Anadarko Petroleum 8-K/A Financial Statements and Exhibits

Exhibit 99.2

Kerr-McGee Corporation and Subsidiary Companies

Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Stockholder

Kerr-McGee Corporation

We have audited the accompanying consolidated balance sheets of Kerr-McGee Corporation as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income and stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Kerr-McGee Corporation at December 31, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations. As discussed in Note 7 to the consolidated financial statements, effective December 31, 2003, the Company adopted FASB Interpretation No. 46,Consolidation of Variable Interest Entities.

/S/ ERNST & YOUNG LLP

Oklahoma City, Oklahoma

March 14, 2006,

except for Note 26, as to which the date is

September 6, 2006

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Kerr-McGee Corporation and Subsidiary Companies

Consolidated Statement of Income

(Millions of dollars, except per-share amounts)	2005			2004			2003
Revenues
Oil and gas sales	$	4,704		$	3,165		$	2,014
Loss on commodity derivatives		(1,018	)		(553	)		(216	)
Gas marketing revenues		804			419			298
Other revenues		73			65			36
Total Revenues		4,563			3,096			2,132
Operating Expenses
Lease operating costs		494			322			219
Production and ad valorem taxes		157			104			53
Transportation expense		92			73			50
General and administrative expense		248			186			204
Exploration expense		389			330			331
Gas gathering, processing and other expenses		112			90			69
Gas marketing costs		800			418			291
Depreciation, depletion and amortization		849			646			407
Accretion expense		22			18			15
Asset impairments		17			21			14
(Gain) loss on sales of oil and gas properties		(211	)		29			(30	)
Provision for environmental remediation costs		12			28			6
Total Operating Expenses		2,981			2,265			1,629
Operating Income		1,582			831			503
Interest expense		(226	)		(244	)		(250	)
Loss on early repayment and modification of debt		(42	)		—			—
Other income (expense)		104			(21	)		(15	)
Income from Continuing Operations before Income Taxes		1,418			566			238
Provision for Income Taxes		(486	)		(191	)		(13	)
Income from Continuing Operations		932			375			225
Income from Discontinued Operations, net of taxes		2,279			29			29
Cumulative Effect of Change in Accounting Principle, net of taxes		—			—			(35	)
Net Income	$	3,211		$	404		$	219
Income per Common Share
Basic –
Continuing operations	$	3.56		$	1.49		$	1.12
Discontinued operations		8.70			.11			.14
Cumulative effect of change in accounting principle		—			—			(.17	)
Net income	$	12.26		$	1.60		$	1.09
Diluted –
Continuing operations	$	3.48		$	1.45		$	1.11
Discontinued operations		8.47			.10			.14
Cumulative effect of change in accounting principle		—			—			(.16	)
Net income	$	11.95		$	1.55		$	1.09

The accompanying notes are an integral part of these consolidated financial statements.

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Kerr-McGee Corporation and Subsidiary Companies

Consolidated Balance Sheet

(Millions of dollars)	2005			2004
ASSETS
Current Assets
Cash and cash equivalents	$	1,053		$	76
Accounts receivable		753			603
Derivatives and other current assets		205			145
Deferred income taxes		547			309
Assets of discontinued operations		691			754
Total Current Assets		3,249			1,887
Property, Plant and Equipment – Net		8,435			8,190
Deferred Charges, Derivatives and Other Assets		427			436
Intangible Assets		29			38
Assets Held for Sale and of Discontinued Operations		986			2,782
Goodwill		1,150			1,185
Total Assets	$	14,276		$	14,518
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	425		$	366
Long-term debt due within one year		306			463
Income taxes payable		429			111
Derivative liabilities		1,506			349
Accrued liabilities		846			607
Liabilities associated with discontinued operations		419			609
Total Current Liabilities		3,931			2,505
Long-Term Debt		2,277			3,236
Noncurrent Liabilities
Deferred income taxes		1,445			1,626
Asset retirement obligations		310			305
Derivative liabilities		663			208
Other		466			429
Liabilities associated with discontinued operations		1,069			891
Total Noncurrent Liabilities		3,953			3,459
Contingencies and Commitments (Notes 16 and 17)
Stockholders’ Equity
Common stock, par value $1.00 – 500,000,000 and 300,000,000 shares authorized, 232,231,760 and 296,992,910 shares issued at December 31, 2005 and 2004, respectively		120			152
Capital in excess of par value		3,702			4,205
Preferred stock purchase rights		1			2
Retained earnings		1,704			1,102
Accumulated other comprehensive loss		(1,079	)		(79	)
Common stock in treasury, at cost – 3,456,918 and 159,856 shares at December 31, 2005 and 2004, respectively		(266	)		(8	)
Deferred compensation		(67	)		(56	)
Total Stockholders’ Equity		4,115			5,318
Total Liabilities and Stockholders’ Equity	$	14,276		$	14,518

The “successful efforts” method of accounting for oil and gas exploration and production activities has been followed in preparing this balance sheet.

The accompanying notes are an integral part of these consolidated financial statements.

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Kerr-McGee Corporation and Subsidiary Companies

Consolidated Statement of Cash Flows

(Millions of dollars)	2005			2004			2003
Cash Flows from Operating Activities
Net income	$	3,211		$	404		$	219
Adjustments to reconcile net income to net cash provided by operating activities –
Depreciation, depletion and amortization		1,177			1,124			814
Deferred income taxes		83			108			156
Unrealized losses on derivatives		200			12			5
Dry hole expense		185			161			181
Noncash stock-based compensation and ESOP expense		54			25			42
Asset impairments		17			36			14
Gain on sale of the North Sea oil and gas business		(2,240	)		—			—
(Gain) loss on sale of assets		(327	)		20			(40	)
Loss on early repayment and modification of debt		42			—			—
Accretion expense		30			30			25
Cumulative effect of change in accounting principle		—			—			35
Provision for environmental remediation and restoration, net of reimbursements		49			92			62
Other noncash items affecting net income		116			147			97
Changes in assets and liabilities: (1)
(Increase) decrease in accounts receivable		(232	)		(236	)		45
(Increase) decrease in inventories		(66	)		83			22
Decrease in deposits, prepaids and other assets		7			48			12
Increase (decrease) in accounts payable, derivatives and accrued liabilities		390			136			(57	)
Increase in income taxes payable		418			4			16
Other		(11	)		(144	)		(130	)
Net cash provided by operating activities		3,103			2,050			1,518
Cash Flows from Investing Activities
Capital expenditures		(1,751	)		(1,262	)		(981	)
Dry hole costs		(169	)		(78	)		(181	)
Acquisitions, net of cash acquired(2)		—			43			(110	)
Net proceeds from sale of the North Sea oil and gas business		3,305			—			—
Proceeds from sale of assets		704			23			304
Other investing activities		(8	)		12			17
Net cash provided by (used in) investing activities		2,081			(1,262	)		(951	)
Cash Flows from Financing Activities (2)
Issuance of common stock upon exercise of stock options		225			55			—
Sale of Tronox stock		225			—			—
Purchases of treasury stock		(250	)		—			—
Repurchases of common stock under the tender offer		(3,975	)		—			—
Dividends paid		(153	)		(205	)		(181	)
Repayment of debt		(4,751	)		(1,278	)		(369	)
Proceeds from borrowings		4,800			686			31
Debt issuance costs and other		(71	)		(8	)		(1	)
Cash paid for modification of debt		(22	)		—			—
Settlement of Westport derivatives		(238	)		(101	)		—
Net cash used in financing activities		(4,210	)		(851	)		(520	)
Effects of Exchange Rate Changes on Cash and Cash Equivalents		3			(3	)		5
Net Increase (Decrease) in Cash and Cash Equivalents		977			(66	)		52
Cash and Cash Equivalents at Beginning of Year		76			142			90
Cash and Cash Equivalents at End of Year	$	1,053		$	76		$	142

⁽¹⁾ Excluding effects of acquisitions and dispositions of businesses.

⁽²⁾ See Notes 4 and 8 for information regarding the business combination that occurred in 2004 and the related noncash financing and investing activities.

The accompanying notes are an integral part of these consolidated financial statements.

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Kerr-McGee Corporation and Subsidiary Companies

Consolidated Statement of Comprehensive Income and Stockholders’ Equity

(Millions of dollars)	Common Stock			Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Deferred Compensation and Other			Total Stockholders’ Equity
Balance at December 31, 2002	$	100		$	1,687		$	886		$	(62	)	$	—		$	(75	)	$	2,536
Comprehensive Income:
Net income		—			—			219			—			—			—			219
Other comprehensive income		—			—			—			17			—			—			17
Comprehensive income																				236
Stock option exercises		—			1			—			—			—			—			1
Issuance of employee stock-based awards, net of forfeitures		1			21			—			—			(1	)		(20	)		1
Amortization of deferred compensation cost		—			—			—			—			—			10			10
ESOP deferred compensation and other		—			(1	)		4			—			(1	)		32			34
Dividends declared ($.90 per share)		—			—			(182	)		—			—			—			(182	)
Balance at December 31, 2003		101			1,708			927			(45	)		(2	)		(53	)		2,636
Comprehensive Income:
Net income		—			—			404			—			—			—			404
Other comprehensive loss		—			—			—			(34	)		—			—			(34	)
Comprehensive income																				370
Westport merger		49			2,402			—			—			—			(3	)		2,448
Stock option exercises		2			53			—			—			—			—			55
Issuance of employee stock-based awards, net of forfeitures		—			24			—			—			(6	)		(23	)		(5	)
Amortization of deferred compensation cost		—			—			—			—			—			18			18
ESOP deferred compensation and other		—			—			(1	)		—			—			7			6
Tax benefit from stock-based awards		—			18			—			—			—			—			18
Dividends declared ($.90 per share)		—			—			(228	)		—			—			—			(228	)
Balance at December 31, 2004		152			4,205			1,102			(79	)		(8	)		(54	)		5,318
Comprehensive Income:
Net income		—			—			3,211			—			—			—			3,211
Other comprehensive loss		—			—			—			(1,000	)		—			—			(1,000	)
Comprehensive income																				2,211
Gain on sale of Tronox stock (Note 3)		—			19			—			—			—			—			19
Shares issued upon conversion of debt		10			583			—			—			—			—			593
Purchases of treasury shares		—			—			—			—			(250	)		—			(250	)
Shares repurchased and retired		(47	)		(1,410	)		(2,517	)		—			—			(1	)		(3,975	)
Stock option exercises		4			221			—			—			—			—			225
Issuance of employee stock-based awards, net of forfeitures		1			52			—			—			(8	)		(50	)		(5	)
Amortization of deferred compensation cost		—			—			—			—			—			32			32
ESOP deferred compensation		—			—			—			—			—			7			7
Tax benefit from stock-based awards		—			32			—			—			—			—			32
Dividends declared ($.30 per share)		—			—			(92	)		—			—			—			(92	)
Balance at December 31, 2005	$	120		$	3,702		$	1,704		$	(1,079	)	$	(266	)	$	(66	)	$	4,115

Components of other comprehensive income (loss) for the years ended December 31, 2005, 2004 and 2003 are as follows (net of taxes and reclassification adjustments, which are presented in Note 8).

(Millions of dollars)	2005			2004			2003
Foreign currency translation adjustments	$	(57	)	$	29		$	56
Net losses on cash flow hedges		(938	)		(69	)		(31	)
Available-for-sale securities		—			(5	)		(1	)
Minimum pension liability adjustments		(6	)		11			(7	)
Minority interest		1			—			—
Other comprehensive income (loss)	$	(1,000	)	$	(34	)	$	17

The accompanying notes are an integral part of these consolidated financial statements.

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Notes to Consolidated Financial Statements

1.The Company and Significant Accounting Policies

The Company

Kerr-McGee is an independent exploration and production company that explores for, develops, produces and markets crude oil and natural gas, with major areas of operation in the United States and China. Exploration efforts also extend to the North Slope of Alaska and offshore West Africa, Brazil and Trinidad and Tobago. As of December 31, 2005, Kerr-McGee also owned 56.7% of Tronox, a former wholly-owned subsidiary. Tronox is primarily engaged in the production and marketing of titanium dioxide, a white pigment used in a wide range of products. Tronox has production facilities in the United States, Australia, Germany and the Netherlands. The terms “Kerr-McGee,” “the company,” “we,” “our,” and similar terms are used interchangeably in these consolidated financial statements to refer to the consolidated group or to one or more of the companies that are part of the consolidated group. The term “Tronox” is used interchangeably in this Form 10-K to refer to Tronox Incorporated, one or more of its subsidiaries or the consolidated group of Tronox Incorporated and its subsidiaries.

Information in the accompanying consolidated financial statements and notes thereto has been updated since their original issuance in the company’s Annual Report on Form 10-K for the year ended December 31, 2005 to reflect the effects of certain events that occurred subsequent to that date, as discussed in Note 26.

In 2005, the company made a number of strategic decisions in an effort to reposition Kerr-McGee as a pure-play exploration and production company and enhance value for its stockholders. The company’s strategic plan includes the separation of the chemical business and divestitures of certain oil and gas assets, as more fully discussed below.

• In March 2005, the company’s Board of Directors (the Board) authorized management to pursue alternatives for the separation of the chemical business, including a spinoff or sale. In October 2005, the Board approved the separation of the chemical business through an initial public offering (IPO), with the expectation that it would be followed by a distribution of Kerr-McGee’s remaining ownership in the chemical business subsidiary to Kerr-McGee’s stockholders. The IPO of Tronox Class A common stock was completed in November 2005. On March 8, 2006, the Board declared a dividend of Tronox’s Class B common stock owned by Kerr-McGee to its stockholders (the Distribution). Additional information about the IPO and the Distribution is provided in Notes 3 and 26.

• In April 2005, the company announced its decision to divest lower-growth or shorter-life and higher-decline oil and gas properties. In the fourth quarter of 2005, the company divested its North Sea oil and gas business, certain noncore oil and gas properties onshore in the United States and other assets in several transactions, for aggregate cash proceeds of $4 billion. The net cash proceeds from these divestitures were used to repay borrowings associated with the tender offer discussed below. In January 2006, the company entered into an agreement to sell its interest in Gulf of Mexico shelf oil and gas properties for approximately $1.34 billion in cash. Information about these transactions is provided in Notes 2 and 26.

• In March 2005, the Board authorized a share repurchase program initially set at $1 billion, with an expectation to expand the program as the chemical business separation proceeded. The company repurchased 3.1 million shares of its common stock (on a pre-split basis) at an aggregate cost of $250 million under this program before its termination in connection with the Board’s approval of the tender offer discussed below.

• On April 14, 2005, the company announced its intention to commence a tender offer for its common stock with an aggregate purchase cost of up to $4 billion. Under the tender offer, which was completed in May 2005, the company repurchased 46.7 million of its shares at $85 per share (on a pre-split basis), which represented 29% of shares outstanding at March 31, 2005. The tender offer was financed with the net proceeds of borrowings, which are discussed in Note 10, and cash on hand. By the end of November, the company repaid $4.25 billion of borrowings under the term loans originated in connection with the tender offer. The repayment was funded primarily from the net proceeds of asset sales and the Tronox IPO.

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• In May 2005, the Board revised the company’s dividend policy to a level more consistent with that of other pure-play exploration and production companies. Starting with the July 2005 dividend payment, the annual dividend was reduced from $.90 to $.10 per share.

• In January 2006, the Board approved a $1 billion stock repurchase program and authorized the redemption of the company’s 7% debentures due 2011 at face value of $250 million.

Significant Accounting Policies

Basis of Presentation –The consolidated financial statements include the accounts of all subsidiary companies controlled by Kerr-McGee and the proportionate share of unincorporated joint ventures in which the company has an undivided interest. Minority interest represents minority shareholders’ proportionate share of the equity of Tronox. All material intercompany transactions have been eliminated.

Investments in entities over which Kerr-McGee has significant influence, but not control, are carried at cost adjusted for equity in undistributed earnings and distributions. Equity in undistributed earnings of such entities is included in other income (expense) in the Consolidated Statement of Income.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates as additional information becomes known.

Reclassifications – With the separation of the chemical business, the income statement format for all periods presented has been changed to better reflect the operations of an exploration and production company. The operating results of and other costs directly associated with Tronox and the company’s North Sea oil and gas business are reported as discontinued operations. Unless indicated otherwise, information presented in the footnotes to the financial statements relates only to the company’s continuing operations.

Foreign Currency Translation –The U.S. dollar is considered the functional currency for each of the company’s international operations, except for Tronox’s European operations. Foreign currency transaction gains or losses are recognized in the period incurred and are included in other income (expense) in the Consolidated Statement of Income. The euro is the functional currency for Tronox’s European operations. Translation adjustments resulting from translating the functional currency financial statements into U.S. dollar equivalents are reflected as a separate component of other comprehensive income (loss).

Cash Equivalents –The company considers all investments with original maturities of three months or less to be cash equivalents. Cash equivalents held by the company at December 31, 2005 and 2004 were $923 million and $17 million, respectively, and were comprised of time deposits, certificates of deposit and U.S. government securities.

Accounts Receivable and Receivable Sales–Accounts receivable are reflected at their net realizable value, reduced by an allowance for doubtful accounts to allow for expected credit losses. The allowance is estimated by management, based on factors such as age of the related receivables and historical experience, giving consideration to customer profiles. The company does not generally charge interest on accounts receivable; however, certain operating agreements have provisions for interest and penalties that may be invoked, if deemed necessary. Accounts receivable are aged in accordance with contract terms and are written off when deemed uncollectible. Any subsequent recoveries of amounts written off are credited to the allowance for doubtful accounts.

Through 2005, Tronox had an accounts receivable monetization program. Information regarding the program is provided in Note 11.

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Concentration of Credit Risk –The company has significant credit risk exposure due to concentration of its crude oil and natural gas receivables with several significant customers. The largest purchaser of Kerr-McGee’s natural gas production accounted for 29% of total crude oil and natural gas sales revenues in 2005. To reduce credit risk, the company performs evaluations of its customers’ financial condition, including establishing credit limits for its customers, and uses credit risk insurance policies from time to time as deemed appropriate to mitigate credit risk. Additionally, the company requires certain customers to post letters of credit, provide parent company guarantees or make prepayments from time to time as deemed appropriate to mitigate credit risk.

Inventories –Inventories are stated at the lower of cost or market. The costs of the company’s product inventories are determined by the first-in, first-out (FIFO) method. Inventory carrying values include material costs, labor and associated indirect manufacturing expenses. Costs for materials and supplies, excluding ore, are determined by average cost to acquire. Raw materials (ore) are carried at actual cost.

Property, Plant and Equipment

Property, plant and equipment is stated at cost less accumulated depreciation, depletion and amortization. Maintenance and repairs are expensed as incurred, except that costs of replacements or renewals that improve or extend the lives of existing properties are capitalized.

Exploration and Production– Exploration expenditures, including geological and geophysical costs, delay rentals and exploration department overhead are charged against earnings as incurred. Costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the discovery. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to dry hole costs. Costs of successful exploratory wells, all developmental wells, production equipment and facilities are capitalized and then depleted using the unit-of-production method by field as oil and gas are produced.

Individual undeveloped leases in the U.S. with an original acquisition cost of greater than $2 million are assessed periodically for impairment based on the company’s current exploration plans and a valuation allowance is provided if impairment is indicated. Lease acquisition costs on unproved oil and gas properties whose acquisition costs are not individually significant are amortized over their lease terms at rates that provide for full amortization of unsuccessful leases upon abandonment. Costs of abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved oil and gas properties. Under this method, the cost of all unsuccessful leases is charged to exploration expense, while the cost of successful activities becomes part of the carrying amount of proved oil and gas properties. In the case of unproved property costs associated with proved reserves acquired in a business combination, recoverability is assessed on a field-by-field basis and a loss is recognized, if indicated, based on the results of drilling activity, planned future drilling activity and management’s estimate of the remaining value attributed to the probable and possible reserves. Unproved acquisition costs not expected to be recovered are charged to expense when that determination is made, while successful activities become part of the carrying amount of proved properties.

Depreciation and Depletion– Property, plant and equipment is depreciated or depleted over its estimated life using the unit-of-production or the straight-line method. Successful exploratory wells and development costs are amortized using the unit-of-production method based on total estimated proved developed oil and gas reserves. Producing leasehold, platform costs, asset retirement costs and acquisition costs of proved properties are amortized using the unit-of-production method based on total estimated proved reserves. Non-oil and gas assets are depreciated using the straight-line method over their estimated useful lives.

Retirements and Sales– The cost and related depreciation, depletion and amortization reserves are removed from the respective accounts upon retirement or sale of property, plant and equipment.

Asset Exchanges – Effective July 1, 2005, the company adopted Statement of Financial Accounting Standards No. 153, “Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29” (FAS No. 153), for exchanges of nonmonetary assets occurring after the implementation date. Prior to implementing FAS No. 153, the company generally did not recognize gains on nonmonetary exchanges involving proved oil and gas properties; however, for exchange transactions involving monetary consideration (if such consideration was less than 25% of the fair value of assets exchanged), a

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proportionate amount of the indicated gain was recognized based on the percentage of monetary consideration received. Exchanges of proved oil and gas properties involving receipt of monetary consideration of 25% or more were accounted for at fair value with full gain recognition. According to the provisions of FAS No. 153, all nonmonetary asset exchanges that have commercial substance, as defined, will be measured at fair value with gain or loss recognized in earnings.

Capitalized Interest – The company capitalizes interest costs on major projects that require an extended period of time to complete. Interest capitalized in 2005, 2004 and 2003 was $28 million, $13 million and $10 million, respectively.

Asset Impairments–Proved oil and gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are calculated based on estimated future oil and gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these estimated future cash flows (undiscounted and without interest charges) is less than the carrying amount of the property, an impairment loss is recognized for the excess of the property’s carrying amount over its estimated fair value based on estimated discounted future cash flows.

Other assets are reviewed for impairment by asset group for which the lowest level of independent cash flows can be identified. If the sum of these estimated future cash flows (undiscounted and without interest charges) is less than the carrying amount of the assets, an impairment loss is recognized for the excess of the carrying amount of the asset over its estimated fair value.

Assets Held for Sale–Assets are classified as held for sale when the company commits to a plan to sell the assets and completion of the sale is probable and expected to occur within one year. Upon classification as held-for-sale, long-lived assets are no longer depreciated or depleted and a loss is recognized, if any, based on the excess of carrying value over fair value less costs to sell. Previous losses may be reversed up to the original carrying value as estimates are revised; however, gains are recognized only upon disposition.

Goodwill and Other Intangible Assets –Goodwill is initially measured as the excess of the purchase price of an acquired entity over the fair values of individual assets acquired and liabilities assumed. Goodwill and certain indefinite-lived intangibles are not amortized but are reviewed annually for impairment, or more frequently if impairment indicators arise. The annual assessment for goodwill impairment is completed as of June 30 each year. Based upon the most recent assessment, no impairment was indicated. Intangibles with finite lives are amortized over their estimated useful lives. Intangibles subject to amortization are reviewed for impairment whenever impairment indicators are present.

Derivative Instruments and Hedging Activities –The company accounts for all derivative financial instruments in accordance with FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS No. 133). Derivative instruments are recorded as assets or liabilities at fair value. Fair value is estimated based on market quotes for exchange-traded futures contracts, if available, or dealer quotes for financial instruments with similar characteristics. An option-pricing model is used to determine fair value of option-based derivative instruments, such as collars.

The company uses futures, forwards, options, collars and swaps to reduce the effects of fluctuations in crude oil and natural gas prices, foreign currency exchange rates and interest rates. Unrealized gains and losses on derivative instruments that are designated as cash flow hedges and that qualify for hedge accounting under the provisions of FAS No. 133 are recorded in accumulated other comprehensive income (loss), net of hedge ineffectiveness which is included in current earnings. Realized hedging gains and losses are recognized in earnings in the periods during which the hedged forecasted transactions affect earnings. For discontinued cash flow hedges, changes in the fair value of the derivative instrument are recognized in earnings prospectively through the remaining duration of the contracts. Unrealized gains or losses recorded in other comprehensive income (loss) prior to the hedging relationship being discontinued remain in stockholders’ equity until the original hedged forecasted transaction affects earnings.

