.  Financial Instruments (Continued)

the extent the counterparty is unable to meet its settlement commitment. The Company monitors the creditworthiness of each counterparty and assesses the impact, if any, on fair valuation and hedge accounting criteria. In addition, the Company routinely exercises its contractual right to net realized gains against realized losses in settling with its swap and option counterparties.

Oil and Gas Activities  At December 31, 2005 and 2004, the Company had option contracts, swap contracts and fixed price physical delivery contracts in place to hedge the sales price of a portion of its expected future sales of equity oil and gas production (non-trading activities). The fixed price physical delivery contracts are excluded from derivative accounting treatment under the normal sale provision. The derivative financial instruments receive hedge accounting treatment if they qualify and are so designated. For those derivatives that do not qualify for hedge accounting, unrealized gains and losses are recognized currently in oil and gas revenues.

      The fair value and the accumulated other comprehensive income balance applicable to the derivative financial instruments (excluding the physical delivery sales contracts) are as follows:

		2005			2004
millions
Fair Value — Asset (Liability)
	Current	$	(28	)	$	(58	)
	Long-term	$	(25	)		(12	)
	Total	$	(53	)	$	(70	)
Accumulated other comprehensive loss before income taxes		$	(8	)	$	(35	)
Accumulated other comprehensive loss after income taxes		$	(5	)	$	(22	)

      The difference between the fair value and the unrealized loss before income taxes recognized in accumulated other comprehensive income is due to premiums, recognition of unrealized gains and losses on derivatives that did not qualify for hedge accounting and hedge ineffectiveness. The net losses of $8 million ($5 million after income taxes) in the accumulated other comprehensive income balance as of December 31, 2005 are expected to be reclassified into gas and oil sales beyond 2006 as the hedged transactions occur.

      Gains attributable to cash flow hedge ineffectiveness of $10 million and $12 million were recognized in revenue during 2005 and 2004, respectively. During 2005 and 2004, net unrealized losses of zero and $22 million, respectively, (before income taxes) were reclassified from accumulated other comprehensive income to gas and oil sales for certain cash flow hedges of expected future years production for which hedge accounting was discontinued since the expected production was probable of not occurring due to either property divestitures or well performance.

18

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

7.  Financial Instruments (Continued)

      Below is a summary of the Company’s financial derivative instruments and fixed price physical delivery sales contracts related to its oil and gas activities (non-trading) as of December 31, 2005, including the hedged volumes per day and the related weighted-average prices. The natural gas prices are NYMEX Henry Hub. The crude oil prices are a combination of NYMEX Cushing and Brent Dated. Cash flow hedges on natural gas beyond 2006 and on crude oil beyond 2011 are not significant.

				Hedge Accounting
		2006		Applied
Natural Gas
Two-Way Collars (thousand MMBtu/d)			10		No
Price per MMBtu
	Ceiling sold price	$	5.88
	Floor purchased price	$	4.00

   MMBtu — million British thermal units

   MMBtu/d — million British thermal units per day

				Five Year
				Average		Hedge Accounting
		2006		2007-2011		Applied
Crude Oil
Two-Way Collars (MBbls/d)			1		—		No
Price per barrel
	Ceiling sold price	$	26.32	$	—
	Floor purchased price	$	22.00	$	—
Three-Way Collars (MBbls/d)			—		9		Yes
Price per barrel
	Ceiling sold price	$	—	$	85.43
	Floor purchased price	$	—	$	49.46
	Floor sold price	$	—	$	34.46
Total (MBbls/d)			1		9

   MBbls/d — thousand barrels per day

      A two-way collar is a combination of options, a sold call and a purchased put. The sold call establishes a maximum price (ceiling) and the purchased put establishes a minimum price (floor) the Company will receive for the volumes under contract. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The sold call establishes a maximum price the Company will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX) plus the difference between the purchased put and the sold put strike price. The fixed price hedges consist of swaps and physical delivery contracts and establish a fixed price the Company will receive for the volumes under contract.

19

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

7.  Financial Instruments (Continued)

Marketing and Trading Activities  Unrealized gains and losses attributed to the Company’s marketing and trading derivative instruments (both physically and financially settled) are recognized currently in earnings. The fair values of these derivatives as of December 31, 2005 and 2004 are as follows:

		2005		2004
millions
Fair Value — Asset (Liability)
	Current	$	1	$	5
	Long-term		2		2
	Total	$	3	$	7

Firm Transportation Keep-Whole Agreement A company Anadarko acquired in 2000 was a party to several long-term firm gas transportation agreements that supported its gas marketing program within its gathering, processing and marketing (GPM) business segment, which was sold in 1999 to Duke. Most of these agreements were transferred to Duke in the GPM disposition. One agreement was retained, but is managed and operated by Duke. Anadarko is not responsible for the operations of any of the contracts and does not utilize the associated transportation assets to transport the Company’s natural gas. As part of the GPM disposition, Anadarko pays Duke if transportation market values fall below the fixed contract transportation rates, while Duke pays Anadarko if the transportation market values exceed the contract transportation rates (keep-whole agreement). The term of the agreement extends through February 2009.

      The Company may periodically use derivative instruments to reduce its exposure to potential decreases in future transportation market values. While derivatives are intended to reduce the Company’s exposure to declines in the market value of firm transportation, they also limit the potential to benefit from increases in the market value of firm transportation. Due to decreased liquidity, the use of derivative instruments to manage this risk is generally limited to the forward 12 months. Unrealized gains and losses attributed to the keep-whole agreement and any associated derivative instruments are recognized currently in earnings.

      The fair value of the short-term portion of the firm transportation keep-whole agreement is calculated based on quoted natural gas basis differentials. Basis differentials are the difference in value between gas at various delivery points and the NYMEX gas futures contract price. Management believes that natural gas basis price differential quotes beyond the next 12 months are not reliable indicators of fair value due to decreasing liquidity. Accordingly, the fair value of the long-term portion is estimated based on historical regional natural gas basis differentials. The Company recognized other income of $56 million, $1 million and $9 million during 2005, 2004 and 2003, respectively, related to the keep-whole agreement and associated derivative instruments. Net (payments to) receipts from Duke for 2005 and 2004 were $1 million and $(20) million, respectively. As of December 31, 2005, other current assets included $30 million and other long-term liabilities included $22 million related to the keep-whole agreement and associated derivative instruments. As of December 31, 2004, accounts payable included $15 million and other long-term liabilities included $39 million related to the keep-whole agreement and associated derivative instruments.

      As of December 31, 2005 and 2004, the Company’s derivative financial instruments related to the firm transportation keep-whole agreement were insignificant.

20

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

7.  Financial Instruments (Continued)

Foreign Currency Risk  The Company has Canadian subsidiaries that use the Canadian dollar as their functional currency. The Company’s other international subsidiaries use the U.S. dollar as their functional currency. To the extent that business transactions in these countries are not denominated in the respective country’s functional currency, the Company is exposed to foreign currency exchange rate risk. In addition, in these subsidiaries, certain asset and liability balances are denominated in currencies other than the subsidiary’s functional currency. These asset and liability balances are remeasured for the preparation of the subsidiary’s financial statements using a combination of current and historical exchange rates, with any resulting remeasurement adjustments included in net income during the period.

8. Sale of Future Hard Minerals Royalty Revenues

      In 2004, the Company entered into an agreement whereby it sold a portion of its future royalties associated with existing coal and trona leases to a third party for $158 million, net of transaction costs. The Company conveyed a limited-term nonparticipating royalty interest, which was carved out of the Company’s royalty interests, that entitles the third party to receive up to $229 million in future coal and trona royalty revenue over an 11-year period. Additionally, the third party is entitled to receive 5% of the aggregate royalties earned during the first ten years of the agreement that exceed $400 million. The Company retains 100% of the aggregate royalty payment receipts between $229 million and $400 million during the term of the agreement and 95% of the aggregate royalty payment receipts that are in excess of $400 million during the first ten years of the agreement. The third party relies solely on the royalty payments to recover their investment and, as such, has the risk of the royalties not being sufficient to recover their investment over the term of the agreement.

      Proceeds from this 2004 transaction were accounted for as deferred revenues, classified as liabilities on the balance sheet and reported as a financing activity in the statement of cash flows. The deferred revenues are amortized to other sales on a unit-of-revenue basis over the term of the agreement. During 2005 and 2004, the Company amortized $16 million and $10 million, respectively, of deferred revenues to other sales revenues related to this agreement. Proceeds from the transaction are reported in financing activities in the statement of cash flows and were primarily used to repurchase shares of Anadarko common stock.

      The specified future amounts that the third-party investor expects to receive, prior to the 5% of any excess described above, are shown below. These amounts and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the agreement.

millions
2006	$	24
2007		24
2008		24
2009		24
2010		24
Later years		74
Total	$	194

21

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

9.  Asset Retirement Obligations

      The majority of Anadarko’s asset retirement obligations relate to the plugging and abandonment of oil and gas properties. In 2003, the Company adopted SFAS No. 143 which requires the fair value of a liability for an asset retirement obligation to be recorded in the period incurred with a corresponding increase in the carrying amount of the related long-lived asset. The related cumulative effect adjustment to 2003 net income was an increase of $74 million before income taxes or $47 million after income taxes, or $0.09 per share (diluted). Additionally in 2003, the Company recorded an initial asset retirement obligation liability of $278 million and an increase to net properties and equipment and other assets of $352 million. The Company did not recalculate historical quarterly full cost ceiling test calculations in determining the cumulative effect adjustment to net income. Excluding the cumulative effect adjustment to net income, the application of SFAS No. 143 did not have a material impact on the Company’s DD&A expense, net income or EPS in 2003.

      The asset retirement obligations are recorded at fair value and accretion expense, recognized in DD&A expense over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.

      The following table shows changes in the Company’s asset retirement obligations. Liabilities settled in 2004 include asset retirement obligations that were assumed by the purchasers of divested properties. Revisions in estimated liabilities include, among other things, revisions to estimated property lives and the timing of settling asset retirement obligations.

	2005			2004
millions
Carrying amount of asset retirement obligations at beginning of year	$	210		$	477
Liabilities incurred		56			37
Liabilities settled		(10	)		(285	)
Accretion expense		15			25
Revisions in estimated liabilities		(19	)		(51	)
Impact of foreign currency exchange rate changes		1			7
Carrying amount of asset retirement obligations at end of year	$	253		$	210

      As of December 31, 2005 and 2004, the asset retirement obligations related to discontinued operations included in the table above is $32 million and $27 million, respectively.

