September 2005 10Q

	KERR-McGEE CORPORATION

	INDEX
		PAGE
PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

	Condensed Consolidated Statement of Income for the Three and Nine Months Ended September 30, 2005 and 2004	1

	Condensed Consolidated Balance Sheet at September 30, 2005 and December 31, 2004	2

	Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2005 and 2004	3

	Condensed Consolidated Statement of Comprehensive Income (Loss) and Stockholders’ Equity for the Nine Months Ended September 30, 2005 and 2004	4

	Notes to Condensed Consolidated Financial Statements	5

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		42

Item 3. Quantitative and Qualitative Disclosures about Market Risk		66

Item 4. Controls and Procedures		70

Forward-Looking Information		70


PART II - OTHER INFORMATION

Item 1. Legal Proceedings		70

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		71

Item 6. Exhibits		71

SIGNATURE		72

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Millions of dollars, except per-share amounts)	2005			2004			2005			2004

Revenues	$	1,208		$	1,203		$	4,152		$	3,006

Costs and Expenses
Costs and operating expenses		554			488			1,544			1,238
Selling, general and administrative expenses		104			81			302			231
Shipping and handling expenses		34			35			109			90
Depreciation and depletion		233			320			729			583
Accretion expense		6			5			17			13
Asset impairments		-			7			5			22
(Gain) loss on sale of assets		4			-			(42	)		7
Exploration, including dry holes and amortization
of undeveloped leases		61			95			228			195
Taxes, other than income taxes		52			44			141			98
Provision for environmental remediation and restoration,
net of reimbursements		7			72			33			75
Interest and debt expense		68			68			190			180
Loss on early repayment and modification of debt		9			-			9			-
Total Costs and Expenses		1,132			1,215			3,265			2,732

		76			(12	)		887			274
Other Income (Expense)		(3	)		(20	)		(16	)		(27	)

Income (Loss) from Continuing Operations
before Income Taxes		73			(32	)		871			247
Benefit (Provision) for Income Taxes		(19	)		8			(301	)		(89	)

Income (Loss) from Continuing Operations		54			(24	)		570			158
Income from Discontinued Operations, net of taxes (Note 2)		306			31			515			112

Net Income	$	360		$	7		$	1,085		$	270

Income (Loss) per Common Share
Basic -
Continuing operations	$	.46		$	(.16	)	$	4.18		$	1.34
Discontinued operations		2.68			.21			3.77			.95
Net income	$	3.14		$	.05		$	7.95		$	2.29

Diluted -
Continuing operations	$	.46		$	(.16	)	$	4.09		$	1.33
Discontinued operations		2.63			.21			3.66			.94
Net income	$	3.09		$	.05		$	7.75		$	2.27

Dividends Declared per Common Share	$	.05		$	.45		$	.55		$	1.35

	September 30,			December 31,
(Millions of dollars)	2005			2004

ASSETS
Current Assets
Cash and cash equivalents (Note 2)	$	662		$	76
Accounts receivable		980			825
Inventories		339			314
Derivatives and other current assets		274			151
Deferred income taxes		714			327
Assets held for sale (Note 2)		295			194
Total Current Assets		3,264			1,887

Property, Plant and Equipment		15,331			14,806
Less reserves for depreciation, depletion and amortization		(6,199	)		(5,733	)
		9,132			9,073

Investments, Derivatives and Other Assets		538			484
Goodwill and Other Intangible Assets		1,277			1,288
Assets Held for Sale (Note 2)		1,846			1,786

Total Assets	$	16,057		$	14,518

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	623		$	607
Long-term debt due within one year		433			463
Income taxes payable		101			138
Derivative liabilities		2,219			350
Accrued liabilities		798			755
Liabilities associated with assets held for sale (Note 2)		491			192
Total Current Liabilities		4,665			2,505

Long-Term Debt		5,912			3,236

Noncurrent Liabilities
Deferred income taxes		1,552			1,727
Asset retirement obligations		324			336
Derivative liabilities		977			208
Other		595			571
Liabilities associated with assets held for sale (Note 2)		689			617
Total Noncurrent Liabilities		4,137			3,459

Contingencies and Commitments (Notes 16 and 17)

Stockholders' Equity
Common stock, par value $1 - 500,000,000 and 300,000,000 shares
authorized, 119,351,451 and 152,049,127 shares issued at
September 30, 2005 and December 31, 2004, respectively		119			152
Capital in excess of par value		3,635			4,205
Preferred stock purchase rights		1			2
Retained earnings (accumulated deficit)		(416	)		1,102
Accumulated other comprehensive loss		(1,677	)		(79	)
Common shares in treasury, at cost - 3,371,782 and 159,856 shares
at September 30, 2005 and December 31, 2004, respectively		(262	)		(8	)
Deferred compensation		(57	)		(56	)
Total Stockholders' Equity		1,343			5,318

Total Liabilities and Stockholders’ Equity	$	16,057		$	14,518

	Nine Months Ended
	September 30,
(Millions of dollars)	2005			2004

Cash Flows from Operating Activities
Net income	$	1,085		$	270
Adjustments to reconcile net income to net cash
provided by operating activities -
Depreciation, depletion and amortization		908			785
Deferred income taxes		179			86
Dry hole expense		125			80
Asset impairments		5			22
Gain on sale of North Sea oil and gas assets		(306	)		-
(Gain) loss on sale of other assets		(42	)		7
Loss on early repayment and modification of debt		9			-
Accretion expense		24			22
Provision for environmental remediation and restoration,
net of reimbursements		44			81
Other noncash items affecting net income		497			165
Changes in assets and liabilities		(27	)		(191	)
Net Cash Provided by Operating Activities		2,501			1,327

Cash Flows from Investing Activities
Capital expenditures		(1,292	)		(832	)
Dry hole costs		(118	)		(46	)
Acquisitions, net of cash acquired ⁽¹⁾		-			43
Proceeds from sale of North Sea oil and gas assets		547			-
Proceeds from sale of other assets		68			11
Proceeds from sale of investments		-			39
Other investing activities		(7	)		(31	)
Net Cash Used in Investing Activities		(802	)		(816	)

Cash Flows from Financing Activities
Issuance of common stock		206			34
Purchases of treasury stock		(250	)		-
Shares repurchased under the tender offer		(3,975	)		-
Dividends paid		(148	)		(137	)
Repayment of debt		(998	)		(1,278	)
Proceeds from borrowings		4,250			906
Costs of obtaining financing		(58	)		(6	)
Cash paid for modification of debt		(9	)		-
Settlement of Westport derivatives		(134	)		(45	)
Net Cash Used in Financing Activities		(1,116	)		(526	)

Effects of Exchange Rate Changes on Cash and Cash Equivalents		3			1
Net Increase (Decrease) in Cash and Cash Equivalents		586			(14	)
Cash and Cash Equivalents at Beginning of Period		76			142
Cash and Cash Equivalents at End of Period	$	662		$	128

(Millions of dollars)	Common Stock			Capital in Excess of Par Value			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Loss			Treasury Stock			Deferred Compensation and Other			Total Stockholders' Equity
Balance at December 31, 2003	$	101		$	1,708		$	927		$	(45	)	$	(2	)	$	(53	)	$	2,636
Comprehensive Loss:
Net income		-			-			270			-			-			-			270
Other comprehensive loss		-			-			-			(345	)		-			-			(345	)
Comprehensive loss																				(75	)
Westport merger		49			2,402			-			-			-			(3	)		2,448
Exercise of stock options		2			33			-			-			-			-			35
Restricted stock activity		-			24			-			-			(6	)		(9	)		9
ESOP deferred compensation		-			-			-			-			-			5			5
Tax benefit from stock-based awards		-			15			-			-			-			-			15
Dividends declared ($1.35 per share)		-			-			(160	)		-			-			-			(160	)
Balance at September 30, 2004	$	152		$	4,182		$	1,037		$	(390	)	$	(8	)	$	(60	)	$	4,913

Balance at December 31, 2004	$	152		$	4,205		$	1,102		$	(79	)	$	(8	)	$	(54	)	$	5,318
Comprehensive Loss:
Net income		-			-			1,085			-			-			-			1,085
Other comprehensive loss		-			-			-			(1,598	)		-			-			(1,598	)
Comprehensive loss																				(513	)
Shares issued upon conversion
of 5.25% debentures		10			583			-			-			-			-			593
Purchases of treasury shares		-			-			-			-			(250	)		-			(250	)
Shares repurchased and retired		(47	)		(1,410	)		(2,517	)		-			-			(1	)		(3,975	)
Exercise of stock options		3			203			-			-			-			-			206
Restricted stock activity		1			25			-			-			(4	)		(7	)		15
ESOP deferred compensation		-			-			-			-			-			6			6
Tax benefit from stock-based awards		-			29			-			-			-			-			29
Dividends declared ($.55 per share)		-			-			(86	)		-			-			-			(86	)
Balance at September 30, 2005	$	119		$	3,635		$	(416	)	$	(1,677	)	$	(262	)	$	(56	)	$	1,343

Kerr-McGee is an energy and inorganic chemical company with worldwide operations. The exploration and production unit explores for, develops, produces and markets crude oil and natural gas, with major areas of operation in the United States, the United Kingdom sector of the North Sea and China. Exploration efforts also extend to Angola, Australia, Benin, Bahamas, Brazil, Morocco, Canada and Trinidad. The chemical unit is primarily engaged in the production and marketing of titanium dioxide pigment and 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 condensed consolidated financial statements to refer to the consolidated group or to one or more of the companies that are part of the consolidated group.

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 company completed its evaluation and the Board approved the separation of the chemical business through an initial public offering (IPO), followed by a distribution of Kerr-McGee’s remaining ownership in the chemical business subsidiary to Kerr-McGee’s stockholders through a spinoff, splitoff or a combination of these transactions, planned for 2006. Note 3 provides additional information about the IPO.

In April 2005, the company announced its decision to divest lower-growth or shorter-life and higher-decline oil and gas properties. In connection with the divestiture program, in August 2005, the company entered into agreements to sell its North Sea oil and gas business for aggregate cash proceeds of $3.5 billion. Additionally, in October 2005, the company entered into agreements to divest certain noncore oil and gas properties onshore in the United States. Information about these transactions is provided in Note 2. Other selected oil and gas properties in the U.S. are also being considered for divestiture. The total combined divestitures may represent up to 30% of the company’s proved reserves at December 31, 2004, and up to 35% of its average daily production for the first nine months of 2005. However, the actual impact of any divestitures may differ materially from management’s estimates due to a change in market conditions or in the composition of the properties to be divested, as well as other factors.

On April 14, 2005, the company announced its intention to commence a modified "Dutch Auction" self 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, which represented 29% of shares outstanding at March 31, 2005. Note 15 provides additional information regarding this transaction. The tender offer was financed with the net proceeds of borrowings, which are discussed in Note 10, and cash on hand.

The unaudited condensed consolidated financial statements included herein have been prepared by the company, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) and, in the opinion of management, include all adjustments necessary to a fair statement of the results for the interim periods presented. Except as indicated below, such adjustments are normal and recurring in nature. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. Although the company believes that the disclosures are adequate to make the information presented not misleading, these financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in the company's latest annual report on Form 10-K.

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.

Asset Exchanges - Effective July 1, 2005, the company implemented 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 of its interest in 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 proportionate amount of the total gain was recognized. Exchanges of an interest in oil and gas properties involving receipt of monetary consideration of 25% or more were accounted for at fair value and the full amount of realized gain was recognized. According to the provisions of FAS No. 153, all nonmonetary asset exchanges that have commercial substance will be measured based on the fair values exchanged with any resulting gain or loss recognized in earnings. An exchange is deemed to have commercial substance if it results in a significant change in expected future cash flows.

Employee Stock-Based Compensation - The company accounts for its stock-based awards under the intrinsic-value method permitted by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). Accordingly, net income reflects no stock-based employee compensation expense for the issuance of stock options under the company’s plans, since all options were fixed-price options with an exercise price equal to the market value of the underlying common stock on the date of grant.

Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation” (FAS No. 123), prescribes a 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.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Millions of dollars, except per-share amounts)	2005			2004			2005			2004

Net income, as reported	$	360		$	7		$	1,085		$	270
Add: stock-based employee compensation expense
included in reported net income, net of taxes		7			4			20			10
Deduct: stock-based compensation expense determined
using a fair-value method, net of taxes		(10	)		(7	)		(32	)		(20	)
Pro forma net income	$	357		$	4		$	1,073		$	260

Net income per share -
Basic -
As reported	$	3.14		$	.05		$	7.95		$	2.29
Pro forma		3.13			.03			7.86			2.20

Diluted -
As reported	$	3.09		$	.05		$	7.75		$	2.27
Pro forma		3.07			.03			7.67			2.19

New/Revised Accounting Standards - In December 2004, the Financial Accounting Standards Board (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, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim period after June 15, 2005, with early adoption encouraged. In April 2005, the SEC amended its rules to allow public companies more time to implement the standard. Following the SEC’s rule, the company intends to implement FAS No. 123R effective January 1, 2006. The company plans to adopt the standard 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 company expects that the adoption will not have a material effect on its financial condition and cash flows. The company is evaluating the effect of implementation on its results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (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. FIN No. 47 is effective for the company as of December 31, 2005. The company is evaluating the effect of implementation and at this time does not expect it to have a material effect on its financial statements.

In April 2005, the FASB issued a FASB Staff Position FAS 19-1, "Accounting for Suspended Well Costs" (FSP FAS 19-1) which amends FASB Statement No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." FSP FAS 19-1 requires the continued capitalization of drilling costs if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. The FSP provides a number of indicators that can assist an entity in evaluating whether sufficient progress is being made in assessing the reserves and economic viability of the project and includes new disclosure requirements with respect to capitalized exploratory drilling costs. The company adopted FSP FAS 19-1 effective July 1, 2005. The adoption had no effect on the company's financial statements. Disclosures required by the FSP were provided in the notes to the consolidated financial statements included in the company's latest annual report on Form 10-K.

Overview - As discussed in Note 1, in 2005, the company made a number of strategic decisions 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 the separation of the chemical business and 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. 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 an asset 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, Alaska, Brazil, China, Trinidad and other areas will continue to provide growth opportunities.

The following summarizes divestiture transactions completed or which the company expects to complete in the fourth quarter. In addition, as discussed in Note 3, the company expects to realize net proceeds of $800 million to $900 million from the pending separation of its chemical business. The company intends to use net proceeds from the divestitures and the separation of the chemical business for debt repayment and other corporate purposes. Debt repayments made during the third and fourth quarters of 2005 in connection with completed transactions are discussed in Note 10.

	Three Months Ended September 30,
	2005									2004
	North Sea			Forest						North Sea			Forest
	Oil and Gas			Products						Oil and Gas			Products
(Millions of dollars)	Business			Business			Total			Business			Business			Total

Revenues	$	285		$	-		$	285		$	159		$	5		$	164

Income from Discontinued Operations:
Income (loss) from operations	$	157		$	-		$	157		$	59		$	(5	)	$	54
Gain on sale		306			-			306			-			-			-
Adjustments for contingencies ⁽¹⁾		-			(14	)		(14	)		-			-			-
Pretax income (loss) from discontinued
operations		463			(14	)		449			59			(5	)		54
Income tax (expense) benefit		(148	)		5			(143	)		(25	)		2			(23	)
Income (loss) from discontinued operations,
net of tax	$	315		$	(9	)	$	306		$	34		$	(3	)	$	31

	Nine Months Ended September 30,
	2005									2004
	North Sea			Forest						North Sea			Forest
	Oil and Gas			Products						Oil and Gas			Products
(Millions of dollars)	Business			Business			Total			Business			Business			Total

Revenues	$	908		$	-		$	908		$	555		$	18		$	573

Income from Discontinued Operations:
Income (loss) from operations	$	500		$	-		$	500		$	212		$	(14	)	$	198
Gain (loss) on sale		306			(1	)		305			-			-			-
Adjustments for contingencies ⁽¹⁾		-			(16	)		(16	)		-			-			-
Pretax income (loss) from discontinued
operations		806			(17	)		789			212			(14	)		198
Income tax (expense) benefit		(280	)		6			(274	)		(91	)		5			(86	)
Income (loss) from discontinued operations,
net of tax	$	526		$	(11	)	$	515		$	121		$	(9	)	$	112

As discussed in Note 10, the company is required to use 100% of the net after-tax cash proceeds from sales of certain assets for debt repayment. Because the North Sea oil and gas assets are subject to this requirement, interest expense on debt that is required to be repaid upon their sale is classified as a component of income from discontinued operations. For the three and nine months ended September 30, 2005, pretax interest expense so classified totaled $49 million and $67 million, respectively. These amounts represent interest expense on approximately $3 billion of the company’s obligations under the term loans described in Note 10 expected to be repaid upon completing the North Sea divestiture transactions. Interest expense was allocated to discontinued operations beginning in May 2005, to coincide with initial borrowings under the term loans requiring mandatory prepayments.

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 approximately 242 million barrels of oil equivalent at December 31, 2004, and produced a daily average of 76 thousand barrels of oil equivalent during the first nine months of 2005, representing approximately 21% of the company’s production. The two-step transaction pursuant to the agreements includes:

The following summarizes assets and liabilities of the North Sea oil and gas business and their classification in the accompanying Condensed Consolidated Balance Sheet. Additionally, at September 30, 2005, a net after-tax loss of $171 million associated with cash flow hedges of the North Sea business was included in equity, as a component of accumulated other comprehensive loss. Upon the sale of Kerr-McGee (G.B.) Ltd., unrealized losses on these instruments, which will be assumed by the buyer, will be recognized in income from discontinued operations, as a component of gain on sale.

Forest Products Business - During 2002, the company approved a plan to exit its forest products business, which was part of the chemical - other operating unit. At that time, five plants were in operation. Four of these plants were closed and abandoned during 2003. The fifth plant, a leased facility, was operated throughout 2004 until the lease expired and the fixed assets at the facility were sold in January 2005. Criteria for classification of these assets as held for sale were met in the fourth quarter of 2004, at which time the results of the forest products operations met the requirements for reporting as discontinued operations. The carrying value of assets of discontinued forest products operations was $3 million at December 31, 2004, and is included in assets held for sale in the accompanying Condensed Consolidated Balance Sheet. Proceeds from the sale approximated the carrying value of the assets. As discussed in Note 16, the company retained obligations for environmental remediation and restoration at several wood-treating sites and other contingencies. Charges associated with such retained obligations have been incurred subsequent to the exit of the forest products business as a result of changes in estimates of remediation and restoration costs.

Assets Held for Sale - In addition to assets and liabilities of discontinued operations discussed above, assets held for sale at September 30, 2005 include the carrying value of certain U.S. onshore oil and gas properties, as well as the company’s nonoperating interest in the Javelina gas processing and fractionation facility. Based on the estimated fair value less cost to sell in relation to the carrying value, a loss of $6 million was recognized in the third quarter of 2005 for one U.S. onshore divestiture package. All other assets held for sale are expected to result in gains upon disposition.

In October 2005, the Board approved the separation of the chemical business through an IPO of shares of Class A common stock of the company’s wholly-owned subsidiary, Tronox Incorporated (Tronox). An amended registration statement was filed with the SEC relating to the proposed IPO, and is currently under review by the SEC. Assuming the review is completed and the registration statement is declared effective by the SEC, the company expects to complete the IPO in the fourth quarter of 2005. Following the IPO, the company will continue to hold a controlling interest in Tronox through ownership of Tronox’s Class B common stock. The company expects to distribute those shares to its stockholders during 2006 through a spinoff, splitoff or a combination of those transactions (Distribution). It is expected that Tronox will be included in the company’s consolidated financial statements through the Distribution date. The Distribution is subject to certain conditions, including receipt of a favorable tax opinion, necessary regulatory approvals and approval by the company’s Board of Directors of the final form, structure and other terms of any transaction to effect the Distribution.

Prior to the completion of the IPO, the company will transfer subsidiaries that conduct Kerr-McGee’s chemical business to Tronox. Some of these subsidiaries previously were engaged in the production of ammonium perchlorate, the manufacturing of thorium, 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. Additional discussion regarding environmental obligations is provided below.

Historically, employees of the company’s chemical business participated in stock-based compensation, pension and postretirement plans established by Kerr-McGee. It is expected that in connection with the IPO, Tronox will issue stock-based awards to certain of its employees and non-management directors, while unvested Kerr-McGee stock options and restricted stock held by employees of Tronox will be converted to Tronox stock-based awards on the effective date of the Distribution. Tronox is also 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. The anticipated effects of the separation on the company’s obligations for employee compensation and benefits are more fully discussed below.

It is expected that concurrent with the IPO, Tronox, through its wholly-owned subsidiary, will issue $350 million of unsecured notes in a private offering and will borrow $200 million in term loans. The net proceeds from these borrowings and from the offering of Tronox Class A common stock are expected to be $800 million to $900 million and will be distributed to Kerr-McGee. Any debt incurred by Tronox will affect the consolidated financial statements of Kerr-McGee until Tronox is no longer consolidated by the company.

Obligations for Environmental Remediation - Tronox and its subsidiaries will be subject to obligations for environmental remediation and restoration associated with the chemical business currently in operation, as well as with former operations described above. The carrying value of liabilities associated with such operations is $239 million as of September 30, 2005. Tronox and its subsidiaries also are expected to have contingent obligations of such current and former operations for which no liability is recognized as of September 30, 2005 because the loss is not considered probable or is not estimable. Discussion of the company’s material environmental obligations and other contingencies is provided in Note 16.

Upon completion of the IPO, Kerr-McGee is expected to agree to reimburse Tronox for a portion of the environmental costs incurred and paid by Tronox and its subsidiaries during the seven-year period following the IPO, to the extent such costs, net of any reimbursements received from insurers or other parties, exceed the carrying value of reserves at the time of the IPO. The reimbursement obligation extends to costs incurred 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. The company’s reimbursement obligation will be reflected in its Consolidated Balance Sheet at its estimated fair value at the time of origination. The estimated fair value will be determined considering expected cash outflows pursuant to the reimbursement obligation, their timing and probability of payment.

Pension and Postretirement Obligations - As discussed above, it is anticipated that Tronox will establish its own retirement and postretirement benefit plans for its current and former employees in the U.S. and assume the related benefit obligations. As of September 30, 2005, Kerr-McGee's Condensed Consolidated Balance Sheet included a prepaid pension cost associated with its U.S. qualified retirement plan of $239 million and a liability associated with the postretirement benefit plan of $231 million. It is estimated that upon completion of the Distribution, Kerr-McGee will transfer to Tronox approximately 40% of its pension benefit obligation as of that date. Kerr-McGee will also transfer trust assets to the newly established Tronox plan necessary to fund the transferred obligation in compliance with applicable regulatory requirements. It is also expected that approximately half of the benefit obligation associated with the U.S. postretirement plan, which is unfunded, will be transferred to Tronox following the Distribution. Actual values of the benefit obligation 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 benefit obligation and determination of asset values to be transferred.