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Derivative instruments that are not designated as hedges or that do not meet the criteria for hedge accounting and those designated as fair-value hedges under FAS No. 133 are recorded at fair value, with gains or losses reported currently in earnings (together with offsetting gains or losses on the hedged item for fair value hedges).

Cash flows associated with derivative instruments are included in the same category in the Consolidated Statement of Cash Flows as the cash flows from the item being hedged, unless a derivative instrument includes an other-than-insignificant financing element at inception, in which case associated cash flows are reflected in cash flows from financing activities.

Environmental Remediation and Other Contingencies–As sites of environmental concern are identified, the company assesses the existing conditions, claims and assertions, and records an estimated undiscounted liability when environmental assessments and/or remedial efforts are probable and the associated costs can be reasonably estimated. Estimates of environmental liabilities, which include the cost of investigation and remediation, are based on a variety of matters, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number of factors could significantly change the company’s estimate of environmental remediation costs, such as changes in laws and regulations, or changes in their interpretation or administration, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment and technology.

To the extent costs of investigation and remediation have been incurred and are recoverable from the U.S. government under Title X of the Energy Policy Act of 1992, from insurers under certain insurance policies or other parties, and such recoveries are deemed probable, the company records a receivable for the estimated amounts recoverable (undiscounted). Receivables are reflected as either current or long-term assets depending on estimated timing of collection.

Asset Retirement Obligations–An asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The company adopted the standard on January 1, 2003, which resulted in a charge to earnings of $35 million (net of an income tax benefit of $18 million) to recognize the cumulative effect of adopting the new standard.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations - An Interpretation of FASB Statement No. 143” (FIN No. 47) to clarify that an entity must recognize a liability for the fair value of a conditional asset retirement obligation when incurred, if the liability’s fair value can be reasonably estimated. Conditional asset retirement obligations under this pronouncement are legal obligations to perform asset retirement activities when the timing and/or method of settlement are conditional on a future event or may not be within the control of the entity. FIN No. 47 also provides additional guidance for evaluating whether sufficient information to reasonably estimate the fair value of an asset retirement obligation is available. The company adopted FIN No. 47 as of December 31, 2005 with no material effect to the company’s financial position or results of operations and no effect on reported cash flows.

The company accrues an ARO associated with its oil and gas wells and platforms when those assets are placed in service. The ARO is recorded at its estimated fair value and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Fair value is measured using expected future cash outflows discounted at the company’s credit-adjusted risk-free interest rate. No market-risk premium has been included in the company’s calculation of ARO balances since no reliable estimate can be made by the company.

Repurchases and Retirements of Capital Stock –The company records treasury stock purchases at cost, which includes incremental direct transaction costs. Upon retirement of repurchased shares, the excess of purchase cost over associated common stock par value and preferred stock purchase rights is allocated to capital in excess of par value, with the remaining cost, if any, charged against retained earnings. The allocation to capital in excess of par value is based on the per-share amount of capital in excess of par value for all shares.

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Employee Stock-Based Compensation

Intrinsic-Value Method – The company accounts for its stock-based awards, which consist of fixed-price stock options, restricted stock and performance units, under the intrinsic-value method permitted by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). Performance units provide for cash awards based on the company’s achievement of specified total stockholder return targets over a stated period. In accordance with APB No. 25, compensation cost associated with stock-based awards is determined using the following measurement principles:

• For restricted stock, cost is measured using the market price on the grant date

• For stock options, cost is equal to the excess, if any, of the market price of Kerr-McGee’s stock on the date of grant over the exercise price

• For performance units, the liability is determined at each reporting date based on the estimated payout by reference to Kerr-McGee’s total stockholder return relative to selected peer companies. The liability so determined is further adjusted to reflect the extent to which employee services necessary to earn the awards have been rendered. Compensation cost for any given period equals the increase or decrease in the liability for outstanding awards

• Upon employee forfeiture of an award, any associated compensation expense recognized prior to the forfeiture is reversed.

The aggregate intrinsic value of restricted stock and stock options granted is initially recognized as an increase in common stock and capital in excess of par value, with a corresponding increase in deferred compensation cost in stockholders’ equity. Deferred compensation is amortized ratably as a reduction of earnings over the vesting periods of the underlying grants or over the service period, if shorter.

Pro Forma Fair-Value Method –Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (FAS No. 123), prescribes an alternative fair-value method of accounting for employee stock-based awards. Following this method, compensation expense for such awards is measured based on the estimated grant-date fair value and recognized as the related employee services are provided. If compensation expense for stock-based awards had been determined using the fair value-based method, net income would have been lower, as presented in the following table. Pro forma stock-based compensation expense presented below may not be representative of future compensation expense using the fair-value method of accounting as the number and terms of awards granted in a particular year may not be indicative of the number and terms of awards granted in future years.

(Millions of dollars, except per share amounts)	2005			2004			2003
Net income as reported	$	3,211		$	404		$	219
Add: Stock-based employee compensation expense included in reported net income, net of taxes		31			11			7
Deduct: Stock-based compensation expense determined using a fair-value method, net of taxes		(42	)		(24	)		(23	)
Pro forma net income	$	3,200		$	391		$	203
Net income per share –
Basic -
As reported	$	12.26		$	1.60		$	1.09
Pro forma		12.22			1.55			1.01
Diluted -
As reported	$	11.95		$	1.55		$	1.09
Pro forma		11.91			1.51			1.01

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The following table presents inputs and assumptions used to estimate the grant-date fair value of employee stock options that had no intrinsic value on the fair value measurement date.

	2005			2004			2003
Inputs and assumptions –
Expected life (years)		6.0			5.8			5.8
Risk-free interest rate		3.9	%		3.5	%		3.6	%
Expected dividend yield		3.5			3.6			3.3
Expected volatility		27.4	%		22.6	%		32.7	%
Weighted-average exercise price of options granted(1)	$	56.57		$	49.45		$	42.93
Weighted-average fair value of options granted(1)		12.50			8.63			11.09

⁽¹⁾ The per-option exercise prices and fair values do not give effect to the two-for-one stock split completed in 2006. See Note 26.

While all options granted in 2005 had the same contractual terms, for some of the options, the compensation cost measurement date, as defined by FAS No. 123, occurred subsequent to the date on which the options’ exercise price was set. Because the market price of Kerr-McGee’s stock increased by the measurement date, those options had intrinsic value of $18.26 and an estimated fair value of $22.89, on a pre-split basis, which was determined using the following assumptions: expected life of six years, risk-free interest rate of 4.0%, expected dividend yield of 3.5% and expected volatility of 26.2%.

New Accounting Standard – In December 2004, the FASB issued Statement No. 123 (revised 2004), “Share-Based Payment” (FAS No. 123R), which replaces FAS No. 123 and supersedes APB No. 25. FAS No. 123R requires all share-based payments to employees to be recognized in the financial statements based on their fair values. The company adopted FAS No. 123R effective January 1, 2006 using the modified prospective method, as permitted by the standard. The modified prospective method requires that compensation expense be recorded for all unvested share-based compensation awards at the beginning of the first quarter of adoption. The following provides a summary of some of the implementation effects of this standard:

• A cumulative effect of adoption adjustment, which is required to be recognized in earnings, reflected the change in the company’s accounting policy for forfeitures and an adjustment to the performance units liability to its estimated fair value, which was lower than the intrinsic value as of January 1, 2006. FAS No. 123R requires that compensation cost be recognized only for awards for which the requisite service is expected to be rendered, using an estimated forfeiture rate. The FAS No. 123R cumulative effect adjustment was not material.

• Stock-based compensation expense recognized in the Consolidated Statement of Income will be higher in the future, reflecting a change in the measurement basis of stock options from intrinsic to fair value. The magnitude of the increase will depend upon the number of options granted and other factors affecting fair value.

• Net cash flows provided by operating activities will be lower and cash flows from financing activities will be higher by the amount of the reduction in cash income taxes as a result of tax deductibility of stock options and restricted stock awards.

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Employee Stock Ownership Plan (ESOP)– The company has a leveraged ESOP plan with sponsor financing. Sponsor financing is excluded from debt balances in the accompanying Consolidated Balance Sheet. The company stock owned by the ESOP trust is held in a loan suspense account. Deferred compensation, representing the unallocated ESOP shares, is reflected as a reduction of stockholders’ equity. The company’s matching contributions and dividends on the shares held by the ESOP trust are used to repay the debt, and stock is released from the loan suspense account as the principal and interest are paid. The expense is recognized and stock is then allocated to participants’ accounts at market value as the participants’ contributions are made to the Savings Investment Plan (SIP). Dividends paid on the common stock held in participants’ accounts are also used to repay the loans, and stock with a value equal to the amount of dividends is allocated to participants’ accounts. All ESOP shares are considered outstanding for earnings per share calculations. Dividends on ESOP shares are charged to retained earnings.

Revenue Recognition–Revenue derived from product sales is recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, sales price is fixed or determinable and collectibility is reasonably assured. Oil and gas sales involving balancing arrangements among partners are recognized as revenues when the oil or gas is sold using the entitlements method of accounting based on the company’s net working interest and a receivable or deferred revenue is recorded for any imbalance. At December 31, 2005 and 2004, both the quantity and dollar amount of oil and gas balancing arrangements were immaterial.

Shipping and Handling Fees and Costs–All amounts billed to a customer in a chemical sales transaction related to shipping and handling represent revenues earned and are reported as revenues. Costs incurred by the company for shipping and handling, including transportation costs paid to third-party shippers to transport oil and gas production, are reported as an expense.

Income Taxes–Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, except for deferred taxes on income considered to be indefinitely reinvested in certain foreign subsidiaries.

2. Discontinued Operations and Asset Divestitures and Exchanges

Overview – As discussed in Note 1, the company made a number of strategic decisions in 2005 with the goal of repositioning Kerr-McGee as a pure-play exploration and production company and enhancing value for its stockholders. The company’s strategic plan includes divestitures of certain lower-growth or shorter-life and higher-decline oil and gas assets, including the company’s North Sea oil and gas business and selected oil and gas properties in the U.S., and the separation of the chemical business. At the same time, the company is accelerating its U.S. onshore development activities, with a focus on the Wattenberg and Greater Natural Buttes areas. Management believes this strategy will result in a property base weighted toward longer-life, less capital-intensive properties that will provide greater stability of production and production replacement, while the company’s exploration program in the deepwater Gulf of Mexico and other areas will continue to provide growth opportunities.

The following summarizes divestiture transactions completed in 2005 and through August 2006. In addition, as discussed in Notes 3 and 26, the company completed the Tronox IPO in November 2005 and distributed its remaining interest in Tronox in March 2006. The net proceeds from the 2005 divestitures and the separation of Tronox were used for debt repayment and other corporate purposes. Debt repayments made in 2005 and early 2006 are discussed in Note 10.

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			Pretax Gain on Sale, Net
(Millions of dollars)	Gross Proceeds (1)		Continuing Operations			Discontinued Operations
2005 exchange transactions –
Exchange of interests in certain noncore oil and gas properties for a 37.5% interest in the Blind Faith discovery in the deepwater Gulf of Mexico and cash	$	26	$	21		$	—
Exchange of interests in certain noncore oil and gas properties for overriding royalty interests in the Greater Natural Buttes area and cash		27		24			—
2005 divestiture transactions –
Nonoperated North Sea fields		551		—			306
Remaining oil and gas operations in the North Sea		2,970		—			1,934
Nonoperating interest in gas processing facility		159		120	(2)		—
Several packages of U.S. onshore oil and gas properties		435		149			—
Other noncore oil and gas properties and other assets		56		17			(1	)
Total completed exchange and divestiture transactions	$	4,224	$	331		$	2,239
2006 divestiture transactions –
Interests in oil and gas properties on the Gulf of Mexico shelf		1,030
Noncore oil and gas assets onshore in the U.S.		15

⁽¹⁾ For 2005 transactions, gross proceeds reflect working capital and other adjustments to the base cash purchase price. The following presents a reconciliation of the gross proceeds presented above to the net proceeds from asset divestitures presented in the company’s Consolidated Statement of Cash Flows for the year ended December 31, 2005 (in millions of dollars):

Gross proceeds as reflected above	$	4,224
Cash on hand acquired by the purchasers at closing		(171	)
Transaction costs and expenses paid		(49	)
Proceeds (receivable)/payable, net		5
Proceeds per the Consolidated Statement of Cash Flows	$	4,009

⁽²⁾ Gain on sale of the company’s investment in the Javelina gas processing facility is reflected as a component of other income (expense) in the company’s Consolidated Statement of Income. The company owned an interest in the facility through its 40% ownership of Javelina Company and Javelina Pipeline Company. This investment was accounted for using the equity method of accounting.

Discontinued Operations– Income from discontinued operations in the Consolidated Statement of Income relates to the company’s North Sea oil and gas business and Tronox. The following summarizes the amounts included in income from discontinued operations for all periods presented:

	2005									2004									2003
	North Sea Oil and Gas Business			Tronox			Total			North Sea Oil and Gas Business			Tronox			Total			North Sea Oil and Gas Business			Tronox			Total
(Millions of dollars)
Revenues	$	994		$	1,364		$	2,358		$	759		$	1,324		$	2,083		$	791		$	1,262		$	2,053
Income from discontinued operations –
Income (loss) from operations	$	527		$	16		$	543		$	270		$	(182	)	$	88		$	319		$	(114	)	$	205
Gain (loss) on sale		2,240			(1	)		2,239			—			—			—			—			—			—
Adjustments for contingencies(1)		—			(25	)		(25	)		—			—			—			—			—			—
Pretax income (loss) from discontinued operations		2,767			(10	)		2,757			270			(182	)		88			319			(114	)		205
Income tax (expense) benefit		(487	)(2)		8			(479	)		(119	)		60			(59	)		(210	)		34			(176	)
Minority interest, net of tax		—			1			1			—			—			—			—			—			—
Income (loss) from discontinued operations, net of tax	$	2,280		$	(1	)	$	2,279		$	151		$	(122	)	$	29		$	109		$	(80	)	$	29

⁽¹⁾ These adjustments represent provisions for environmental remediation and restoration and other contingencies incurred subsequent to the exit of the forest products business by Tronox. See Note 16.

⁽²⁾ Represents primarily U.S. taxes on the sale of North Sea oil and gas business. The net U.K. deferred tax liability was assumed by the acquirer as part of the divestiture transaction and, as such, was included in the carrying amount of the investment for purposes of calculating pretax gain on sale of the U.K. subsidiary.

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Under the company’s $5.25 billion secured credit agreement, the company was required to use 100% of the net after-tax cash proceeds from disposition of certain assets to repay debt. Because the North Sea oil and gas and Tronox assets were subject to this requirement, interest expense on debt that was required to be repaid upon the sale of the North Sea business and the Tronox IPO ($92 million and $24 million, respectively) is classified as a component of income from discontinued operations (or $75 million on an after-tax basis). Interest expense was allocated to discontinued operations beginning in May 2005, to coincide with initial borrowings under the term loans requiring mandatory prepayments.

The following presents a reconciliation of the U.S. Federal income tax rate to the company’s effective tax rates for income from discontinued operations.

	2005		2004		2003
U.S. statutory tax rate	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from –
Taxation of foreign operations	3.1		31.8		22.2
Effect of book and tax basis differences of investment in subsidiary stock	8.6		—		—
Utilization of foreign tax credits	(25.6	)	—		—
Utilization of capital loss carryforwards	(4.0	)	—		—
Provision for U.S. income taxes on U.K. remittances (1)	—		—		28.8
State income taxes	.2		—		—
Other – net	.1		.3		(.1	)
Effective tax rate	17.4	%	67.1	%	85.9	%

⁽¹⁾ The 2003 income tax provision includes $59 million U.S. income tax associated with remittances from our North Sea oil and gas business.

North Sea Oil and Gas Business – In August 2005, the company entered into agreements to sell its North Sea oil and gas business for cash consideration of approximately $3.5 billion. The North Sea business included proved reserves of 234 million barrels of oil equivalent (MMboe) at closing and produced a daily average of 65,500 barrels of oil equivalent during the third quarter of 2005, representing approximately 20% of the company’s production during that period (unaudited). The two-step transaction pursuant to the agreements includes:

• The sale of the company’s interests in four nonoperated fields and related exploratory acreage and facilities in the North Sea, which was completed on September 30, 2005

• The sale of all remaining North Sea operations through the sale of the stock of Kerr-McGee (G.B.) Ltd., the company’s wholly-owned subsidiary, and other affiliated entities, completed in November 2005

Tronox – Refer to Notes 3 and 26 for information regarding the Tronox separation.

Assets Held for Sale and of Discontinued Operations – The following table presents the composition of net assets associated with discontinued operations and assets reported as held for sale as of December 31, 2005 and 2004:

	2005								2004
(Millions of dollars)	Tronox (1)			Other		Total			North Sea Oil and Gas Business			Tronox			Other		Total
Cash and cash equivalents	$	69		$	—	$	69		$	14		$	24		$	—	$	38
Current assets		691			—		691			194			560			—		754
Long-term assets		981			5		986			1,778			999			5		2,782
Current liabilities		(419	)		—		(419	)		(192	)		(417	)		—		(609	)
Noncurrent liabilities		(1,069	)		—		(1,069	)		(617	)		(274	)		—		(891	)
Net carrying value (2)	$	253		$	5	$	258		$	1,177		$	892		$	5	$	2,074

⁽¹⁾ The balance of noncurrent liabilities associated with Tronox at December 31, 2005 includes minority interest liability of $212 million and debt of $550 million. Refer to Note 10 for additional information.

⁽²⁾ The balances of accumulated other comprehensive income associated with discontinued operations at December 31, 2005 and 2004 are $35 million and $96 million, respectively.

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Subsequent to December 31, 2005, the company’s interests in oil and gas properties on the Gulf of Mexico shelf met the criteria for reporting as held for sale. As discussed in Note 26, the sale was completed in August 2006, for $1 billion in cash. The following presents the main classes of assets and liabilities associated with the Gulf of Mexico shelf properties as of December 31, 2005 (in millions of dollars):

Current assets	$	15
Long-term assets		671
Current liabilities		(16	)
Noncurrent liabilities		(125	)
Net carrying value	$	545

3.Separation of Tronox

Information in this footnote should be read in connection with Note 26 that provides additional information regarding the Tronox Distribution,

In November 2005, the company completed an IPO of 17.5 million shares of Class A common stock of Tronox, the subsidiary holding Kerr-McGee’s chemical business. Concurrent with the IPO, Tronox, through its wholly-owned subsidiaries, issued $350 million in aggregate principal amount of 9.5% senior unsecured notes due 2012 and borrowed $200 million under a six-year senior secured credit facility. Pursuant to the terms of the Master Separation Agreement (MSA), Tronox distributed to Kerr-McGee the net proceeds from the IPO of $225 million, as well as the net proceeds from the borrowings of approximately $535 million and cash on hand in excess of $40 million.

As a result of the IPO, Kerr-McGee recorded an increase in capital in excess of par value of $19 million related to the excess of the IPO price over the book value of the shares sold. Following the IPO, approximately 43.3% of the total outstanding common stock of Tronox is publicly held and 56.7% is held by Kerr-McGee. Kerr-McGee owns all of Tronox’s Class B common stock (approximately 23 million shares), which is entitled to six votes per share on all matters to be voted on by Tronox’s stockholders, representing approximately 88.7% of Tronox’s total voting power. On March 8, 2006, the Board declared a dividend of Tronox’s Class B common stock owned by Kerr-McGee to its stockholders. Kerr-McGee expects to distribute to its stockholders approximately .20 of a share of Tronox Class B common stock for each outstanding share of Kerr-McGee common stock they own on the record date of March 20, 2006. The final distribution ratio will be set on the record date. Cash will be delivered in lieu of fractional share interests to Kerr-McGee stockholders entitled to receive a fraction of a share of Tronox Class B common stock. The Distribution is expected to be completed on March 30, 2006.

Under the terms of the MSA, Kerr-McGee transferred to Tronox the subsidiaries holding and operating Kerr-McGee’s chemical business. Some of these subsidiaries previously were engaged in the production of ammonium perchlorate, the manufacturing of thorium compounds, treatment of forest products, the refining and marketing of petroleum products, the mining, milling and processing of nuclear materials and other businesses. These subsidiaries are subject to environmental obligations associated with their current and former operations. Under the terms of the MSA, Kerr-McGee agreed to reimburse Tronox for a portion of the environmental remediation costs incurred and paid by Tronox and its subsidiaries prior to November 28, 2012, to the extent such costs, net of any reimbursements received from insurers or other parties, exceed the carrying value of Tronox’s environmental reserves as of November 28, 2005, the date the IPO was completed. Additional discussion regarding environmental obligations and Kerr-McGee’s seven-year reimbursement obligation is provided in Note 16.

Historically, employees of the company’s chemical business participated in stock-based compensation, pension and postretirement plans established by Kerr-McGee. As more fully discussed in Note 19, except for vested stock options and performance unit awards, Kerr-McGee’s stock-based awards held by Tronox employees generally will be forfeited on the effective date of the Distribution and replaced with stock-based awards of comparable value issued by Tronox. Tronox also is expected to establish pension and postretirement plans for its U.S. employees and assume the benefit obligations associated with its current and former employees following the Distribution. Kerr-McGee also will transfer trust assets to the newly established Tronox U.S. pension plan to fund the transferred obligation in compliance with applicable regulatory requirements. Note 15 provides additional information regarding the anticipated effects of the separation on the company’s obligations for pension and postretirement health and welfare benefits.

- 16 -

4.Westport Resources Merger

On June 25, 2004, Kerr-McGee completed a merger with Westport Resources Corporation (Westport), an independent oil and gas exploration and production company with operations in the Rocky Mountain, Mid-Continent and Gulf Coast areas onshore U.S. and in the Gulf of Mexico. The merger increased Kerr-McGee’s proved reserves by 281 MMboe (unaudited). On the effective date of the merger, each issued and outstanding share of Westport common stock was converted into .71 shares of Kerr-McGee common stock (on a pre-split basis). As a result, Kerr-McGee issued 48.9 million shares of common stock to Westport’s stockholders valued at $2.4 billion based on Kerr-McGee’s weighted average stock price two days before and after the merger was publicly announced. Kerr-McGee also exchanged 1.9 million stock options (on a pre-split basis) for options held by Westport employees with a fair value of $34 million.

On June 25, 2004, after completion of the merger, Kerr-McGee paid down all outstanding borrowings under the Westport revolving credit facility and the facility was terminated on July 13, 2004.

During June 2004, Kerr-McGee purchased Westport’s 8.25% notes with an aggregate principal amount of $14 million ($16 million fair value). On July 1, 2004, Kerr-McGee issued a notice of redemption for the remaining 8.25% Westport notes and the notes were redeemed on July 31, 2004, at an aggregate redemption price of $786 million. The redemption price consisted of the face value of $700 million, less the amount previously purchased by Kerr-McGee of $14 million, plus a make-whole premium of $100 million.

On July 1, 2004, Kerr-McGee issued $650 million of 6.95% notes due July 1, 2024, with interest payable semi-annually. The notes were issued at 99.2% of par, resulting in a discount of $5 million, which will be recognized as additional interest expense over the term of the notes. The proceeds from this debt issuance, together with proceeds from borrowings under the company’s revolving credit facilities, were used to redeem the 8.25% Westport notes discussed above.