10.  Preferred Stock

      Anadarko has $89 million of 5.46% Series B Cumulative Preferred Stock issued in the form of 0.89 million Depositary Shares, each Depositary Share representing 1/10th of a share of the 5.46% Series B Cumulative Preferred Stock. The preferred stock has no stated maturity and is not subject to a sinking fund or mandatory redemption. The shares are not convertible into other securities of the Company.

      Anadarko has the option to redeem the shares at $100 per Depositary Share on or after May 15, 2008. Holders of the shares are entitled to receive, when, and as declared by the Board of Directors, cumulative cash dividends at an annual dividend rate of $5.46 per Depositary Share. In the event of a liquidation of the Company, the holders of the shares will be entitled to receive liquidating distributions in the amount of $100 per Depositary Share, for a total of $89 million, plus any accrued or unpaid dividends, before any distributions are made on the Company’s common stock.

      Anadarko repurchased $12 million of preferred stock during 2003. No gain or loss was recorded in 2003 related to the preferred stock repurchases. For each of the years 2005, 2004 and 2003, dividends of $54.60 per share (equivalent to $5.46 per Depositary Share) were paid to holders of preferred stock.

22

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

11.  Common Stock and Stock Options

      In May 2006, the Company’s shareholders approved a two-for-one stock split to be effected in the form of a stock dividend. The distribution date was May 26, 2006 to stockholders of record on May 12, 2006. Except for the presentation of common shares authorized and issued on the consolidated balance sheet and shares presented in the table below, all share and per share information has been restated to give retroactive effect to the stock split.

      The changes in the Company’s shares of common stock are as follows:

	2005		2004			2003
millions
Shares of common stock issued
Beginning of year		262		257			255
Exercise of stock options		4		5			2
End of year		266		262			257
Shares of common stock held in treasury
Beginning of year		23		3			3
Purchase of treasury stock		11		20			—
End of year		34		23			3
Shares of common stock held for Employee Stock Ownership Plan
Beginning of year		—		1			1
Release of Shares		—		(1	)		—
End of year		—		—			1
Shares of common stock held for Executives and Directors Benefits Trust
Beginning of year		2		2			2
End of year		2		2			2
Shares of common stock outstanding at end of year		230		237			251

      The following activities and balances include amounts associated with Canadian operations which have been presented as discontinued operations.

      In each quarter of 2005, dividends of nine cents per share were paid to holders of common stock. In each quarter of 2004 and in the fourth quarter of 2003, dividends of seven cents per share were paid to holders of common stock. For the first, second and third quarters of 2003, dividends of five cents per share were paid to holders of common stock. The covenants in the Company’s credit agreement provide for a maximum capitalization ratio of 60% debt, exclusive of the effect of any noncash writedowns. Retained earnings were not restricted as to the payment of dividends at December 31, 2005 and 2004.

      Under the Anadarko Stockholders Rights Plan, Rights were attached automatically to each outstanding share of common stock in 1998. Each Right, at the time it becomes exercisable and transferable apart from the common stock, entitles stockholders to purchase from the Company 1/1000th of a share of a new series of junior participating preferred stock at an exercise price of $175. The Right will be exercisable only if a person or group acquires 15% or more of Anadarko common stock or announces a tender offer or exchange offer, the consummation of which would result in ownership by a person or group of 15% or more of Anadarko common stock. The Board of Directors may elect to exchange and redeem the Rights. The Rights expire in 2008.

      During 2005, a $2 billion stock buyback program announced in 2004 was completed and an additional $1 billion stock buyback program was authorized. Shares may be repurchased either in the open market or through privately negotiated transactions. The repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. During 2005 and 2004, Anadarko purchased 10.8 million and 20.3 million shares (pre-split) of common stock for $0.9 billion and $1.3 billion, respectively, under these programs through purchases in the open market, under share repurchase agreements or in connection with put option agreements.

23

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

11.  Common Stock and Stock Options (Continued)

      As of December 31, 2005 and 2004, the Company had 4 million shares of common stock in the Anadarko Petroleum Corporation Executives and Directors Benefits Trust (Trust) to secure present and future unfunded benefit obligations of the Company. These obligations are provided for under pension plans and deferred compensation plans for certain employees and nonemployee directors of the Company. The obligations recorded in other long-term liabilities — other are $34 million and $25 million as of December 31, 2005 and 2004, respectively. The shares issued to the Trust are not considered outstanding for quorum or voting calculations and are not included in the calculation of EPS. The fair market value of these shares is included in common stock and paid-in capital and as a reduction to stockholders’ equity. See Note 20.

      Certain employees may be granted options to purchase shares of Anadarko common stock and other stock related awards under the 1999 Stock Incentive Plan. Stock options are generally granted at the fair market value of Anadarko common stock on the date of grant and have a maximum term of seven years from the date of grant. Stock option vesting terms range from one to four years.

      Nonemployee directors may be granted nonqualified stock options under the 1998 Director Stock Plan. Stock options are granted at the fair market value of Anadarko common stock on the date of grant and have a maximum term of ten years from the date of grant. Stock option vesting terms range from the date of grant up to two years.

      Unexercised stock options are included in the diluted EPS using the treasury stock method. Information regarding the Company’s stock option plans is summarized below:

	2005					2004					2003
				Weighted-					Weighted-					Weighted-
				Average					Average					Average
				Exercise					Exercise					Exercise
	Shares			Price		Shares			Price		Shares			Price
option shares in millions
Shares under option at beginning of year		16.3		$	23.09		25.2		$	21.64		30.7		$	21.34
Granted		0.9		$	43.85		1.1		$	30.97		2.1		$	21.65
Exercised		(7.5	)	$	22.26		(9.9	)	$	20.20		(4.3	)	$	17.91
Surrendered or expired		(0.1	)	$	28.88		(0.1	)	$	24.24		(3.3	)	$	23.78
Shares under option at end of year		9.6		$	25.57		16.3		$	23.09		25.2		$	21.64
Options exercisable at December 31		7.0		$	23.32		13.0		$	22.45		19.0		$	21.41
Shares available for future grant at end of year		16.4					3.0					4.3
Weighted-average fair value of options granted during the year				$	14.43				$	11.48				$	8.91

24

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

11.  Common Stock and Stock Options (Continued)

      The following table summarizes information about the Company’s stock options outstanding at December 31, 2005:

	Options Outstanding						Options Exercisable
			Weighted-
	Options		Average		Weighted-		Options		Weighted-
Range of	Outstanding		Remaining		Average		Exercisable		Average
Exercise	at Year		Contractual		Exercise		at Year		Exercise
Prices	End		Life (Years)		Price		End		Price
options in millions
$15.02 - 21.13		1.6		1.9	$	17.53		1.3	$	16.90
$21.45 - 24.22		2.1		5.4	$	22.35		1.3	$	22.29
$24.27 - 24.27		3.4		1.5	$	24.27		3.4	$	24.27
$24.50 - 48.13		2.5		5.5	$	35.21		1.0	$	30.22
Total		9.6		3.5	$	25.57		7.0	$	23.32

      In addition, the Plans provide that shares of common stock may be granted to certain employees and nonemployee directors as restricted stock. Generally, restricted stock is subject to forfeiture restrictions and cannot be sold, transferred or disposed of during the restriction period. The holders of the restricted stock have all the rights of a stockholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to such shares. During 2005, 2004 and 2003, the Company granted 1.9 million, 0.5 million and 2.1 million shares, respectively, of restricted stock with a weighted-average grant date fair value of $42.38, $32.06 and $21.82 per share, respectively. In 2005, 2004 and 2003, expense related to restricted stock grants was $20 million, $11 million and $12 million, respectively.

      Anadarko and key officers of the Company have two Performance Unit Agreements with three-year terms under the 1999 Stock Incentive Plan. The agreements provide for issuance of up to a maximum of 706,400 shares of Anadarko common stock through the end of 2008. The number of shares to be issued will be determined based on a market objective and a performance objective. The shares are equally weighted between the two objectives. The number of performance units to be issued with respect to the first objective will be determined by comparing the Company’s total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The number of performance units to be issued with respect to the second objective will be determined based on the Company’s reserve replacement efficiency ratio over the performance period. During 2005, the Company recognized expense of $2 million under the agreements.

      Anadarko and a key officer of the Company have entered into a Performance Share Agreement under the 1999 Stock Incentive Plan. The agreement provides for issuance of up to 160,000 shares of Anadarko common stock after a two-year period that ended in 2005 and a four-year period ending in 2007. The number of shares to be issued is determined by comparing the Company’s total shareholder return to the total shareholder return of a predetermined group of peer companies. In February 2006, 28,800 shares were issued for the period ended in 2005. During both 2005 and 2004, the Company recognized expense of $1 million under the agreement.

25

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

11.  Common Stock and Stock Options (Continued)

      The reconciliation between basic and diluted EPS from continuing operations is as follows:

	2005						2004						2003
					Per Share						Per Share						Per Share
	Income		Shares		Amount		Income		Shares		Amount		Income		Shares		Amount
millions except per share amounts
Basic EPS
Income from continuing operations	$	2,073					$	1,301					$	892
Preferred stock dividends		5						5						5
Net income from continuing operations available to common stockholders before cumulative effect of change in accounting principle	$	2,068		470	$	4.40	$	1,296		499	$	2.60	$	887		499	$	1.78
Effect of convertible debentures and ZYP-CODES		—		1				—		—				3		5
Effect of dilutive stock options, performance-based stock awards and common stock put options		—		4				—		4				—		3
Diluted EPS
Net income from continuing operations available to common stockholders before cumulative effect of change in accounting principle plus assumed conversion	$	2,068		475	$	4.36	$	1,296		503	$	2.58	$	890		507	$	1.76

      For the years ended December 31, 2005, 2004 and 2003, options for 0.1 million, 1.5 million and 16.8 million average shares, respectively, of common stock were excluded from the diluted EPS calculation because the options’ exercise price was greater than the average market price of common stock for the respective period.

12.  Statements of Cash Flows Supplemental Information

      The difference between cash and cash equivalents on the consolidated balance sheet and statement of cash flows at December 31, 2005 and 2004 is due to cash of $178 million and $526 million, respectively, related to Canadian operations which is included in Current Assets Held for Sale.