Stock-Based Awards - It is expected that the terms of the employee benefits agreement between Kerr-McGee and Tronox will provide that Tronox employees will have the right to exercise their vested Kerr-McGee stock options in accordance with the original terms of the awards. All unvested Kerr-McGee stock options held by Tronox employees on the effective date of the Distribution will be converted into options to purchase Tronox Class A common stock. The converted options will have the same terms and conditions, including the same vesting provisions and exercise periods, as the unvested Kerr-McGee stock options immediately prior to their conversion. The number of shares and exercise price of each Kerr-McGee stock option will be adjusted so that each Tronox option will have the same ratio of the exercise price per share to the market value per share and the same aggregate difference between market value and exercise price as the Kerr-McGee options prior to conversion. All shares of Kerr-McGee restricted stock held by Tronox employees on the effective date of the Distribution will be converted into restricted shares of Tronox Class A common stock with the same terms and conditions, except that the number of shares covered by the awards will be adjusted as specified in the employee benefits agreement. Based on the number of Kerr-McGee stock options and restricted stock held at September 30, 2005 by the company’s employees that are or are expected to become employees of Tronox, the company estimates that approximately 84,000 restricted shares of Kerr-McGee common stock and approximately 167,000 stock options will be unvested as of the date of the Distribution and will be converted into Tronox awards as described above. 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.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Millions of dollars)	2005			2004			2005			2004

Net income	$	360		$	7		$	1,085		$	270
After-tax changes in:
Loss on cash flow hedges		(1,022	)		(159	)		(1,570	)		(344	)
Foreign currency translation adjustments		(14	)		7			(28	)		(3	)
Reclassification of foreign currency translation
losses		-			7			-			7
Reclassification of unrealized gain on
available-for-sale securities		-			-			-			(5	)
Comprehensive loss	$	(676	)	$	(138	)	$	(513	)	$	(75	)

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 gas production, forward contracts to buy and sell foreign currencies and interest rate swaps to hedge the fair value of its fixed-rate debt. Gains and losses on derivatives designated as cash flow hedges are deferred in accumulated other comprehensive income (loss) and reclassified into earnings when the hedged forecasted transactions affect earnings. Gains and losses associated with hedge ineffectiveness and with positions in excess of expected physical deliveries are recognized in current earnings as a component of revenues.

For the three- and nine-month periods ended September 30, 2005, as a result of significantly increased commodity prices and widening natural gas basis differentials, the company recognized losses on hedge ineffectiveness of $212 million and $256 million, respectively, 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.

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 for the fourth quarter of 2005 are expected to be insufficient to cover the associated derivative contracts in place. Consequently, the company recognized an unrealized loss of $103 million in the third quarter associated with certain fourth-quarter 2005 derivative contracts assigned to hedge cash flows from sales of Gulf of Mexico natural gas production, although total U.S. natural gas production in the fourth quarter is still expected to exceed volumes covered by hedge instruments. Additionally, realized losses of $22 million associated with September derivative contracts in excess of hedged physical deliveries for that month are reported as overhedge derivative loss in revenues. The company believes that it is probable that by January 2006 deliveries in the Gulf of Mexico will resume in sufficient volumes to match its remaining 2006 and 2007 derivative contracts.

At September 30, 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 production through 2007. The company expects to reclassify $1.1 billion 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. This excludes $171 million of net after-tax losses associated with derivatives of our North Sea oil and gas business which will be recognized in income from discontinued operations, as a component of gain on sale, in connection with the expected completion of the divestiture transactions in November 2005.

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. In June 2004, the company assumed a net liability associated with commodity derivatives in connection with the Westport merger. While the company designated Westport’s fixed-price oil and gas swaps as hedges after the merger, costless and three-way collars do 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 will recognize mark-to-market gains and losses in earnings until the collars mature, rather than deferring such amounts in accumulated other comprehensive income (loss). The net fair value of these derivatives at September 30, 2005 was a liability of $130 million.

	As of September 30, 2005
	Derivative Fair Value
	Current		Long-Term		Current			Long-Term			Deferred Gain
(Millions of dollars)	Asset		Asset		Liability			Liability			(Loss) in AOCI⁽¹⁾

Oil and gas commodity derivatives -
Kerr-McGee positions	$	154	$	36	$	(2,006	)	$	(959	)	$	(1,532	)
Acquired Westport positions		2		-		(184	)		(15	)		(29	)
Cash collateral		2		-		-			-			-
Gas marketing-related derivatives		23		1		(23	)		(1	)		-
Foreign currency forward contracts		1		-		-			-			1
Interest rate swaps		2		-		(6	)		(2	)		-
Other derivatives		5		-		-			-			4
Total - continuing operations		189		37		(2,219	)		(977	)		(1,556	)
North Sea oil and gas business		28		-		(184	)		(145	)		(171	)
Total derivative contracts	$	217	$	37	$	(2,403	)	$	(1,122	)	$	(1,727	)

	As of December 31, 2004
	Derivative Fair Value
	Current			Long-Term		Current			Long-Term			Deferred Gain
(Millions of dollars)	Asset			Asset		Liability			Liability			(Loss) in AOCI⁽¹⁾

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		6			2		(6	)		(2	)		-
Foreign currency forward contracts		(2	)		-		(6	)		-			(2	)
Interest rate swaps		4			-		(1	)		(2	)		-
Other derivatives		3			-		(1	)		-			1
Total - continuing operations		53			15		(350	)		(208	)		(182	)
North Sea oil and gas business		35			-		(22	)		-			25
Total derivative contracts	$	88		$	15	$	(372	)	$	(208	)	$	(157	)

	Three Months Ended								Three Months Ended
	September 30, 2005								September 30, 2004
				Costs and			Other Income					Costs and		Other Income
(Millions of dollars)	Revenues			Expenses			(Expense)		Revenues			Expenses		(Expense)
Hedge Activity:
Oil and gas commodity derivatives	$	(180	)	$	-		$	-	$	(132	)	$	-	$	-
Foreign currency contracts		1			-			-		-			2		-
Interest rate swaps		-			(2	)		-		-			4		-
Other derivatives		-			3			-		-			-		-
Gain (loss) on hedge ineffectiveness		(212	)		-			-		3			-		-
Total hedging contracts		(391	)		1			-		(129	)		6		-

Nonhedge Activity:
Oil and gas commodity derivatives -
Kerr-McGee positions		48			-			-		-			-		1
Acquired Westport positions		(77	)		-			-		(42	)		-		-
Overhedge derivative loss		(125	)		-			-		-			-		-
Gas marketing-related derivatives		1			-			-		1			-		-
DECS call option ⁽¹⁾		-			-			-		-			-		(29	)
Other derivatives		-			-			1		-			-		-
Total nonhedge contracts		(153	)		-			1		(41	)		-		(28	)

Total derivative contracts	$	(544	)	$	1		$	1	$	(170	)	$	6	$	(28	)

	Nine Months Ended								Nine Months Ended
	September 30, 2005								September 30, 2004
				Costs and			Other Income					Costs and		Other Income
(Millions of dollars)	Revenues			Expenses			(Expense)		Revenues			Expenses		(Expense)
Hedge Activity:
Oil and gas commodity derivatives	$	(265	)	$	-		$	-	$	(283	)	$	-	$	-
Foreign currency contracts		-			(4	)		-		-			7		-
Interest rate swaps		-			(2	)		-		-			13		-
Other derivatives		-			4			-		-			1		-
Gain (loss) on hedge ineffectiveness		(256	)		-			-		2			-		-
Total hedging contracts		(521	)		(2	)		-		(281	)		21		-

Nonhedge Activity:
Oil and gas commodity derivatives -
Kerr-McGee positions		62			-			-		(10	)		-		3
Acquired Westport positions		(130	)		-			-		(27	)		-		-
Overhedge derivative loss		(125	)		-			-		-			-		-
Gas marketing-related derivatives		5			-			-		5			-		(1	)
DECS call option ⁽¹⁾		-			-			-		-			-		(101	)
Other derivatives		-			-			2		-			-		(1	)
Total nonhedge contracts		(188	)		-			2		(32	)		-		(100	)

Total derivative contracts	$	(709	)	$	(2	)	$	2	$	(313	)	$	21	$	(100	)

Through April 2005, the company had an accounts receivable monetization program with a maximum availability of $165 million. Under the terms of the program, selected qualifying customer accounts receivable of the company’s chemical - pigment business 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. The company 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 Condensed 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 have subsequently been collected by the company.

Exchanges of Assets - In the first quarter of 2005, the company acquired a 37.5% interest in the Blind Faith discovery in the deepwater Gulf of Mexico from BP Exploration & Production in exchange for the company's interests in various proved oil and gas properties in the Arkoma Basin of southeast Oklahoma. In connection with this transaction, the company received $24 million in cash and recognized a $19 million gain on sale based on the percentage of the Arkoma properties' fair value that was received in cash.

Exploratory Drilling Costs - At September 30, 2005, the company had capitalized exploratory drilling costs of approximately $224 million associated with ongoing exploration and/or appraisal activities primarily in the deepwater Gulf of Mexico, Alaska, Brazil and China. Such capitalized costs may be charged against earnings in a future period if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur. Capitalized exploratory well costs have increased by $88 million from December 31, 2004 primarily due to additional exploration activities in the Gulf of Mexico ($49 million), Alaska ($44 million) and Brazil ($18 million) partially offset by successful exploration costs in China that were reclassified to proved oil and gas properties.

The American Jobs Creation Act of 2004 - On October 22, 2004, the President of the United States signed into law the American Jobs Creation Act of 2004 (the “Act”). 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. On April 11, 2005, management completed its analysis of the impact of the Act on the company's plans for repatriation. Based on this analysis, the company decided to repatriate up to $500 million in extraordinary dividends, as defined in the Act. During the second quarter of 2005, the company repatriated $200 million under the provisions of the Act and recognized income tax expense of $12 million. During the third quarter of 2005, an additional $21 million of foreign earnings were repatriated. However, the company reduced its provision for income taxes for repatriation of dividends under the provisions of the Act by $4 million, reflecting a change in the company’s expected utilization of foreign tax credits. The company may repatriate up to an additional $279 million in extraordinary dividends under the provisions of the Act. Pending completion of the divestiture of the company’s North Sea operations, management has not yet decided whether, and to what extent, additional amounts of foreign earnings will be repatriated, but will make this determination in the fourth quarter of 2005. Accordingly, the accompanying financial statements do not reflect any additional provision for taxes on unremitted foreign earnings that may be repatriated under the provisions of the Act. If the company decides to repatriate up to an additional $279 million as discussed above, additional income tax expense of up to $15 million may be recognized in the fourth quarter.

Income Tax, Continuing Operations - The effective tax rate for income from continuing operations for the three and nine months ended September 30, 2005 is 26% and 35%, respectively. Excluding the effect of the income tax provision for repatriation of foreign earnings under the Act discussed above and a $1 million tax benefit resulting from a change in estimated income tax obligations for 2004, the effective tax rate on income from continuing operations is 33% and 34% for the three and nine months ended September 30, 2005, respectively. The company expects that the effective tax rate for income from continuing operations for the full year 2005 will be approximately 35%.

Income Tax, Discontinued Operations - As discussed in Note 2, beginning with the third quarter of 2005, results of the company’s North Sea oil and gas business are reported as a discontinued operation. In connection with the divestiture of this business, management determined in June 2005 that the sale of the company’s investment in the stock of a foreign subsidiary was likely to occur, which resulted in recognizing a tax benefit of $27 million in the second quarter of 2005 related to the estimated difference between the book and tax bases of the company’s investment in the subsidiary. Investment in the stock of that subsidiary was sold on September 30, 2005, and the company revised its estimate of the related income tax benefit from $27 million to $24 million. Additionally, in connection with the third-quarter divestiture of the company’s interests in four nonoperated fields in the North Sea, the company recognized a provision for foreign income and withholding taxes of $29 million and a U.K. income tax benefit of $9 million. The combined tax effect of the September divestiture transactions was a benefit of $4 million for the first nine months of 2005, in relation to a pretax gain on sale of $306 million. The relationship between pretax gain on sale and the related tax effects is affected by the company’s utilization of capital loss carryforwards in the U.K. not previously benefited for income tax purposes and the difference between the book and tax bases of the company’s investment in the stock of a foreign subsidiary.