In exchange for Westport’s common stock and options, Kerr-McGee issued stock valued at $2.4 billion, options valued at $34 million and assumed debt of $1 billion, for a total of $3.5 billion (net of $43 million of cash acquired). The fair value assigned to assets acquired and goodwill totaled $4.6 billion. Westport’s assets and liabilities are reflected in the company’s balance sheet at December 31, 2004, and Westport’s results of operations are included in the company’s Statement of Income from June 25, 2004. The purchase price was allocated to specific assets and liabilities based on their estimated fair values at the merger date, with $804 million recorded as goodwill and $561 million recorded for net deferred tax liabilities (as adjusted for final merger-date tax basis and loss carryforwards). In 2005, the company completed its analysis of merger-date tax basis, which resulted in a reduction of net deferred tax liabilities by $35 million and a commensurate decrease in goodwill, due to higher than initially estimated tax basis and loss carryforwards.

The strategic benefits of the merger and the principal factors that contributed to Kerr-McGee recognizing goodwill are as follows:

• Provides complementary high-quality assets in core U.S. onshore and Gulf of Mexico regions

• Enhances the stability of high-margin production

• Expands low-risk exploitation opportunities

• Increases free cash flow for Kerr-McGee’s high-potential exploration opportunities

• Reduces leverage and enables greater financial flexibility

• Provides opportunities for synergies and related cost savings

- 17 -

The condensed balance sheet information presented below shows the allocation of purchase price to Westport’s assets and liabilities as of the merger date after taking into account the final tax analysis discussed above.

(Millions of dollars)
Assets
Current assets	$	291
Property, plant and equipment		3,494
Other assets		39
Goodwill		804
Total Assets	$	4,628
Liabilities and Stockholders’ Equity
Current liabilities	$	360
Long-term debt		1,046
Deferred income taxes		656
Other liabilities		118
Total Noncurrent Liabilities		1,820
Stockholders’ Equity		2,448
Total Liabilities and Stockholders’ Equity	$	4,628

The pro forma information presented below has been prepared to give effect to the Westport merger as if it had occurred at the beginning of the periods presented. The pro forma information is presented for illustrative purposes only and is based on estimates and assumptions deemed appropriate by Kerr-McGee. If the Westport merger had occurred in the past, Kerr-McGee’s operating results would have been different from those reflected in the pro forma information below; therefore, the pro forma information should not be relied upon as an indication of the operating results that Kerr-McGee would have achieved if the merger had occurred at the beginning of each period presented. The pro forma information also should not be used as an indication of the results that Kerr-McGee will achieve in future periods.

Pro Forma Information (Unaudited)

	Year Ended December 31,
(Millions of dollars, except per-share amounts)	2004		2003
Revenues	$	3,546	$	2,860
Income from continuing operations		436		268
Net income		465		258
Net income per common share -
Basic	$	1.55	$	.86
Diluted		1.51		.86

5.Statement of Income Data

Asset Impairments– Impairment losses of $17 million in 2005 related primarily to a U.S. onshore property in Texas where unsuccessful drilling resulted in a reduction in proved undeveloped reserves ($10 million) and two U.S. Gulf of Mexico shelf properties that ceased producing in the first quarter. Impairment losses of $21 million in 2004 related primarily to a U.S. Gulf of Mexico field that ceased production sooner than expected. The 2003 impairments of $14 million related to mature oil and gas producing assets in the U.S. onshore and Gulf of Mexico shelf areas.

- 18 -

Additionally, in 2004 Tronox recognized an impairment loss of $8 million associated with the shutdown of sulfate-process titanium dioxide pigment production at its Savannah, Georgia facility. This charge is reflected in income from discontinued operations, net of taxes.

Gain (Loss) on Sale of Assets –Net gains (losses) on sale of assets in 2005, 2004 and 2003 were $211 million, $(29) million and $30 million, respectively. Note 2 provides information regarding 2005 gains on sales of assets. The 2004 loss was associated primarily with the conveyance of the company’s interest in a nonproducing Gulf of Mexico field to another participating partner ($25 million), as well as losses of $6 million and gains of $2 million on sales of noncore properties in the Gulf of Mexico shelf and U.S. onshore areas. A net gain of $30 million was recognized in 2003 upon concluding the company’s 2002 divestiture program in the U.S., and for the sale of the company’s interest in the South China Sea (Liuhua field) and other noncore U.S. properties.

Other Income (Expense) –Other income (expense) includes the following:

(Millions of dollars)	2005			2004			2003
Gain on sale of nonoperating interest in gas processing facility(1)	$	120		$	—		$	—
Equity in net losses of equity method investees		(23	)		(28	)		(33	)
Net foreign currency transaction gain (loss)		1			(8	)		(2	)
Gain on sale of Devon stock (2)		—			9			17
DECS and Devon stock revaluation		—			2			8
Interest income		9			1			—
Other		(3	)		3			(5	)
Total	$	104		$	(21	)	$	(15	)

⁽¹⁾ Additional information about this transaction is provided in Note 2.

⁽²⁾ Refer to Note 12 for additional information related to DECS and Devon stock.

Earnings per Share– Basic earnings per share includes no dilution and is computed by dividing income or loss from continuing operations available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if security interests were exercised or converted into common stock.

The following table sets forth the computation of basic and diluted earnings per share from continuing operations for the years ended December 31, 2005, 2004 and 2003:

	2005					2004					2003
	Income from Continuing Operations		Shares	Per- share Income		Income from Continuing Operations		Shares	Per- share Income		Income from Continuing Operations		Shares		Per- share Income
(Millions of dollars , except per-share amounts, and thousands of shares)
Basic earnings per share	$	932	262,024	$	3.56	$	375	252,625	$	1.49	$	225	200,289	��	$	1.12
Effect of dilutive securities:
5.25% convertible debentures		4	3,169				21	19,648				21	19,648
Restricted stock and stock options		—	3,780				—	1,565				—	1,428
Diluted earnings per share	$	936	268,973	$	3.48	$	396	273,838	$	1.45	$	246	221,365		$	1.11

The weighted average of diluted shares outstanding during 2004 and 2003 does not include the effect of employee stock options that were antidilutive because they were not “in the money” during the respective years. At December 31, 2004 and 2003 there were 6 million and 9.8 million of such options outstanding, with weighted average exercise prices of $31.82 and $30.13, respectively. All options outstanding at December 31, 2005 were “in the money.”

- 19 -

In March 2005, all of the 5.25% debentures were converted by the holders into 9.8 million shares of common stock (on a pre-split basis). Accordingly, shares issued upon conversion of the debentures are included in basic earnings per share from the conversion date and in diluted earnings per share for periods prior to conversion.

In January 2006, the Board of Directors approved a $1 billion stock repurchase program. Note 26 provides information on share repurchases made under this program through August 2006. Additionally, as discussed in Note 19, subsequent to year-end 2005 the company issued additional stock options and restricted stock to its employees.

6.Balance Sheet Data

Property, Plant and Equipment – Property, plant and equipment at December 31, 2005 and 2004, is as follows:

	Gross Property				Accumulated Depreciation and Depletion						Net Property
(Millions of dollars)	2005		2004		2005			2004			2005		2004
Exploration and production	$	13,490	$	12,553	$	(5,108	)	$	(4,443	)	$	8,382	$	8,110
Other		139		182		(86	)		(102	)		53		80
Total	$	13,629	$	12,735	$	(5,194	)	$	(4,545	)	$	8,435	$	8,190

Deferred Charges, Derivatives and Other Assets– Deferred charges, derivatives and other assets include the following at December 31, 2005 and 2004:

(Millions of dollars)	2005		2004
Prepaid pension cost	$	237	$	239
Investment in equity method investees		69		95
Nonqualified benefit plan deposits		48		48
Unamortized debt issue costs		25		24
Long-term derivative assets		35		15
Other assets		13		15
Total	$	427	$	436

Goodwill and Other Intangible Assets– Goodwill and other intangible assets recorded in the Westport merger were $839 million and $35 million, respectively, at the merger date. As discussed in Note 4, in 2005 the company refined its estimate of merger-date tax basis and loss carryforwards and reduced net deferred tax liabilities by $35 million, with a commensurate decrease in goodwill.

The changes in the carrying amount of goodwill for 2005 and 2004 are as follows:

(Millions of dollars)
Balance at December 31, 2003	$	346
Goodwill associated with the Westport merger		839
Balance at December 31, 2004		1,185
Tax-related adjustment to goodwill		(35	)
Balance at December 31, 2005	$	1,150

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Intangible assets subject to amortization at December 31, 2005 and 2004 are as follows:

(Millions of dollars)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Balance at December 31, 2004 –
Transportation contracts	$	49	$	(13	)	$	36
Other		3		(1	)		2
Total	$	52	$	(14	)	$	38
Balance at December 31, 2005 –
Transportation contracts	$	49	$	(20	)	$	29
Other		3		(3	)		—
Total	$	52	$	(23	)	$	29

Intangible asset amortization expense associated with continuing operations was $10 million, $6 million and $5 million in 2005, 2004 and 2003, respectively. The estimated amortization expense for the next five years totals $22 million, ranging from $4 million to $6 million annually. The remaining weighted average amortization period for the transportation contracts is 7 years.

Accrued Liabilities – Accrued liabilities at December 31, 2005 and 2004 are as follows:

(Millions of dollars)	2005		2004
Accrued operating expenses and exploration and development costs	$	406	$	261
Employee-related costs and benefits		111		110
Reserves for royalties and interest (1)		108		45
Reserves for environmental remediation and restoration		12		—
Interest payable		68		97
Taxes other than income taxes		83		65
Asset retirement obligations		24		17
Other		34		12
Total	$	846	$	607

⁽¹⁾ Refer to Note 16 for additional information.

Other Noncurrent Liabilities –Other noncurrent liabilities consist of the following at year-end 2005 and 2004:

(Millions of dollars)	2005		2004
Postretirement benefit liability	$	210	$	209
Pension benefit liability		62		33
Reserves for environmental remediation and restoration		32		42
Litigation reserves		19		24
Accrued rent for spar operating leases		54		46
Ad valorem taxes		39		33
Other		50		42
Total	$	466	$	429

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Asset Retirement Obligations– A summary of the changes in the ARO liability during 2005 and 2004 is included in the table below and reflects activity associated with the North Sea oil and gas business, which was sold in 2005, and Tronox:

(Millions of dollars)	2005			2004
Balance at January 1	$	524		$	421
Obligations incurred, including obligations acquired		42			30
Liability assumed in the Westport merger		—			79
Accretion expense		30			30
Changes in estimates, including timing		(32	)		(16	)
Abandonment expenditures		(19	)		(17	)
Obligations settled through divestitures		(195	)		(3	)
Adoption of FIN No. 47(1)		19			—
Balance at December 31		369			524
Less: ARO associated with discontinued operations		(35	)		(202	)
Less: Current asset retirement obligation		(24	)		(17	)
Noncurrent asset retirement obligation	$	310		$	305

⁽¹⁾ Refer to Note 1 for a discussion of FIN No. 47, “Accounting for Conditional Asset Retirement Obligations,” which the company adopted effective December 31, 2005.

As discussed in Note 14, Tronox shut down its synthetic rutile plant in Mobile, Alabama, in 2003. In September 2004, Tronox shut down sulfate and gypsum production at its Savannah, Georgia, plant. Until the decisions to shut down these facilities had been made, it was indeterminable when the asset retirement liability associated with these facilities would be settled. Upon deciding to shut down the facilities, the timing of settlement became estimable and the related asset retirement obligation was recorded at the estimated fair value. For the synthetic rutile plant in Mobile, Alabama, an $18 million liability was recognized at the beginning of 2003. For the sulfate production facility at the company’s Savannah, Georgia, plant, an abandonment liability of $13 million was recognized in September 2004.

Operations at Tronox’s Mobile, Alabama, facility included production of feedstock for titanium dioxide pigment plant. The facility ceased feedstock production in June 2003, though it is still being used to dry ore for titanium dioxide production. Feedstock operations had resulted in minor contamination of groundwater adjacent to surface impoundments. A groundwater recovery system was installed prior to closure and continues in operation as required under the National Pollutant Discharge Elimination System (NPDES) permit. Remediation work, including groundwater recovery, closure of the impoundments and other minor work, is expected to be substantially completed five years after the facility is no longer being used to dry ore. As of December 31, 2005, Tronox had a remaining abandonment reserve of $17 million. Although actual costs may exceed current estimates, the amount of any increases cannot be reasonably estimated at this time.

An abandonment reserve related to Tronox’s titanium dioxide pigment sulfate production at Savannah, Georgia, was established to address probable remediation activities, including environmental assessment, closure of certain impoundments, groundwater monitoring, asbestos abatement and other work, expected to take more than 25 years. As of December 31, 2005, Tronox’s reserve balance was approximately $14 million. Although actual costs may exceed current estimates, the amount of any increase cannot be reasonably estimated at this time.

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7.Cash Flow Statement Data

For all periods presented, cash flows from operating, investing and financing activities in the Consolidated Statement of Cash Flows and supplemental cash flow data provided below include effects of discontinued operations.

Net cash provided by operating activities reflects cash payments for income taxes and interest as follows:

(Millions of dollars)	2005			2004			2003
Income tax payments	$	481		$	154		$	115
Less: refunds received		(30	)		(19	)		(49	)
Net income tax payments	$	451		$	135		$	66
Interest payments	$	345		$	247		$	227

Other noncash items included in the reconciliation of net income to net cash provided by operating activities include the following:

(Millions of dollars)	2005		2004			2003
Pension and postretirement expense	$	39	$	36		$	44
Litigation reserves		9		8			8
Equity in net losses of equity method investees		19		26			33
Noncash interest expense		22		17			20
Noncash spar rental expense		7		14			8
Increase in fair value of embedded options in the DECS(1)		—		101			88
Increase in fair value of trading securities(1)		—		(103	)		(96	)
All other		20		48			(8	)
Total	$	116	$	147		$	97

⁽¹⁾ See Note 12 for a discussion of the accounting for the Devon Stock and DECS.

Details of changes in other assets and liabilities within the operating section of the Consolidated Statement of Cash Flows are as follows:

(Millions of dollars)	2005			2004			2003
Environmental expenditures	$	(71	)	$	(99	)	$	(104	)
Reimbursements of environmental expenditures		72			50			15
Cash abandonment expenditures		(19	)		(17	)		(17	)
Contributions to pension and postretirement plans		(33	)		(67	)		(29	)
All other		40			(11	)		5
Total	$	(11	)	$	(144	)	$	(130	)

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Information about noncash investing and financing activities not reflected in the Consolidated Statement of Cash Flows follows:

(Millions of dollars)	2005			2004			2003
Noncash investing activities –
Increase in property, plant and equipment associated with –
Westport merger	$	—		$	3,494		$	—
Asset retirement obligations incurred (including changes in estimates)		7			7			30
Asset retirement costs recognized upon adopting a new accounting standard		19			—			108
Gunnison Trust(1)		—			(83	)		83
Trading securities used for redemption of long-term debt(2)		—			(586	)		—
Increase in fair value of securities available for sale(2)		—			—			9
Noncash financing activities –
Common stock and stock options issued in connection with the Westport merger	$	—		$	2,448		$	—
Increase (decrease) in debt associated with –
Conversion of 5.25% debentures to common stock		(600	)		—			—
Westport merger		—			1,046			—
Gunnison Trust(1)		—			(75	)		75
Debt redemption with trading securities(2)		—			(330	)		—
Settlement of DECS derivative(2)		—			(256	)		—
Increase in valuation of the DECS(2)		—			—			8

⁽¹⁾ During 2001, the company entered into a leasing arrangement with Kerr-McGee Gunnison Trust (Gunnison Trust) for the construction of the company’s share of a platform to be used in the development of the Gunnison field, in which the company has a 50% working interest. Adoption of the FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN No. 46) resulted in the company consolidating the Gunnison Trust as of December 31, 2003. In January 2004, the $83 million of the synthetic lease facility was converted to a leveraged lease structure, whereby the company leases an interest in the platform under an operating lease agreement from a separate business trust. Because the company is not the primary beneficiary of the operating lease trust, property, plant and equipment, debt and other assets and liabilities of the Gunnison Trust were de-consolidated in 2004.

⁽²⁾ See Note 12 for a discussion of the accounting for the Devon Stock and DECS.

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8.Other Comprehensive Income (Loss)

Components of other comprehensive income (loss) for the years ended December 31, 2005, 2004 and 2003 are as follows. Activity and balances presented below include discontinued operations.

(Millions of dollars)	2005			2004			2003
Foreign currency translation –
Translation adjustments	$	(41	)	$	22		$	56
Reclassification to net income		—			7			—
Reclassification to gain on sale of Tronox stock		(16	)		—			—
Total foreign currency translation adjustments		(57	)		29			56
Net losses on cash flow hedges –
Unrealized losses, net of taxes of $838, $296 and $124		(1,512	)		(531	)		(203	)
Reclassification of realized losses to net income, net of taxes of $(329), $(267) and $(94)		575			462			172
Reclassification of unrealized gains to gain on sale of Tronox stock		(1	)		—			—
Total losses on cash flow hedges, net		(938	)		(69	)		(31	)
Available-for-sale securities –
Unrealized gain, net of taxes of $(3)		—			—			6
Reclassification of realized gain, net of taxes of $3 and $3		—			(5	)		(7	)
Total available-for-sale securities		—			(5	)		(1	)
Minimum pension liability –
Minimum pension liability adjustments, net of taxes of $4, $(7) and $5		(7	)		11			(7	)
Reclassification to gain on sale of Tronox stock		1			—			—
Total minimum pension liability adjustments		(6	)		11			(7	)
Minority interest, net of tax		1			—			—
Other comprehensive income (loss)	$	(1,000	)	$	(34	)	$	17

Components of accumulated other comprehensive loss at December 31, 2005 and 2004, net of applicable tax effects, are as follows:

(Millions of dollars)	2005			2004
Foreign currency translation adjustments	$	35		$	91
Unrealized loss on cash flow hedges		(1,095	)		(157	)
Minimum pension liability adjustments		(19	)		(13	)
	$	(1,079	)	$	(79	)

9. Derivative Instruments

The company is exposed to risk from fluctuations in crude oil and natural gas prices, foreign currency exchange rates and interest rates. To reduce the impact of these risks on earnings and to increase the predictability of its cash flows, the company enters into certain derivative contracts, primarily swaps and collars for a portion of its future oil and natural gas production, forward contracts to buy and sell foreign currencies and interest rate swaps to hedge the fair value of its fixed-rate debt.

- 25 -

The following tables summarize the balance sheet presentation of the company’s derivatives as of December 31, 2005 and 2004. Derivative assets and liabilities associated with Tronox and the North Sea oil and gas business are included in assets and liabilities of discontinued operations in the Consolidated Balance Sheet.

	December 31, 2005
	Derivative Fair Value
	Current Asset		Long-Term Asset		Current Liability			Long-Term Liability			Deferred Gain (Loss) in AOCI(1)
(Millions of dollars)
Oil and gas commodity derivatives –
Kerr-McGee positions	$	101	$	34	$	(1,422	)	$	(658	)	$	(1,095	)
Acquired Westport positions		—		—		(70	)		—			—
Gas marketing-related derivatives(2)		13		1		(14	)		—			—
Interest rate swaps		—		—		—			(5	)		—
Total - continuing operations		114		35		(1,506	)		(663	)		(1,095	)
Discontinued operations		1		—		(2	)		—			—
Total derivative contracts	$	115	$	35	$	(1,508	)	$	(663	)	$	(1,095	)

	December 31, 2004
	Derivative Fair Value
	Current Asset		Long-Term Asset		Current Liability			Long-Term Liability			Deferred Gain (Loss) in AOCI(1)
(Millions of dollars)
Oil and gas commodity derivatives –
Kerr-McGee positions	$	41	$	12	$	(213	)	$	(188	)	$	(174	)
Acquired Westport positions		1		1		(123	)		(16	)		(7	)
Gas marketing-related derivatives(2)		6		2		(6	)		(2	)		—
Foreign currency derivatives		—		—		(6	)		—			—
Interest rate swaps		4		—		(1	)		(2	)		—
Total - continuing operations		52		15		(349	)		(208	)		(181	)
Discontinued operations		36		—		(23	)		—			24
Total derivative contracts	$	88	$	15	$	(372	)	$	(208	)	$	(157	)

⁽¹⁾ Amounts deferred in accumulated other comprehensive income (AOCI) are reflected net of tax.

⁽²⁾ The company’s marketing subsidiary, Kerr-McGee Energy Services (KMES) purchases third-party natural gas for aggregation and sale with the company’s own production in the Rocky Mountain area. Under some of its marketing arrangements, KMES receives fixed prices for the sale of natural gas. Existing contracts for the physical delivery of gas at fixed prices have not been designated as hedges and are marked-to-market through earnings in accordance with FAS No. 133. KMES has entered into natural gas swaps and basis swaps that largely offset its fixed-price risk on physical contracts and lock in margins associated with the physical sales. The gains and losses on the swaps, which also are marked-to-market through earnings, substantially offset the gains and losses from the fixed-price physical delivery contracts.

- 26 -

The following tables summarize the gain (loss) on the company’s derivative instruments associated with continuing operations and its classification in the Consolidated Statement of Income for each of the last three years:

(Millions of dollars)	2005			2004			2003
Gain (loss) on derivatives –
Hedge derivatives	$	(655	)	$	(533	)	$	(215	)
Nonhedge derivatives		(38	)		(23	)		2
Hedge ineffectiveness		(206	)		4			(1	)
Overhedge derivative loss		(119	)		—			—
Gas marketing-related derivatives		6			6			(12	)
Interest rate swaps		(4	)		15			11
DECS call option (1)		—			(101	)		(88	)
Foreign currency derivatives		4			(7	)		(7	)
Total	$	(1,012	)	$	(639	)	$	(310	)
Classification in income from continuing operations –
Loss on commodity derivatives	$	(1,018	)	$	(553	)	$	(216	)
Gas marketing revenues		6			7			(7	)
Interest expense		(4	)		15			11
Other income (expense)		4			(108	)		(98	)
Total	$	(1,012	)	$	(639	)	$	(310	)

⁽¹⁾ As discussed in Note 5, other income (expense) in 2004 and 2003 also includes unrealized gains on Devon stock classified as trading.

Oil and Gas Commodity Derivatives – The company periodically enters into financial derivative instruments that generally fix the commodity prices to be received for a portion of its future sales of oil and natural gas produced. The fair value of the company’s oil and gas commodity derivative instruments was determined based on prices actively quoted, generally NYMEX prices.

Hedge Ineffectiveness – For the year ended December 31, 2005, as a result of significantly increased commodity prices and widening differentials between NYMEX forward prices and expected future oil and gas sales prices, the company recognized losses on hedge ineffectiveness of $206 million, associated with its commodity derivative instruments designated as hedges of future oil and gas sales. These losses represent the excess of mark-to-market losses on the company’s commodity derivatives over the higher cash flows expected to be realized upon sales of hedged production.

Nonhedge Derivatives – Realized and unrealized gains and losses arising from derivative instruments that have not been designated as hedges or that do not qualify for hedge accounting (“nonhedge derivatives”) are recognized in current earnings. Historically, such gains and losses have primarily related to certain contracts acquired in the Westport merger that do not qualify for hedge accounting as well as natural gas basis swaps that have not been designated in a hedging relationship. At the date of the merger, Westport’s costless and three-way collars did not qualify for hedge accounting treatment because they represented “net written options” at the merger date. As a result, even though these collars help mitigate commodity price risk, the company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (loss). We recognized net mark-to-market losses of $45 million and $23 million during 2005 and 2004, respectively, associated with these Westport-related collars and our nonhedge natural gas basis swaps.