      The amounts of cash paid for interest (net of amounts capitalized) and income taxes, including amounts related to discontinued operations, are as follows:

	2005		2004		2003
millions
Interest	$	191	$	345	$	262
Income taxes	$	439	$	256	$	90

13.  Major Customers

      The Company’s natural gas is sold to interstate and intrastate gas pipelines, direct end-users, industrial users, local distribution companies and gas marketers. Crude oil and condensate are sold to marketers, gatherers and refiners. NGLs are sold to direct end-users, refiners and marketers. These purchasers are located in the United States, Bermuda, Canada, Singapore and Switzerland. The majority of the Company’s receivables are paid within two months following the month of purchase.

      The Company generally performs a credit analysis of customers prior to making any sales to new customers or increasing credit for existing customers. Based upon this credit analysis, the Company may require a standby letter of credit or a financial guarantee. As of December 31, 2005 and 2004, accounts receivable are shown net of allowance for uncollectible accounts of $6 million and $9 million, respectively.

26

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

13.  Major Customers (Continued)

      In 2005, 2004 and 2003, sales to affiliates of Duke were $747 million, $903 million and $1.4 billion, respectively, which accounted for 12%, 18% and 33% of the Company’s total 2005, 2004 and 2003 revenues, respectively. These sales relate primarily to the Company’s oil and gas segment.

14.  Segment and Geographic Information

      Anadarko’s primary business segments are vertically integrated business units that are principally within the oil and gas industry. These segments are managed separately because of their unique technology, marketing and distribution requirements. The Company’s three segments are upstream oil and gas activities, marketing and trading activities and minerals activities. The oil and gas exploration and production segment finds and produces natural gas, crude oil, condensate and NGLs. The marketing and trading segment is responsible for gathering, transporting and selling most of Anadarko’s natural gas production as well as volumes of gas, oil and NGLs purchased from third parties. The marketing and trading segment is also responsible for the development of liquefied natural gas facilities and markets. The minerals segment participates in non-operated joint ventures and royalty arrangements in several coal, trona (natural soda ash) and industrial mineral mines. The segment shown as All Other and Intercompany Eliminations includes other smaller operating units, corporate activities, financing activities and intercompany eliminations.

      The Company’s accounting policies for segments are the same as those described in the summary of significant accounting policies. Management evaluates segment performance based on operating income and various other factors. Transfers between segments are accounted for at market value.

      The following table illustrates information related to Anadarko’s business segments. Operating income (loss), shown in the table below, agrees to the consolidated statement of income where it reconciles to income before income taxes.

		Oil and Gas		Marketing				All Other &
		Exploration		and				Intercompany
		and Production		Trading		Minerals		Eliminations			Total
millions
2005
Total Revenues		$	6,013	$	180	$	40	$	(46	)	$	6,187
Depreciation, depletion and amortization			1,039		21		3		48			1,111
Impairments			78		—		—		—			78
Other costs and expenses			1,058		152		2		251			1,463
	Total costs and expenses		2,175		173		5		299			2,652
Operating income (loss)		$	3,838	$	7	$	35	$	(345	)	$	3,535
Net properties and equipment		$	13,280	$	405	$	1,188	$	322		$	15,195
Capital expenditures		$	2,816	$	77	$	—	$	50		$	2,943
Goodwill		$	1,089	$	—	$	—	$	—		$	1,089

27

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

14.  Segment and Geographic Information (Continued)

		Oil and Gas		Marketing				All Other &
		Exploration		and				Intercompany
		and Production		Trading		Minerals		Eliminations			Total
millions
2004
Total Revenues		$	4,963	$	155	$	35	$	(29	)	$	5,124
Depreciation, depletion and amortization			1,061		20		4		47			1,132
Impairments			72		—		—		—			72
Other costs and expenses			982		115		2		304			1,403
	Total costs and expenses		2,115		135		6		351			2,607
Operating income (loss)		$	2,848	$	20	$	29	$	(380	)	$	2,517
Net properties and equipment		$	11,690	$	357	$	1,192	$	324		$	13,563
Capital expenditures		$	2,417	$	57	$	—	$	36		$	2,510
Goodwill		$	1,202	$	—	$	—	$	—		$	1,202
2003
Total Revenues		$	4,091	$	121	$	29	$	5		$	4,246
Depreciation, depletion and amortization			964		18		3		48			1,033
Impairments			103		—		—		—			103
Other costs and expenses			901		82		2		295			1,280
	Total costs and expenses		1,968		100		5		343			2,416
Operating income (loss)		$	2,123	$	21	$	24	$	(338	)	$	1,830
Net properties and equipment		$	12,662	$	253	$	1,199	$	358		$	14,472
Capital expenditures		$	2,222	$	33	$	—	$	34		$	2,289
Goodwill		$	1,282	$	—	$	—	$	—		$	1,282

      The following table shows Anadarko’s revenues (based on the origin of the sales) and net properties and equipment by geographic area:

	2005		2004		2003
millions
Revenues
United States	$	4,573	$	4,131	$	3,521
Algeria		1,292		770		541
Other International		322		223		184
Total	$	6,187	$	5,124	$	4,246

28

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

14.  Segment and Geographic Information (Continued)

	2005		2004
millions
Net Properties and Equipment
United States	$	13,518	$	11,819
Algeria		843		881
Other International		834		863
Total	$	15,195	$	13,563

15.  Restructuring Costs

      In July 2003, Anadarko announced a cost reduction plan to reduce overhead costs from the Company’s cost structure. This plan included a reduction in personnel and corporate expenses and was substantially completed in 2003. The related costs of $40 million were charged to general and administrative costs in 2003 as specific liabilities were incurred. Of this amount, $25 million is related to corporate costs and $15 million is related to oil and gas costs.

16.  Other Taxes

      Significant taxes, other than income taxes, are as follows:

	2005		2004		2003
Production and severance	$	213	$	157	$	148
Ad valorem		121		112		110
Payroll and other		24		23		19
Total	$	358	$	292	$	277

17.  Other (Income) Expense

      Other (income) expense consists of the following:

	2005			2004			2003
millions
Operating lease settlement	$	—		$	63		$	—
Firm transportation keep-whole contract valuation		(56	)		(1	)		(9	)
Interest income		(17	)		(5	)		(2	)
Foreign currency translation (gains) losses		(3	)		(9	)		(4	)
Other		—			11			(5	)
Total	$	(76	)	$	59		$	(20	)

      The operating lease settlement in 2004 relates to the Corpus Christi West Plant Refinery (West Plant). See Note 21. Foreign currency transaction (gains) losses for the years ended December 31, 2005, 2004 and 2003, exclude (benefits) expenses of $(3) million, $(6) million and $8 million, respectively, related to the remeasurement of the Venezuelan deferred tax liability, which amounts are included in income tax expense.

29

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

18.  Income Taxes

      Income tax expense including deferred amounts, is summarized as follows:

	2005		2004		2003
millions
Current
Federal	$	327	$	283	$	66
State		2		22		4
Foreign		523		283		177
Total		852		588		247
Deferred
Federal		363		175		380
State		64		35		28
Foreign		53		1		29
Total		480		211		437
Total	$	1,332	$	799	$	684

      Total income taxes differed from the amounts computed by applying the statutory income tax rate to income from continuing operations before income taxes. The sources of these differences are as follows:

		2005			2004			2003
millions
Income from Continuing Operations Before Income Taxes
	Domestic	$	2,356		$	1,544		$	1,359
	Foreign		1,049			556			217
Total		$	3,405		$	2,100		$	1,576
Statutory tax rate			35	%		35	%		35	%
Tax computed at statutory rate		$	1,192		$	735		$	552
Adjustments resulting from:
	State income taxes (net of federal income tax benefit)		43			37			21
	Foreign taxes in excess of federal statutory tax rate		157			38			78
	Excess U.S. foreign tax credit generated in current year		(79	)		—			—
	Other — net		19			(11	)		33
Total income tax expense		$	1,332		$	799		$	684
Effective tax rate			39	%		38	%		43	%

      The effect of stock-based compensation expense for tax purposes in excess of amounts recognized for financial accounting purposes has been credited directly to stockholders’ equity in amounts of $53 million, $36 million and $1 million for 2005, 2004 and 2003, respectively.

      Tax effects related to restructuring of certain foreign operations in prior years have been recorded to other assets on the balance sheet and are being recognized in the income statement over the estimated life of the related properties under Accounting Research Bulletin (ARB) No. 51, “Consolidated Financial Statements.” During 2005, an ARB No. 51 liability of $17 million associated with a prior year restructuring of the Company’s Venezuelan operations was reversed to income.

      The Company is currently under examination by the Internal Revenue Service (IRS), various state and foreign taxing jurisdictions covering multiple tax years. Although the Company believes that it has adequately provided for income taxes and related interest which may become payable for years that are under examination, the resolution of pending tax issues cannot be predicted with certainty and differences may occur in the future.

30

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

18.  Income Taxes (Continued)

      Certain subsidiaries of the Company are currently in administrative appeals with the IRS or under examination with various foreign jurisdictions for years prior to their acquisition by the Company. The Company determined in 2005 and 2004 that deferred tax liabilities related to pre-acquisition tax contingencies of approximately $101 million and $103 million, respectively, were no longer required due to completion of audits and administrative appeals, filing amended returns, reevaluation of contingencies and changes in the Company’s estimate of the ultimate tax basis of acquired assets and liabilities. Accordingly, these liabilities were reversed with an offsetting decrease to goodwill. Future events, including the conclusion of examinations and administrative appeals by taxing authorities and resolution of pre-acquisition contingencies, may result in additional adjustments to goodwill.

      The tax effects of temporary differences that give rise to significant portions of the deferred assets (liabilities) at December 31, 2005 and 2004 are as follows:

	2005			2004
millions
Net current deferred tax assets		9			8
Net current deferred tax liability		(6	)		—
Oil and gas exploration and development costs		(3,264	)		(3,101	)
Mineral operations		(443	)		(441	)
Other		(655	)		(462	)
Gross long-term deferred tax liabilities		(4,362	)		(4,004	)
Oil and gas exploration and development costs		71			87
Net operating loss carryforward		88			90
Foreign tax credit carryforward		83			17
Other		338			434
Gross long-term deferred tax assets		580			628
Less: valuation allowance on deferred tax assets not expected to be realized		(211	)		(252	)
Net long-term deferred tax assets		369			376
Net long-term deferred tax liabilities		(3,993	)		(3,628	)
Total deferred taxes	$	(3,990	)	$	(3,620	)

      Total deferred taxes at December 31, 2005 and 2004 include state deferred taxes of approximately $213 million and $172 million, respectively. Total deferred taxes as of December 31, 2005 and 2004 also include foreign deferred taxes of approximately $280 million and $213 million, respectively.