As discussed in Note 10, the company is required to use 100% of the net cash proceeds from sales of certain assets for debt repayment. Because the North Sea oil and gas assets are subject to this requirement and the related sales proceeds will be remitted to the United States for debt repayment, the company recognized $11 million and $57 million in the second and third quarters of 2005, respectively, of U.S. income tax expense on foreign earnings previously intended to have been indefinitely reinvested overseas (in addition to a previously established liability for U.S. income taxes on U.K. earnings of $59 million). The second-quarter income tax provision of $11 million reflected the company’s expected repatriation to the U.S. of foreign earnings associated with the company’s interests in nonoperated North Sea fields. During the third quarter, the sale of the entire North Sea oil and gas business became probable. Consequently, additional U.S. deferred tax provision of $57 million was recognized, primarily associated with an increase in foreign earnings expected to be remitted to the U.S. that are not sheltered by foreign tax credits. Any amounts remitted to the U.S. in connection with the divestiture of oil and gas properties in the U.K. will not be considered repatriated under the provisions of the Act as discussed above.

	September 30,			December 31,
(Millions of dollars)	2005			2004
Debentures -
5.25% Convertible subordinated debentures due February 15, 2010
(convertible at $61.08 per share)	$	-		$	600
7% Debentures due November 1, 2011, net of unamortized debt
discount of $72 and $77 (14.25% effective rate)		178			173
7.125% Debentures due October 15, 2027		150			150
Notes payable -
5.375% Notes due April 15, 2005 (includes a premium of $4 in 2004
for fair value hedge adjustment)		-			354
8.125% Notes due October 15, 2005 (includes a premium of $2 in 2005
and a discount of $1 in 2004 for fair value hedge adjustment)		111			108
5.875% Notes due September 15, 2006, net of unamortized debt discount
of $1 and a fair value hedge discount of $6 in 2005 (5.89% effective rate)		300			307
6.625% Notes due October 15, 2007, net of discount of $2
for fair value hedge adjustment in both 2005 and 2004		148			148
6.875% Notes due September 15, 2011, net of unamortized debt discount
of $2 and $1 (6.90% effective rate)		673			674
6.95% Notes due July 1, 2024, net of unamortized debt discount of $6
in 2005 and $5 in 2004 (7.02% effective rate)		644			645
7.875% Notes due September 15, 2031, net of unamortized debt
discount of $3 and $2 (7.91% effective rate)		497			498
Term Loans -
Variable rate Tranche X term loan due May 24, 2007 (1)		1,400			-
Variable rate Tranche B term loan due in installments through May 24, 2011 (1) (2)		2,244			-

Commercial paper		-			41
Guaranteed Debt of Employee Stock Ownership Plan 9.61% Notes
due in installments through January 2, 2005		-			1
		6,345			3,699
Long-term debt due within one year		(433	)		(463)

Total	$	5,912		$	3,236

As discussed in Note 15, 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 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 (Revolving Facility). In satisfaction of one of the closing conditions, the company repaid all outstanding indebtedness under the $1.5 billion revolving credit agreement previously in effect and terminated the agreement. No penalties were incurred in connection with the early termination.

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, plus a margin, as summarized below. Interest is paid at the end of an interest period selected by the company, but not less frequently than quarterly. The applicable margin may vary based on the company’s Consolidated Leverage Ratio, as defined in the Credit Agreement, and other specified events and conditions. The Consolidated Leverage Ratio determined pursuant to the terms of the Credit Agreement is based on the company's total funded debt and its earnings over a period of four consecutive quarters (before considering interest, taxes, depreciation, depletion and amortization, noncash exploration expense and other specified noncash items).

Guarantee and Collateral Provisions - The company’s obligations under the Credit Agreement are (a) unconditionally guaranteed, jointly and severally, by certain of the company’s domestic subsidiaries and (b) secured by a perfected first priority security interest, subject to existing liens and customary exceptions and to the rights of the company’s existing bondholders to be equally and ratably secured, in a substantial portion of the company’s tangible and intangible assets located in the United States (excluding assets relating to the company’s chemical business), and all of the capital stock of specified direct and indirect subsidiaries (limited, in the case of foreign subsidiaries, to 66% of the capital stock of the company’s first tier foreign subsidiaries).

As discussed in Note 1, the company decided to separate its chemical business. The company’s chemical business subsidiary, Tronox Worldwide LLC (formerly Kerr-McGee Chemical Worldwide LLC), is 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, provides 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.

Pursuant to the terms of the consent solicitation, the company paid an initial consent fee (execution fee) of $2.50 for each $1,000 principal to each consenting holder, for a total of approximately $5 million, which was recorded as a reduction in the carrying value of the associated debt securities and will increase interest expense over the remaining terms of the Notes. If an IPO, spinoff or splitoff occurs and Tronox Worldwide LLC is released from its guaranty of the Notes, the company will pay an additional consent fee to each consenting holder. This additional payment is estimated to be $13 million in the aggregate and will be accounted for in the same manner as the execution fee. In connection with the consent solicitation, the company incurred transaction costs of $4 million in the third quarter, which is included in loss on early repayment and modification of debt in the accompanying Condensed Consolidated Statement of Income.

Debt Covenants - The terms of the Credit Agreement provide for customary representations and warranties, affirmative and negative covenants, and events of default. Specifically, the Credit Agreement limits the company’s ability to incur or secure other debt, make investments, sell assets, pay dividends and repurchase stock. Additionally, the company’s ability to make capital expenditures (including dry hole costs) is limited by the provisions of the Credit Agreement to $2.35 billion in any given year. The company also is required to maintain compliance with the following financial covenants (in each case, as defined in the Credit Agreement):

(Millions of dollars)

Balance at December 31, 2004	$	524
New obligations incurred, including obligations acquired		15
Accretion expense		24
Changes in estimates, including timing		(6	)
Abandonment expenditures		(15	)
Abandonment obligations settled through property divestitures		(41	)
Balance at September 30, 2005		501
Less: asset retirement obligations associated with assets held for sale		(153	)
Less: current asset retirement obligation		(24	)
Noncurrent asset retirement obligation	$	324

Following are the changes in the reserve for exit and restructuring activities during the nine months ended September 30, 2005. Except as discussed below, no significant changes in the status of such activities occurred during this period. Condensed Consolidated Statement of Income for the three and nine months of 2004 includes a pretax charge of $123 million for costs associated with the shutdown of sulfate and gypsum production at the company’s Savannah, Georgia, facility and accelerated depreciation of other assets at that facility. Of the total charge, $86 million is reflected in depreciation and depletion expense, $30 million in costs and operating expenses and $7 million in asset impairments.

As discussed in Note 2, the company plans to separate its chemical business unit and divest selected oil and gas properties. In April 2005, in connection with the planned exit activities, the company initiated employee compensation programs designed to provide an incentive to certain employees to remain with the company over a stated period ranging from six to 18 months. The total cost of the retention programs is expected to be $34 million, assuming all participating employees meet the service and other conditions and before considering any awards that may be made in future periods upon successful disposition of certain assets, as discussed below. Of the total expected cost, $21 million is associated with the company’s exploration and production segment, $4 million with the chemical-pigment segment and $9 million with corporate activities. Through September 30, 2005, the company recognized $16 million as a component of selling, general and administrative expenses in connection with the retention programs. The remaining cost of $18 million will be recognized as the related services are provided by the participating employees. Under the plan covering employees of the chemical business unit, awards totaling $2 million are payable upon the earlier of the disposition of the chemical business or the end of a one-year service period. Additional payments may be due to certain employees upon successful disposition of the chemical business or divestiture of certain oil and gas assets.

In connection with the separation of Tronox, the company and its affiliates are evaluating organizational needs for both Kerr-McGee as a pure-play exploration and production company and Tronox as a separate publicly-traded chemical company. As part of this process, in October 2005, the company identified 75 employees that are expected to be involuntarily terminated 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 fourteen months. Assuming all employees meet the service and other conditions, the company's obligation for severance, outplacement assistance and other benefits will result in payments totaling $5 million by the end of 2006. Qualifying employees terminated under this program will also be eligible for enhanced benefits under the company's pension and postretirement plans.

Stock-Based Compensation - In January 2005, annual stock-based compensation awards were granted to eligible employees and directors under the company’s 2002 Long Term Incentive Plan. The awards included approximately 450,000 shares of restricted stock, 1.7 million stock options and 16.3 million performance units that provide for cash awards based on the company’s achievement of certain financial performance measures over a stated period. The fair value of the restricted stock grant on the grant date was $25 million, which will be recognized as compensation expense (net of forfeitures) ratably over a three-year vesting period or the service period, if shorter. The exercise price of the options granted of $56.57 per share equaled the fair value of the underlying stock on the date of grant, and therefore, did not result in any compensation expense. As of September 30, 2005, the company had 5.3 million stock options and 1.3 million shares of restricted stock outstanding.

In May 2005, the shareholders approved the 2005 Long Term Incentive Plan (2005 Plan), which authorizes the issuance of shares of the company’s common stock to certain employees and non-employee directors in the form of stock options, restricted stock or performance awards. The options may be accompanied by stock appreciation rights. A total of 10 million shares of the company’s common stock is authorized to be issued under the 2005 Plan any time prior to May 10, 2015, of which a maximum of 3 million shares of common stock is authorized for issuance in connection with awards of restricted stock and performance awards. Performance awards may be granted in the form of performance shares or performance units. Performance shares define a benefit to the grantee by reference to shares of stock, while performance units provide for cash awards based on the company’s achievement of certain financial performance measures over a stated period. As of September 30, 2005, no awards have been made under this plan.

							Postretirement
	Retirement Plans						Health and Life Plans
	Three Months Ended						Three Months Ended
	September 30,						September 30,
(Millions of dollars)	2005			2004			2005		2004
Net periodic cost -
Service cost	$	8		$	7		$	1	$	1
Interest cost		17			17			4		4
Expected return on plan assets		(25	)		(28	)		-		-
Net amortization -
Prior service cost		2			2			-		-
Net actuarial loss		1			1			-		-
Special termination benefits and
curtailment losses ⁽¹⁾		-			2			-		-
Total net periodic cost	$	3		$	1		$	5	$	5

							Postretirement
	Retirement Plans						Health and Life Plans
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
(Millions of dollars)	2005			2004			2005			2004
Net periodic cost -
Service cost	$	24		$	19		$	3		$	2
Interest cost		49			52			12			14
Expected return on plan assets		(74	)		(86	)					-
Net amortization -
Prior service cost		6			6			(2	)		1
Net actuarial loss		3			2			2			2
Special termination benefits and
curtailment losses ⁽¹⁾		-			2			-			-
Total net periodic cost (benefit)	$	8		$	(5	)	$	15		$	19

The following tables set forth the computation of basic and diluted earnings per share from continuing operations for the three and nine months ended September 30, 2005 and 2004. All options outstanding at September 30, 2005 were in-the-money, and therefore, the dilutive effect of such options is reflected in diluted earnings per share for the three and nine months ended September 30, 2005. As discussed in Note 10, during the first quarter of 2005, the company’s 5.25% convertible subordinated debentures were converted by the holders into approximately 9.8 million shares of common stock. The effect of convertible debentures was excluded from the determination of diluted earnings per share for the nine months ended September 30, 2004, because they were antidilutive. For the three months ended September 30, 2004, all potentially issuable shares were antidilutive due to loss from continuing operations for that period.

	Three Months Ended September 30,
			2005							2004
	Income from		Weighted-				Loss from			Weighted-
(In millions, except	Continuing		Average		Per-Share		Continuing			Average		Per-Share
per-share amounts)	Operations		Shares		Income		Operations			Shares		Loss

Basic earnings per share	$	54		114	$	.46	$	(24	)		150	$	(.16	)
Effect of dilutive securities:
Restricted stock		-		1				-			-
Stock options		-		1				-			-
Diluted earnings per share	$	54		116	$	.46	$	(24	)		150	$	(.16	)

	Nine Months Ended September 30,
			2005						2004
	Income from		Weighted-				Income from		Weighted-
(In millions, except	Continuing		Average		Per-Share		Continuing		Average		Per-Share
per-share amounts)	Operations		Shares		Income		Operations		Shares		Income

Basic earnings per share	$	570		137	$	4.18	$	158		118	$	1.34
Effect of dilutive securities:
5.25% convertible debentures		4		2				-		-
Restricted stock		-		1				-		-
Stock options		-		1				-		1
Diluted earnings per share	$	574		141	$	4.09	$	158		119	$	1.33

On April 18, 2005, the company commenced a modified "Dutch Auction" self 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 terms of the tender offer provided for the company to determine the lowest per-share price within the range that would enable it to buy up to $4 billion of its common stock based on the number of shares tendered and the prices specified by the tendering stockholders. Under the tender offer, which expired on May 18, 2005, approximately 138.9 million shares were properly tendered at a price of $85 per share and not withdrawn. Since the number of shares tendered exceeded 43.5 million, purchases of shares by the company were made based on a proration factor of 33.64%. In accordance with applicable securities laws, 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.