A significant portion of 2006 and 2007 natural gas derivatives entered into during 2005 were assigned as hedges of future production from our Rocky Mountain properties. At the time the company entered into these derivatives, physical sales prices in the Rocky Mountains correlated well with NYMEX natural gas prices; however, beginning in the second half of 2005, basis differentials began to widen and continued to widen throughout the year as NYMEX natural gas prices reached historical levels. In the fourth quarter, our correlation assessment indicated that NYMEX natural gas derivatives could no longer be considered “highly effective” hedges under the parameters of the accounting rules. Consequently, we discontinued hedge accounting effective October 1, 2005 for all 2006/2007 natural gas derivatives assigned to the Rocky Mountains (except those matched with basis swaps) and recognized a net mark-to-market nonhedge gain of $7 million in the fourth quarter.

- 27 -

Overhedge Derivative Loss – As a result of two major hurricanes in the Gulf of Mexico late in the third quarter of 2005, the company’s physical deliveries to certain Gulf of Mexico sales indices in the third and fourth quarters of 2005 were insufficient to cover the associated derivative contracts in place. Consequently, the company recognized realized losses of $119 million in 2005 associated with certain derivative contracts in excess of hedged physical deliveries for 2005. Such losses are reported as overhedge derivative losses in revenues.

Hedge Gains (Losses) in Equity – At December 31, 2005, the net after-tax loss on oil and gas derivatives in accumulated other comprehensive loss relates to a portion of the company’s expected oil and gas sales through 2007. The company expects to reclassify $617 million of the total net after-tax derivative loss from accumulated other comprehensive loss to earnings during the next 12 months, assuming no further changes in the fair value of the related contracts.

Discontinuation of Hedge Accounting– Because a large portion of the company’s natural gas derivatives no longer qualify for hedge accounting and to increase clarity in its financial statements, the company elected to discontinue hedge accounting prospectively for its commodity derivatives beginning March 1, 2006. Consequently, from that date forward, the company will recognize mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (stockholders’ equity). The net mark-to-market loss on our outstanding derivatives at February 28, 2006 included in accumulated other comprehensive income will be reported in future earnings through 2007 as the original hedged transactions occur. This change in reporting will have no impact on the company’s reported cash flows, although future results of operations will be affected by mark-to-market gains and losses which fluctuate with volatile oil and gas prices.

Foreign Currency Derivatives– From time to time, Tronox enters into forward contracts to buy and sell foreign currencies. Certain of these contracts (purchases of Australian dollars and sales of euro) have been designated and have qualified as cash flow hedges of Tronox’s anticipated future cash flows related to pigment sales, raw material purchases and operating costs.

Interest Rate Derivatives– From time to time, the company enters into interest rate swaps to hedge against changes in fair value of the related debt as a result of interest rate changes. The swaps are carried in the Consolidated Balance Sheet at their estimated fair value. Any unrealized gain or loss on the swaps is offset by a comparable gain or loss resulting from recording changes in the fair value of the related debt. Gains and losses on interest rate swaps, along with the changes in the fair value of the related debt, are reflected in interest and debt expense in the Consolidated Statement of Income. The critical terms of the swaps match the terms of the debt; therefore, the swaps are considered highly effective and no hedge ineffectiveness has been recognized.

10.Debt

As discussed in Note 3, in November 2005, the company completed the IPO of Tronox Class A common stock. Notes 3 and 26 provide additional information about the IPO and the subsequent Distribution. Concurrent with the IPO, Tronox, through its wholly-owned subsidiaries, borrowed $550 million and entered into a senior secured credit agreement.

Lines of Credit

The following presents a summary of revolving credit facilities that served as a source of liquidity in 2005 and those that are currently in effect. No borrowings were outstanding under the revolving credit agreements at December 31, 2005. Available capacity under the credit agreements presented below reflects capacity utilization in support of outstanding letters of credit.

- 28 -

Revolving Credit Facility	Term (years)	Period Effective	Period Terminated	Available Capacity at December 31, 2005
Kerr-McGee Corporation –
$1.5 billion unsecured facility	5	November 2004	May 2005		—
$1.25 billion senior secured facility (1)	5	May 2005	January 2006	$	1.18 billion
$1.25 billion unsecured facility(2)	5	January 2006	Facility currently in effect		—
Tronox Incorporated –
$250 million senior secured facility(3)	5	November 2005	Facility currently in effect	$	216 million

⁽¹⁾ The $1.25 billion secured credit facility was available to the company under the $5.5 billion credit agreement, which also included $4.25 billion in term loan facilities. As discussed below, the term loans were repaid in 2005.

⁽²⁾ Available capacity under this facility was $1.18 billion as of February 28, 2006, reflecting capacity utilization in support of outstanding letters of credit.

⁽³⁾ In November 2005, Tronox Incorporated and certain of its wholly-owned subsidiaries entered into a $450 million senior secured credit agreement which provides for a six-year term loan facility of $200 million (which was fully drawn at the time of the IPO) and a $250 million five-year multicurrency revolving credit facility.

The company has arrangements to maintain compensating balances with certain banks that provide credit. At year-end 2005, the aggregate amount of such compensating balances was not material, and the company was not legally restricted from withdrawing all or a portion of such balances at any time during the year.

$1.25 Billion Unsecured Revolving Credit Agreement (effective January 2006)– The facility is available to provide support for commercial paper and for general corporate purposes. Interest on amounts borrowed under the credit agreement is payable, at the company’s election, at an alternate base rate (ABR) or a Eurodollar rate, in each case as defined in the credit agreement. The initial margin applicable to Eurodollar borrowings is 125 basis points and may vary from 50 to 150 basis points depending on the company’s credit rating.

The terms of the revolving credit agreement provide for customary representations and warranties, affirmative and negative covenants, and events of default. The company also is required to maintain compliance with the following financial covenants (in each case, as defined in the agreement):

• Consolidated Leverage Ratio of no more than 3.5:1

• Consolidated Interest Coverage Ratio over a specified period of at least 3:1

• Asset Coverage Ratio of more than 1.75:1 so long as the company’s corporate credit rating is below investment grade

During 2005, the company was subject to covenants specified in credit agreements in effect at that time and was in compliance with all such covenants. Compliance with the covenants under the $1.25 billion revolving credit agreement entered into in January 2006 will be determined starting with the first quarter of 2006. Management expects the company to be in compliance with such covenants.

Tronox’s $450 million Senior Secured Credit Agreement – In November 2005, Tronox entered into a senior secured credit facility consisting of a $200 million six-year term loan facility and a five-year multicurrency revolving credit facility of $250 million. Interest on amounts borrowed under the Tronox credit agreement is payable, at Tronox’s election, at a base rate or a LIBOR rate, in each case as defined in the Tronox credit agreement. The initial margin applicable to LIBOR borrowings is 175 basis points and may vary from 100 to 200 basis points depending on Tronox’s credit rating.

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The terms of the Tronox credit agreement provide for customary representations and warranties, affirmative and negative covenants, and events of default. Tronox is also required to maintain compliance with the following financial covenants beginning in 2006 (in each case, as defined in the agreement):

• Consolidated Total Leverage Ratio of no more than 3.75:1

• Consolidated Interest Coverage Ratio of at least 2:1

• Limitation on Capital Expenditures

Tronox Incorporated and certain of its subsidiaries have guaranteed the obligations under the Tronox credit agreement and have granted a security interest in specified assets including property and equipment, inventory and accounts receivable.

Long-Term Debt

As more fully discussed below, in 2005, the company borrowed and repaid an aggregate of $4.25 billion under term loans. In February 2005, the company called for redemption all of the $600 million aggregate principal amount of its 5.25% convertible subordinated debentures due 2010 at a price of 102.625%. Prior to March 4, 2005, the redemption date, all of the debentures were converted by the holders into approximately 9.8 million shares of Kerr-McGee common stock (on a pre-split basis). In February 2006, the company redeemed the 7% debentures due 2011 at face value of $250 million using cash on hand. In connection with the early redemption, a pretax loss of $69 million, representing a write-off of unamortized discount on the debentures, will be recognized in the first quarter of 2006. The following table presents the composition of long-term debt at December 31, 2005 and 2004.

	December 31,
(Millions of dollars)	2005			2004
Kerr-McGee Corporation –
Debentures
5.25% Convertible subordinated debentures due February 15, 2010	$	—		$	600
7% Debentures due November 1, 2011, net of unamortized discount of $70 and $77 (14.25% effective rate)(1)		180			173
7.125% Debentures due October 15, 2027		150			150
Notes payable
5.375% Notes due April 15, 2005, including a premium of $4 in 2004 for fair value hedge adjustment		—			354
8.125% Notes due October 15, 2005, net of a discount of $1 in 2004 for fair value hedge adjustment		—			108
5.875% Notes due September 15, 2006, net of unamortized discount of $1 in 2005 (6.23% effective rate)		306			307
6.625% Notes due October 15, 2007, net of discount of $5 and $2 for fair value hedge adjustment		145			148
6.875% Notes due September 15, 2011, net of unamortized discount of $4 and $1 (6.99% effective rate)		671			674
6.95% Notes due July 1, 2024, net of unamortized discount of $12 in 2005 and $5 in 2004 (7.05% effective rate)		638			645
7.875% Notes due September 15, 2031, net of unamortized discount of $7 and $2 (7.93% effective rate)		493			498
Commercial paper and other		—			42
Total Kerr-McGee debt		2,583			3,699
Long-term debt due within one year		(306	)		(463	)
	$	2,277		$	3,236
Tronox Incorporated(3) –
9.5% Notes due December 1, 2012	$	350		$	—
Variable-rate term loan due in installments through November 28, 2011		200			—
Total Tronox debt		550			—
Long-term debt due within one year		(2	)		—
	$	548		$	—

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The following summarizes the scheduled debt maturities as of December 31, 2005:

(Millions of dollars)	2006		2007		2008		2009		2010		There- after (1)		Total (2)
Kerr-McGee debt	$	306	$	145	$	—	$	—	$	—	$	2,132	$	2,583
Tronox debt		2		2		2		2		2		540		550
Total long-term debt	$	308	$	147	$	2	$	2	$	2	$	2,672	$	3,133

⁽¹⁾ As discussed above, the 7% debentures due in 2011 were redeemed in February 2006.

⁽²⁾ These amounts include unamortized discount on issuance of $94 million and net fair value hedge adjustments of $5 million.

⁽³⁾ These notes are reported in discontinued operations in the Consolidated Balance Sheet.

$5.5 Billion Secured Credit Agreement– In May 2005, the company completed a self tender offer for its common stock for an aggregate cost of $4 billion. In connection with the tender offer, the company entered into a $5.5 billion secured credit agreement (Credit Agreement) consisting of a $2 billion two-year term loan (Tranche X), a $2.25 billion six-year term loan (Tranche B) and a $1.25 billion five-year revolving credit facility. The term loans were fully funded at closing, with proceeds used primarily to finance the tender offer and to pay fees and expenses associated with the Credit Agreement. While the Tranche X and Tranche B term loans were outstanding, the weighted average interest rates on the loans were 5.9% and 6.2%, respectively. All borrowings under the Credit Agreement were repaid by the end of 2005 and the Credit Agreement was terminated on January 9, 2006.

Under the Credit Agreement, the company was subject to mandatory prepayment provisions, including required prepayments with 100% of the net cash proceeds, as defined, from asset disposals. The following provides information on repayments of the Tranche X and Tranche B term loans during 2005. As discussed in Note 2, as a result of this requirement, a portion of interest and debt expense associated with term loan borrowings was reflected in income from discontinued operations.

(Million of dollars)	Mandatory Prepayment		Optional Prepayment		Total		Debt Issue Costs Written Off
Transactions Resulting in Prepayments –
Sale of the North Sea oil and gas business	$	3,072	$	102	$	3,174	$	28
Sale of nonoperating interest in gas processing facility		111		39		150		1
Tronox initial public offering		800		120		920		9
	$	3,983	$	261		4,244	$	38
Scheduled principal payment						6
Total term loan repayments					$	4,250

In connection with the Credit Agreement, the company incurred financing costs of $58 million, which were initially capitalized and amortized as interest expense over the terms of the related facilities. Repayment of term loan borrowings earlier than scheduled resulted in writing off $38 million of debt issue costs during 2005. This charge is included in loss on early repayment and modification of debt in the Consolidated Statement of Income. The company will recognize an additional charge of $12 million in the first quarter of 2006 in connection with the termination of the Credit Agreement. This charge represents unamortized financing costs associated with the $1.25 billion revolving credit facility under the Credit Agreement.

Modification to Guarantee Provisions– Prior to completing Tronox’s IPO, the company’s chemical business subsidiary, Tronox Worldwide LLC (formerly Kerr-McGee Chemical Worldwide LLC), was one of the guarantor subsidiaries of the company’s 5.875% Notes due 2006, 6.875% Notes due 2011, 6.95% Notes due 2024 and 7.875% Notes due 2031 (collectively referred to herein as the Notes). In September 2005, the company received consent from a majority of the noteholders to amend the indenture governing the Notes. The supplemental indenture, which became effective as of September 21, 2005, provided for the release of Tronox Worldwide LLC as a guarantor of the Notes upon an IPO by Tronox Worldwide LLC, or upon a spinoff or splitoff of Tronox Worldwide LLC, or its parent, Tronox Incorporated. Upon completing the IPO, Tronox Worldwide LLC was released from its guaranty of the Notes. As a result of this modification to the indenture governing the Notes, the company paid aggregate consent and release fees to noteholders of $18 million, which were recorded as a reduction in the carrying value of the associated Notes and will increase interest expense over the remaining terms of the Notes. In connection with the consent solicitation, the company incurred transaction costs of $4 million, which is included in loss on early repayment and modification of debt in the accompanying Consolidated Statement of Income.

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11.Accounts Receivable Sales

Through April 2005, Tronox had an accounts receivable monetization program with a maximum availability of $165 million. Under the terms of the program, selected qualifying customer accounts receivable arising from sales of titanium dioxide pigment by Tronox were sold monthly to a special-purpose entity (SPE), which in turn sold an undivided ownership interest in the receivables to a third-party multi-seller commercial paper conduit sponsored by an independent financial institution. Tronox sold, and retained an interest in, excess receivables to the SPE as over-collateralization for the program. The retained interest in sold receivables was subordinate to, and provided credit enhancement for, the conduit’s ownership interest in the SPE’s receivables, and was available to the conduit to pay certain fees or expenses due to the conduit, and to absorb credit losses incurred on any of the SPE’s receivables in the event of program termination. No recourse obligations were recorded since the company had no obligations for any recourse actions on the sold receivables. At December 31, 2004, the outstanding balance of receivables sold (and excluded from the company’s Consolidated Balance Sheet as of that date) was $165 million, which was net of the company’s retained interest in receivables serving as over-collateralization of $39 million.

The accounts receivable monetization program included ratings downgrade triggers that provided for certain program modifications, including a program termination event upon which the program would effectively liquidate over time and the third-party multi-seller commercial paper conduit would be repaid with the collections on accounts receivable sold by the SPE. In April 2005, following the announcement of the self tender offer and the related increase in the company’s leverage discussed in Note 1, the company’s senior unsecured debt was downgraded, triggering program termination. As opposed to liquidating the program over time in accordance with its terms, the company entered into an agreement to terminate the program by repurchasing the then outstanding balance of receivables sold of $165 million. Repurchased accounts receivable were collected by the company later in 2005.

While the program was in effect in 2005 and during 2004 and 2003, the company sold $384 million, $1.1 billion and $836 million, respectively. The resulting losses are reflected as a component of income from discontinued operations. The losses are equal to the difference in the book value of the receivables sold and the total of cash and the fair value of the deposit retained by the SPE.

12.Financial Instruments

The company holds or issues financial instruments for other than trading purposes. Prior to 2005, the company invested in certain available for sale and trading securities, substantially all of which were disposed of by the end of 2004. Investments in marketable securities are classified as either “trading” or “available for sale” depending on management’s intent and are carried in the Consolidated Balance Sheet at their estimated fair values based on quoted market prices. Unrealized gains or losses on trading securities are recognized in earnings, while unrealized gains or losses on available-for-sale securities are recorded as a component of other comprehensive income (loss) within stockholders’ equity. Realized gains and losses are determined using the average cost method and are reflected as a component of other income (expense) in the Consolidated Statement of Income. Discussion that follows provides information about debt exchangeable for common stock (DECS) which was redeemed using shares of Devon Energy Corporation common stock (Devon stock).

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DECS and Investment in Devon Stock

The company issued 5.5% notes exchangeable for common stock (DECS) in August 1999, which allowed each holder to receive between .85 and 1.0 share of Devon common stock or, at the company’s option, an equivalent amount of cash at maturity in August 2004. Embedded options in the DECS provided the company a floor price on Devon’s common stock of $33.19 per share (the put option). The company also had the right to retain up to 15% of the shares if Devon’s stock price was greater than $39.16 per share (the DECS holders had an embedded call option on 85% of the shares). Using the Black-Scholes valuation model, the company estimated the fair value of the put and call options and recognized gains or losses resulting from changes in their fair value in other income (expense) in the Consolidated Statement of Income, along with the changes in the market value of Devon stock classified as trading. The company classified a portion of its Devon stock holdings necessary to repay the DECS as trading (8.4 million shares), with the remaining shares designated as available for sale.

Available-for-Sale Securities – Through January 2004, the company held shares of Devon stock considered to be available for sale. A portion of this investment was sold in December 2003, resulting in a gain of $17 million. The remaining shares were sold in January 2004 for a gain of $9 million. Proceeds from the December 2003 sales totaled $59 million ($47 million received in 2003 and $12 million received in 2004) and proceeds from the January 2004 sales totaled $27 million.

Trading Securities and DECS Redemption– Unrealized gains related to the company’s investment in Devon stock classified as trading amounted to $103 million in 2004 through the date of disposition and $96 million in 2003. These gains were partially offset by unrealized losses on the embedded options associated with the DECS of $101 million in 2004 through the date of the DECS redemption, and $88 million in 2003.

On August 2, 2004, the company’s DECS matured and were settled with the distribution of shares of Devon stock, at which time the fair values of the embedded put and call options in the DECS were nil and $256 million, respectively, and the fair value of the 8.4 million shares of Devon stock was $586 million. The fair value of Devon stock less the call option liability resulted in a net asset carrying value of $330 million, which was offset exactly by the fair value of the DECS resulting in no gain or loss on redemption of the debt. The company recognized, as a component of other income (expense), a charge against earnings of $7 million related to a cumulative translation adjustment recorded prior to 1999 when the company accounted for its investment in Devon using the equity method. The proportionate share of Devon’s cumulative translation adjustment was removed from equity and reported in earnings in 2004, when the liquidation of the associated investment occurred.

Financial Instruments for Other than Trading Purposes

At December 31, 2005 and 2004, the carrying amount and estimated fair value of financial instruments held or issued for other than trading purposes are as follows:

	2005						2004
	Carrying			Fair			Carrying		Fair
(Millions of dollars)	Amount			Value			Amount		Value
Cash and cash equivalents	$	1,053		$	1,053		$	76	$	76
Long-term debt		3,133	(1)		3,414	(1)		3,699		4,039

⁽¹⁾ Includes carrying amount and fair value of $550 million associated with Tronox debt.

The carrying amount of cash and cash equivalents approximates fair value of those instruments due to their short maturity. The fair value of the company’s long-term debt is based on the quoted market prices for the same or similar debt issues or on the current rates offered to the company for debt with the same remaining maturity. Carrying values of derivative instruments, which reflect their estimated fair values, are presented in Note 9.

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13.Income Taxes

The 2005, 2004 and 2003 income tax provision (benefit) from continuing operations are summarized below:

(Millions of dollars)	2005		2004			2003
U.S. Federal –
Current	$	345	$	55		$	16
Deferred		64		115			6
		409		170			22
International –
Current		36		(2	)		(9	)
Deferred		31		21			(4	)
		67		19			(13	)
State		10		2			4
Total	$	486	$	191		$	13

On October 22, 2004, the President of the United States signed the American Jobs Creation Act of 2004 (the “Act”) into law. A provision of the Act includes a one time dividends received deduction of 85% of certain foreign earnings that are repatriated, as defined in the Act. In 2005, management completed its analysis of the impact of the Act on the company’s plans for repatriation. Based upon this analysis, the company repatriated $231 million of qualifying foreign earnings in 2005 and recognized income tax expense of $9 million (net of foreign tax credits of $5 million), including $5 million of income tax expense associated with extraordinary dividends repatriated by Tronox.

In the following table, the U.S. federal income tax rate is reconciled to the company’s effective tax rates for income or loss from continuing operations as reflected in the Consolidated Statement of Income.

	2005		2004		2003
U.S. statutory tax rate	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from –
Charitable contribution	—		—		(2.2	)
U.S. federal tax audit settlement	—		—		(24.7	)
Taxation of foreign operations	(.7	)	(.2	)	(3.7	)
State income taxes	.4		.2		.9
Other – net	(.4	)	(1.3	)	.2
Effective tax rate	34.3	%	33.7	%	5.5	%

Taxation for a company with operations in several foreign countries involves many complex variables, such as tax structures that differ from country to country and the effect on U.S. taxation of international earnings. These complexities do not permit meaningful comparisons between the U.S. and international components of income before income taxes and the provision for income taxes, and disclosures of these components do not necessarily provide reliable indicators of relationships in future periods. Income from continuing operations before income taxes is comprised of the following:

(Millions of dollars)	2005		2004		2003
United States	$	1,212	$	515	$	300
International		206		51		(62	)
Total	$	1,418	$	566	$	238

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Net deferred tax liabilities at December 31, 2005 and 2004 are comprised of the following:

(Millions of dollars)	2005			2004
Deferred tax liabilities –
Property, plant and equipment	$	1,769		$	1,777
Undistributed earnings of certain foreign subsidiaries		28			28
Deferred state, local and other taxes		36			16
Intangible assets		7			22
Other		31			32
Deferred tax liabilities of discontinued operations		154			703
Total deferred tax liabilities		2,025			2,578
Deferred tax assets –
Net operating loss and other carryforwards		(1	)		(155	)
Derivative instruments		(694	)		(123	)
Asset retirement and environmental obligations		(131	)		(101	)
Foreign exploration expenses		(59	)		(83	)
Obligations for pension and other benefits		(42	)		(24	)
Financial accruals and deferrals		(44	)		(54	)
Other		(2	)		(18	)
Deferred tax assets of discontinued operations		(115	)		(175	)
		(1,088	)		(733	)
Valuation allowance associated with discontinued operations		6			8
Net deferred tax assets		(1,082	)		(725	)
Net deferred tax liability		943			1,853
Less: net deferred tax liability of discontinued North Sea operations (1)		—			453
Less: net deferred tax liability associated with Tronox		45			83
Net deferred tax liability – continuing operations	$	898		$	1,317

⁽¹⁾ The net U.K. deferred tax liability associated with discontinued operations was assumed by the acquirer as part of the divestiture transaction discussed in Note 2 and, as such, was included in the carrying amount of the investment for purposes of calculating pretax gain on sale of the U.K. subsidiary.

At December 31, 2005, Tronox had a $7.5 million United States federal net operating loss carryforward. Such loss could not be utilized by Kerr-McGee due to Tronox’s status as a non-consolidated corporation for U.S. federal tax reporting following the November 2005 IPO. No valuation allowance has been provided for the net operating loss carryforward, as Tronox management expects to use the full amount of the loss carryforward in the 2006 Tronox federal income tax return.

At December 31, 2005, Tronox and its consolidated subsidiaries had foreign operating loss carryforwards totaling $158 million. Of this amount, $10 million expires in 2009, $21 million in 2011, $1 million in 2012 and $126 million has no expiration date. Realization of these operating loss carryforwards depends on generating sufficient taxable income in future periods. A valuation allowance of $6 million has been recorded to reduce deferred tax assets associated with loss carryforwards that the company does not expect to fully realize prior to expiration.