      As of December 31, 2004, the Company no longer meets the indefinite reinvestment criterion of Accounting Principles Board (APB) Opinion No. 23, “Accounting for Income Taxes — Special Areas,” for the unremitted earnings of foreign subsidiaries. The resulting deferred tax liabilities have been offset with foreign tax credits.

      The Jobs Act introduced a special one-time, 85% dividends received deduction on the repatriation of certain foreign earnings to a U.S. taxpayer provided certain criteria are met. In 2005, Anadarko’s Chief Executive Officer and Board of Directors approved a domestic reinvestment plan for a $500 million repatriation of foreign earnings under the Jobs Act. The $26 million tax effect of this repatriation was recorded as current tax expense in 2005.

31

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

18.  Income Taxes (Continued)

      Tax carryforwards at December 31, 2005, which are available for utilization on future income tax returns, are as follows:

					Domestic		Foreign
	Domestic		Foreign		Expiration		Expiration
millions
Net operating loss — regular tax	$	—	$	6		—		2010
Net operating loss — state	$	1,437	$	—		2006-2025		—
Foreign tax credit	$	83	$	—		2011-2015		—

19.  Commitments

LNG Facility Related Commitments   In 2005, the Company entered into precedent agreements with a third party in order to secure delivery of natural gas from a liquefied natural gas facility Anadarko is constructing in Nova Scotia, Canada, referred to as Bear Head, to prospective markets in eastern Canada and the northeastern United States. The third party has agreed to expand the capacity of its pipeline so it can accommodate the projected natural gas volumes from Bear Head. The precedent agreements signed by the parties establish the conditions on which the third party will proceed with design, regulatory approvals and construction of the expansion facilities, and be obligated to transport a specified volume of gas. As a condition to entering into the precedent agreements, Anadarko executed firm service agreements for transportation on the Canadian and United States portions of the pipeline. Upon satisfaction of the obligations under the precedent agreements, the initial term of the transportation agreements is 20 years.

      Based upon the terms, Anadarko projects that annual demand charges due under the firm transportation service agreements may be in the range of $123 million to $182 million per year for the first five years from commencement of full service, potentially escalating by up to 5% in year six and 10% in year seven, exclusive of fuel and surcharges. No later than the eighth year from commencement of full service, rates under the agreements are to be redetermined based on then current conditions.

      The precedent agreements contain certain termination rights. The Company’s potential reimbursement obligation under the precedent agreements increases over time as the third party incurs pre-service costs. According to the original schedule provided by the third party, this reimbursement obligation is expected to increase from about $8 million at December 31, 2005 to $100 million at December 31, 2006, up to a maximum of $215 million in May 2007.

Leases  The Company has long-term drilling rig commitments that qualify as operating leases of $1,998 million. The Company also has various commitments under noncancelable operating lease agreements of $305 million for a production platform and equipment, buildings, facilities and aircraft. These operating leases expire at various dates through 2016. The majority of the operating lease agreements are expected to be renewed or replaced as they expire. The Company’s balance sheet does not include assets or liabilities related to these operating lease

32

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

19.  Commitments (Continued)

agreements since these agreements were structured as operating leases for accounting purposes. At December 31, 2005, future minimum lease payments under operating leases are as follows:

	Operating
	Leases
millions
2006	$	360
2007		649
2008		638
2009		510
2010		99
Later years		47
Total future minimum lease payments	$	2,303

      The above table excludes $24 million related to discontinued operations.

      Total rental expense, net of sublease income, amounted to $40 million in 2005 and 2004 and $25 million in 2003. Total rental expense includes contingent rental expense related to processing fees of $7 million and $8 million in 2005 and 2004, respectively.

Drilling Rig Commitments  During 2005, Anadarko entered into various agreements to secure the necessary drilling rigs to execute a portion of its drilling strategy over the next several years. As part of the plan, Anadarko, with two other producers, signed a four-year rig-share agreement under which a third party will build and own a new semi-submersible drilling rig with a target delivery date of mid-2008. Anadarko committed to 50% of the rig time at a cost of approximately $200 million over the contract term. The Company also executed a three-year contract for the Discoverer Spirit drillship and a contract for the Deepwater Millennium drillship of slightly more than four years. The Discoverer Spirit drillship contract begins in 2007 and the Deepwater Millennium drillship contract begins in 2006 for a combined commitment of $1.1 billion. In addition, the Company executed a three-year drilling contract to secure the Belford Dolphin drillship at a cost of $460 million over the contract period. It is anticipated the vessel will be released to Anadarko beginning in mid-2007. The Company also has multi-year contracts for drilling rigs onshore in the United States. The table of future minimum lease payments above includes approximately $2.0 billion for the Discoverer Spirit, Deepwater Millennium and Belford Dolphin drillships and certain contracts for onshore United States drilling rigs that qualify as operating leases. Lease payments for these drilling rig commitments, net of amounts billed to partners, will be capitalized as a component of oil and gas properties.

Production Platforms  During 2004, Anadarko and a group of energy companies (Atwater Valley Producers Group) executed agreements with a third party for the dedication, processing and gathering of natural gas and condensate production from several natural gas fields in the deepwater Gulf of Mexico. The third party will design, construct, install and own Independence Hub, a semi-submersible platform in the deepwater Gulf of Mexico. The platform structure, expected to be mechanically complete in late 2006, will be operated by Anadarko. First production from Anadarko’s discoveries to be processed on the facility is expected in the second half of 2007. The agreements require a monthly demand charge of about $2 million for five years beginning at the time of mechanical completion, a processing fee based upon production throughput and a transportation fee based upon pipeline throughput. Since the Company’s obligation related to the agreements begins at the time of mechanical completion, the table of future minimum lease payments above does not include any amounts related to these agreements. The agreements do not contain any purchase options, purchase obligations or value guarantees.

33

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

19.  Commitments (Continued)

      In 2002, the Company entered into an agreement under which a floating production platform for its Marco Polo discovery in the deepwater Gulf of Mexico was installed in 2004. The other party to the agreement constructed and owns the platform and production facilities that upon mechanical completion became operated by Anadarko. The agreement provides that Anadarko dedicate its production from Green Canyon Block 608 and 11 other Green Canyon blocks to the production facilities. The agreement requires a monthly demand charge of approximately $2 million for five years and a processing fee based upon production throughput. Anadarko’s commitment to begin payments for the monthly demand charges was incurred upon mechanical completion in 2004. The table of future minimum lease payments above includes amounts related to the monthly demand charge for this agreement. The agreement does not contain any purchase options, purchase obligations or value guarantees.

Buildings  The Company leases two corporate office buildings located in The Woodlands, Texas. The lease term is seven years and the monthly lease payments are based on the London interbank borrowing rate applied against the lease balance. The lease contains various covenants including covenants regarding the Company’s financial condition. Default under the lease, including violation of these covenants, could require the Company to purchase the facilities for a specified amount, which approximates the lessor’s original cost of $214 million. As of December 31, 2005, the Company was in compliance with these covenants.

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

      The Company has a $5 million liability and corresponding prepaid rent asset as of December 31, 2005 related to its residual value guarantee on the corporate office buildings. If the Company determines that it is probable that the expected fair value of the property at the end of the lease term will be less than the lease balance, the liability will be adjusted accordingly. Currently, Management does not believe it is probable that the fair market value of the properties will be less than the lease balance at the end of the lease term.

Aircraft  The table of future minimum lease payments above includes the Company’s lease payment obligations of $44 million related to aircraft leases. One lease includes a residual value guarantee for any deficiency if the aircraft is sold for less than the sale option amount (approximately $11 million). In addition, the Company is entitled to any proceeds from a sale of the aircraft in excess of the sale option amount. No liability has been recorded related to this guarantee.

20.  Pension Plans, Other Postretirement Benefits and Employee Savings Plans

Pension Plans and Other Postretirement Benefits  The Company has defined benefit pension plans and supplemental pension plans that are noncontributory and a foreign contributory defined benefit pension plan. The Company also provides certain health care and life insurance benefits for retired employees. Health care benefits are funded by contributions from the Company and the retiree, with the retiree contributions adjusted according to the provisions of the Company’s health care plans. The Company’s retiree life insurance plan is noncontributory. The Company uses a December 31 measurement date for the majority of its plans.

      The following activities and balances include amounts associated with Canadian operations which have been presented as discontinued operations.

      In 2005, the Company made contributions of $116 million to its funded pension plans, $5 million to its unfunded pension plans and $7 million to its unfunded other postretirement benefit plans. Contributions to the funded plans increase the plan assets while contributions to unfunded plans are used for current benefit payments.

34

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)

In 2006, the Company expects to contribute about $61 million to its funded pension plans, $10 million to its unfunded pension plans and $7 million to its unfunded other postretirement benefit plans.

      The following table sets forth the Company’s pension and other postretirement benefits changes in projected benefit obligation, fair value of plan assets, funded status and amounts recognized in the financial statements as of December 31, 2005 and 2004.