	Common			Treasury
(Thousands of shares)	Stock			Stock

Balance at December 31, 2003		100,892			32
Shares issued in Westport merger		48,949			-
Exercise of stock options		1,268			-
Issuance of restricted stock		483			-
Forfeiture of restricted stock		-			118
Balance at September 30, 2004		151,592			150

Balance at December 31, 2004		152,049			160
Exercise of stock options		3,762			-
Issuance of restricted stock		450			-
Forfeiture of restricted stock		-			67
Shares issued upon conversion of 5.25% debentures		9,818			-
Purchases of treasury shares		-			3,145
Shares repurchased and retired		(46,728	)		-
Balance at September 30, 2005		119,351			3,372

unanticipated construction problems and weather conditions can hinder the completion of environmental remediation; the inability to implement a planned engineering design or use planned technologies and excavation methods may require revisions to the design of remediation measures, resulting in delayed remediation and increased costs; and 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.

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 Tronox LLC. 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 requires 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.

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 indicate that Tronox LLC may need to operate the system through 2011. The scope, duration and cost of groundwater remediation ultimately 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. The Environmental Protection Agency (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 September 30, 2005, reserves for environmental remediation at Henderson totaled $38 million. This amount includes $2 million added to the reserve during the third quarter because of increased costs for removing and treating ammonium perchlorate solids contained in a lined pond and purchasing additional equipment to perform clean-up. 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 is 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. The discovery stage of litigation is complete, and the parties are engaged in settlement negotiations. Although the outcome of the litigation is uncertain, the company believes it is likely to recover a portion of its costs from the government. The amount and timing of any recovery cannot be estimated at this time and, accordingly, the company has not recorded a receivable or otherwise reflected in the financial statements any potential recovery from the government.

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 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.

Closed Facility - Pursuant to agreements reached in 1994 and 1997 among Tronox LLC, the City of West Chicago 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 10 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 is expected to take about four to five years to complete, will require excavation of contaminated soils and stream sediments, shipment of excavated materials to a licensed disposal facility and restoration of affected areas.

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 inflation adjustments. That amount is expected to cover the government’s full share of West Chicago cleanup costs. Through September 30, 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 Tronox LLC’s cleanup expenditures. As of September 30, 2005, the government’s share of costs incurred by Tronox LLC but not yet reimbursed by the DOE totaled approximately $21 million. The company believes receipt of the $21 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.

From the late 1950s until 1988, an affiliate of Tronox Worldwide LLC (formerly Kerr-McGee Chemical Worldwide LLC), an affiliate of the company, 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 to an unaffiliated third party in 1989, 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 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 the current owner, 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 the current owner 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 non-radiological 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, the current owner is investigating soil contamination potentially caused by past discharge of mine water from the site, for which no reserve has been established.

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 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.

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 its ultimate parent 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 demand is for payment of past costs in the amount of approximately $179 million, plus 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, it appears there may be other PRPs, though it is not known whether the other PRPs have received similar letters from EPA, whether there are any defenses to liability available to the other PRPs or whether any other PRPs have the financial resources necessary to meet their obligations. Tronox LLC intends to vigorously defend against EPA’s demand. No reserve for reimbursement of cleanup costs at the site has been recorded, as it is not possible to reliably estimate the liability, if any, Tronox LLC may have for the site because of the aforementioned defenses and uncertainties.

In 1972, Kerr-McGee Refining Corporation (“KM Refining”), an affiliate of the company, closed a petroleum refinery it had operated near Cushing, Oklahoma. Prior to closing the refinery, KM Refining also had produced uranium and thorium fuel and metal at the site pursuant to licenses issued by the AEC. The uranium and thorium operations commenced in 1962 and were shut down in 1966, at which time KM Refining decommissioned and cleaned up to applicable standards the portion of the facility related to uranium and thorium operations. The refinery also was cleaned up to applicable standards at the time of closing.

Subsequent regulatory changes have required more extensive remediation at the site. In 1990, KM Refining 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 (ODEQ). Soil remediation to address hydrocarbon contamination 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.

In addition to the sites described above, the company and 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 September 30, 2005, the company and its affiliates had reserves of $88 million for the environmental costs in connection with these other sites. This amount includes $23 million added to reserves in the third quarter 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.

A predecessor of Tronox Worldwide LLC, an affiliate of the company, entered into a coal supply contract with Peabody Coaltrade, Inc. (‘‘PCI’’) in February 1998. In 1998, the predecessor exited the coal business and assigned its rights and obligations under the coal supply contract to a third party. In connection with the assignment, the predecessor agreed to guarantee performance under the contract. PCI has notified Tronox Worldwide LLC of a threatened default by the assignee under the coal supply contract and that PCI may seek to hold Tronox Worldwide LLC liable under the 1998 guaranty in the event of a default. In addition to other defenses to the enforceability of the guaranty, the company believes the guaranty expired in January 2003 when the primary term of the coal supply contract expired. No reserve has been provided for performance under the guaranty because the company does not believe a loss is probable and the amount of any loss is not reasonably estimable.

In 2002, Kerr-McGee North Sea (U.K.) Limited, an affiliate of the company (“KM North Sea”), entered into a contract with CNR International (“CNR”) to sell certain assets located in the United Kingdom sector of the North Sea. In the fourth quarter of 2004, CNR asserted claims for alleged breaches of contractual representations and warranties and demanded damages. The company’s evaluation of the claims is in its early stages. The company has not provided a reserve for the claims because at this time the company cannot reasonably determine the probability of a loss and the amount of loss, if any, cannot be reasonably estimated. The company does not expect the resolution of the claims to have a material adverse effect on the company.

Between 1999 and 2001, Tronox LLC was named in 22 lawsuits in three states (Mississippi, Louisiana and Pennsylvania) in connection with former forest products operations located in those states (in Columbus, Mississippi; Bossier City, Louisiana; and Avoca, Pennsylvania). The lawsuits sought recovery under a variety of common law and statutory legal theories for personal injuries and property damages allegedly caused by exposure to and/or release of creosote and other substances used in the wood-treatment process. Tronox LLC has executed settlement agreements that are expected to resolve substantially all of the Louisiana, Pennsylvania and Mississippi lawsuits described above. Resolution of the remaining cases is not expected to have a material adverse effect on the company.

Following the adoption by the Mississippi legislature of tort reform, plaintiffs’ lawyers filed many new lawsuits across the state of Mississippi in advance of the reform’s effective date. On December 31, 2002, August 31, 2004, September 27, 2004 and May 2, 2005, approximately 250 lawsuits were filed against Tronox LLC on behalf of approximately 5,100 claimants in connection with Tronox LLC’s Columbus, Mississippi, operations, seeking recovery on legal theories substantially similar to those advanced in the litigation referred to above. Substantially all of these lawsuits were filed in or have been removed to the U.S. District Court for the Northern District of Mississippi, and the court has consolidated these lawsuits for pretrial and discovery purposes. On December 31, 2002, June 13, 2003, and June 25, 2004, three lawsuits were filed against Tronox LLC in connection with a former wood-treatment plant located in Hattiesburg, Mississippi. On September 9, 2004, February 11, 2005, and March 2, 2005, three lawsuits were filed against Tronox LLC in connection with a former wood-treatment plant located in Texarkana, Texas. In addition, on January 3, 2005, February 16, 2005, March 11, 2005, May 24, 2005, June 27, 2005 and July 26, 2005, 35 lawsuits were filed against Tronox LLC and Tronox Worldwide LLC in connection with the Avoca, Pennsylvania, facility described above. These lawsuits seek recovery on legal theories substantially similar to those advanced in the litigation referred to above. A total of approximately 3,300 claimants now have asserted claims in connection with the Hattiesburg plant, there are 64 plaintiffs named in the Texarkana lawsuits and approximately 4,600 plaintiffs are named in the new Avoca lawsuits. Tronox LLC has resolved approximately 1,490 of the Hattiesburg claims pursuant to a settlement reached in April 2003, which has resulted in aggregate payments by Tronox LLC of approximately $600,000.

Tronox LLC believes that the follow-on Columbus and Avoca claims, the remaining Hattiesburg claims and the claims related to the Texarkana plants are without substantial merit and it is vigorously defending against them. There is not a reserve for these lawsuits because at this time, it is not possible to reasonably determine the probability of a loss, and the amount of loss, if any, cannot be reasonably estimated. The company believes that the ultimate resolution of the forest products litigation will not have a material adverse effect on the company.

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, Tronox LLC discovered that certain matters associated with environmental conditions and plant infrastructure were not consistent with representations made by the Sellers. Tronox LLC sought recovery for breach of representations and warranties in a proceeding before the London Court of International Arbitration (LCIA). On May 9, 2005, Tronox LLC received notice from the LCIA that the LCIA had found in favor of Tronox LLC as to liability with respect to certain of the claims. The LCIA still must determine the amount of damages. 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.

The company and its affiliates are parties to a number of legal and administrative proceedings involving environmental and/or other matters pending in various courts or agencies. These proceedings, individually and in the aggregate, are not expected to have a material adverse effect on the company. These also are proceedings 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. Current and former operations of the company also involve 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 EPA pursuant to CERCLA or state equivalents. Similar environmental laws and regulations and other requirements exist in foreign countries in which the company operates.

In 2005, the company entered into additional drilling rig commitments to assure availability for executing our drilling program. The company’s commitments under these arrangements total $601 million, $52 million of which relates to rig utilization in 2005, $441 million in 2006-2007, $38 million in 2008-2009 and $70 million thereafter. A portion of expenditures under these commitments will be billed to other working interest partners once actual utilization is known. The company has also entered into additional international exploration licenses, which carry work commitments of approximately $31 million and expects to incur $16 million of associated expenditures in 2005 and a total of $15 million in 2006 and 2007.

Segment performance is evaluated using operating profit (loss), which represents the results of segment operations before considering interest and debt expense, loss on early repayment and modification of debt, general corporate expenses, environmental provisions related to businesses in which the company’s affiliates are no longer engaged, other income (expense) and income taxes. Following is a summary of revenues and operating profit (loss) from continuing operations for each of the company's business segments for the three and nine months ended September 30, 2005 and 2004.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Millions of dollars)	2005			2004			2005			2004

Revenues
Exploration and production ⁽¹⁾	$	881		$	864		$	3,135		$	2,066
Chemical - Pigment		302			315			944			870
Chemical - Other		25			24			73			70
Total Revenues	$	1,208		$	1,203		$	4,152		$	3,006

Operating Profit (Loss)
Exploration and production ⁽¹⁾	$	185		$	267		$	1,166		$	707
Chemical - Pigment ⁽²⁾		16			(110	)		80			(89	)
Chemical - Other		1			1			(6	)		(2	)
		202			158			1,240			616

Interest and debt expense		(68	)		(68	)		(190	)		(180	)
Loss on early repayment and modification of debt		(9	)		-			(9	)		-
Corporate expenses		(45	)		(31	)		(135	)		(88	)
Provision for environmental remediation and
restoration, net of reimbursements ⁽³⁾		(4	)		(71	)		(19	)		(74	)
Other income (expense) ⁽⁴⁾		(3	)		(20	)		(16	)		(27	)

Income from Continuing Operations
before Income Taxes	$	73		$	(32	)	$	871		$	247

⁽⁴⁾

The company owns a 50% interest in Avestor, a joint venture involved in the production of lithium-metal-polymer batteries, and accounts for its investment under the equity method. The company’s equity in the net losses of Avestor was $13 million and $10 million during the three months ended September 30, 2005 and 2004, respectively, and $28 million and $29 million during the nine months ended September 30, 2005 and 2004, respectively. The carrying value of the company’s investment in Avestor at September 30, 2005 and December 31, 2004 was $71 million and $60 million, respectively.