Undistributed earnings of certain consolidated foreign subsidiaries totaled $185 million and $115 million for Kerr-McGee and Tronox, respectively. No provision for deferred U.S. income taxes has been made for these earnings because they are considered to be indefinitely invested outside the United States. The distribution of these earnings in the form of dividends or otherwise, may subject the company to U.S. income taxes and, possibly, foreign withholding taxes. However, because of the complexities of U.S. taxation of foreign earnings, it is not practicable to estimate the amount of additional tax that might be payable on the eventual remittance of these earnings.

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The Internal Revenue Service has completed its examination of the Kerr-McGee Corporation and subsidiaries’ federal income tax returns for all years through 2002 and is conducting an examination of the years 2003 and 2004. The years through 1996 have been closed with the exception of issues for which a refund claim has been filed. The Oryx Energy Company income tax returns have been examined through 1997, and the years through 1978 have been closed, as have the years 1988 through 1998. Oryx and Kerr-McGee merged in 1999. The company believes that it has made adequate provision for income taxes that may be payable with respect to open years.

Tax Sharing Agreement and Tax Allocations– Kerr-McGee entered into a tax sharing agreement with Tronox that governs each party’s respective rights, responsibilities and obligations subsequent to the IPO with respect to taxes for tax periods ending in 2005 and prior. Generally, taxes incurred or accrued prior to the IPO that are attributable to the business of one party will be borne solely by that party.

Kerr-McGee may incur certain restructuring taxes as a result of the Tronox separation. Under the tax sharing agreement, restructuring tax is any tax incurred as a result of any restructuring transaction undertaken to effectuate the Tronox separation, which in the judgment of the parties is currently required to be taken into account in determining the tax liability of Kerr-McGee or Tronox (or their respective subsidiaries) for any pre-IPO period. The tax sharing agreement provides that Kerr-McGee will be responsible for 100% of the restructuring taxes up to, but not to exceed, $17 million. In addition, Tronox is required to indemnify Kerr-McGee for any tax liability incurred by reason of the IPO and subsequent Distribution being considered a taxable transaction to Kerr-McGee as a result of a breach of any of Tronox’s representations, warranties, or covenants contained in the tax sharing agreement.

14.Exit, Disposal and Restructuring Activities

The following table presents a reconciliation of the beginning and ending balances of reserves for exit and restructuring activities for the last three years, as well as charges not affecting reserve balances, such as accelerated depreciation of assets, asset impairments and benefit plan curtailment charges. Discussion of significant exit, disposal and restructuring activities is provided below.

	Reserve Activity									Other Activity
(Millions of dollars)	Dismantlement and Closure			Personnel Costs			Total			Asset Write-downs		Benefit Plan Charges		Total Charges
Balance at December 31, 2002	$	23		$	4		$	27
Provisions / Accruals		12			37			49		$	20	$	48	$	117
Payments		(18	)		(16	)		(34	)
Adjustments (1)		(5	)		2			(3	)						(1	)
Balance at December 31, 2003		12			27			39						$	116
Provisions / Accruals		17			23			40		$	114	$	6	$	160
Payments		(16	)		(40	)		(56	)
Adjustments (1)		1			(2	)		(1	)						(1	)
Balance at December 31, 2004		14			8			22						$	159
Provisions / Accruals		—			29			29		$	—	$	3	$	32
Payments		(6	)		(15	)		(21	)
Adjustments (1)		(2	)		(1	)		(3	)						(3	)
Balance at December 31, 2005	$	6		$	21		$	27						$	29
Costs expected to be incurred in excess of established reserves (2)	$	—		$	12		$	12
Expected payments -
2006	$	4		$	31		$	35
2007 and thereafter		2			2			4

⁽¹⁾ Includes effects of foreign currency translation

⁽²⁾ For certain employee severance and retention programs, the company recognizes provisions and associated reserves over the period when employee services necessary to earn the benefits are provided.

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The following summarizes costs associated with exit, disposal and restructuring activities incurred in the last three years and their classification in the company’s financial statements. These costs have not been allocated to the company’s reportable business segments. Accruals for severance associated with the Westport merger were reflected in the purchase price allocation as an assumed liability.

(Millions of dollars)	2005		2004		2003
Classification of costs and charges –
General and administrative expense	$	26	$	2	$	33
Costs reflected in income from discontinued operations (pretax)		3		139		83
Severance costs associated with the Westport merger		—		18		—
Total	$	29	$	159	$	116

Activities Initiated in 2005– As discussed in Note 1, in 2005, the company made a number of strategic decisions, including divestitures of its North Sea oil and gas business and selected oil and gas properties in the U.S. and the separation of Tronox. In April 2005, in connection with the planned exit activities, the company initiated employee retention programs with an aggregate cost of $34 million, designed to provide an incentive to certain employees to remain with the company over a stated period ranging from six to 18 months. Later in 2005, in connection with the Tronox separation, the company identified approximately 80 employees for involuntary termination by the end of 2006. The majority of these employees will receive severance payments and other benefits upon completion of a specified service period of up to 14 months, for an aggregate cost of $5 million. Qualifying employees terminated under this program also will be eligible for enhanced benefits under the company’s pension and postretirement plans.

Activities Initiated in 2004– In 2004, Tronox shut down its titanium dioxide pigment sulfate and gypsum production at its Savannah, Georgia, facility as a result of unacceptable financial returns for the facility due to declining demand and prices for sulfate anatase pigments, along with unanticipated environmental and infrastructure issues discovered after the facility was acquired in 2000. The Savannah facility’s work force of 410 was reduced by approximately 100 positions. Tronox incurred an aggregate charge of $123 million in 2004 associated with the shutdown.

Activities Initiated in 2003 – In September 2003, the company announced a program to reduce its U.S. nonbargaining work force through both voluntary retirements and involuntary terminations. As a result of the program, the company’s eligible U.S. nonbargaining work force was reduced by approximately 9%, or 271 employees. Qualifying employees terminated under this program were eligible for enhanced benefits under the company’s pension and postretirement plans, along with severance payments. The program was substantially complete by the end of 2003 and resulted in a charge of $56 million in 2003, of which $34 million was for curtailment and special termination benefits associated with the company’s retirement plans.

In June 2003, Tronox closed its synthetic rutile plant in Mobile, Alabama. The plant processed and supplied a portion of the feedstock for Tronox’s titanium dioxide pigment plants in the United States. The plant was closed when the company identified opportunities to purchase the feedstock more economically than it could be manufactured at the Mobile plant. Tronox provided $61 million and $7 million in 2003 and 2004, respectively, for costs associated with the plant closure. The Mobile plant closure will ultimately result in 127 employees being terminated, of which 112 were terminated by year-end 2005.

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15.Employee Benefit Plans

Overview– Kerr-McGee is a sponsor of noncontributory defined-benefit retirement plans and contributory postretirement plans for health care and life insurance, in each case for the benefit of the company’s current and former employees in the U.S. Most U.S. employees are covered under the company’s retirement plans, and substantially all U.S. employees may become eligible for the postretirement benefits if they reach retirement age while working for the company. Additionally, certain foreign subsidiaries of Tronox sponsor contributory retirement plans in Germany and the Netherlands. As discussed in Note 3, under the provisions of the Employee Benefits Agreement between Kerr-McGee and Tronox, qualifying current and former U.S. employees of Tronox also participate in Kerr-McGee’s benefit plans through the date of the Distribution. Effects of the Distribution on defined-benefit plans sponsored by Kerr-McGee are discussed in more detail below. The measurement date used for all plans is December 31.

Effect of Tronox Separation– It is expected that upon completion of the Distribution, the company will transfer to Tronox approximately 40% of its U.S. pension benefit obligation and approximately 50% of its U.S. postretirement benefit obligation as of that date. Kerr-McGee also will transfer approximately 40% of its trust assets to the newly established U.S. pension plan to fund the transferred pension benefit obligation in compliance with applicable regulatory requirements. Actual values of the benefit obligations and associated plan assets transferred to Tronox will be determined at the time of the Distribution and will depend on the level of retirement plan assets, interest rates and other factors relevant to the measurement of the obligations and determination of asset values to be transferred. Note 26 provides additional information regarding the Tronox Distribution.

Benefit Obligations and Funded Status– The following provides a reconciliation of benefit obligations, plan assets and funded status of the company’s pension and other postretirement plans as of and for the years ended December 31, 2005 and 2004, prior to the transfer of obligations and assets to Tronox. The following table excludes information associated with the U.K. retirement plan sponsored by the company’s North Sea oil and gas business that was sold in 2005, as discussed in Note 2. At December 31, 2004, the projected benefit obligation and the fair value of plan assets for the U.K. retirement plan were $88 million and $79 million, respectively. Long-term assets of discontinued operations in the company’s Consolidated Balance Sheet as of December 31, 2004 include prepaid pension cost of $23 million associated with this plan.

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	Retirement Plans						Postretirement Health and Life Plans
(Millions of dollars)	2005			2004			2005			2004
Change in benefit obligations –
Benefit obligation, beginning of year	$	1,172		$	1,175		$	276		$	314
Service cost		32			26			3			3
Interest cost		66			68			16			18
Plan amendments/law changes (1)		—			1			—			(72	)
Net actuarial loss		84			91			24			38
Foreign currency rate changes		(11	)		6			—			—
Contributions by plan participants		—			—			9			9
Special termination benefits, settlement and curtailment (gains) losses		3			(1	)		—			—
Benefits paid		(91	)		(194	)		(31	)		(34	)
Benefit obligation, end of year		1,255			1,172			297			276
Change in plan assets –
Fair value of plan assets, beginning of year		1,168			1,239			—			—
Actual return on plan assets		54			102			—			—
Employer contributions (2)		9			16			22			25
Participant contributions		—			—			9			9
Foreign currency rate changes		(8	)		5			—			—
Benefits paid		(91	)		(194	)		(31	)		(34	)
Fair value of plan assets, end of year (3)		1,132			1,168			—			—
Funded status of plans - under funded		(123	)		(4	)		(297	)		(276	)
Amounts not recognized in the Consolidated Balance Sheet –
Prior service costs		42			49			(14	)		(16	)
Net actuarial loss		282			159			80			59
Net prepaid expense (accrued liability) recognized	$	201		$	204		$	(231	)	$	(233	)
Classification of amounts recognized in the Consolidated Balance Sheet –
Prepaid pension cost	$	249		$	239		$	—		$	—
Accrued benefit liability		(79	)		(55	)		(231	)		(233	)
Accumulated other comprehensive loss (pretax)		31			20			—			—
Total	$	201		$	204		$	(231	)	$	(233	)

⁽¹⁾ The 2004 reduction in the postretirement benefit obligation related to plan amendments/law changes of $72 million is primarily the result of the company’s adoption of FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” and a November 1, 2004 plan change causing prescription drug coverage provided by the company’s U.S. postretirement health and life plan to become secondary to Medicare Part D coverage.

⁽²⁾ During 2005, the company made a discretionary contribution of approximately $7 million to the Netherlands trust fund to increase plan assets above the accumulated benefit obligation level. The company expects 2006 contributions to be $5 million for the U.S. nonqualified plans, $21 million for the U.S. postretirement plans and approximately $2 million for the foreign retirement plans. No contributions are expected in 2006 for the U.S. qualified retirement plan.

⁽³⁾ Excludes the grantor trust assets of $50 million at year-end 2005 and 2004 associated with the company’s supplemental nonqualified U.S. plans. In January 2006, the company made an additional $22 million discretionary contribution to the grantor trust.

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The following table summarizes the accumulated benefit obligations and the projected benefit obligations associated with the company’s unfunded benefit plans.

	At December 31, 2005						At December 31, 2004
(Millions of dollars)	U.S. Nonqualified Plans(1)		U.S. Postretirement Plan		Germany Retirement Plan		U.S. Nonqualified Plans(1)		U.S. Postretirement Plan		Germany Retirement Plan
Accumulated benefit obligation	$	65	$	297	$	13	$	37	$	276	$	12
Projected benefit obligation		80		297		14		55		276		13

⁽¹⁾ Although not considered plan assets, a grantor trust was established from which payments for certain U.S. supplemental benefits are made. The trust assets had a balance of $50 million at year-end 2005 and 2004. In January 2006, the company made and additional $22 million discretionary contribution to the grantor trust.

Summarized below are the accumulated benefit obligation, the projected benefit obligation, the market value of plan assets and the funded status of the company’s funded retirement plans.

	At December 31, 2005						At December 31, 2004
(Millions of dollars)	U.S. Qualified Plan			The Netherlands Retirement Plan			U.S. Qualified Plan		The Netherlands Retirement Plan
Accumulated benefit obligation	$	990		$	59		$	941	$	61
Projected benefit obligation	$	1,093		$	68		$	1,034	$	70
Market value of plan assets		1,070			62			1,109		59
Funded status – (under)/over funded	$	(23	)	$	(6	)	$	75	$	(11	)

Expected Benefit Payments – Following are the expected benefit payments for the next five years and in the aggregate for the years 2011 through 2015:

(Millions of dollars)	2006		2007		2008		2009		2010		2011- 2015
Retirement Plans	$	92	$	102	$	90	$	94	$	97	$	478
Postretirement Health and Life Plans		21		21		21		21		21		106

For the retirement plans that qualify under the Employee Retirement Income Security Act of 1974 (ERISA), the benefit amount that can be provided to employees by the plans is limited by both ERISA and the Internal Revenue Code. Therefore, the company has unfunded supplemental nonqualified plans designed to maintain benefits for all employees at the plan formula level and to provide senior executives with benefits equal to a specified percentage of their final average compensation.

Net Periodic Cost– Income from continuing operations for 2005, 2004 and 2003 includes the following components of net periodic cost (benefit) associated with the company’s U.S. benefit plans:

	Retirement Plans									Postretirement Health and Life Plans
(Millions of dollars)	2005			2004			2003			2005			2004		2003
Net periodic cost (benefit) –
Service cost	$	30		$	23		$	21		$	3		$	3	$	3
Interest cost		63			65			67			16			18		17
Expected return on plan assets		(96	)		(110	)		(117	)		—			—		—
Special termination benefits, settlement and curtailment losses		3			14			38			—			—		10
Net amortization –
Prior service cost		8			9			9			(2	)		1		—
Net actuarial (gain) loss		3			—			(11	)		3			2		—
Total		11			1			7			20			24		30
Less: net periodic cost associated with Tronox discontinued operations		—			2			9			9			10		12
Total – continuing operations	$	11		$	(1	)	$	(2	)	$	11		$	14	$	18

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Net periodic pension cost for the year ended December 31, 2005 includes special termination benefits resulting from an involuntary termination program initiated by the company in October 2005. The 2003 net periodic cost includes curtailment losses associated with the 2003 work force reduction program.

Assumptions– The following weighted average assumptions were used to determine the net periodic cost:

	2005				2004				2003
	United States		International		United States		International		United States		International
Discount rate	5.75	%	4.75	%	6.25	%(1)	5.29	%	6.75	%	5.55	%
Expected return on plan assets	8.25		5.50		8.50		5.75		8.50		5.75
Rate of compensation increases	4.50		3.42		4.50		2.81		4.50		2.55

⁽¹⁾ Following remeasurement at July 1, 2004 to recognize a settlement for the qualified plan, the discount rate for the qualified plan was 6.5% for the remainder of the year.

The following assumptions were used in estimating the actuarial present value of the plans’ benefit obligations:

	2005				2004				2003
	United States		International		United States		International		United States		International
Discount rate	5.50	%	4.25	%	5.75	%	4.75	%	6.25	%	5.29	%
Rate of compensation increases	4.50		3.42		4.50		3.42		4.50		2.81

In forming the assumption of the U.S. long-term rate of return, the company takes into account the expected earnings on funds already invested, earnings on contributions expected to be received in the current year, and earnings on reinvested returns. The long-term rate of return estimation methodology for U.S. plans is based on a capital asset pricing model using historical data. An expected return analysis is performed which incorporates the current portfolio allocation, historical asset-class returns and an assessment of expected future performance using asset-class risk factors. Our assumption of the long-term rate of return for the Netherlands plan is developed considering the portfolio mix and country-specific economic data that includes the rates of return on local government and corporate bonds.

The company selects a discount rate for its U.S. qualified plan and its postretirement plan using the results of a cash flow matching analysis based on projected cash flows for the plans. For foreign plans, the company bases the discount rate assumption on local corporate bond index rates.

The health care cost trend rates used to determine the year-end 2005 postretirement benefit obligation were 10% in 2006, gradually declining to 5% in 2012 and thereafter. A 1% increase in the assumed health care cost trend rate for each future year would increase the postretirement benefit obligation at December 31, 2005 by $14 million, while the aggregate of the service and interest cost components of the 2005 net periodic postretirement cost would increase by $1 million. A 1% decrease in the trend rate for each future year would reduce the benefit obligation at year-end 2005 by $12 million and decrease the aggregate of the service and interest cost components of the net periodic postretirement cost for 2005 by $1 million.

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Plan Assets – Asset categories for the company’s funded retirement plans and the associated asset allocations by category at December 31, 2005 and 2004 are as follows:

	U.S. Plan Assets				The Netherlands Plan Assets
	2005		2004		2005		2004
Equity securities	55	%	57	%	28	%	24	%
Debt securities	42		41		63		76
Cash and cash equivalents	3		2		9		—
Total	100	%	100	%	100	%	100	%

The U.S. plan is administered by a board-appointed committee that has fiduciary responsibility for the plan’s management. The committee maintains an investment policy stating the guidelines for the performance and allocation of plan assets, performance review procedures and updating of the policy. At least annually, the U.S. plan’s asset allocation guidelines are reviewed in light of evolving risk and return expectations. Current guidelines permit the committee to manage the allocation of funds between equity and debt securities within the range of 40-60% equity securities and 40-60% debt securities.

Substantially all of the plan’s assets are invested with eight equity fund managers and six fixed-income fund managers. At year-end 2005 and 2004, equity securities held by the plan included $5 million and $3 million of Kerr-McGee stock, respectively, or 101,474 shares. Dividends paid on these shares were less than $100,000 in 2005 and 2004. To control risk, equity fund managers are prohibited from entering into the following transactions, (i) investing in commodities, including all futures contracts, (ii) purchasing letter stock, (iii) short selling and (iv) option trading. In addition, equity fund managers are prohibited from purchasing on margin and are prohibited from purchasing Kerr-McGee securities. Equity managers are monitored to ensure investments are in line with their style and are generally permitted to invest in U.S. common stock, U.S. preferred stock, U.S. securities convertible into common stock, common stock of foreign companies listed on major U.S. exchanges, common stock of foreign companies listed on foreign exchanges, covered call writing, and cash and cash equivalents.

Fixed-income fund managers are prohibited from investing in (i) direct real estate mortgages or commingled real estate funds, (ii) private placements above certain portfolio thresholds, (iii) tax exempt debt of state and local governments above certain portfolio thresholds, (iv) fixed income derivatives that would cause leverage, (v) guaranteed investment contracts, and (vi) Kerr-McGee securities. They are permitted to invest in debt securities issued by the U.S. government, its agencies or instrumentalities, commercial paper rated A3/P3, FDIC insured certificates of deposit or bankers acceptances, and corporate debt obligations. Each fund manager’s portfolio should have an average credit rating of A or better.

The Netherlands plan is administered by a pension committee representing the employer, the employees and the pensioners, each with one equal vote. The pension committee members are approved by the state’s lead pension agency based upon experience and character. The pension committee meets at least quarterly to discuss regulatory changes, asset performance and asset allocation. The plan assets are managed by one Dutch fund manager against a mandate set at least annually by the pension committee. The plan assets are evaluated annually by a multinational benefits consultant against state defined actuarial tests to determine funding requirements.

16.Contingencies

Effect of Tronox Separation – As discussed in Note 3, in 2005, Kerr-McGee transferred to Tronox the subsidiaries holding and operating Kerr-McGee’s chemical business and completed the IPO of Tronox Class A common stock. As discussed in Note 26, the company distributed its remaining 56.7% ownership interest in Tronox to Kerr-McGee’s stockholders in March 2006.

Tronox and its subsidiaries are subject to obligations for environmental remediation and restoration associated with the chemical business currently in operation, as well as with former operations, including the production of ammonium perchlorate, the manufacturing of thorium compounds, treatment of forest products, the refining and marketing of petroleum products, and the mining, milling and processing of

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nuclear materials. Under the terms of the Master Separation Agreement (MSA), Kerr-McGee agreed to reimburse Tronox for 50% of the environmental remediation costs incurred and paid by Tronox and its subsidiaries, to the extent such costs, net of any reimbursements received from insurers or other parties, exceed the carrying value of Tronox’s environmental reserves as of November 28, 2005. Notwithstanding the foregoing, Kerr-McGee is not obligated to reimburse Tronox if such excess expenditures at any individual site are $200,000 or less, or for any remediation costs incurred and paid by Tronox after November 28, 2012. This seven-year reimbursement obligation extends to costs incurred and paid at any site associated with any of the former businesses and operations of Tronox and is limited to a maximum aggregate reimbursement of $100 million for all covered sites. Additionally, Kerr-McGee is not obligated to reimburse Tronox for amounts paid to third parties in connection with tort claims or personal injury lawsuits, or for costs incurred and paid by Tronox in excess of the lowest cost response, as defined in the MSA.

Because Tronox is a consolidated subsidiary of Kerr-McGee as of December 31, 2005, the Consolidated Balance Sheet reflects Tronox’s liabilities for environmental remediation and restoration costs that are probable and estimable. The accompanying financial statements do not include any effects of the reimbursement obligation discussed above between the parties within the consolidated group. Upon completion of the Distribution, Tronox ceased to be a consolidated subsidiary of Kerr-McGee, at which time Kerr-McGee recognized a liability of $56 million associated with its reimbursement obligation, measured at its estimated fair value.

The following table presents December 31, 2005 balances of reserves for environmental and legal contingencies and the related reimbursements receivable from the U.S. government and insurers.

(Millions of dollars)	Legal Reserves		Reserves for Environmental Remediation		Reimbursements Receivable
Tronox	$	9	$	224	$	57
Other Kerr-McGee		21		44		—
Balance at December 31, 2005	$	30	$	268	$	57

Overview – The following table summarizes the reserve balances, provisions, payments and settlements for 2003, 2004 and 2005 associated with environmental and legal contingencies, as well as balances, accruals and receipts of reimbursements of environmental costs from other parties.

(Millions of dollars)	Legal Reserves(1)			Reserves for Environmental Remediation (2)			Reimbursements Receivable(2)
Balance at December 31, 2002	$	73		$	258		$	113
Provisions / Accruals		8			94			32
Payments / Settlements		(44	)		(104	)		(15	)
Balance at December 31, 2003		37			248			130
Provisions / Accruals(3)		15			106			14
Payments / Settlements		(13	)		(99	)		(50	)
Balance at December 31, 2004		39			255			94
Provisions / Accruals		9			84			35
Payments / Settlements		(18	)		(71	)		(72	)
Balance at December 31, 2005	$	30		$	268		$	57

⁽¹⁾ Provisions for legal reserves in 2005, 2004 and 2003 include $8 million, $5 million and $1 million, respectively, related to Tronox’s operations. These changes are reflected in the Consolidated Statement of Income as a component of income from discontinued operations (net of tax).

⁽²⁾ Provisions for environmental remediation and restoration net of reimbursements in 2005, 2004 and 2003 include $37 million, $64 million and $56 million, respectively, related to Tronox, which are reflected as a component of income from discontinued operations (net of tax) in the Consolidated Statement of Income.

⁽³⁾ The 2004 accruals for litigation include a $7 million increase in the reserve upon Kerr-McGee’s assumption of contingent obligations in connection with the Westport merger.

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Management believes, after consultation with its internal legal counsel, that currently the company has reserved adequately for the reasonably estimable costs of environmental matters and other contingencies. However, additions to the reserves may be required as additional information is obtained that enables the company to better estimate its liabilities, including liabilities at sites now under review, though the company cannot now reliably estimate the amount of future additions to the reserves. Reserves for each environmental site are based on assumptions regarding the volumes of contaminated soils and groundwater involved, as well as associated excavation, transportation and disposal costs.