		Pension Benefits						Other Benefits
		2005			2004			2005			2004
millions
Change in projected benefit obligation
Benefit obligation at beginning of year		$	675		$	559		$	164		$	161
Service cost			36			24			15			11
Interest cost			38			32			9			9
Plan amendments			—			(2	)		—			—
Special termination benefits			—			1			—			—
Actuarial (gain) loss			61			130			6			(10	)
Foreign currency exchange rate change			(3	)		5			—			—
Benefit payments			(45	)		(74	)		(6	)		(7	)
Benefit obligation at end of year		$	762		$	675		$	188		$	164
Change in plan assets
Fair value of plan assets at beginning of year		$	475		$	375		$	—		$	—
Actual return on plan assets			38			54			—			—
Employer contributions			121			116			7			7
Foreign currency exchange rate change			(1	)		4			—			—
Benefit payments			(45	)		(74	)		(7	)		(7	)
Fair value of plan assets at end of year		$	588		$	475		$	—		$	—
Funded status of the plan		$	(174	)	$	(200	)	$	(188	)	$	(164	)
Unrecognized actuarial loss			314			271			47			44
Unrecognized prior service cost			6			7			1			—
Total recognized		$	146		$	78		$	(140	)	$	(120	)
Total recognized amounts in the balance sheet consist of:
	Prepaid benefit cost	$	170		$	32		$	—		$	—
	Accrued benefit liability		(49	)		(83	)		(140	)		(120	)
	Intangible asset		—			8			—			—
	Other comprehensive expense		25			121			—			—
Total recognized		$	146		$	78		$	(140	)	$	(120	)

      The accumulated benefit obligation for all defined benefit pension plans was $589 million and $534 million as of December 31, 2005 and 2004, respectively. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $57 million, $49 million and zero, respectively, as of December 31, 2005, and $648 million, $507 million and $427 million, respectively, as of December 31, 2004. The Company’s benefit obligation under the unfunded pension plans are secured by the Anadarko Petroleum Corporation Executives and Directors Benefits Trust. See Note 11.

35

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)

      The following table sets forth the Company’s pension and other postretirement benefit cost.

	Pension Benefits									Other Benefits
	2005			2004			2003			2005		2004		2003
millions
Components of net periodic benefit cost
Service cost	$	36		$	24		$	22		$	15	$	11	$	7
Interest cost		38			32			34			9		9		9
Expected return on plan assets		(38	)		(33	)		(30	)		—		—		—
Settlements		—			—			17			—		—		—
Special termination benefits		—			1			3			—		—		—
Amortization values and deferrals		18			11			14			2		3		2
Net periodic benefit cost	$	54		$	35		$	60		$	26	$	23	$	18

      As a result of executive retirements in 2003, a settlement charge of $17 million was recorded to general and administrative expense in 2003. The increase (decrease) in the Company’s minimum liability included in other comprehensive income related to the pension plans was $(96) million, $31 million and $(29) million before income taxes for 2005, 2004 and 2003, respectively.

      Following are the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations as of December 31, 2005 and 2004:

	Pension						Other
	Benefits						Benefits
	2005			2004			2005			2004
percent
Discount rate		5.75	%		5.75	%		5.75	%		5.75	%
Rates of increase in compensation levels		5.0	%		5.0	%		5.0	%		5.0	%

      The discount rate assumption used by the Company is meant to reflect the interest rate at which the pension and other postretirement obligations could effectively be settled on the measurement date. The Company currently uses a yield curve analysis, for a majority of the plans, to support the discount rate assumption. This analysis involves the creation of a hypothetical Aa spot yield curve represented by a series of high-quality, non-callable, marketable bonds, then discounts the projected cash flows from each plan at interest rates on the created curve specifically applicable to the timing of each respective cash flow. The present values of the cash flows are then accumulated, and a weighted-average discount rate is calculated by imputing the single discount rate that equates to the total present value of the cash flows. The consolidated discount rate assumption is determined by evaluation of the weighted-average discount rates determined for each of the Company’s significant pension and postretirement plans.

      Following are the weighted-average assumptions used by the Company in determining the net periodic pension and other postretirement benefit cost for 2005 and 2004:

	Pension						Other
	Benefits						Benefits
	2005			2004			2005			2004
percent
Discount rate		5.75	%		6.25	%		5.75	%		6.25	%
Long-term rate of return on plan assets		8.0	%		8.0	%		n/a			n/a
Rates of increase in compensation levels		5.0	%		5.0	%		5.0	%		5.0	%

      The Company has adopted a balanced, diversified investment strategy, with the intent of maximizing returns without exposure to undue risk. Investments are typically made through investment managers across several investment categories (Domestic Large and Small Cap, International, Domestic Fixed Income, Real Estate and

36

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)

Private Equity), with selective exposure to Growth/ Value investment styles. Performance for each investment is measured relative to the appropriate index benchmark for its category. Target asset allocation percentages by major category are 65% equity securities, 25% fixed income, 5% real estate and 5% private equity. Investment managers have full discretion as to investment decisions regarding all funds under their management to the extent permitted within investment guidelines. Certain investments are prohibited, including short sales, sales on margin, securities of companies in bankruptcy, investments in financial futures and commodities and currency exchanges.

      The Company’s pension plans as of December 31, 2005 and 2004 were comprised of assets by category as follows:

	2005			2004
percent
Assets
Equity securities		79	%		73	%
Fixed income		19			23
Other		2			4
Total		100	%		100	%

      There are no direct investments in Anadarko common stock included in plan assets; however, there may be indirect investments in Anadarko common stock through the plans’ mutual fund investments. The expected long-term rate of return on assets assumption was determined using the year-end 2005 pension investment balances by category and projected target asset allocations for 2006. The expected return for each of these categories was determined by using capital market projections provided by the Company’s external pension consultants, with consideration of actual five-year performance statistics for investments in place.

      The following benefit payments and federal Medicare Part D subsidy receipts, which reflect expected future service, as appropriate, are expected to be paid (received) as follows:

	Pension		Other		Federal
	Benefit		Benefit		Subsidy
	Payments		Payments		Receipts
millions
2006	$	40	$	8	$	(1	)
2007		36		8		(1	)
2008		40		9		(1	)
2009		43		10		(1	)
2010		49		11		(1	)
2011-2015		342		72		(6	)

      For year-end 2005 measurement purposes, an 11% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005. The rate was assumed to decrease gradually to 5% in 2011 and later years. For year-end 2004 measurement purposes, a 12% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2004. The rate was assumed to decrease gradually to 5% in 2011 and later years. The assumed health care cost trend rate has a significant effect on the amounts reported for the health care plan. A 1% change in the assumed health care cost trend rate over the projected period would have the following effects:

	1% Increase		1% Decrease
millions
Effect on total of service and interest cost components	$	4	$	(3	)
Effect on other postretirement benefit obligation	$	20	$	(17	)

37

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)

Employee Savings Plan  The Company has an employee savings plan (ESP), which is a defined contribution plan. The Company matches a portion of employees’ contributions. Participation in the ESP is voluntary and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $14 million, in each of the years 2005, 2004 and 2003. The contributions were funded through the Employee Stock Ownership Plan (ESOP) until mid-2005 when the shares of the ESOP were depleted. Contributions are currently funded in cash.

21.  Contingencies

General  Litigation charges of $64 million and $62 million were expensed during 2005 and 2004, respectively. There were no significant litigation charges in 2003. 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 claims by employees of third-party contractors alleging exposure to asbestos, silica and benzene while working at refineries located in Texas, California and Oklahoma. Two companies Anadarko acquired in 2000 and 2002 sold the refineries prior to being acquired by Anadarko. 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, results of operations or cash flow of the Company.

Litigation  The Company is subject to various claims from its royalty owners in the regular course of business as an oil and gas producer, including disputes regarding measurement, costs and expenses beyond the wellhead and basis for royalty valuations. Among such claims, the Company was named as a defendant in a case styled U.S. of America ex rel. Harold E. Wright v. AGIP Company, et al. (the “Gas Qui Tam case”) filed in September 2000 in the U.S. District Court for the Eastern District of Texas, Lufkin Division. This lawsuit generally alleges that the Company and 118 other defendants undervalued natural gas in connection with a payment of royalties on production from federal and Indian lands. Based on the Company’s present understanding of these various governmental and False Claims Act proceedings, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. However, if the Company is found to have violated the Civil False Claims Act, the Company could be subject to a variety of sanctions, including treble damages and substantial monetary fines. All defendants jointly filed a motion to dismiss the action on jurisdictional grounds based on Mr. Wright’s failure to qualify as the original source of the information underlying his fraud claims, and the Company filed additional motions to dismiss on separate grounds. On September 14, 2005, the trial court declined an early appeal of its order denying the defendants’ motion to dismiss. Meanwhile, the discovery process is ongoing. The court has set a trial date for fall 2007. Management is unable to determine a reasonable range of loss, if any, related to this matter.

Other  The Company is subject to other legal proceedings, claims and liabilities which arise in the ordinary course of its business. In the opinion of Anadarko, the liability with respect to these actions will not have a material effect on the Company.

Lease Agreement  The Company, through one of its affiliates (formerly a subsidiary of Union Pacific Resources Group, Inc. or UPRG), is a party to a lease agreement for the West Plant, a refinery facility located in Corpus Christi, Texas. The initial term of the lease expired December 31, 2003, but Anadarko had renewal options extending through January 31, 2011 at fair market rental rates and the right to purchase the West Plant at a fair market sales value on January 31, 2011. In conjunction with UPRG exiting the refinery business in 1987, the West Plant was subleased to CITGO Petroleum Corporation (CITGO) under terms substantially the same as the Company’s lease, with sublease payments during any renewal period equal to the lesser of the fair market

38

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

21.  Contingencies (Continued)

rental rates as determined in the Company’s lease or $5 million. Additionally, CITGO has the option under the sublease to purchase the West Plant from the Company on January 31, 2011 at a specified purchase price.

      For the renewal term, the fair market rental rates of the West Plant were to be determined by the appraisal process specified in the lease agreement. Prior to the completion of the fair market rental rate determination by the appraisers, Anadarko and the lessor agreed to rental rates for the period 2004 to 2011 and a maximum purchase price at the end of the lease term. Subsequent to this agreement, Anadarko also agreed to purchase the West Plant on January 31, 2011 at a price less than the previously stipulated maximum amount. Since the agreed upon rental rates exceeded the capped sublease payments from CITGO and the Company’s purchase price exceeded CITGO’s specified purchase price in 2011, the Company recorded a liability of $63 million in 2004. This amount represented the present value of the excess of the annual rental amounts payable to the lessor over the amounts under the sublease for 2004 to 2011 as well as the present value of the excess of the purchase price payable to the lessor in 2011 over CITGO’s specified purchase price.

Guarantees and Indemnifications  The Company has made a residual value guarantee in connection with an aircraft operating lease for any deficiency if the aircraft is sold for less than the maximum lessee risk amount of approximately $11 million. No liability has been recorded related to this guarantee.