	Kerr-McGee			Guarantor			Non-Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated

Revenues	$	-		$	351		$	857		$	-		$	1,208

Costs and Expenses
Costs and operating expenses		-			200			354			-			554
Selling, general and administrative expenses		-			3			101			-			104
Shipping and handling expenses		-			4			30			-			34
Depreciation and depletion		-			30			203			-			233
Accretion expense		-			1			5			-			6
Loss on sale of assets		-			-			4			-			4
Exploration, including dry holes and amortization
of undeveloped leases		-			1			60			-			61
Taxes, other than income taxes		-			9			43			-			52
Provision for environmental remediation
and restoration, net of reimbursements		-			4			3			-			7
Interest and debt expense		61			-			122			(115	)		68
Loss on early repayment and modification of debt		9			-			-			-			9
Total Costs and Expenses		70			252			925			(115	)		1,132

		(70	)		99			(68	)		115			76
Other Income (Expense)		444			(89	)		91			(449	)		(3	)
Income from Continuing Operations
before Income Taxes		374			10			23			(334	)		73
Benefit (Provision) for Income Taxes		41			(39	)		(21	)		-			(19	)
Income (Loss) from Continuing Operations		415			(29	)		2			(334	)		54
Income (Loss) from Discontinued Operations,
net of taxes		(32	)		(7	)		345			-			306
Net Income (Loss)	$	383		$	(36	)	$	347		$	(334	)	$	360

	Kerr-McGee			Guarantor			Non-Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated

Revenues	$	-		$	235		$	968		$	-		$	1,203

Costs and Expenses
Costs and operating expenses		-			123			365			-			488
Selling, general and administrative expenses		-			5			76			-			81
Shipping and handling expenses		-			2			33			-			35
Depreciation and depletion		-			30			290			-			320
Accretion expense		-			1			4			-			5
Asset impairments		-			-			7			-			7
Exploration, including dry holes and
amortization of undeveloped leases		-			1			94			-			95
Taxes, other than income taxes		-			10			34			-			44
Provision for environmental remediation
and restoration, net of reimbursements		-			48			24			-			72
Interest and debt expense		41			8			82			(63	)		68
Total Costs and Expenses		41			228			1,009			(63	)		1,215

		(41	)		7			(41	)		63			(12	)
Other Income (Expense)		64			(136	)		21			31			(20	)
Income (Loss) from Continuing Operations
before Income Taxes		23			(129	)		(20	)		94			(32	)
Benefit (Provision) for Income Taxes		(16	)		62			(22	)		(16	)		8
Income (Loss) from Continuing Operations		7			(67	)		(42	)		78			(24	)
Income from Discontinued Operations,
net of taxes		-			(2	)		33			-			31
Net Income (Loss)	$	7		$	(69	)	$	(9	)	$	78		$	7

	Kerr-McGee			Guarantor			Non-Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated

Revenues	$	-		$	905		$	3,247		$	-		$	4,152

Costs and Expenses
Costs and operating expenses		-			524			1,021			(1	)		1,544
Selling, general and administrative expenses		-			3			299			-			302
Shipping and handling expenses		-			10			99			-			109
Depreciation and depletion		-			88			641			-			729
Accretion expense		-			2			15			-			17
Asset impairments		-			-			5			-			5
Gain on sale of assets		-			-			(42	)		-			(42	)
Exploration, including dry holes and amortization
of undeveloped leases		-			5			223			-			228
Taxes, other than income taxes		-			25			116			-			141
Provision for environmental remediation
and restoration, net of reimbursements		-			20			13			-			33
Interest and debt expense		157			9			317			(293	)		190
Loss on early repayment and modification of debt		9			-			-			-			9
Total Costs and Expenses		166			686			2,707			(294	)		3,265

		(166	)		219			540			294			887
Other Income (Expense)		1,258			41			306			(1,621	)		(16	)
Income from Continuing Operations
before Income Taxes		1,092			260			846			(1,327	)		871
Benefit (Provision) for Income Taxes		60			(81	)		(280	)		-			(301	)
Income from Continuing Operations		1,152			179			566			(1,327	)		570
Income (Loss) from Discontinued Operations,
net of taxes		(44	)		(7	)		566			-			515
Net Income	$	1,108		$	172		$	1,132		$	(1,327	)	$	1,085

	Kerr-McGee			Guarantor			Non-Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated

Revenues	$	-		$	662		$	2,344		$	-		$	3,006

Costs and Expenses
Costs and operating expenses		-			342			897			(1	)		1,238
Selling, general and administrative expenses		1			5			225			-			231
Shipping and handling expenses		-			6			84			-			90
Depreciation and depletion		-			90			493			-			583
Accretion expense		-			2			11			-			13
Asset impairments		-			1			21			-			22
Loss on sale of assets		-			-			7			-			7
Exploration, including dry holes and
amortization of undeveloped leases		-			8			187			-			195
Taxes, other than income taxes		-			27			71			-			98
Provision for environmental remediation
and restoration, net of reimbursements		-			51			24			-			75
Interest and debt expense		95			27			220			(162	)		180
Total Costs and Expenses		96			559			2,240			(163	)		2,732

		(96	)		103			104			163			274
Other Income (Expense)		541			(127	)		71			(512	)		(27	)
Income (Loss) from Continuing Operations
before Income Taxes		445			(24	)		175			(349	)		247
Benefit (Provision) for Income Taxes		(175	)		24			(90	)		152			(89	)
Income (Loss) from Continuing Operations		270			-			85			(197	)		158
Income from Discontinued Operations,
net of taxes		-			(4	)		116			-			112
Net Income (Loss)	$	270		$	(4	)	$	201		$	(197	)	$	270

	Kerr-McGee		Guarantor		Non-Guarantor
(Millions of dollars)	Corporation		Subsidiaries		Subsidiaries		Eliminations			Consolidated

ASSETS
Current Assets
Cash and cash equivalents	$	3	$	-	$	659	$	-		$	662
Accounts receivable		-		264		716		-			980
Inventories		-		3		336		-			339
Derivatives and other current assets		-		24		250		-			274
Deferred income taxes		-		24		690		-			714
Assets held for sale		-		-		295		-			295
Total Current Assets		3		315		2,946		-			3,264

Property, Plant and Equipment - Net		-		1,922		7,210		-			9,132
Investment in Subsidiaries		5,906		597		-		(6,503	)		-
Investments, Derivatives and Other Assets		60		23		535		(80	)		538
Goodwill and Other Intangible Assets		-		349		928		-			1,277
Assets Held for Sale		-		-		1,846		-			1,846
Total Assets	$	5,969	$	3,206	$	13,465	$	(6,583	)	$	16,057

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Intercompany borrowings	$	60		$	519	$	1,197	$	(1,776	)	$	-
Accounts payable		6			55		562		-			623
Long-term debt due within one year		323			-		110		-			433
Derivative liabilities		6			23		2,190		-			2,219
Accrued liabilities		(79	)		242		736		-			899
Liabilities associated with assets held for sale		-			-		491		-			491
Total Current Liabilities		316			839		5,286		(1,776	)		4,665

Long-Term Debt		5,436			-		476		-			5,912
Noncurrent Liabilities
Deferred income taxes		(19	)		504		1,067		-			1,552
Derivative liabilities		-			1		976		-			977
Other noncurrent liabilities		-			189		732		(2	)		919
Liabilities associated with assets held for sale		-			-		689		-			689
Total Noncurrent Liabilities		(19	)		694		3,464		(2	)		4,137

Stockholders' Equity		236			1,673		4,239		(4,805	)		1,343

Total Liabilities and Stockholders' Equity	$	5,969		$	3,206	$	13,465	$	(6,583	)	$	16,057

	Kerr-McGee		Guarantor		Non-Guarantor
(Millions of dollars)	Corporation		Subsidiaries		Subsidiaries		Eliminations			Consolidated

ASSETS
Current Assets
Cash and cash equivalents	$	2	$	-	$	74	$	-		$	76
Intercompany receivables		-		-		58		(58	)		-
Accounts receivable		-		206		619		-			825
Inventories		-		5		309		-			314
Derivatives and other current assets		4		24		123		-			151
Deferred income taxes		2		13		312		-			327
Assets held for sale		-		-		194		-			194
Total Current Assets		8		248		1,689		(58	)		1,887

Property, Plant and Equipment - Net		-		1,947		7,126		-			9,073
Investment in Subsidiaries		6,306		645		-		(6,951	)		-
Investments, Derivatives and Other Assets		17		24		523		(80	)		484
Goodwill and Other Intangible Assets		-		351		937		-			1,288
Assets Held for Sale		-		-		1,786		-			1,786

Total Assets	$	6,331	$	3,215	$	12,061	$	(7,089	)	$	14,518

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Intercompany borrowings	$	68		$	598	$	1,189	$	(1,855	)	$	-
Accounts payable		68			55		484		-			607
Long-term debt due within one year		354			-		109		-			463
Derivative liabilities		6			71		273		-			350
Accrued liabilities		10			203		680		-			893
Liabilities associated with assets held for sale		-			-		192		-			192
Total Current Liabilities		506			927		2,927		(1,855	)		2,505

Long-Term Debt		2,125			-		1,111		-			3,236

Noncurrent Liabilities
Deferred income taxes		(2	)		545		1,184		-			1,727
Derivative liabilities		-			59		149		-			208
Other noncurrent liabilities		-			224		686		(3	)		907
Liabilities associated with assets held for sale		-			-		617		-			617
Total Noncurrent Liabilities		(2	)		828		2,636		(3	)		3,459

Stockholders' Equity		3,702			1,460		5,387		(5,231	)		5,318

Total Liabilities and Stockholders' Equity	$	6,331		$	3,215	$	12,061	$	(7,089	)	$	14,518

							Non-
	Kerr-McGee			Guarantor			Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated

Cash Flows from Operating Activities
Net income	$	1,108		$	172		$	1,132		$	(1,327	)	$	1,085
Adjustments to reconcile net income to net cash
provided by (used in) operating activities-
Depreciation, depletion and amortization		-			89			819			-			908
Deferred income taxes		(17	)		35			161			-			179
Dry hole expense		-			-			125			-			125
Asset impairments		-			-			5			-			5
Gain on sale of North Sea oil and gas assets		-			-			(306	)		-			(306	)
Gain on sale of other assets		-			-			(42	)		-			(42	)
Loss on early repayment and modification of debt		9			-			-			-			9
Accretion expense		-			2			22			-			24
Provision for environmental remediation
and restoration, net of reimbursements		-			31			13			-			44
Equity in earnings of subsidiaries		(1,197	)		(39	)		-			1,236			-
Other noncash items affecting net income		(11	)		46			369			93			497
Changes in assets and liabilities		(79	)		(77	)		131			(2	)		(27	)
Net Cash Provided by (Used in)
Operating Activities		(187	)		259			2,429			-			2,501

Cash Flows from Investing Activities
Capital expenditures		-			(93	)		(1,199	)		-			(1,292	)
Dry hole costs		-			-			(118	)		-			(118	)
Proceeds from sale of North Sea oil and gas assets		-			-			547			-			547
Proceeds from sale of other assets		-			-			68			-			68
Accounts receivable purchase and collection		(165	)		-			165			-			-
Other investing activities		-			-			(7	)		-			(7	)
Net Cash Used in Investing Activities		(165	)		(93	)		(544	)		-			(802	)