The company provides for costs related to contingencies when a loss is probable and the amount is reasonably estimable. It is not possible for the company to reliably estimate the amount and timing of all future expenditures related to environmental and legal matters and other contingencies because, among other reasons:

• Some sites are in the early stages of investigation, and other sites may be identified in the future.

• Remediation activities vary significantly in duration, scope and cost from site, to site depending on the mix of unique site characteristics, applicable technologies and regulatory agencies involved.

• Cleanup requirements are difficult to predict at sites where remedial investigations have not been completed or final decisions have not been made regarding cleanup requirements, technologies or other factors that bear on cleanup costs.

• Environmental laws frequently impose joint and several liability on all responsible parties, and it can be difficult to determine the number and financial condition of other responsible parties and their respective shares of responsibility for cleanup costs.

• Environmental laws and regulations, as well as enforcement policies, are continually changing, and the outcome of court proceedings and discussions with regulatory agencies are inherently uncertain.

• Unanticipated construction problems and weather conditions can hinder the completion of environmental remediation.

• Some legal matters are in the early stages of investigation or proceeding or their outcomes otherwise may be difficult to predict, and other legal matters may be identified in the future.

• The inability to implement a planned engineering design or use planned technologies and excavation methods may require revisions to the design of remediation measures, which can delay remediation and increase costs.

• The identification of additional areas or volumes of contamination and changes in costs of labor, equipment and technology generate corresponding changes in environmental remediation costs.

Current and former operations of the company and its affiliates require the management of regulated materials and are subject to various environmental laws and regulations. These laws and regulations will obligate the company to clean up various sites at which petroleum and other hydrocarbons, chemicals, low-level radioactive substances and/or other materials have been contained, disposed of or released. Some of these sites have been designated Superfund sites by the U.S. Environmental Protection Agency (EPA) pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) or state equivalents. Similar environmental laws and regulations and other requirements exist in foreign countries in which the company operates. Following are discussions regarding certain environmental sites and litigation of Tronox and its subsidiaries, as well as discussions of other Kerr-McGee sites and matters.

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Contingencies of Tronox

Environmental

Henderson, Nevada

In 1998, Tronox LLC (formerly Kerr-McGee Chemical LLC) decided to exit the ammonium perchlorate business. At that time, Tronox LLC curtailed operations and began preparation for the shutdown of the associated production facilities in Henderson, Nevada, that produced ammonium perchlorate and other related products. Manufacture of perchlorate compounds began at Henderson in 1945 in facilities owned by the U.S. government. The U.S. Navy expanded production significantly in 1953 when it completed construction of a plant for the manufacture of ammonium perchlorate. The Navy continued to own the ammonium perchlorate plant as well as other associated production equipment at Henderson until 1962, when the plant was purchased by a predecessor of the company. The ammonium perchlorate produced at the Henderson facility was used primarily in federal government defense and space programs. Perchlorate that may have originated, at least in part, from the Henderson facility has been detected in nearby Lake Mead and the Colorado River, which contribute to municipal water supplies in Arizona, Southern California and Southern Nevada.

Tronox LLC began decommissioning the facility and remediating associated perchlorate contamination, including surface impoundments and groundwater, when it decided to exit the business in 1998. In 1999 and 2001, Tronox LLC entered into consent orders with the Nevada Division of Environmental Protection (NDEP) that require it to implement both interim and long-term remedial measures to capture and remove perchlorate from groundwater. In April 2005, Tronox LLC entered into an amended consent order with NDEP that requires, in addition to the capture and treatment of groundwater, the closure of a certain impoundment related to the past production of ammonium perchlorate, including treatment and disposal of solution and sediment contained in the impoundment. An agreement with NDEP requires Tronox LLC to test for various potential contaminants at the site, which is ongoing.

In 1999, Tronox LLC initiated the interim measures required by the consent orders. A long-term remediation system is operating in compliance with the consent orders. Initially, the remediation system was projected to operate through 2007. However, studies of the decline of perchlorate levels in the groundwater now indicate that Tronox LLC may need to operate the system through 2011. The scope, duration and cost of groundwater remediation likely will be driven in the long term by drinking water standards regarding perchlorate, which to date have not been formally established by applicable state or federal regulatory authorities. EPA and other federal and state agencies continue to evaluate the health and environmental risks associated with perchlorate as part of the process for ultimately setting drinking water standards. One state agency, the California Environmental Protection Agency (CalEPA), has set a public health goal for perchlorate, and the federal EPA has established a reference dose for perchlorate, which are preliminary steps to setting drinking water standards. The establishment of drinking water standards could materially affect the scope, duration and cost of the long-term groundwater remediation that Tronox LLC is required to perform.

Financial Reserves – As of December 31, 2005, reserves for environmental remediation at Henderson totaled $37 million. This includes $32 million added to the reserve in 2005 because of increased costs for removing and treating ammonium perchlorate solids contained in a lined pond, purchasing additional equipment to perform cleanup and extending the projected operating period of the groundwater remediating system through 2011. As noted above, the long-term scope, duration and cost of groundwater remediation and impoundment closure are uncertain and, therefore, additional costs beyond those accrued may be incurred in the future. However, the amount of any additional costs cannot be reasonably estimated at this time.

Litigation – In 2000, Tronox LLC initiated litigation against the United States seeking contribution for its Henderson response costs. The suit was based on the fact that the government owned the plant in the early years of its operation, exercised significant control over production at the plant and the sale of products produced at the plant, even while not the owner, and was the largest consumer of products produced at the plant. Before trial, the parties agreed to a settlement of the claims against the United States. The settlement was memorialized in a consent decree approved by the court on January 13, 2006. Under the consent decree, the United States will pay Tronox LLC approximately $21 million in contribution for past costs and, commencing January 1, 2011, the United States will be obligated to pay 21% of Tronox LLC’s remaining response costs at Henderson, if any, related to perchlorate. In the first quarter of 2006, Tronox LLC recognized a receivable for environmental cost reimbursement of $21 million pursuant to the consent decree provisions. The receivable was collected in February 2006.

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Insurance – In 2001, Tronox LLC purchased a 10-year, $100 million environmental cost cap insurance policy for groundwater and other remediation at Henderson. The insurance policy, which began to provide coverage only after Tronox LLC exhausted a self-insured retention of approximately $61 million, covers only those costs incurred to achieve a cleanup level specified in the policy. As noted above, federal and state agencies have not established a drinking water standard and, therefore, it is possible that Tronox LLC may be required to achieve a cleanup level more stringent than that covered by the policy. If so, the amount recoverable under the policy may be less than the ultimate cleanup cost.

At December 31, 2005, Tronox LLC had received $6 million of cost reimbursement under the insurance policy, and expects additional estimated aggregate cleanup costs of $92 million less the $61 million self-insured retention to be covered by the policy (for a net amount of $31 million in additional reimbursement, including $22 million accrued in 2005). The company believes that additional reimbursement of $31 million is probable, and, accordingly, the company has recorded a receivable in the financial statements for that amount.

West Chicago, Illinois

In 1973, Tronox LLC closed a facility in West Chicago, Illinois, that processed thorium ores for the federal government and for certain commercial purposes. Historical operations had resulted in low-level radioactive contamination at the facility and in surrounding areas. The original processing facility is regulated by the State of Illinois (the State), and four vicinity areas are designated as Superfund sites on the National Priorities List (NPL).

Closed Facility– Pursuant to agreements reached in 1994 and 1997 among Tronox LLC, the City of West Chicago (the City) and the State regarding the decommissioning of the closed West Chicago facility, Tronox LLC has substantially completed the excavation of contaminated soils and has shipped those soils to a licensed disposal facility. Surface restoration was completed in 2004, except for areas designated for use in connection with the Kress Creek and Sewage Treatment Plant remediation discussed below. Groundwater monitoring and remediation is expected to continue for approximately ten years.

Vicinity Areas – EPA has listed four areas in the vicinity of the closed West Chicago facility on the NPL and has designated Tronox LLC as a Potentially Responsible Party (PRP) in these four areas. Tronox LLC has substantially completed remedial work for two of the areas (known as the Residential Areas and Reed-Keppler Park). The other two NPL sites, known as Kress Creek and the Sewage Treatment Plant, are contiguous and involve low levels of insoluble thorium residues, principally in streambanks and streambed sediments, virtually all within a floodway. Tronox LLC has reached an agreement with the appropriate federal and state agencies and local communities regarding the characterization and cleanup of the sites, past and future government response costs, and the waiver of natural resource damages claims. The agreement is incorporated in consent decrees, which were approved and entered by the federal court in August 2005. The cleanup work, which began in the third quarter of 2005, is expected to take about four to five years to complete and will require excavation of contaminated soils and stream sediments, shipment of excavated materials to a licensed disposal facility and restoration of affected areas.

Financial Reserves – As of December 31, 2005, the company had reserves of $87 million for costs related to the West Chicago facility and vicinity properties. This includes approximately $12 million added to the reserve in 2005 as a result of additional volumes of contaminated materials being identified at the Kress Creek site and the agreement described above requiring the company to reimburse local communities for certain cleanup costs. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time. The amount of the reserve is not reduced by reimbursements expected from the federal government under Title X of the Energy Policy Act of 1992 (Title X) (discussed below).

Government Reimbursement– Pursuant to Title X, the U.S. Department of Energy (DOE) is obligated to reimburse Tronox LLC for certain decommissioning and cleanup costs incurred in connection with the West Chicago sites in recognition of the fact that about 55% of the facility’s production was dedicated to U.S. government contracts. The amount authorized for reimbursement under Title X is $365 million plus

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inflation adjustments. That amount is expected to cover the government’s full share of West Chicago cleanup costs. Through December 31, 2005, Tronox LLC had been reimbursed approximately $281 million under Title X.

Reimbursements under Title X are provided by congressional appropriations. Historically, congressional appropriations have lagged the company’s cleanup expenditures. As of December 31, 2005, the government’s share of costs incurred by Tronox LLC but not yet reimbursed by the DOE totaled approximately $26 million, which includes $13 million accrued in 2005. The company believes receipt of the $26 million government share in due course following additional congressional appropriations is probable and has reflected that amount as a receivable in the financial statements. The company will recognize recovery of the government’s share of future remediation costs for the West Chicago sites as it incurs the cash expenditures.

Ambrosia Lake, New Mexico

From the late 1950s until 1988, an affiliate of Tronox Worldwide LLC (formerly Kerr-McGee Chemical Worldwide LLC) operated a uranium mining and milling operation at Ambrosia Lake near Grants, New Mexico, pursuant to a license issued by the Atomic Energy Commission (AEC) (now the Nuclear Regulatory Commission (NRC)). When the operation was sold, Tronox Worldwide LLC retained responsibility for certain environmental conditions existing at the site, including mill tailings, selected ponds and groundwater contamination related to the mill tailings and unlined ponds. Since 1989, the unaffiliated current owner of the site, Rio Algom Mining LLC (Rio Algom), has been decommissioning the site pursuant to the license issued by NRC. Mill tailings, certain impacted surface soils, and selected pond sediments have been consolidated in an onsite containment unit, and groundwater treatment has been ongoing. Under terms of the sales agreement, which included provisions capping the liability of Rio Algom, Tronox Worldwide LLC became obligated to solely fund the remediation for the items described above when total expenditures exceeded $30 million, which occurred in late 2000. A request to cease groundwater treatment has been under review by the NRC since 2001. In addition, a decommissioning plan for remaining impacted soil was submitted by Rio Algom to the NRC in January 2005, and is currently under review. If approved, the soil decommissioning plan would take two to three years to complete. The State of New Mexico has recently raised issues about certain nonradiological constituents in the groundwater at the site. The request to cease groundwater treatment, which is being reviewed by the NRC, was amended to address these nonradiological constituents. Discussions regarding these issues are ongoing, and resolution of them could affect remediation costs and/or delay ultimate site closure.

In addition to those remediation activities described above for which reserves have been established as described below, Rio Algom is investigating soil contamination potentially caused by past discharge of mine water from the site, for which no reserve has been established.

Financial Reserves – As of December 31, 2005, the company had reserves of $11 million for the costs of the remediation activities described above, including groundwater remediation. This includes $8 million added to the reserve in 2005, as a result of the discussions between Rio Algom and the NRC, and primarily to cover additional costs associated with pond closure, rock placement, and surface water channels. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time.

Litigation – On January 18, 2006, Rio Algom filed suit against Tronox Worldwide LLC in the U.S. District Court for the District of New Mexico. The suit seeks a determination regarding responsibility for certain labor-related and environmental remediation costs. The parties have discussed submitting the dispute to binding arbitration and negotiations regarding arbitration are ongoing. The company has not provided a reserve for this lawsuit because at this time it cannot reasonably determine the probability of a loss, and the amount of loss, if any, cannot be reasonably estimated. The ultimate resolution of the litigation is not expected to have a material adverse effect on the company.

Milwaukee, Wisconsin

In 1976, Tronox LLC closed a wood-treatment facility it had operated in Milwaukee, Wisconsin. Operations at the facility prior to its closure had resulted in the contamination of soil and groundwater at and around the site with creosote and other substances used in wood treating. In 1984, EPA designated the Milwaukee wood-treatment facility as a Superfund site under CERCLA, listed the site on the NPL and

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named Tronox LLC as a PRP. Tronox LLC executed a consent decree in 1991 that required it to perform soil and groundwater remediation at and below the former wood-treatment area and to address a tributary creek of the Menominee River that had become contaminated as a result of the wood-treatment operations. Actual remedial activities were deferred until after the decree was finally entered in 1996 by a federal court in Milwaukee.

Groundwater treatment was initiated in 1996 to remediate groundwater contamination below and in the vicinity of the former wood-treatment area. It is not possible to reliably predict how groundwater conditions will be affected by soil removal in the vicinity of the former wood-treatment area, which has been completed, and by ongoing groundwater treatment. It is unknown, therefore, how long groundwater treatment will continue. Soil cleanup of the former wood-treatment area began in 2000 and was completed in 2002. Also in 2002, remedial designs for the upper portion of the tributary creek were agreed to with EPA, after which Tronox LLC began the implementation of a remedy to reroute the creek and to remediate associated sediment and stream bank soils. Remediation of the upper portion of the creek is expected to take about three more years. Tronox LLC has not yet agreed with relevant regulatory authorities regarding remedial designs for the lower portion of the tributary creek.

Financial Reserves – As of December 31, 2005, the company had reserves of $4 million for the costs of the remediation work described above. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time. The costs associated with remediation, if any, of the lower portion of the tributary creek are not reasonably estimable.

New Jersey Wood-Treatment Site

Tronox LLC was named in 1999 as a PRP under CERCLA at a former wood-treatment site in New Jersey at which EPA is conducting a cleanup. On April 15, 2005, Tronox LLC and Tronox Worldwide LLC received a letter from EPA asserting that they are liable under CERCLA as a former owner or operator of the site and demanding reimbursement of costs expended by EPA at the site. The letter made demand for payment of past costs in the amount of approximately $179 million, plus interest, though EPA has informed Tronox LLC that it expects final project costs will be approximately $236 million, plus possible other costs and interest. Tronox LLC did not operate the site, which had been sold to a third party before Tronox LLC succeeded to the interests of a predecessor owner in the 1960’s. The predecessor also did not operate the site, which had been closed down before it was acquired by the predecessor. Based on historical records, there are substantial uncertainties about whether or under what terms the predecessor assumed liabilities for the site. In addition, although it appears there may be other PRPs, the company does not know whether the other PRPs have received similar letters from EPA, whether there are any defenses to liability available to the other PRPs or whether the other PRPs have the financial resources necessary to meet their obligations. By letter dated December 15, 2005, EPA advised that it currently does not intend to seek reimbursement of response costs from Tronox Worldwide LLC, though it still seeks reimbursement of response costs from Tronox LLC. The company intends to vigorously defend against EPA’s demand, though the company expects to have discussions with EPA that could lead to a settlement or resolution of the EPA demand. No reserve for reimbursement of cleanup costs at the site has been recorded because it is not possible to reliably estimate the liability, if any, the company may have for the site because of the aforementioned defenses and uncertainties.

Cushing, Oklahoma

In 1972, Triple S Refining Corporation (Triple S), an affiliate of Tronox, closed a petroleum refinery it had operated near Cushing, Oklahoma. Prior to closing the refinery, Triple S also had produced uranium and thorium fuel and metal at the site pursuant to licenses issued by the AEC.

In 1990, Triple S entered into a consent agreement with the State of Oklahoma to investigate the site and take appropriate remedial actions related to petroleum refining and uranium and thorium residuals. Investigation and remediation of hydrocarbon contamination is being performed under the oversight of the Oklahoma Department of Environmental Quality. Remediation to address hydrocarbon contamination in soils is expected to take about four more years. The long-term scope, duration and cost of groundwater remediation are uncertain and, therefore, additional costs beyond those accrued may be incurred in the future.

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In 1993, Triple S received a decommissioning license from the NRC, the successor to AEC’s licensing authority, to perform certain cleanup of uranium and thorium residuals. All known radiological contamination has been removed from the site and shipped to a licensed disposal facility, substantially completing the license requirements.

Financial Reserves – As of December 31, 2005, the company had reserves of $12 million for the costs of the ongoing remediation and decommissioning work described above. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time.

Litigation and Claims

Forest Products Litigation

Between December 31, 2002 and May 2, 2005, approximately 250 lawsuits (filed on behalf of approximately 5,100 claimants) were filed against Tronox LLC in connection with the former wood-treatment plant in Columbus, Mississippi. Substantially all of these lawsuits are pending in the U.S. District Court for the Northern District of Mississippi and have been consolidated for pretrial and discovery purposes. In addition, a suit filed by the Maranatha Faith Center against Tronox LLC and Tronox Worldwide LLC on February 18, 2000, relates to the former wood-treatment plant in Columbus and is pending in the Circuit Court of Lowndes County, Mississippi. Between December 31, 2002 and June 25, 2004, three lawsuits (filed on behalf of approximately 3,300 claimants) were filed against Tronox LLC in connection with a former wood-treatment plant located in Hattiesburg, Mississippi. These lawsuits were removed to the U.S. District Court for the Southern District of Mississippi. Between September 9, 2004 and December 28, 2005, four lawsuits (filed on behalf of 69 claimants) were filed against Tronox LLC in connection with a former wood-treatment plant located in Texarkana, Texas. Two of the Texarkana lawsuits that were filed in Oklahoma (on behalf of 30 claimants) have been dismissed on jurisdictional grounds. Between January 3, 2005 and July 26, 2005, 35 lawsuits (filed on behalf of approximately 4,600 claimants) were filed against Tronox LLC and Tronox Worldwide LLC in connection with the former wood-treatment plant in Avoca, Pennsylvania. All of these lawsuits seek recovery under a variety of common law and statutory legal theories for personal injuries and/or property damages allegedly caused by exposure to and/or release of creosote, a chemical used in the wood-treatment process.

In 2003, Tronox LLC entered into a settlement agreement that resolved approximately 1,490 of the Hattiesburg claims, which resulted in aggregate payments by Tronox LLC of approximately $600,000. In December 2005, Tronox LLC entered into settlement agreements to resolve up to 1,335 of the remaining Hattiesburg claims and up to 879 of the Columbus claims. The December 2005 settlement agreements require Tronox LLC to pay up to $2.5 million, of which $2 million was paid in December 2005. In addition, all of the remaining Hattiesburg claims have been dismissed without prejudice on the bases of failure to pay filing fees and failure to disclose information in compliance with court orders. The company currently believes that the unresolved claims relating to the Columbus, Hattiesburg, Texarkana and Avoca plants are without substantial merit and is vigorously defending against them.

Financial Reserves – As of December 31, 2005, the company had reserves of $7 million related to forest products litigation. Although actual costs may differ from the current estimates, the amount of any revisions in litigation costs cannot be reasonably estimated at this time. The company currently believes that the ultimate resolution of the forest products litigation is not likely to have a material adverse effect on the company.

Kemira

In 2000, Tronox LLC acquired its titanium dioxide production facility in Savannah, Georgia, from Kemira Pigments Oy, a Finnish company, and its parent, Kemira Oyj (together, “the Sellers”). After acquiring the facility, the company discovered that certain matters associated with environmental conditions and plant infrastructure were not consistent with representations made by the Sellers. The company sought recovery for breach of representations and warranties in a proceeding before the London Court of International Arbitration (LCIA). On May 9, 2005, the Company received notice from the LCIA that the LCIA had found in favor of the company as to liability with respect to certain of the claims. The LCIA still must determine the amount of damages, a hearing with respect to which has been scheduled for late May 2006. The company currently cannot reasonably estimate the amount of damages that will be awarded. The company will recognize a receivable, if and when damages are awarded and all contingencies associated with any recovery are resolved.

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Other Sites and Matters

In addition to the environmental sites described above, Tronox and/or its affiliates are responsible for environmental costs related to certain other sites. These sites relate primarily to wood-treating, chemical production, landfills, mining, and oil and gas refining, distribution and marketing. As of December 31, 2005, the company and its affiliates had reserves of $73 million for the environmental costs in connection with these other sites. This amount includes $20 million added to reserves in 2005 for additional costs estimated at various of these other sites. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time.

The company and its affiliates are parties to a number of legal and administrative proceedings involving disputes with federal, state and private parties, environmental matters and/or other matters pending in various courts or agencies. Some of these proceedings are associated with facilities currently or previously owned, operated or used by the company and/or its predecessors, some of which include claims for personal injuries, property damages, cleanup costs and other environmental matters. These proceedings, individually and in the aggregate, are not expected to have a material adverse effect on the company.

Other Contingencies of Kerr-McGee

Los Angeles County, California

During 2004, the company began remediation and restoration of an oil and gas field that was operated by an affiliate of the company and its predecessors from about 1936 to 1990 in Los Angeles County, California. The company is obligated to remediate soils contaminated with petroleum hydrocarbons associated with certain early drilling and production pits and sumps and other historic leaks and spills. The remediation and restoration of this oil and gas field is expected to take about five years.

Financial Reserves– As of December 31, 2005, environmental reserves for this project totaled $23 million. This includes approximately $5 million added to the reserve in 2005 as a result of identifying additional contaminated locations in the field. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time.

Other Sites and Matters

Deepwater Royalty Relief Act

In 1995, the United States Congress passed the Deep Water Royalty Relief Act (DWRRA) to stimulate exploration and production of oil and natural gas in the deepwater Gulf of Mexico by providing relief from the obligation to pay royalty on certain federal leases. In January 2006, the Department of the Interior (DOI) ordered Kerr-McGee Oil and Gas Corporation (KMOG) to pay oil and gas royalties and accrued interest on certain of KMOG’s deepwater Gulf of Mexico production for which KMOG believes royalties are suspended under the DWRRA. DOI issued the Order to Pay based on the assertion that DOI has the discretion to suspend royalty relief under the DWRRA with respect to the subject leases when oil and gas prices reach certain levels specified by DOI. KMOG believes that DOI does not have the authority to suspend royalty relief on the subject leases and, accordingly, intends to contest the Order to Pay and vigorously defend against DOI’s claim for additional royalties. The company has recorded reserves for the full amount of the DOI claim, including interest. As of December 31, 2005, reserves for royalties and interest potentially payable to the DOI totaled $108 million.

Other

In addition to the site in Los Angeles County described above, Kerr-McGee and/or its affiliates are responsible for environmental costs related to certain other sites where exploration and production activities where conducted. As of December 31, 2005, the company and its affiliates had reserves of $21 million for the environmental costs in connection with these other sites. This amount includes $7 million added to reserves in 2005 for additional costs estimated at various of these sites. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time.