      The Company is guarantor for specific financial obligations of a trona mining affiliate. The investment in this entity, which is not a consolidated subsidiary, is accounted for using the equity method. The Company has guaranteed a portion of amounts due under a revolving credit agreement, a term loan and various letters of credit used to secure industrial revenue bonds. The Company’s guarantees under the revolving credit agreement and the term loan expire in 2007 and 2010, respectively, coinciding with the maturity of those agreements. The Company’s guarantees under the letters of credit securing the industrial revenue bonds expire in 2006; however, these letters of credit and the related guarantees are expected to be extended or to continue until the maturity dates of the obligations which range from 2007 to 2018. The Company would be obligated to pay up to $15 million for the revolving credit agreement, $15 million for the term loan and $15 million for the industrial revenue bonds if the affiliate defaulted on these obligations. No liability has been recognized for these guarantees as of December 31, 2005.

22.  Discontinued Operations

      In June 2006, the Company’s Board of Directors approved a plan to sell its Canadian operations. Accordingly, the Canadian operations have been classified as discontinued operations in the consolidated statements of income and cash flows and the associated assets and liabilities have been classified as held for sale in the consolidated balance sheets. The following table summarizes the amounts included in income from discontinued operations for all periods presented:

	2005		2004		2003
millions
Revenues	$	913	$	955	$	867
Costs and expenses		433		579		498
Income from discontinued operations	$	490	$	377	$	398
Income tax expense		92		72		45
Income from discontinued operations, net of tax	$	398	$	305	$	353

39

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

22.  Discontinued Operations (Continued)

      Total income taxes differed from the amount computed by applying the statutory income tax rate to income from discontinued operations. The source of these differences are as follows:

		2005			2004			2003
millions
Income from discontinued operations		$	490		$	377		$	398
Statutory tax rate			35	%		35	%		35	%
Tax computed at statutory rate		$	172		$	132		$	139
Adjustment resulting from:
	Foreign taxes differing from statutory rate		(29	)		6			3
	Cross border financing		(51	)		(51	)		(51	)
	Effect of change in Canadian income tax rate		—			(15	)		(46	)
Total income tax expense related to discontinued operations		$	92		$	72		$	45
Effective tax rate			19	%		19	%		11	%

      The tax effects of temporary differences that give rise to significant portions of the deferred assets (liabilities) associated with assets held for sale at December 31, 2005 and 2004 are as follows:

	2005			2004
millions
Net operating loss carryforward		—			83
Other		—			9
Net current deferred tax assets		—			92
Oil and gas exploration and development costs		(38	)		—
Net current deferred tax liabilities		(38	)		—
Oil and gas exploration and development costs		(665	)		(787	)
Other		(107	)		(53	)
Gross long-term deferred tax liabilities		(772	)		(840	)
Other		46			61
Gross long-term deferred tax assets		46			61
Less: valuation allowance on deferred tax assets not expected to be realized		—			(7	)
Net long-term deferred tax assets		46			54
Net long-term deferred tax liabilities		(726	)		(786	)
Total deferred taxes		(764	)		(694	)

40

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

      The following presents the assets and liabilities associated with Canadian operations as of December 31, 2005 and 2004, respectively.

		2005		2004
millions
ASSETS
Cash		$	178	$	526
Accounts receivable			248		196
Other current assets			51		125
	Total Current Assets Held for Sale	$	477	$	847
Property, plant and equipment		$	2,667	$	2,350
Other assets			53		46
Goodwill			107		107
	Total Long-Term Assets Held for Sale	$	2,827	$	2,503
LIABILITIES
Accounts payable		$	240	$	220
Accrued expenses			57		16
Current debt			42		—
	Total Current Liabilities associated with Assets Held for Sale	$	339	$	236
Long-term debt		$	8	$	50
Deferred income taxes			726		786
Other liabilities			41		46
	Total Long-Term Liabilities associated with Assets Held for Sale	$	775	$	882

41

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Oil and Gas Exploration and Production Activities

      The following is historical revenue and cost information relating to the Company’s oil and gas activities. The Canadian activities presented on the following pages are associated with the Company’s Canadian operations which have been presented as discontinued operations in the accompanying consolidated financial statements.

Costs Excluded

      Costs associated with unproved properties and major development projects of $1.3 billion and $1.6 billion as of December 31, 2005 and 2004, respectively, are excluded from amounts subject to amortization. The majority of the evaluation activities are expected to be completed within three to ten years.

Costs Excluded by Year Incurred

	Year Costs Incurred								Excluded
									Costs at
	Prior								Dec. 31,
	Years		2003		2004		2005		2005
millions
Property acquisition	$	581	$	40	$	90	$	230	$	941
Exploration		37		26		52		140		255
Capitalized interest		62		9		13		29		113
Total	$	680	$	75	$	155	$	399	$	1,309

Costs Excluded by Country

							Other
	U.S.		Canada		Algeria		International		Total
millions
Property acquisition	$	834	$	101	$	—	$	6	$	941
Exploration		142		3		5		105		255
Capitalized interest		91		7		—		15		113
Total	$	1,067	$	111	$	5	$	126	$	1,309

Changes in Costs Excluded by Country

										Other
	U.S.			Canada			Algeria			International			Total
millions
December 31, 2003	$	2,030		$	343		$	9		$	142		$	2,524
Additional costs incurred		410			51			8			50			519
Costs transferred to DD&A pool		(1,129	)		(229	)		(11	)		(44	)		(1,413	)
Impact of foreign currency exchange rate changes		—			12			—			—			12
December 31, 2004		1,311			177			6			148			1,642
Additional costs incurred		691			62			7			64			824
Costs transferred to DD&A pool		(935	)		(130	)		(8	)		(86	)		(1,159	)
Impact of foreign currency exchange rate changes		—			2			—			—			2
December 31, 2005	$	1,067		$	111		$	5		$	126		$	1,309

42

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Capitalized Costs Related to Oil and Gas Producing Activities

		2005		2004
millions
United States
Capitalized
	Unproved properties	$	1,067	$	1,311
	Proved properties		17,282		14,566
			18,349		15,877
Accumulated depreciation, depletion and amortization			6,627		5,845
Net capitalized costs			11,722		10,032
Canada
Capitalized
	Unproved properties		111		177
	Proved properties		5,148		4,457
			5,259		4,634
Accumulated depreciation, depletion and amortization			2,611		2,307
Net capitalized costs			2,648		2,327
Algeria
Capitalized
	Unproved properties		5		6
	Proved properties		1,262		1,199
			1,267		1,205
Accumulated depreciation, depletion and amortization			432		335
Net capitalized costs			835		870
Other International
Capitalized
	Unproved properties		126		148
	Proved properties		1,144		1,094
			1,270		1,242
Accumulated depreciation, depletion and amortization			547		454
Net capitalized costs			723		788
Total
Capitalized
	Unproved properties		1,309		1,642
	Proved properties		24,836		21,316
			26,145		22,958
Accumulated depreciation, depletion and amortization			10,217		8,941
Net capitalized costs		$	15,928	$	14,017

43

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Costs Incurred in Oil and Gas Producing Activities

		2005		2004			2003
millions
United States
Property acquisition
	Exploration	$	216	$	123		$	100
	Development		44		(1	)		203
Exploration			527		339			454
Development(1)			1,854		1,809			1,400
Total United States(2)			2,641		2,270			2,157
Canada
Property acquisition
	Exploration		40		20			24
	Development		1		4			—
Exploration			134		126			176
Development(1)			319		429			307
Total Canada(2)			494		579			507
Algeria
Exploration			12		20			17
Development(1)			45		40			62
Total Algeria(2)			57		60			79
Other International
Property acquisition
	Exploration		13		12			—
	Development		—		—			—
Exploration			49		28			66
Development(1)			60		70			77
Total Other International(2)		$	122	$	110		$	143

44

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Costs Incurred in Oil and Gas Producing Activities (Continued)

		2005		2004		2003
millions
Total
Property acquisition
	Exploration	$	269	$	155	$	124
	Development		45		3		203
Exploration			722		513		713
Development(1)			2,278		2,348		1,846
Total(2)		$	3,314	$	3,019	$	2,886

⁽¹⁾  Development costs incurred for the year include costs related to the prior year-end proved undeveloped reserves as follows:

	2005		2004		2003
millions
United States	$	367	$	861	$	507
Canada		76		138		92
Algeria		28		22		35
Other International		34		29		25
Total	$	505	$	1,050	$	659

⁽²⁾  The 2005, 2004 and 2003 total costs incurred include asset retirement costs and exclude actual asset retirement expenditures as follows. The 2003 total costs incurred exclude the initial asset retirement costs of $352 million as of January 1, 2003.

							Asset Retirement
	Asset Retirement						Expenditures
	Cost Included						Excluded
	2005		2004		2003		2005		2004		2003
millions
United States	$	29	$	46	$	164	$	25	$	24	$	15
Canada		8		5		15		4		2		5
Algeria		—		1		1		—		—		—
Other International		—		—		7		—		—		—
Total	$	37	$	52	$	187	$	29	$	26	$	20

45

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Results of Operations for Producing Activities

      The following schedule includes only the revenues from the production and sale of gas, oil, condensate and NGLs. Results of operations from gas, oil and NGLs marketing and gas gathering are excluded. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

		2005		2004		2003
millions
United States
Net revenues from production
	Third-party sales of gas, oil, condensate and NGLs	$	1,688	$	1,621	$	2,044
	Gas and oil sold to consolidated affiliates		2,808		2,430		1,392
			4,496		4,051		3,436
Production costs
	Direct operating		309		390		349
	Transportation and cost of product		201		160		126
	Production related general and administrative expenses		36		28		31
	Other taxes		317		267		247
			863		845		753
Depreciation, depletion and amortization			833		896		827
			2,800		2,310		1,856
Income tax expense			980		825		643
Results of operations		$	1,820	$	1,485	$	1,213
DD&A rate per net equivalent barrel		$	7.84	$	6.82	$	6.15
Canada
Net revenues from production
	Third-party sales of gas, oil, condensate and NGLs	$	877	$	849	$	828
	Gas and oil sold to consolidated affiliates		36		96		30
			913		945		858
Production costs
	Direct operating		107		160		163
	Transportation and cost of product		16		26		22
	Production related general and administrative expenses		49		49		39
	Other taxes		19		21		18
			191		256		242
Depreciation, depletion and amortization			223		305		259
			499		384		357
Income tax expense			190		150		147
Results of operations		$	309	$	234	$	210
DD&A rate per net equivalent barrel		$	11.02	$	10.55	$	8.58