Cash Flows from Financing Activities
Issuance of common stock		206			-			-			-			206
Purchases of treasury stock		(250	)		-			-			-			(250	)
Shares repurchased under the tender offer		(3,975	)		-			-			-			(3,975	)
Dividends paid		(148	)		-			-			-			(148	)
Repayment of debt		(956	)		-			(42	)		-			(998	)
Proceeds from borrowings		4,250			-			-			-			4,250
Costs of obtaining financing		(58	)		-			-			-			(58	)
Cash paid for modification of debt		(9	)		-			-			-			(9	)
Increase (decrease) in intercompany
notes payable		1,293			(166	)		(1,127	)		-			-
Settlement of Westport derivatives		-			-			(134	)		-			(134	)
Net Cash Provided by (Used in)
Financing Activities		353			(166	)		(1,303	)		-			(1,116	)

Effects of Exchange Rate Changes on Cash
and Cash Equivalents		-			-			3			-			3
Net Increase in Cash and Cash Equivalents		1			-			585			-			586
Cash and Cash Equivalents at Beginning of Period		2			-			74			-			76
Cash and Cash Equivalents at End of Period	$	3		$	-		$	659		$	-		$	662

							Non-
	Kerr-McGee			Guarantor			Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated

Cash Flows from Operating Activities
Net income (loss)	$	270		$	(4	)	$	201		$	(197	)	$	270
Adjustments to reconcile net income (loss) to net
cash provided by (used in) operating activities -
Depreciation, depletion and amortization		-			95			690			-			785
Deferred income taxes		37			(9	)		58			-			86
Dry hole expense		-			-			80			-			80
Asset impairments		-			1			21			-			22
Loss on sale of assets		-			-			7			-			7
Accretion expense		-			2			20			-			22
Provision for environmental remediation
and restoration, net of reimbursements		-			57			24			-			81
Equity in losses (earnings) of subsidiaries		(292	)		94			-			198			-
Other noncash items affecting net income		1			29			135			-			165
Changes in assets and liabilities		(86	)		(8	)		(96	)		(1	)		(191	)
Net Cash Provided by (Used in)
Operating Activities		(70	)		257			1,140			-			1,327

Cash Flows from Investing Activities
Capital expenditures		-			(83	)		(749	)		-			(832	)
Dry hole costs		-			-			(46	)		-			(46	)
Acquisitions, net of cash acquired		-			-			43			-			43
Proceeds from sale of assets		-			7			4			-			11
Proceeds from sale of investments		-			-			39			-			39
Other investing activities		-			-			(31	)		-			(31	)
Net Cash Used in Investing Activities		-			(76	)		(740	)		-			(816	)


Cash Flows from Financing Activities
Issuance of common stock		34			-			-			-			34
Dividends paid		(137	)		-			-			-			(137	)
Repayment of debt		-			-			(1,278	)		-			(1,278	)
Proceeds from borrowings		745			-			161			-			906
Costs of obtaining financing		(6	)		-			-			-			(6	)
Settlement of Westport derivatives		-			-			(45	)		-			(45	)
Increase (decrease) in intercompany
notes payable		(567	)		(181	)		748			-			-
Net Cash Provided by (Used in)
Financing Activities		69			(181	)		(414	)		-			(526	)

Effects of Exchange Rate Changes on Cash
and Cash Equivalents		-			-			1			-			1
Net Decrease in Cash and Cash Equivalents		(1	)		-			(13	)		-			(14	)
Cash and Cash Equivalents at Beginning of Period		2			-			140			-			142
Cash and Cash Equivalents at End of Period	$	1		$	-		$	127		$	-		$	128

Kerr-McGee Corporation is one of the largest U.S.-based independent oil and gas exploration and production companies in terms of production volumes and the world's third-largest producer and marketer of titanium dioxide pigment based on reported industry capacity by the leading titanium dioxide producers. Kerr-McGee has three reportable business segments, oil and gas exploration and production, production and marketing of titanium dioxide pigment (chemical - pigment), and production and marketing of other chemical products (chemical - other). The terms “Kerr-McGee,”“the company,”“we,”“our,” and similar terms are used interchangeably in this Form 10-Q to refer to the consolidated group or to one or more of the companies that are part of the consolidated group.

In 2005, we 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 our stockholders. Our strategic plan includes the separation of the chemical business and divestitures of certain lower-growth or shorter-life and higher-decline oil and gas assets, including our North Sea oil and gas business and selected properties in the U.S. We expect to realize aggregate net cash proceeds from asset divestitures, including the separation of the chemical business, of approximately $4.4 billion by the end of 2005 and plan to use the proceeds for debt reduction and other corporate purposes. At the same time, we are accelerating our U.S. onshore development activities, with a focus on the Wattenberg and Greater Natural Buttes areas. Management believes this strategy will result in an asset 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, Alaska, Brazil, China, Trinidad and other areas will continue to provide growth opportunities.

Separation of the Chemical Business - 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 company completed its evaluation and the Board approved the separation of the chemical business through an initial public offering (IPO) of shares of Class A common stock of the company’s wholly-owned subsidiary, Tronox Incorporated (Tronox). The IPO is planned for the fourth quarter of 2005. Following the IPO, Kerr-McGee will have at least 50.1% equity interest in Tronox and at least 80% of Tronox’s total voting power. The separation of the chemical business is expected to result in net proceeds of $800 million to $900 million. The company expects to distribute the remaining ownership interest in Tronox to Kerr-McGee stockholders through a spinoff, splitoff or a combination of those transactions during 2006. Additional information regarding the separation is provided under Pending Separation of Tronox Incorporated below.

Repurchases of Common Stock and Related Financing - Concurrent with the decision to pursue the separation of the chemical business, 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 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 modified "Dutch Auction" self 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, which represented 29% of shares outstanding at March 31, 2005. The tender offer was financed with the net proceeds of borrowings and cash on hand. Effects of the tender offer on our results of operations and financial condition are discussed under Results of Consolidated Operations and Financial Condition and Liquidity below.

As a result of our decision to consummate the tender offer and the related increase in the company’s leverage, the company’s credit rating was lowered and is no longer investment grade. We plan to repay debt associated with the tender offer in the fourth quarter using proceeds from the planned divestitures discussed above and cash flow, which has been underpinned by an expanded oil and gas hedging program. As of November 8, 2005, we have prepaid $750 million of debt incurred in connection with the tender offer using proceeds from asset sales and cash on hand. Refer to Financial Condition and Liquidity - Repurchases of Common Stock and Related Financing - Tranche X and Tranche B Term Loans for additional information on such prepayments.

Expanded Hedging Program - To increase the predictability of cash flows, we expanded our hedging program in April 2005 and, as of September 30, 2005, had costless collars and fixed-priced swaps covering at least 75% of the company’s 2005 and 2006 expected eligible production (after the possible divestitures) and approximately 50% of its 2007 expected eligible production. Eligible production excludes oil production in China. Additional information regarding our commodity price risk management activities is included in Item 3, Quantitative and Qualitative Disclosures about Market Risk.

	Three Months Ended						Nine Months ended
	September 30,						September 30,
(Millions of dollars)	2005			2004			2005			2004

Revenues(2)	$	1,208		$	1,203		$	4,152		$	3,006

Segment operating profit (loss) (1)
Exploration and production (2)	$	185		$	267		$	1,166		$	707

Chemical -
Pigment (3)		16			(110	)		80			(89	)
Other		1			1			(6	)		(2	)
Total Chemical		17			(109	)		74			(91	)

Total segment operating profit		202			158			1,240			616

Interest and debt expense		(68	)		(68	)		(190	)		(180	)
Loss on early repayment and modification of debt		(9	)		-			(9	)		-
Corporate expenses		(45	)		(31	)		(135	)		(88	)
Environmental provisions, net of reimbursements		(4	)		(71	)		(19	)		(74	)
		76			(12	)		887			274

Other income (expense)		(3	)		(20	)		(16	)		(27	)
Benefit (provision) for income taxes		(19	)		8			(301	)		(89	)

Income (loss) from continuing operations		54			(24	)		570			158
Income from discontinued operations, net of taxes		306			31			515			112
Net Income	$	360		$	7		$	1,085		$	270

Net Income per Common Share:
Basic	$	3.14		$	0.05		$	7.95		$	2.29
Diluted		3.09			0.05			7.75			2.27

⁽²⁾

Revenues and operating profit of the exploration and production segment for the three and nine months ended September 30, 2005 include $315 million and $359 million, respectively, of unrealized losses on hedge ineffectiveness and overhedge positions. Revenues and operating profit for the three and nine months ended September 30, 2004 include unrealized gains on hedge ineffectiveness of $3 million and $2 million, respectively. Refer to Results of Operations by Segment - Exploration and Production - Revenues.

General - Income from continuing operations for the third quarter of 2005 was $54 million, compared with a loss of $24 million in the same 2004 period. The increase is primarily due to $126 million better operating results of the chemical business unit and a decrease in environmental provisions, net of reimbursements, of $67 million, partially offset by $82 million lower operating profit of our exploration and production segment and an increase in income tax expense of $27 million. Lower operating profit of the exploration and production segment in 2005 reflects higher lifting costs, partially offset by lower exploration expense, and a decline in revenues (excluding gas marketing revenues) due to the net effect of higher oil and gas sales prices, lower sales volumes due to recent hurricanes and higher losses on nonhedge derivatives and hedge ineffectiveness. The improvement in chemical operating profit is largely attributable to charges totaling $123 million in 2004 associated with the shutdown of a production facility in Savannah, Georgia. An analysis of operating profit for each of our segments is provided under Results of Operations by Segment that follows.

	Three Months Ended September 30,
(Millions of dollars)	2005		2005 vs. 2004			2004

*Revenues*	$	1,208	$	5		$	1,203
Increase (decrease) in:
Oil and gas sales revenues due to changes in realized prices			$	311
Oil and gas sales revenues due to volume changes				(47	)
Hedge ineffectiveness, overhedge positions and nonhedge derivative losses				(327	)
Other exploration and production segment revenues				80
Pigment sales revenues due to changes in realized prices				33
Pigment sales revenues due to volume changes				(46	)
Other chemical segment revenues				1
Total change in revenues			$	5

Interest and Debt Expense - Interest and debt expense affecting income (loss) from continuing operations was $68 million in the third quarter of 2005, unchanged from 2004. As discussed below, a portion of 2005 interest and debt expense is reported in income from discontinued operations (net of tax) in connection with the anticipated divestiture of the company’s North Sea oil and gas business. Including amounts reported in income from discontinued operations, our total interest and debt expense was $117 million, $49 million higher than in the third quarter of 2004. This increase is primarily the result of $2.8 billion higher average outstanding debt in the 2005 third quarter.

In May 2005, the company entered into a credit agreement for three credit facilities with an aggregate commitment of $5.5 billion (Credit Agreement), as more fully discussed under Financial Condition and Liquidity. Financing costs of $58 million were capitalized when incurred and are being amortized as interest expense over the terms of the related facilities. Total interest and debt expense for the third quarter of 2005 related to borrowings under the Credit Agreement was $67 million (including amortization of financing costs). Provisions of the Credit Agreement require the company to use 100% of the net after-tax cash proceeds from sales of certain assets for debt repayment. Because the company’s North Sea assets are subject to this requirement, interest expense on debt that is required to be repaid upon their sale is classified as a component of income from discontinued operations. For the third quarter of 2005, pretax interest expense so classified totaled $49 million. The amount of interest and debt expense allocated to discontinued operations is based on approximately $3 billion of the company’s obligations under the term loans expected to be repaid with the net after-tax cash proceeds from the divestiture of the North Sea oil and gas business. Interest expense was allocated to discontinued operations beginning in May 2005, to coincide with initial borrowings under the term loans requiring mandatory prepayments.

As discussed under Financial Condition and Liquidity, during the third quarter of 2005, we made an aggregate of $600 million in mandatory and optional term loan prepayments, which resulted in accelerated amortization of debt issuance costs. Assuming the planned asset divestitures discussed under Overview and Recent Developments, including the IPO of Tronox, are completed by the end of 2005, we expect to fully repay the outstanding term loan balances, which would result in the write-off of any unamortized debt issuance costs at that time. As of September 30, 2005, the unamortized balance of debt issuance costs associated with the term loans was $34 million.