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Kerr-McGee and its affiliates are parties to a number of legal and administrative proceedings involving the False Claims Act and other royalty-related claims and disputes with federal, state and private parties, environmental matters and/or other matters pending in various courts or agencies. Some of these proceedings are associated with facilities currently or previously owned, operated or used by the company and/or its predecessors, some of which include claims for personal injuries, property damages, cleanup costs and other environmental matters. These proceedings, individually and in the aggregate, are not expected to have a material adverse effect on the company.

17.Commitments

Lease Obligations and Guarantees– The company has various commitments under noncancelable operating lease agreements, principally for office space, production and gathering facilities and other equipment. The company also has entered into operating lease agreements for the use of the Nansen, Boomvang and Gunnison spar platforms located in the Gulf of Mexico. Aggregate minimum annual rentals under all operating leases (including the platform leases in effect at December 31, 2005) total $807 million (including $48 million of Tronox’s obligations), of which $85 million is due in 2006, $66 million in 2007, $65 million in 2008, $54 million in 2009, $42 million in 2010 and $495 million thereafter. Total lease rental expense was $98 million in 2005, $84 million in 2004 and $65 million in 2003.

The company has guaranteed that the Nansen, Boomvang and Gunnison platforms will have residual values at the end of the operating leases equal to at least 10% of the fair value of the platform at the inception of the lease. For Nansen and Boomvang, the guaranteed values are $14 million and $8 million, respectively, in 2022, and for Gunnison the guarantee is $15 million in 2024.

Under the terms of the Master Separation Agreement, Kerr-McGee agreed to reimburse Tronox for a portion of the environmental costs incurred and paid by Tronox and its subsidiaries prior to November 28, 2012. Additional information about this reimbursement obligation is provided in Note 16.

During 2003 and 2002, the company entered into sale-leaseback arrangements with General Electric Capital Corporation (GECC) covering assets associated with a gas-gathering system in the Wattenberg field. The 2002 operating lease agreements have an initial term of five years, with two 12-month renewal options, and the company may elect to purchase the equipment at specified amounts after the end of the fourth year. The 2003 operating lease agreement has an initial term of four years, with two 12-month renewal options. In the event the company does not purchase the equipment and it is returned to GECC, the company may be required to make payments in connection with residual value guarantees ranging from $35 million at the end of the initial terms to $27 million at the end of the last renewal option. The company recorded no gain or loss associated with the GECC sale-leaseback agreements. The future minimum annual rentals due under noncancelable operating leases shown above include payments related to these agreements.

In connection with certain contracts and agreements, the company has entered into indemnifications related to title claims, environmental matters, litigation and other claims. The company has recorded no material obligations in connection with its indemnification agreements.

Purchase Obligations– In the normal course of business, the company enters into contractual agreements to purchase raw materials, pipeline capacity, utilities and other services. Aggregate future payments under these contracts total $1.484 billion (including $1.002 billion associated with Tronox’s obligations), of which $481 million is expected to be paid in 2006, $337 million in 2007, $255 million in 2008, $161 million in 2009, $109 million in 2010, and $141 million thereafter.

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Drilling Rig Commitments– During the normal course of business, the company enters into arrangements to participate in the use of various drilling rigs. The commitment with respect to these arrangements totals up to $749 million, depending on partner utilization, of which $226 million is expected to be paid in 2006, $392 million in 2007, $36 million in 2008, $26 million in 2009, $26 million in 2010, and $43 million thereafter. Subsequent to December 31, 2005, the company entered into additional agreements totaling $19 million, of which $6 million is due in 2006, $8 million is due in 2007 and $5 million is due in 2008.

Letters of Credit and Other– At December 31, 2005, outstanding letters of credit totaled $114 million (including $34 million issued by Tronox). Most of these letters of credit have been granted by financial institutions to support international drilling commitments, environmental remediation activities and insurance agreements. As of February 28, 2006, outstanding letters of credit totaled $144 million, which included $40 million associated with Tronox.

18.Capital Stock

In May 2005, the stockholders approved an increase in the authorized number of shares of common stock from 300 million to 500 million shares. Following this approval, authorized capital stock of the company consists of 500 million shares of common stock with a par value of $1.00 per share and 40 million shares of preferred stock without par value. No shares of preferred stock have been issued.

As discussed in Note 1, in March 2005, the company’s Board of Directors authorized a share repurchase program initially set at $1 billion, with an expectation to expand the program as the chemical business separation proceeded. Before terminating this program in connection with the Board’s approval of the tender offer discussed below, the company repurchased 3.1 million shares (on a pre-split basis) of its common stock in the open market at an aggregate cost of $250 million. Shares repurchased under this program are held in treasury.

On April 18, 2005, the company commenced a tender offer to repurchase 43.5 million shares of its common stock at a price not lower than $85 or higher than $92 per share. The company exercised its right to increase the number of shares purchased pursuant to the tender offer by 3.2 million shares, which resulted in repurchasing 46.7 million shares of common stock at $85 per share, for an aggregate cost of approximately $4 billion (including transaction costs of approximately $3 million). All of the shares repurchased under the tender offer were retired immediately. The cost of the repurchase was financed with a portion of the net proceeds of the borrowings under the Credit Agreement discussed in Note 10 and cash on hand. The share and per-share information in this paragraph is stated on a pre-split basis.

In January 2006, the Board of Directors approved a $1 billion stock repurchase program. Note 26 provides information on share repurchases made under this program through August 2006.

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Changes in common stock issued and treasury stock held for 2005, 2004 and 2003 are as presented in the following table. As discussed in Note 26, on June 14, 2006, the company executed a two-for-one split of Kerr-McGee common stock issued and outstanding as of that date. Common stock held in treasury was unaffected by the split. The following table presents changes in common stock issued and held in treasury on a pre-split basis, followed by disclosure of common stock outstanding as revised to give retroactive effect to the stock split.

(Thousands of shares)	Shares Issued		Treasury Stock
Balance at December 31, 2002	100,391		7
Stock option exercises	18		—
Issuance of restricted stock	483		—
Forfeiture of restricted stock	—		25
Balance at December 31, 2003	100,892		32
Shares issued in Westport merger	48,949		—
Stock option exercises	1,725		—
Issuance of restricted stock	483		—
Forfeiture of restricted stock	—		128
Balance at December 31, 2004	152,049		160
Stock option exercises	4,078		—
Issuance of restricted stock	452		—
Forfeiture of restricted stock	—		152
Shares issued upon conversion of 5.25% debentures	9,818		—
Purchases of treasury shares	—		3,145
Shares repurchased and retired	(46,728	)	—
Balance at December 31, 2005	119,669		3,457

As revised to reflect the effect of the stock split, the balances of common stock outstanding at December 31, 2005, 2004 and 2003 are as follows:

(Thousands of shares)	Shares Outstanding
2005	228,775
2004	296,833
2003	194,647

There are 2,215,384 shares of the company’s common stock registered in the name of a wholly-owned subsidiary of the company. These shares are not included in the number of shares shown in the preceding tables or in the Consolidated Balance Sheet. These shares are not entitled to be voted.

Preferred Share Purchase Rights Plan– The company has had a stockholders’ rights plan since 1986. The current rights plan is dated July 26, 2001, and replaced the previous plan prior to its expiration. Rights were distributed as a dividend at the rate of one right for each share of the company’s common stock and continue to trade together with each share of common stock. Generally, the rights become exercisable the earlier of 10 days after a public announcement that a person or group has acquired, or a tender offer has been made for, 15% or more of the company’s then-outstanding stock. If either of these events occurs, each right would entitle the holder (other than a holder owning more than 15% of the outstanding stock) to buy the number of shares of the company’s common stock having a market value two times the exercise price. The exercise price is $215. Generally, the rights may be redeemed at $.01 per right until a person or group has acquired 15% or more of the company’s stock. The rights expire in July 2006. Refer to Note 26 for information regarding a 2006 amendment to the rights plan.

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19.Employee Stock-Based Compensation Plans

Information included below should be read in connection with Note 26 which describes the effect of certain 2006 events on the company’s stock-based awards.

Overview – The 2005 Long-Term Incentive Plan (Plan) authorizes the issuance of shares of the company’s common stock to certain employees and non-employee directors any time prior to May 10, 2015, in the form of fixed-price stock options, restricted stock or performance awards. The options may be accompanied by stock appreciation rights. A total of 10 million shares (on a pre-split basis) of the company’s common stock is authorized to be issued under the Plan, of which a maximum of 3 million shares of common stock (on a pre-split basis) is authorized for issuance in connection with awards of restricted stock and performance awards to employees. The Plan also includes certain limitations on the size of awards to an individual employee and to non-employee directors as a group. Subject to these limits, a committee of the Board of Directors administering the Plan (Committee) determines the size and types of awards to be issued.

The maximum period for exercise of an option granted under the Plan may not be more than ten years from the date the grant is authorized by the Committee and the exercise price may not be less than the fair value of the shares underlying the option on the grant authorization date. Performance awards may be granted in the form of performance shares or performance units, with performance period of no less than one year. Subject to the Plan provisions, the Committee determines the terms of the awards, such as dates on which the awards become fully vested and, for performance awards, performance period and performance goal(s) to be achieved to receive a specified benefit from the award.

At December 31, 2005, approximately 10 million shares of Kerr-McGee stock (on a pre-split basis) were available to be granted under the Plan. Prior to the approval of the Plan by the company’s stockholders, stock-based awards were granted under similar plans, all of which have been terminated. Although no more awards can be issued under those plans, their termination had no effect on awards previously issued and outstanding.

Stock-based awards granted by the company to its employees and non-employee directors during the last three years generally had the following terms:

	Contractual Life (years)	Vesting Period (years)	Vesting Term		Cash- or Stock- Settled	Vesting and Other Conditions
Stock options	10	3	Graded	(1)	Stock	Employee service
Restricted stock	not applicable	3	Cliff	(2)	Stock	Employee service
Performance units(3)	3	3	Cliff	(2)	Cash	Employee service and achievement of specified stockholder return targets

⁽¹⁾ An employee vests in one third of the award at the end of each year of service.

⁽²⁾ An employee vests in the entire award at the end of the three-year service period.

⁽³⁾ Performance unit awards provide an employee with a potential cash payment at the end of a three-year performance cycle based on Kerr-McGee’s total stockholder return (stockholder return assuming dividend reinvestment) relative to selected peer companies. Payout levels vary depending upon Kerr-McGee’s rank relative to its peers.

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The following summarizes stock-based compensation expense recognized in income from continuing operations for the years ended December 31, 2005, 2004 and 2003, determined based on the intrinsic value of the awards. As discussed in Note 1, as a result of implementing a new accounting standard effective January 1, 2006, stock-based compensation expense in future periods will be based on the fair value of the awards.

(Millions of dollars)	2005		2004		2003
Stock options	$	8	$	1	$	—
Restricted stock		20		13		9
Performance units		18		2		—
Total	$	46	$	16	$	9

Effect of Tronox Separation – As provided in the Employee Benefits Agreement between Kerr-McGee and Tronox, except for vested stock options and performance unit awards, Kerr-McGee stock-based awards held by Tronox employees at the date of the Distribution will be forfeited and replaced with stock-based awards of comparable value issued by Tronox. The conversion ratio will be determined on the effective date of the Distribution based on the relative values of Kerr-McGee common stock and Tronox Class A common stock. Generally, Tronox employees holding vested options to purchase Kerr-McGee common stock as of the date of the Distribution may exercise such options for the lesser of three months after the effective date of the Distribution or the remaining term of the option award. Vested options not exercised during the specified time period will expire.

Restricted Stock– The following summarizes information about shares of restricted stock granted during the last three years (information presented in the table and discussion that follows does not give effect to the two-for-one stock split discussed in Note 26):

	2005		2004		2003
Restricted shares granted		452,000		483,000		483,000
Weighted average grant-date fair value per share	$	68.80	$	49.97	$	43.18

At December 31, 2005, 1.2 million unvested shares of restricted stock were outstanding. In the first quarter of 2006, the company granted 241,000 additional shares with an estimated grant-date fair value per share of $98.58. Approximately 92,000 shares of Kerr-McGee’s restricted stock held by Tronox employees at December 31, 2005 are expected to be forfeited, as discussed under Effect of Tronox Separation above.

Performance Units– The following summarizes information about the company’s performance unit awards for 2005, 2004 and 2003:

	2005		2004		2003
Performance units granted during the year		16,274,800		11,061,700		11,331,000
Performance units outstanding at year-end		33,545,679		19,151,627		10,809,000
Per-unit liability at year-end	$	.63	$	.11	$	—

At December 31, 2005, the carrying value of the company’s aggregate liability for performance units was $21 million, $8 million of which was paid to eligible employees in January 2006. In the first quarter of 2006, the company granted an additional 17 million performance units to its employees. The terms of performance units issued in 2006 are consistent with previously issued awards. It is expected that approximately 2.5 million performance units held by Tronox employees as of December 31, 2005 will be forfeited, as discussed above underEffect of Tronox Separation.

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Stock Options– The following table summarizes the stock option transactions during 2005, 2004 and 2003 under Kerr-McGee’s compensation plans and in connection with the Westport merger. As discussed in Note 4, on June 25, 2004, the company completed its merger with Westport. In connection with the merger, the company exchanged Westport options outstanding as of the merger date for Kerr-McGee options based on the exchange factor set forth in the merger agreement. Information presented in the table does not give effect to the two-for-one stock split discussed in Note 26.

	2005				2004				2003
	Options		Price(1)		Options		Price(1)		Options		Price(1)
Outstanding, beginning of year	7,516,655		$	53.63	6,418,719		$	56.02	5,406,424		$	59.27
Issued in Westport merger	—			—	1,901,988			29.55	—			—
Granted	1,663,490			56.57	1,385,536			49.45	1,353,100			42.93
Exercised	(4,077,929	)		55.36	(1,744,179	)		32.42	(18,500	)		44.55
Forfeited	(288,637	)		52.39	(183,545	)		47.26	(189,638	)		55.35
Expired	(14,455	)		57.93	(261,864	)		60.99	(132,667	)		57.78
Outstanding, end of year	4,799,124			53.21	7,516,655			53.63	6,418,719			56.02
Exercisable, end of year	2,103,823			54.59	4,636,210			56.89	3,382,550			59.81

⁽¹⁾ Represents weighted average exercise price.

The following table summarizes information about stock options issued under the plans described above that are outstanding and exercisable at December 31, 2005. Approximately 160,000 Kerr-McGee options held by Tronox employees (on a pre-split basis) are expected to be forfeited, as discussed above underEffect of Tronox Separation. Information presented in the table does not give effect to the two-for-one stock split discussed in Note 26.

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Options	Contractual Life (years) (1)	Price(1)		Options	Price(1)
$15.00 – $29.99	127,538	5.1	$	26.77	91,334	$	26.05
30.00 – 39.99	41,316	3.0		33.62	38,003		33.64
40.00 – 49.99	1,758,267	7.2		46.48	583,393		44.80
50.00 – 59.99	1,961,773	8.0		56.25	480,863		55.27
60.00 – 69.99	832,362	4.9		63.45	832,362		63.45
70.00 – 79.99	77,868	1.3		72.65	77,868		72.65
	4,799,124	6.9		53.21	2,103,823		54.59

⁽¹⁾ Represents weighted average remaining contractual life or weighted average exercise price, as applicable.

Following provisions of the long-term incentive plans, stock options outstanding as of June 14, 2006, the date of the two-for-one stock split, were modified, whereby the number of shares subject to each option was doubled and the exercise price decreased 50%. The following table presents the number of shares subject to stock options outstanding and exercisable at December 31, 2005, 2004 and 2003 and associated weighted average exercise prices, as adjusted for the stock split:

	2005			2004			2003
	Options	Price		Options	Price		Options	Price
Outstanding	9,598,248	$	26.61	15,033,310	$	26.82	12,837,438	$	28.01
Exercisable	4,207,646		27.30	9,272,420		28.45	6,765,100		29.91

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Employee Stock Ownership Plan– In 1989, the company’s Board of Directors approved a leveraged Employee Stock Ownership Plan (ESOP) into which the company’s matching contribution for the employees’ contributions to the Kerr-McGee Corporation Savings Investment Plan (SIP) is paid. Most of the company’s employees are eligible to participate in the SIP and matching contributions to the ESOP fund are contingent upon participants’ contributions to the SIP.

In 1989, the ESOP trust borrowed $125 million from a group of lending institutions and used the proceeds to purchase approximately 3 million shares of the company’s treasury stock. The company used the $125 million in proceeds from the sale of the stock to acquire shares of its common stock in open-market and privately negotiated transactions. In 1996, a portion of the third-party borrowings was replaced with a note payable to the company (sponsor financing), which was fully paid in 2003. The third-party borrowings were repaid in 2005.

In 1999, the company merged with Oryx Energy Company, which sponsored the Oryx Capital Accumulation Plan (CAP). CAP was a combined stock bonus and leveraged employee stock ownership plan available to substantially all U.S. employees of the former Oryx operations. During 1999, the company merged the Oryx CAP into the ESOP and SIP. In 1989, Oryx privately placed $110 million of notes pursuant to the provisions of the CAP. Oryx loaned the proceeds to the CAP, which used the funds to purchase Oryx common stock that was placed in a trust. Because this loan represents sponsor financing, it does not appear in the accompanying balance sheet. The remaining balance of the sponsor financing is $25 million at year-end 2005.

Shares of stock allocated to the ESOP participants’ accounts and in the loan suspense account are as follows:

(Thousands of shares)	2005	2004
Participants’ accounts	2,238	2,864
Loan suspense account	374	492

The shares in the loan suspense account at December 31, 2005, included approximately 22,000 released shares that were allocated to participants’ accounts in January 2006. At December 31, 2004, the shares in the loan suspense account included approximately 34,000 released shares that were allocated to participants’ accounts in January 2005.

Compensation expense related to the plan was $14 million, $13 million and $33 million in 2005, 2004 and 2003, respectively (of which $4 million in each of 2005 and 2004 and $10 million in 2003 was associated with discontinued Tronox operations). These amounts include interest expense incurred on the third-party ESOP debt, which was not material for 2005, 2004 or 2003. The company contributed $14 million, $17 million and $42 million to the ESOP in 2005, 2004 and 2003, respectively. Included in the respective contributions were $8 million, $10 million and $37 million for principal and interest payments on the financings. The cash contributions are net of $1 million, $3 million and $4 million for the dividends paid on the company stock held by the ESOP trust in 2005, 2004 and 2003, respectively.

20.Business Segments

In 2006, the company completed the separation of Tronox and expanded its segment presentation based on the way management currently reviews operating results to make decisions about resource allocation and assess individual segment performance. Segment performance is evaluated based on operating profit, which represents results of operations before considering marketing activities, certain corporate costs, oil and gas derivatives, interest and debt expense, and other income (expense). Segment information for prior periods has been restated to conform with this new presentation, except information concerning total assets by segment which is not available.

The company has four operating segments, all of which are in the business of crude oil and natural gas exploration and production (E&P). In the U.S., the company operates offshore in the Gulf of Mexico and onshore in the Rocky Mountain and Southern (Midcontinent) areas. We also have exploration and production operations in China, and exploration activities in Alaska, Brazil and other international locations.

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The following table sets forth the revenues and operating profit for each of our operating segments, as well as reconciliation to income from continuing operations before income taxes.

(Millions of dollars)	Gulf of Mexico		Rocky Mountain		Southern		China		Other (1)			Total
2005
Revenues (2)	$	2,158	$	1,362	$	945	$	312	$	—		$	4,777
Operating profit	$	1,349	$	841	$	598	$	197	$	(151	)	$	2,834
Net marketing margin													4
Loss on oil and gas derivatives													(1,018	)
Corporate costs (3)													(238	)
Interest and debt expense													(268	)
Other income (expense) (4)													104
Income from continuing operations before income taxes												$	1,418
DD&A expense (5)	$	306	$	235	$	232	$	56	$	9		$	838
Capital expenditures	$	720	$	473	$	285	$	95	$	116		$	1,689
2004
Revenues (2)	$	1,674	$	808	$	656	$	92	$	—		$	3,230
Operating profit	$	900	$	409	$	351	$	43	$	(130	)	$	1,573
Net marketing margin													1
Loss on oil and gas derivatives													(553	)
Corporate costs (3)													(190	)
Interest and debt expense													(244	)
Other income (expense) (4)													(21	)
Income from continuing operations before income taxes												$	566
DD&A expense (5)	$	281	$	170	$	153	$	23	$	10		$	637
Capital expenditures	$	512	$	241	$	170	$	90	$	88		$	1,101
2003
Revenues (2)	$	1,174	$	445	$	408	$	23	$	—		$	2,050
Operating profit	$	593	$	195	$	240	$	1	$	(124	)	$	905
Net marketing margin													7
Loss on oil and gas derivatives													(216	)
Corporate costs (3)													(193	)
Interest and debt expense													(250	)
Other income (expense) (4)													(15	)
Income from continuing operations before income taxes												$	238
DD&A Expense (5)	$	196	$	123	$	66	$	2	$	12		$	399
Capital expenditures	$	627	$	128	$	91	$	73	$	36		$	955

(1) Represents exploration activities outside our core operating areas and certain general and administrative costs associated with E&P operations.

(2) Excludes third-party marketing revenues and oil and gas derivatives that are not considered in the determination of segment operating profit.

(3) Represents general and administrative costs, depreciation expense and property taxes incurred outside our E&P operations.

(4) The company owns a 50% interest in Avestor, a joint venture involved in production of lithium-metal-polymer batteries. Investment in Avestor is accounted for under the equity method. The company’s equity in the net losses of Avestor was $37 million, $39 million and $28 million in 2005, 2004 and 2003, respectively. The carrying value of the company’s investment in Avestor at December 31, 2005 and 2004 was $69 million and $60 million, respectively.

(5) Excludes depreciation, depletion and amortization (DD&A) expense of $11 million, $9 million and $8 million for 2005, 2004 and 2003, respectively, associated with corporate assets that is not considered in determining segment operating profit.

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21.Costs Incurred in Crude Oil and Natural Gas Activities

The following reflects total expenditures, both capitalized and expensed, for crude oil and natural gas property acquisition, exploration and development activities for the three years ended December 31, 2005.

(Millions of dollars)	Property Acquisition Costs			Exploration Costs(2)		Development Costs(3)		Total
2005 –
Continuing operations –
United States	$	56		$	382	$	1,212	$	1,650
China		—			21		81		102
Other international		14			67		—		81
Total – continuing operations		70	(1)		470		1,293		1,833	(4)
Discontinued operations		21			57		141		219
Total costs incurred	$	91		$	527	$	1,434	$	2,052
2004 –
Continuing operations –
United States	$	3,477		$	235	$	757	$	4,469
China		1			20		75		96
Other international		25			52		—		77
Total – continuing operations		3,503	(1)		307		832		4,642	(4)
Discontinued operations		4			36		110		150
Total costs incurred	$	3,507		$	343	$	942	$	4,792
2003 –
Continuing operations –
United States	$	122		$	360	$	475	$	957
China		1			31		45		77
Other international		1			50		—		51
Total – continuing operations		124	(1)		441		520		1,085	(4)
Discontinued operations		54			43		55		152
Total costs incurred	$	178		$	484	$	575	$	1,237

⁽¹⁾ Includes $24 million, $2.374 billion and $60 million applicable to purchases of proved reserves in place in 2005, 2004 and 2003, respectively.

⁽²⁾ Exploration costs include delay rentals, exploratory dry holes, dry hole and bottom hole contributions, geological and geophysical costs, costs of carrying and retaining properties, and capital expenditures, such as costs of drilling and equipping successful exploratory wells.

⁽³⁾ Development costs include costs incurred to obtain access to proved reserves (surveying, clearing ground, building roads), to drill and equip development wells, and to acquire, construct and install production facilities and improved-recovery systems. Development costs also include costs of developmental dry holes.