46

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Results of Operations for Producing Activities (Continued)

		2005		2004		2003
millions
Algeria
Net revenues from production
	Third-party sales of oil	$	455	$	203	$	170
	Oil sold to consolidated affiliates		837		567		371
			1,292		770		541
Production costs
	Direct operating		34		34		22
	Transportation and cost of product		23		22		18
	Production related general and administrative expenses		10		9		8
			67		65		48
Depreciation, depletion and amortization			97		91		70
			1,128		614		423
Income tax expense			429		233		161
Results of operations		$	699	$	381	$	262
DD&A rate per net equivalent barrel		$	4.08	$	4.11	$	3.68
Other International
Net revenues from production
	Third-party sales of gas, oil and condensate	$	208	$	146	$	124
	Oil sold to consolidated affiliates		113		79		60
			321		225		184
Production costs
	Direct operating		57		57		62
	Production related general and administrative expenses		4		5		5
	Other taxes		7		3		2
			68		65		69
Depreciation, depletion and amortization			109		75		67
Impairments related to oil and gas properties			78		72		103
			66		13		(55	)
Income tax expense (benefit)			36		7		(22	)
Results of operations		$	30	$	6	$	(33	)
DD&A rate per net equivalent barrel		$	13.33	$	9.31	$	8.44

47

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Results of Operations for Producing Activities (Continued)

		2005		2004		2003
millions
Total
Net revenues from production
	Third-party sales of gas, oil, condensate and NGLs	$	3,228	$	2,819	$	3,166
	Gas and oil sold to consolidated affiliates		3,794		3,172		1,853
			7,022		5,991		5,019
Production costs
	Direct operating		507		641		596
	Transportation and cost of product		240		208		166
	Production related general and administrative expenses		99		91		83
	Other taxes		343		291		267
			1,189		1,231		1,112
Depreciation, depletion and amortization			1,262		1,367		1,223
Impairments related to oil and gas properties			78		72		103
			4,493		3,321		2,581
Income tax expense			1,635		1,215		929
Results of operations		$	2,858	$	2,106	$	1,652
DD&A rate per net equivalent barrel		$	7.96	$	7.18	$	6.38

48

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Oil and Gas Reserves

      The following table shows internal estimates prepared by the Company’s engineers of proved reserves, proved developed reserves and proved undeveloped reserves (PUDs), net of royalty interests, of natural gas, crude oil, condensate and NGLs owned at year-end and changes in proved reserves during the last three years. Volumes for natural gas are in billions of cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch and volumes for oil, condensate and NGLs are in millions of barrels (MMBbls). Total volumes are in millions of barrels of oil equivalent (MMBOE). For this computation, one barrel is the equivalent of six thousand cubic feet of gas. NGLs are included with oil and condensate reserves and the associated shrinkage has been deducted from the gas reserves.

      Algerian reserves are shown in accordance with each Production Sharing Agreement (PSA). The reserves include estimated quantities allocated to Anadarko for recovery of costs and Algerian taxes and Anadarko’s net equity share after recovery of such costs. Other international reserves are shown in accordance with the respective PSA or risk service contract and are calculated using the economic interest method.

      The Company’s reserves increased in 2005 primarily due to successful exploration and development drilling onshore North America and in the deepwaters of the Gulf of Mexico. The Company’s reserves decreased in 2004 primarily due to the divestiture of properties under the Company’s refocused strategy and current year production, offset in part by reserve additions related to exploration and development drilling in North America.

      Anadarko’s operations in Venezuela have been governed by an Operating Service Agreement (OSA) that was entered into with an affiliate of Petroleos de Venezuela, S.A. (PDVSA), the national oil company of Venezuela. Under the terms of the OSA, Anadarko earns a fee that is translated into barrels of oil based on current prices. This means that higher oil prices reduce the Company’s reported oil reserves and production volumes from that project; however, reserve and production fluctuations due to the economic interest calculation have no impact on the value of the project.

      In 2005, the Venezuelan Ministry of Energy and Petroleum announced that all OSAs concluded by PDVSA, between 1992 and 1997, will be subject to renegotiation. The Company and Petrobras signed a Transitory Agreement with PDVSA in September 2005. Under this agreement, the parties are currently negotiating in good faith for the conversion of the OSA to a company in which Anadarko, Petrobras and PDVSA will each have an interest. PDVSA is expected to have a majority participation interest in this company. For the year ended December 31, 2005, approximately 2% of the Company’s proved reserves were associated with operations located in Venezuela. The Company is unable to determine the impact of the current situation in Venezuela on future operating results or proved reserves.

      The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates, made by the Company’s engineers, are reviewed annually and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits sooner.

      The procedures and controls used by Anadarko in preparing its estimates of proved reserves, as of December 31, 2005, were examined by Netherland, Sewell & Associates, Inc. (NSAI), an independent worldwide petroleum consultant. NSAI reviewed fields comprising 90% of the Company’s total proved reserves, and based on those reviews and investigative analysis, conducted substantive testing on 29% of the Company’s total proved reserves.

      NSAI was able to determine that Anadarko’s estimates of proved oil and gas reserves are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles in conformity with SEC definitions and guidelines. It should be understood that NSAI’s examination of Anadarko’s oil and gas properties does not constitute a complete reserve study or one of NSAI’s traditional audits. NSAI’s examination consisted of: (1) a review and verification of the internal reserve management and control systems; (2) a series of reviews with each of the asset teams to investigate conformance with SEC

49

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Oil and Gas Reserves (Continued)

definitions and guidelines; and, (3) substantive testing of the reserve estimates, including a detailed evaluation and comparison of the estimates for certain properties.

      Anadarko’s internal controls over reserve additions include using a corporate review team comprised of five technical experts: four members from within Anadarko, who are independent of the operating groups responsible for the reserve estimates, and a member from NSAI. Through participation on the team, NSAI reviewed 79% of the Company’s 2005 proved reserve additions. A copy of the NSAI report is attached as Exhibit 99.1 of this Form 10-K.

      The Company annually reviews all PUDs, with a particular focus on those PUDs that have been booked for three or more years, to ensure that there is an appropriate plan for development. Generally, onshore United States PUDs are converted to proved developed reserves within two years. Certain projects, such as enhanced oil recovery, arctic development, deepwater development and many international programs, may take longer, sometimes beyond five years. Over 50% of the Company’s PUDs booked prior to 2002 are in Algeria and are being developed according to an Algerian government approved plan. The remaining PUDs booked prior to 2002 are primarily associated with Alaska and ongoing programs in the onshore United States for improved recovery.

      The following table presents the Company’s PUDs vintage, geographic location and percentage of total proved reserves as of December 31, 2005:

																Percentage
										Other						of Total
	U.S.			Canada			Algeria			Int’l			Total			Proved Reserves
MMBOE
Year added
2005		263			22			10			—			295			12	%
2004		187			14			4			3			208			8	%
2003		166			8			11			6			191			8	%
2002		28			10			8			—			46			2	%
2001		49			4			34			7			94			4	%
Prior years		13			5			62			11			91			4	%
Total Proved Undeveloped Reserves		706			63			129			27			925			38	%
Total Proved Reserves		1,805			262			324			58			2,449
Percentage of Total Proved Reserves		39	%		24	%		40	%		47	%		38	%

      The following table compares the December 31, 2005 PUDs to the December 31, 2004 and 2003 PUDs by year added. It illustrates the Company’s effectiveness in converting PUDs to developed reserves.

							% Reduction			% Reduction
	2005		2004		2003		2004-2005			2003-2005
MMBOE
Year added
2005		295		—		—		n/a			n/a
2004		208		310		—		33	%		n/a
2003		191		221		328		14	%		42	%
2002		46		64		100		28	%		54	%
2001		94		132		184		29	%		49	%
Prior years		91		123		174		26	%		48	%
Total Proved Undeveloped Reserves		925		850		786

50

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Oil and Gas Reserves (Continued)

		Natural Gas												Oil, Condensate and NGLs
		(Bcf)												(MMBbls)
								Other															Other
		U.S.			Canada			Int’l			Total			U.S.			Canada			Algeria			Int’l			Total
Proved Reserves
December 31, 2002			5,693			1,343			144			7,180			578			64			372			117			1,131
Revisions of prior estimates
	Performance		(228	)		57			(1	)		(172	)		15			3			1			(1	)		18
	Price-related		31			—			1			32			(1	)		(1	)		2			1			1
Extensions, discoveries and other additions			982			221			—			1,203			55			4			5			—			64
Improved recovery			18			2			—			20			72			2			—			—			74
Purchases in place			115			48			—			163			27			—			—			—			27
Sales in place			(21	)		(38	)		—			(59	)		(4	)		—			—			—			(4	)
Production			(503	)		(140	)		—			(643	)		(51	)		(7	)		(19	)		(8	)		(85	)
December 31, 2003			6,087			1,493			144			7,724			691			65			361			109			1,226
Revisions of prior estimates
	Performance		(245	)		(36	)		9			(272	)		4			(5	)		—			(4	)		(5	)
	Price-related		(4	)		1			—			(3	)		(5	)		1			7			(5	)		(2	)
Extensions, discoveries and other additions			1,387			227			—			1,614			66			5			4			—			75
Improved recovery			—			(1	)		—			(1	)		42			(1	)		—			—			41
Purchases in place			10			3			—			13			1			—			—			—			1
Sales in place			(643	)		(267	)		—			(910	)		(119	)		(19	)		—			—			(138	)
Production			(499	)		(138	)		—			(637	)		(48	)		(6	)		(22	)		(9	)		(85	)
December 31, 2004			6,093			1,282			153			7,528			632			40			350			91			1,113
Revisions of prior estimates
	Performance		29			(35	)		—			(6	)		—			—			(20	)		(16	)		(36	)
	Price-related		28			1			—			29			3			1			14			(9	)		9
Extensions, discoveries and other additions			912			188			—			1,100			74			2			4			—			80
Improved recovery			—			—			—			—			45			—			—			—			45
Purchases in place			28			2			—			30			—			—			—			—			—
Sales in place			(98	)		(4	)		(153	)		(255	)		(9	)		—			—			—			(9	)
Production			(414	)		(102	)		—			(516	)		(37	)		(3	)		(24	)		(8	)		(72	)
December 31, 2005			6,578			1,332			—			7,910			708			40			324			58			1,130
Proved Developed Reserves
December 31, 2002			4,299			995			—			5,294			377			46			191			72			686
December 31, 2003			4,725			1,164			—			5,889			451			48			182			65			746
December 31, 2004			4,469			997			—			5,466			350			29			176			51			606
December 31, 2005			4,553			1,024			—			5,577			340			28			195			31			594
Proved Undeveloped Reserves
December 31, 2002			1,394			348			144			1,886			201			18			181			45			445
December 31, 2003			1,362			329			144			1,835			240			17			179			44			480
December 31, 2004			1,624			285			153			2,062			282			11			174			40			507
December 31, 2005			2,025			308			—			2,333			368			12			129			27			536