⁽⁴⁾ Asset retirement costs of $37 million, $83 million and $3 million for 2005, 2004, and 2003, respectively, represent the noncash increase in property, plant and equipment recognized when initially recording a liability for abandonment obligations (discounted) associated with the company’s oil and gas wells and platforms. Asset retirement costs are depleted on a unit-of-production basis over the useful life of the related field.

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22.Results of Operations from Crude Oil and Natural Gas Activities

The results of operations from crude oil and natural gas activities (excluding discontinued operations) for the years ended December 31, 2005, 2004 and 2003 were as follows:

(Millions of dollars)	Revenues		Production (Lifting) Costs		Other Costs (1)		Exploration Expenses		Depreciation, Depletion and Accretion		Loss (Gain) on Asset Sales and Impairments			Income Tax Expense (Benefit)			Results of Operations, Producing Activities
2005 –
United States	$	3,374	$	618	$	104	$	307	$	789	$	(194	)	$	613		$	1,137
China		312		33		—		23		56		—			66			134
Other international		—		—		1		59		—		—			(21	)		(39	)
Total	$	3,686	$	651	$	105	$	389	$	845	$	(194	)	$	658		$	1,232
2004 –
United States	$	2,520	$	413	$	82	$	269	$	620	$	51		$	380		$	705
China		92		13		1		12		22		(1	)		15			30
Other international		—		—		1		49		1		—			(18	)		(33	)
Total	$	2,612	$	426	$	84	$	330	$	643	$	50		$	377		$	702
2003 –
United States	$	1,775	$	267	$	56	$	252	$	400	$	(4	)	$	281		$	523
China		23		5		1		19		2		(12	)		3			5
Other international		—		—		1		60		1		—			(22	)		(40	)
Total	$	1,798	$	272	$	58	$	331	$	403	$	(16	)	$	262		$	488

⁽¹⁾ Includes transportation and taxes other than income taxes associated with oil and natural gas producing activities.

The table below presents the company’s average per-unit sales price of crude oil and natural gas and lifting costs (lease operating expense and production and ad valorem taxes) per barrel of oil equivalent for continuing operations for each of the three years in the period ended December 31, 2005. Natural gas production has been converted to a barrel of oil equivalent based on approximate relative heating value (6 Mcf equals 1 barrel).

	2005		2004		2003
Average realized price of crude oil (per barrel)(1) –
United States	$	42.55	$	29.11	$	26.14
China		44.45		32.37		29.66
Average - continuing operations		42.89		29.38		26.24
Average realized price of natural gas (per Mcf)(1) –
United States	$	6.66	$	5.24	$	4.56
Lifting costs (per barrel of oil equivalent) –
United States	$	6.12	$	4.63	$	3.57
China		4.79		4.37		6.02
Average -continuing operations		6.03		4.63		3.61

⁽¹⁾ Includes the results of the company’s hedging program, which reduced the average price of crude oil sold by $5.68, $8.03 and $2.48 per barrel and natural gas sold by $1.21, $.82 and $.63 per Mcf in 2005, 2004 and 2003, respectively.

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23.Capitalized Costs Related to Crude Oil and Natural Gas Activities

Capitalized costs related to crude oil and natural gas activities and the related reserves for depreciation, depletion and amortization at the end of 2005 and 2004 are set forth in the table below. Capitalized costs presented as assets held for sale and of discontinued operations at December 31, 2004 primarily relate to the North Sea oil and gas business, which was sold in 2005, as discussed in Note 2.

(Millions of dollars)	2005		2004
Capitalized costs –
Proved properties	$	11,615	$	10,467
Unproved properties		1,427		1,674
Other		448		412
		13,490		12,553
Assets held for sale and of discontinued operations		8		4,183
Total		13,498		16,736
Accumulated depreciation, depletion and amortization –
Proved properties		4,744		4,154
Unproved properties		248		190
Other		116		99
		5,108		4,443
Assets held for sale and of discontinued operations		3		2,424
Total		5,111		6,867
Net capitalized costs	$	8,387	$	9,869

Exploratory Drilling Costs

Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. In the case of onshore wells and offshore wells in relatively shallow water, that determination usually can be made upon or shortly after cessation of exploratory drilling operations. However, such determination may take longer in other areas (specifically, deepwater exploration and international locations) depending upon, among other things, (i) the amount of hydrocarbons discovered, (ii) the outcome of planned geological and engineering studies, (iii) the need for additional appraisal drilling to determine whether the discovery is sufficient to support an economic development plan and (iv) the requirement for government sanctioning in certain international locations before proceeding with development activities. As a consequence, the company has capitalized costs associated with exploratory wells on its Consolidated Balance Sheet at any point in time that may be charged to earnings in a future period if management determines that commercial quantities of hydrocarbons have not been discovered.

Initial and Ongoing Assessment of Deferred Exploratory Drilling Costs– When initial drilling operations are complete, management determines whether the well has discovered oil and gas reserves and, if so, whether those reserves can be classified as proved. Often, the determination of whether proved reserves can be recorded under strict Securities and Exchange Commission (SEC) guidelines cannot be made when drilling is completed. In those situations where management believes that commercial hydrocarbons have not been discovered, the exploratory drilling costs are reflected in the Consolidated Statement of Income as dry hole costs (a component of exploration expense). Where sufficient hydrocarbons have been discovered to justify further exploration and/or appraisal activities, exploratory drilling costs are deferred on the Consolidated Balance Sheet pending the outcome of those activities.

At the end of each quarter, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities – in particular, whether the company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are under way and proceeding as planned. If management determines that future appraisal drilling or development activities are not likely to occur in the future, any associated exploratory well costs are expensed in that period.

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Financial Statement Balances – The following table presents the amount of capitalized exploratory drilling costs relating to continuing operations at December 31 for each of the last three years, and changes in those amounts during the years then ended (excluding costs incurred and either reclassified to proved oil and gas properties or charged to expense in the same year):

(Millions of dollars)	2005			2004			2003
Balance at January 1	$	130		$	135		$	116
Additions, pending determination of proved reserves		139			76			64
Reclassification to proved oil and gas properties		(53	)		(14	)		(39	)
Capitalized exploratory well costs charged to expense		(8	)		(67	)		(6	)
Balance at December 31	$	208		$	130		$	135

At December 31, 2005, the company had capitalized costs of approximately $208 million associated with ongoing exploration and/or appraisal activities, primarily in the deepwater Gulf of Mexico, Alaska, Brazil and China. The following table presents the total amount of exploratory drilling costs at year-end 2005 by geographic area, including the length of time such costs have been carried on the Consolidated Balance Sheet:

			Costs Incurred
(Millions of dollars)	Total		2005			2004		2003
Gulf of Mexico(1)	$	98	$	68		$	5	$	25
Alaska		68		48			20		—
Brazil		30		20			10		—
China		8		(1	)		9		—
Other		4		4			—		—
Total capitalized exploratory drilling costs	$	208	$	139		$	44	$	25

⁽¹⁾ Approximately $43 million is associated with properties sold to W&T in 2006 as part of the Gulf of Mexico shelf divestiture.

Analysis of Exploratory Costs at December 31, 2005 – The majority of exploratory drilling costs deferred at year-end are associated with wells that are either (i) drilling at December 31, (ii) in an area requiring a major capital expenditure or additional appraisal activities before recording proved reserves such as the deepwater Gulf of Mexico, Alaska, Brazil and China, or (iii) subject to government review and approval of our development plans. The company has no deferred drilling costs associated with areas that require gas sales contracts or project financing in order to proceed with development plans. The following discussion describes major projects shown in the table above with costs deferred beyond one year from the balance sheet date.

Deepwater Gulf of Mexico – Costs incurred in the deepwater Gulf of Mexico prior to 2004 ($25 million) relate to an exploration well located in an area requiring additional appraisal activity before the determination of proved reserves can be made. The drilling rig for this well was released in October 2003 after successfully encountering hydrocarbons. The company is conducting appraisal activities at this time. Management expects that appraisal drilling may occur during 2006; however, if management determines during the year that future appraisal drilling is not likely to occur, all capitalized costs will be charged to exploration expense.

Alaska – Costs incurred in Alaska prior to 2005 ($20 million) are associated with the company’s Nikaitchuq discovery on Alaska’s North Slope. The discovery well was followed by an appraisal well drilled during 2004. Further appraisal drilling and flow testing was carried out in 2005. Development assessment and planning for this discovery is under way. The company is working towards possible development sanctioning in 2006.

Brazil – Costs incurred prior to 2005 ($10 million) are associated with the BMC-7 discovery located in the Campos Basin offshore Brazil. The original discovery well was drilled in 2004, followed by two successful appraisal wells in 2005. A successful flow test of one of these wells was also conducted during 2005. Development planning is under way and these costs have been deferred pending formal approval of a development plan.

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China –Costs incurred in China prior to 2005 ($9 million) are associated with the CFD 14-5-1 discovery drilled in late 2004. Further assessment of the discovery is under way utilizing 3-D seismic data obtained to the west of the discovery well to develop an appraisal plan. If management determines that future appraisal drilling is not likely to occur, all capitalized costs will be charged to exploration expense.

24.Crude Oil, Condensate, Natural Gas Liquids and Natural Gas Net Reserves (Unaudited)

The following tables show estimates of proved reserves prepared by the company’s engineers in accordance with the SEC definitions. Data is shown for crude oil in millions of barrels, for natural gas in billions of cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch and for total proved reserves in millions of barrels of oil equivalent. For total proved reserves, natural gas is converted to barrels of oil equivalent using a conversion factor of six thousand cubic feet of natural gas per barrel.

During 2005, the company expanded the involvement of third-party engineers in its reserve estimation processes. In July 2004, the company engaged Netherland, Sewell & Associates, Inc. (NSAI) to provide independent third-party review of the company’s procedures and methods for reserves estimation. During 2004, NSAI performed a procedures and methods review of about 43% of the company’s year-end 2004 proved reserves. In 2005, NSAI’s review was expanded to 75% of the company’s year-end proved reserves. The purpose of NSAI’s ongoing review is to verify that reserve estimates prepared by the company’s internal technical staff are in accordance with the guidelines and definitions of the SEC using generally accepted petroleum engineering and evaluation principles. As a result of its review, NSAI determined that the procedures and methods were reasonable and estimates had been prepared in accordance with Rule 4-10(a) of SEC Regulation S-X and generally accepted petroleum engineering and evaluation principles. A copy of the NSAI report is included as exhibit 99 to this Annual Report on Form 10-K. In 2006 the company plans to continue third-party review of its reserves estimation procedures and methods.

The company’s estimates of proved reserves are derived from data prepared by its engineers using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional data. Revisions of previous estimates can occur due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. For example, a decrease in commodity price could result in a decrease in proved reserves as the economic limit of a reservoir might be reached sooner. Conversely, an improvement in reservoir performance could result in an increase in proved reserves, indicating higher ultimate recovery from previous estimates.

The company’s engineering staff is highly skilled with average industry experience of more than 20 years. The company relies primarily on its internal engineering expertise, augmented by third-party engineering oversight and advice to ensure objective estimates of the company’s proved reserves. The company mitigates the inherent risks associated with reserve estimation through a comprehensive reserves administration process. The company’s process includes:

• Independent third-party procedures and methods assessment

• Internal peer review and third-party assessment of all individually significant reserve additions (defined as those in excess of 5 million barrels of oil equivalent on a net basis)

• Annual internal review of about 80% of the company’s total proved reserves

The following tables summarize changes in the estimated quantities of proved reserves for the three years ended December 31, 2005. As more fully discussed in Note 2, in 2005, the company divested its North Sea oil and gas business, which is reported as a discontinued operation for all periods presented, and certain onshore oil and gas properties in the United States. As discussed in Note 26, in August 2006, Kerr-McGee sold its interest in Gulf of Mexico shelf oil and natural gas properties to W&T. Proved reserves for the company’s Gulf of Mexico shelf assets are included in the following tables as a component of continuing operations and are less than 10% of the company’s total proved reserves at year-end 2005. As described in Note 4, we completed a merger with Westport in 2004, which resulted in reserve additions of 281 million barrels of oil equivalent.

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	Continuing Operations
Crude Oil, Condensate and Natural Gas Liquids (Millions of barrels)	United States		China		Total		Discontinued Operations		Total
Proved developed and undeveloped reserves –
Balance at December 31, 2002	241		35		276		211		487
Revisions of previous estimates	7		2		9		(7	)	2
Purchases of reserves in place	3		—		3		12		15
Sales of reserves in place	(16	)	(3	)	(19	)	(9	)	(28	)
Extensions, discoveries and other additions	55		6		61		14		75
Production	(28	)	(1	)	(29	)	(26	)	(55	)
Balance at December 31, 2003	262		39		301		195		496
Revisions of previous estimates	9		1		10		6		16
Purchases of reserves in place	67		—		67		—		67
Sales of reserves in place	(10	)	—		(10	)	—		(10	)
Extensions, discoveries and other additions	14		—		14		1		15
Production	(32	)	(3	)	(35	)	(23	)	(58	)
Balance at December 31, 2004	310		37		347		179		526
Revisions of previous estimates	31		2		33		1		34
Purchases of reserves in place	1		—		1		4		5
Sales of reserves in place	(27	)	—		(27	)	(168	)	(195	)
Extensions, discoveries and other additions	40		8		48		3		51
Production	(33	)	(7	)	(40	)	(19	)	(59	)
Balance at December 31, 2005	322		40		362		—		362
Natural Gas (Billions of cubic feet)
Proved developed and undeveloped reserves –
Balance at December 31, 2002	2,779		—		2,779		496		3,275
Revisions of previous estimates	(10	)	—		(10	)	11		1
Purchases of reserves in place	57		—		57		30		87
Sales of reserves in place	(77	)	—		(77	)	—		(77	)
Extensions, discoveries and other additions	152		—		152		8		160
Production	(230	)	—		(230	)	(35	)	(265	)
Balance at December 31, 2003	2,671		—		2,671		510		3,181
Revisions of previous estimates	86		—		86		(98	)	(12	)
Purchases of reserves in place	1,289		—		1,289		—		1,289
Sales of reserves in place	(27	)	—		(27	)	—		(27	)
Extensions, discoveries and other additions	59		—		59		—		59
Production	(306	)	—		(306	)	(31	)	(337	)
Balance at December 31, 2004	3,772		—		3,772		381		4,153
Revisions of previous estimates	128		—		128		26		154
Purchases of reserves in place	19		—		19		9		28
Sales of reserves in place	(208	)	—		(208	)	(396	)	(604	)
Extensions, discoveries and other additions	273		—		273		3		276
Production	(351	)	—		(351	)	(23	)	(374	)
Balance at December 31, 2005	3,633		—		3,633		—		3,633

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	Continuing Operations
Crude Oil, Condensate and Natural Gas Liquids (Millions of barrels)	United States	China	Total	Discontinued Operations	Total
Proved developed reserves –
December 31, 2003	122	—	122	125	247
December 31, 2004	197	16	213	120	333
December 31, 2005	234	19	253	—	253
Natural Gas (Billions of cubic feet)
Proved developed reserves –
December 31, 2003	1,502	—	1,502	113	1,615
December 31, 2004	2,620	—	2,620	135	2,755
December 31, 2005	2,560	—	2,560	—	2,560

The following presents the company’s barrel of oil equivalent proved developed and undeveloped reserves based on approximate heating value (6 Mcf equals 1 barrel).

	Continuing Operations
Barrels of Oil Equivalent (Millions of barrels)	United States		China		Total		Discontinued Operations		Total
Proved developed and undeveloped reserves –
Balance at December 31, 2002	704		35		739		294		1,033
Revisions of previous estimates	5		2		7		(5	)	2
Purchases of reserves in place	12		—		12		17		29
Sales of reserves in place	(29	)	(3	)	(32	)	(9	)	(41	)
Extensions, discoveries and other additions	81		6		87		15		102
Production	(66	)	(1	)	(67	)	(32	)	(99	)
Balance at December 31, 2003	707		39		746		280		1,026
Revisions of previous estimates	24		1		25		(11	)	14
Purchases of reserves in place	282		—		282		—		282
Sales of reserves in place	(15	)	—		(15	)	—		(15	)
Extensions, discoveries and other additions	24		—		24		1		25
Production	(83	)	(3	)	(86	)	(28	)	(114	)
Balance at December 31, 2004	939		37		976		242		1,218
Revisions of previous estimates	52		2		54		5		59
Purchases of reserves in place	4		—		4		6		10
Sales of reserves in place	(61	)	—		(61	)	(234	)	(295	)
Extensions, discoveries and other additions	85		8		93		4		97
Production	(91	)	(7	)	(98	)	(23	)	(121	)
Balance at December 31, 2005	928		40		968		—		968

	Continuing Operations
(Millions of equivalent barrels)	United States	China	Total	Discontinued Operations	Total
Proved developed reserves –
December 31, 2003	372	—	372	144	516
December 31, 2004	634	16	650	142	792
December 31, 2005	661	19	680	—	680
Proved undeveloped reserves –
December 31, 2003	335	39	374	136	510
December 31, 2004	305	21	326	100	426
December 31, 2005	267	21	288	—	288

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25.Standardized Measure of and Reconciliation of Changes in Discounted Future Net Cash Flows (Unaudited)

The standardized measure of future net cash flows presented in the following table was computed using year-end prices and costs and a 10% discount factor. The future income tax expense was computed by applying the appropriate year-end statutory rates, with consideration of future tax rates already legislated, to the future pretax net cash flows less the tax basis of the associated properties. However, the company cautions that actual future net cash flows may vary considerably from these estimates. Although the company’s estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of the oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the company’s estimate of the expected revenues or the current value of existing proved reserves.

(Millions of dollars)	Future Cash Inflows (1)		Future Production Costs		Future Development Costs		Future Income Taxes		Future Net Cash Flows		10% Annual Discount		Standardized Measure of Discounted Future Net Cash Flows
2005 –
United States	$	48,739	$	10,722	$	3,232	$	11,661	$	23,124	$	9,402	$	13,722
China		1,821		415		98		363		945		319		626
Total	$	50,560	$	11,137	$	3,330	$	12,024	$	24,069	$	9,721	$	14,348	(2)
2004 –
United States	$	33,512	$	7,976	$	2,752	$	7,158	$	15,626	$	6,549	$	9,077
China		986		306		83		113		484		148		336
Total – continuing operations		34,498		8,282		2,835		7,271		16,110		6,697		9,413
Discontinued operations		8,927		2,988		999		1,863		3,077		934		2,143
Total	$	43,425	$	11,270	$	3,834	$	9,134	$	19,187	$	7,631	$	11,556
2003 –
United States	$	23,850	$	5,002	$	2,067	$	5,467	$	11,314	$	4,721	$	6,593
China		1,114		306		130		178		500		208		292
Total – continuing operations		24,964		5,308		2,197		5,645		11,814		4,929		6,885
Discontinued operations		7,770		2,437		790		1,552		2,991		970		2,021
Total	$	32,734	$	7,745	$	2,987	$	7,197	$	14,805	$	5,899	$	8,906

⁽¹⁾ Future cash inflows from sales of crude oil and natural gas are based on average year-end prices of $53.96, $37.02 and $29.05 per barrel of oil and $8.56, $5.78 and $5.77 per Mcf of natural gas for 2005, 2004 and 2003, respectively.

⁽²⁾ Approximately 10% of the total standardized measure of discounted future net cash flows is associated with the company’s Gulf of Mexico shelf assets, which the company sold in August 2006, as discussed in Note 26.

The changes in the standardized measure of future net cash flows are presented below for each of the past three years:

(Millions of dollars)	2005			2004			2003
Net change in sales prices and production costs	$	7,760		$	2,069		$	3,308
Sales revenues less production costs		(4,891	)		(3,454	)		(2,383	)
Purchases of reserves in place		222			3,850			344
Extensions, discoveries and other additions		2,061			438			1,183
Revisions in quantity estimates		808			(66	)		63
Sales of reserves in place		(4,042	)		(204	)		(255	)
Current-period development costs incurred		1,398			928			573
Changes in estimated future development costs		(913	)		(852	)		(472	)
Accretion of discount		1,696			1,323			1,033
Change in income taxes		(1,761	)		(1,097	)		(978	)
Timing and other		454			(285	)		(572	)
Net change		2,792			2,650			1,844
Total at beginning of year		11,556			8,906			7,062
Total at end of year	$	14,348		$	11,556		$	8,906

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26.Subsequent Events

Merger with Anadarko Petroleum Corporation (Anadarko)

On June 22, 2006, Kerr-McGee and Anadarko entered into a definitive agreement providing for the company’s merger with a subsidiary of Anadarko. After receiving approval from the majority of the company’s stockholders, the merger was completed on August 10, 2006 and all of the company’s issued and outstanding common stock was acquired by Anadarko for cash consideration of $70.50 per-share. Consistent with the provisions of the company’s long term incentive plans, upon completion of the merger, all options to purchase Kerr-McGee common stock, shares of Kerr-McGee restricted stock and performance units outstanding as of the merger date became fully vested. All outstanding stock options were cancelled and the option holders received cash consideration for each option equal to the excess of $70.50 per-share over the exercise price (subject to applicable tax withholdings). Restrictions on all shares of restricted stock outstanding as of the merger date lapsed and the holders received the same merger consideration as the holders of Kerr-McGee unrestricted common stock. The company’s performance unit awards were settled in cash consistent with the provisions of the long-term incentive plans under which they were issued.

On June 23, 2006, the company entered into an amendment to render the stockholders’ rights plan discussed in Note 18 inapplicable to (i) the approval, execution or delivery of the merger agreement with Anadarko, (ii) the announcement of the merger, (iii) the consummation of the merger or the other transactions contemplated by the merger agreement and (iv) the acquisition of the company’s common stock pursuant to the merger or the merger agreement. In addition, the amendment provides for the extension of the expiration date of the rights plan from July 26, 2006 to July 22, 2016; and the termination of the rights plan upon the earliest of the expiration date, redemption, exchange or immediately prior to the effective date of the merger.

Other Subsequent Events

Information in the accompanying consolidated financial statements and notes thereto has been updated since their original issuance in the company’s Annual Report on Form 10-K for the year ended December 31, 2005 to reflect the effects of matters discussed below:

• On August 24, 2006, the company completed the sale of its interests in certain Gulf of Mexico shelf oil and gas properties to W&T for $1 billion, after adjusting for net cash flows subsequent to the October 1, 2005 effective date. As discussed in Note 2, these properties met the criteria for classification as held for sale in early 2006.

• On June 14, 2006, the company completed a two-for-one split of Kerr-McGee’s outstanding common stock. The stock split was effected through a stock dividend issued to stockholders of record at the close of business on June 2, 2006 (including holders of restricted stock). The par value of Kerr-McGee’s common stock remains $1 per share. Unless otherwise indicated, historical common shares outstanding and per-share amounts in the accompanying consolidated financial statements and notes thereto have been retroactively adjusted to reflect the stock split. As a result, certain information in Notes 1, 4, 5, 18 and 19 has been updated to give effect to the stock split.

• On March 30, 2006, Kerr-McGee completed a pro rata distribution in the form of a dividend to its stockholders of approximately 23 million shares of Tronox Class B common stock the company owned as of December 31, 2005. Upon completing the Distribution, results of Tronox operations are required to be reported as a discontinued operation in Kerr-McGee’s consolidated financial statements. The accompanying consolidated financial statements and Notes 2, 4, 5, 6, 9, 13, 14, 15, 16, 17 and 19 thereto have been revised accordingly.

• With the separation of the chemical business, the income statement format for all periods presented has been changed to better reflect the operations of an exploration and production company. Additionally, information with respect to Kerr-McGee’s reportable business segments presented in Note 20 has been revised to be consistent with the company’s 2006 segment presentation.

• Prior to the merger with Anadarko, the company repurchased approximately 3.4 million shares (on a pre-split basis) under the share repurchase program initiated in January 2006, at an aggregate cost of $356 million. This program is discussed in Notes 1, 5 and 18.

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