51

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Oil and Gas Reserves (Continued)

		Total
		(MMBOE)
											Other
		U.S.			Canada			Algeria			Int’l			Total
Proved Reserves
December 31, 2002			1,526			288			372			142			2,328
Revisions of prior estimates
	Performance		(24	)		12			1			(1	)		(12	)
	Price-related		5			(1	)		2			1			7
Extensions, discoveries and other additions			219			41			5			—			265
Improved recovery			75			2			—			—			77
Purchases in place			46			8			—			—			54
Sales in place			(8	)		(6	)		—			—			(14	)
Production			(135	)		(30	)		(19	)		(8	)		(192	)
December 31, 2003			1,704			314			361			134			2,513
Revisions of prior estimates
	Performance		(37	)		(11	)		—			(3	)		(51	)
	Price-related		(6	)		1			7			(5	)		(3	)
Extensions, discoveries and other additions			297			43			4			—			344
Improved recovery			42			(1	)		—			—			41
Purchases in place			3			1			—			—			4
Sales in place			(226	)		(64	)		—			—			(290	)
Production			(131	)		(29	)		(22	)		(9	)		(191	)
December 31, 2004			1,646			254			350			117			2,367
Revisions of prior estimates
	Performance		5			(6	)		(20	)		(16	)		(37	)
	Price-related		9			1			14			(10	)		14
Extensions, discoveries and other additions			226			34			4			—			264
Improved recovery			45			—			—			—			45
Purchases in place			5			—			—			—			5
Sales in place			(25	)		(1	)		—			(25	)		(51	)
Production			(106	)		(20	)		(24	)		(8	)		(158	)
December 31, 2005			1,805			262			324			58			2,449
Proved Developed Reserves
December 31, 2002			1,093			212			191			72			1,568
December 31, 2003			1,238			242			182			65			1,727
December 31, 2004			1,095			195			176			51			1,517
December 31, 2005			1,099			199			195			31			1,524
Proved Undeveloped Reserves
December 31, 2002			433			76			181			70			760
December 31, 2003			466			72			179			69			786
December 31, 2004			551			59			174			66			850
December 31, 2005			706			63			129			27			925

52

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Discounted Future Net Cash Flows

      Estimates of future net cash flows from proved reserves of gas, oil, condensate and NGLs were made in accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” The amounts were prepared by the Company’s engineers and are shown in the following table. The estimates are based on prices at year-end. Gas, oil, condensate and NGLs prices are escalated only for fixed and determinable amounts under provisions in some contracts. Estimated future cash inflows are reduced by estimated future development, production, abandonment and dismantlement costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Income tax expense, both U.S. and foreign, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense.

      At December 31, 2005, the present value (discounted at 10%) of future net cash flows from Anadarko’s proved reserves was $29.3 billion, (stated in accordance with the regulations of the SEC and the FASB). The increase of $10.6 billion or 57% in 2005 compared to 2004 is primarily due to higher natural gas and oil prices at year-end 2005 and successful exploration and development drilling in North America. Derivative instruments that qualify as cash flow hedges have not been included in the estimates of future net cash flows. As of December 31, 2005, the undiscounted and discounted amounts related to cash flow hedges that would have reduced future net cash flows were $40 million and $37 million, respectively, before income taxes.

      The present value of future net cash flows does not purport to be an estimate of the fair market value of Anadarko’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Significant changes in estimated reserve volumes or commodity prices could have a material effect on the Company’s consolidated financial statements.

      Under the full cost method of accounting, a noncash charge to earnings related to the carrying value of the Company’s oil and gas properties on a country-by-country basis may be required when prices are low. Whether the Company will be required to take such a charge depends on the prices for crude oil and natural gas at the end of any quarter, as well as the effect of both capital expenditures and changes to proved reserves during that quarter. If a noncash charge were required, it would reduce earnings for the period and result in lower DD&A expense in future periods.

          Expected future development costs over the next three years to develop PUDs as of December 31, 2005 are as follows:

	2006		2007		2008
millions
United States	$	1,499	$	1,277	$	427
Canada		190		238		228
Algeria		92		205		161
Other International		76		47		47
Total	$	1,857	$	1,767	$	863

53

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

	2005		2004		2003
millions
United States
Future cash inflows	$	87,304	$	54,908	$	51,346
Future production costs		17,262		12,303		11,529
Future development costs		5,231		3,718		2,796
Future income tax expenses		22,671		13,582		12,736
Future net cash flows		42,140		25,305		24,285
10% annual discount for estimated timing of cash flows		22,384		13,382		11,789
Standardized measure of discounted future net cash flows		19,756		11,923		12,496
Canada
Future cash inflows		12,679		7,564		9,602
Future production costs		2,847		1,969		2,548
Future development costs		1,076		648		637
Future income tax expenses		2,692		1,493		1,714
Future net cash flows		6,064		3,454		4,703
10% annual discount for estimated timing of cash flows		3,075		1,653		2,165
Standardized measure of discounted future net cash flows		2,989		1,801		2,538
Algeria
Future cash inflows		19,192		14,348		11,092
Future production costs		1,025		1,108		1,052
Future development costs		746		599		596
Future income tax expenses		6,445		4,611		3,417
Future net cash flows		10,976		8,030		6,027
10% annual discount for estimated timing of cash flows		5,238		3,915		3,036
Standardized measure of discounted future net cash flows		5,738		4,115		2,991
Other International
Future cash inflows		2,507		2,669		2,680
Future production costs		515		543		648
Future development costs		238		365		370
Future income tax expenses		607		560		434
Future net cash flows		1,147		1,201		1,228
10% annual discount for estimated timing of cash flows		338		391		470
Standardized measure of discounted future net cash flows		809		810		758
Total
Future cash inflows		121,682		79,489		74,720
Future production costs		21,649		15,923		15,777
Future development costs		7,291		5,330		4,399
Future income tax expenses		32,415		20,246		18,301
Future net cash flows		60,327		37,990		36,243
10% annual discount for estimated timing of cash flows		31,035		19,341		17,460
Standardized measure of discounted future net cash flows	$	29,292	$	18,649	$	18,783

54

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves

	2005			2004			2003
millions
United States
Beginning of year	$	11,923		$	12,496		$	8,597
Sales and transfers of oil and gas produced, net of production costs		(3,633	)		(3,206	)		(2,698	)
Net changes in prices and production costs		10,768			1,519			3,492
Changes in estimated future development costs		(255	)		(527	)		288
Extensions, discoveries, additions and improved recovery, less related costs		2,826			4,233			4,053
Development costs incurred during the period		874			818			524
Revisions of previous quantity estimates		(48	)		(707	)		(616	)
Purchases of minerals in place		73			28			501
Sales of minerals in place		(324	)		(4,118	)		(44	)
Accretion of discount		1,828			1,876			1,271
Net change in income taxes		(4,043	)		(89	)		(2,154	)
Other		(233	)		(400	)		(718	)
End of year		19,756			11,923			12,496
Canada
Beginning of year		1,801			2,538			1,746
Sales and transfers of oil and gas produced, net of production costs		(722	)		(689	)		(616	)
Net changes in prices and production costs		1,809			(75	)		320
Changes in estimated future development costs		(259	)		(84	)		(32	)
Extensions, discoveries, additions and improved recovery, less related costs		648			507			321
Development costs incurred during the period		76			158			152
Revisions of previous quantity estimates		(104	)		(124	)		136
Purchases of minerals in place		4			7			64
Sales of minerals in place		(8	)		(785	)		(50	)
Accretion of discount		241			329			257
Net change in income taxes		(478	)		143			68
Other		(19	)		(124	)		172
End of year		2,989			1,801			2,538
Algeria
Beginning of year		4,115			2,991			3,036
Sales and transfers of oil produced, net of production costs		(1,225	)		(705	)		(493	)
Net changes in prices and production costs		3,732			1,962			32
Changes in estimated future development costs		(235	)		(23	)		(139	)
Extensions, discoveries, additions and improved recovery, less related costs		120			73			59
Development costs incurred during the period		45			36			60
Revisions of previous quantity estimates		(465	)		(118	)		20
Accretion of discount		650			471			478
Net change in income taxes		(1,034	)		(663	)		29
Other		35			91			(91	)
End of year	$	5,738		$	4,115		$	2,991

55

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves (Continued)

	2005			2004			2003
millions
Other International
Beginning of year	$	810		$	758		$	731
Sales and transfers of oil and gas produced, net of production costs		(253	)		(160	)		(115	)
Net changes in prices and production costs		771			272			(59	)
Changes in estimated future development costs		14			(46	)		(5	)
Development costs incurred during the period		57			66			64
Revisions of previous quantity estimates		(688	)		(122	)		19
Sales of minerals in place		(51	)		—			—
Accretion of discount		118			103			105
Net change in income taxes		(75	)		(104	)		48
Other		106			43			(30	)
End of year		809			810			758
Total
Beginning of year		18,649			18,783			14,110
Sales and transfers of oil and gas produced, net of production costs		(5,833	)		(4,760	)		(3,922	)
Net changes in prices and production costs		17,080			3,678			3,785
Changes in estimated future development costs		(735	)		(680	)		112
Extensions, discoveries, additions and improved recovery, less related costs		3,594			4,813			4,433
Development costs incurred during the period		1,052			1,078			800
Revisions of previous quantity estimates		(1,305	)		(1,071	)		(441	)
Purchases of minerals in place		77			35			565
Sales of minerals in place		(383	)		(4,903	)		(94	)
Accretion of discount		2,837			2,779			2,111
Net change in income taxes		(5,630	)		(713	)		(2,009	)
Other		(111	)		(390	)		(667	)
End of year	$	29,292		$	18,649		$	18,783

56