Corporate Expenses - Corporate expenses for the third quarter of 2005 were $45 million, reflecting an increase of $14 million compared with 2004. The increase is due in part to $7 million higher expense associated with performance unit awards. The per-unit liability associated with these awards increased as a result of Kerr-McGee’s higher total shareholder return relative to selected peer companies. Additionally, the number of outstanding performance units increased following the January 2005 grant. Corporate expenses for the third quarter of 2005 also included $3 million of costs incurred in connection with the separation of the chemical business and $2 million associated with the employee retention programs initiated in April 2005. The retention programs are discussed under Obligations and Commitments below.

In the fourth quarter of 2005 and in 2006 we expect to recognize additional expenses related to an involuntary termination program initiated in October of 2005, as part of our evaluation of organizational needs for both Kerr-McGee as a pure-play exploration and production company and Tronox as a separate publicly-traded chemical company. The company identified 75 employees that are expected to be involuntarily terminated 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 fourteen months. Assuming all employees meet the service and other conditions, the company's obligation for severance, outplacement assistance and other benefits will result in payments totaling $5 million by the end of 2006. Qualifying employees terminated under this program will also be eligible for enhanced benefits under the company's pension and postretirement plans, which is expected to result in additional fourth-quarter charges for special termination benefits.

Environmental Provisions - Environmental provisions, net of reimbursements, were $4 million for the third quarter of 2005, $67 million lower compared with 2004. The company monitors reserves for environmental remediation and adjusts reserves, as needed, based upon new facts affecting completion of remediation projects. In the 2004 third quarter, environmental provisions were recognized for the following sites, primarily due to changes in estimates of contaminated soil volumes and groundwater remediation: West Chicago, Illinois ($28 million); Los Angeles County, California ($14 million); and Cushing, Oklahoma ($10 million). Total environmental provisions, net of reimbursements, for the third quarter of 2005 were $17 million, of which $10 million relates to our former forest products business and is reported in income from discontinued operations (net of tax) and $3 million is included in operating profit of our business segments.

On October 22, 2004, the President of the United States signed into law the American Jobs Creation Act of 2004 (the “Act”). 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. On April 11, 2005, management completed its analysis of the impact of the Act on the company's plans for repatriation. Based on this analysis, the company decided to repatriate up to $500 million in extraordinary dividends, as defined in the Act. During the second quarter of 2005, we repatriated $200 million under the provisions of the Act and recognized income tax expense of $12 million. During the third quarter of 2005, an additional $21 million of foreign earnings were repatriated. However, we reduced the provision for income taxes for repatriation of dividends under the provisions of the Act by $4 million, reflecting a change in the expected utilization of foreign tax credits. We may repatriate up to an additional $279 million in extraordinary dividends under the provisions of the Act. Pending completion of the divestiture of the company’s North Sea operations, management has not yet decided whether, and to what extent, additional amounts of foreign earnings will be repatriated, but will make that determination in the fourth quarter of 2005. Accordingly, the accompanying financial statements do not reflect any additional provision for taxes on unremitted foreign earnings that may be repatriated under the provisions of the Act. If the company decides to repatriate up to an additional $279 million as discussed above, additional income tax expense of up to $15 million may be recognized in the fourth quarter.

	Three Months Ended September 30,
	2005									2004
	North Sea			Forest						North Sea			Forest
	Oil and Gas			Products						Oil and Gas			Products
(Millions of dollars)	Business			Business			Total			Business			Business			Total

Revenues	$	285		$	-		$	285		$	159		$	5		$	164

Income from Discontinued Operations:
Income (loss) from operations	$	157		$	-		$	157		$	59		$	(5	)	$	54
Gain on sale		306			-			306			-			-			-
Adjustments for contingencies(1)		-			(14	)		(14	)		-			-			-
Pretax income (loss) from
discontinued operations		463			(14	)		449			59			(5	)		54
Income tax (expense) benefit		(148	)		5			(143	)		(25	)		2			(23	)
Income (loss) from discontinued
operations, net of tax	$	315		$	(9	)	$	306		$	34		$	(3	)	$	31

General - Income from continuing operations for the first nine months of 2005 was $570 million compared with $158 million for the prior-year period. The increase in 2005 is primarily attributable to $459 million higher operating profit from our exploration and production segment and an improvement of $165 million in the operating results of our chemical business. Operating performance of our exploration and production operations was favorably affected by higher realized commodity prices and higher sales volumes, partially offset by increased operating costs and losses associated with commodity derivatives. The improvement in chemical operating results is largely attributable to charges totaling $123 million associated with the shutdown of a production facility in Savannah, Georgia, which affected third-quarter 2004 results. An analysis of operating profit for each of our segments is provided under Results of Operations by Segment below.

Revenues - Revenues for the nine-month period ended September 30, 2005 increased 38% over the prior-year period. Year-to-date oil and gas sales volumes increased primarily due to the contribution from Westport properties acquired in June 2004 and increased production in China, partially offset by production losses as a result of hurricane activity in the third quarter of 2005. The main factors contributing to the increase in consolidated revenues are summarized below, with additional analysis provided under Results of Operations by Segment.

	Nine Months Ended September 30,
(Millions of dollars)	2005		2005 vs. 2004			2004

*Revenues*	$	4,152	$	1,146		$	3,006
Increase (decrease) in:
Oil and gas sales revenues due to changes in realized prices			$	785
Oil and gas sales revenues due to volume changes				511
Hedge ineffectiveness, overhedge positions and nonhedge derivative losses				(414	)
Other exploration and production segment revenues				187
Pigment sales revenues due to changes in realized prices				113
Pigment sales revenues due to volume changes				(39	)
Other chemical segment revenues				3
Total change in revenues			$	1,146

Interest and Debt Expense - As discussed in the preceding analysis of results of operations for the third quarter, the company allocated a portion of total interest and debt expense to discontinued operations in 2005. Total interest and debt expense for the first nine months of 2005 was $257 million ($67 million of which is reported in income from discontinued operations, net of tax) compared with $180 million for the same 2004 period. The increase in the total interest and debt expense reflects primarily higher debt balances as a result of borrowings under the Credit Agreement and a $15 million reduction in gains on interest rate swaps designated to hedge the fair value of our debt, partially offset by $8 million higher capitalized interest driven by increased qualifying capital expenditures. Additional information regarding borrowings incurred under the Credit Agreement is provided under Financial Condition and Liquidity.

Corporate Expenses - The year-to-date increase in corporate expenses of $47 million is due primarily to approximately $29 million higher cost of employee compensation and benefits and $11 million of consulting and other costs incurred in 2005 in connection with the company’s consideration of strategic alternatives, including the separation of the chemical business. Employee compensation expense increased in part due to $4 million recognized in connection with employee retention programs implemented in April 2005, as discussed under Obligations and Commitments below, $7 million related to higher pension and other postretirement benefit cost and $12 million higher expense associated with performance unit awards. The per-unit liability associated with these awards increased as a result of Kerr-McGee’s higher total shareholder return relative to selected peer companies. Additionally, the number of outstanding performance units increased following the January 2005 grant.

Environmental Provisions - For the nine-month periods ended September 30, 2005 and 2004, environmental provisions, net of reimbursements, were $19 million and $74 million, respectively. The decrease is primarily attributable to three sites with ongoing remediation activities. The following are the provisions for these sites for the first nine months of 2004: West Chicago, Illinois ($28 million); Cushing, Oklahoma ($16 million); and Los Angeles County, California ($14 million). During the 2005 nine-month period, changes in the estimated remediation and restoration costs for these sites resulted in a provision of $9 million. Total environmental provisions, net of reimbursements, for the first nine months of 2005 totaled $44 million, of which $11 million relates to our former forest products business and is reported in income from discontinued operations (net of tax) and $14 million is included in operating profit of our business segments.

	Nine Months Ended September 30,
	2005									2004
	North Sea			Forest						North Sea			Forest
	Oil and Gas			Products						Oil and Gas			Products
(Millions of dollars)	Business			Business			Total			Business			Business			Total

Revenues	$	908		$	-		$	908		$	555		$	18		$	573

Income from Discontinued Operations:
Income (loss) from operations	$	500		$	-		$	500		$	212		$	(14	)	$	198
Gain (loss) on sale		306			(1	)		305			-			-			-
Adjustments for contingencies (1)		-			(16	)		(16	)		-			-			-
Pretax income (loss) from discontinued
operations		806			(17	)		789			212			(14	)		198
Income tax (expense) benefit		(280	)		6			(274	)		(91	)		5			(86	)
Income (loss) from discontinued operations,
net of tax	$	526		$	(11	)	$	515		$	121		$	(9	)	$	112

Pretax income from our oil and gas operations in the North Sea increased by $288 million, primarily as a result of $353 million higher revenues which were favorably affected by higher realized commodity prices, partially offset by interest and debt expense allocated to discontinued operations of $67 million. For additional information regarding the allocation of interest and debt expense and gain on sale of North Sea assets, refer to the analysis of results of consolidated operations for the three months ended September 30, 2005 and 2004 provided above.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Millions of dollars)	2005			2004			2005			2004

Revenues, excluding marketing revenues	$	704		$	766		$	2,688		$	1,799

Operating costs and expenses -
Lifting costs:
Lease operating expense		120			89			321			188
Production and ad valorem taxes		43			34			107			67
Total lifting costs		163			123			428			255

Depreciation, depletion and amortization		206			203			643			408
Accretion expense		6			5			16			13
Asset impairments		-			-			5			14
(Gain) loss associated with assets held for sale		4			-			(42	)		7
General and administrative expense		39			32			108			89
Transportation expense		22			21			69			51
Exploration expense		61			95			228			195
Gas gathering, pipeline and other expenses		21			20			71			61
Total operating costs and expenses		522			499			1,526			1,093

Operating profit, excluding net marketing margin		182			267			1,162			706

Marketing - Gas sales revenues		177			98			447			267
Marketing - Gas purchase costs (including transportation)		(174	)		(98	)		(443	)		(266	)
Net marketing margin		3			-			4			1

Total Operating Profit	$	185		$	267		$	1,166		$	707

	Three Months Ended						Nine months Ended
	September 30,						September 30,
(Millions of dollars, except per-unit amounts)	2005			2004			2005			2004
Revenues -
Crude oil and condensate sales	$	439		$	305		$	1,300		$	690
Natural gas sales		613			483			1,781			1,095
Gain (loss) on hedge ineffectiveness		(212	)		3			(256	)		2
Losses on overhedge positions⁽¹⁾		(125	)		-			(125	)		-
Nonhedge derivative losses		(29	)		(42	)		(68	)		(37	)
Gas marketing activities		177			98			447			267
Other revenues		18			17			56			49
Total	$	881		$	864		$	3,135		$	2,066

Production -
Crude oil and condensate (thousands of barrels per day):
U.S. Gulf of Mexico		49			62			57			59
U.S. onshore		37			37			37			25
China		19			11			19			4
Total		105			110			113			88

Natural gas (million cubic feet per day):
U.S. Gulf of Mexico		360			394			408			345
U.S. onshore		577			605			582			421
Total		937			999			990			766

Total equivalent barrels of oil (thousands of boe per day)		261			277			278			216

Average sales prices (excluding hedges) -
Crude oil and condensate (per barrel):
U.S. Gulf of Mexico	$	57.90		$	39.45		$	49.55		$	36.04
U.S. onshore		52.92			39.31			46.19			35.27
China		50.34			36.38			43.45			36.38
Average		54.86			39.13			47.43			35.83

Natural gas (per thousand cubic feet):
U.S. Gulf of Mexico	$	8.78		$	5.93		$	7.42		$	5.98
U.S. onshore		7.90			5.61			6.71			5.59
Average		8.24			5.74			7.00			5.77


Average realized sales prices (including hedges) -
Crude oil and condensate (per barrel):
U.S. Gulf of Mexico	$	47.58		$	29.86		$	43.60		$	28.93
U.S. onshore		42.60			29.73			39.91			27.68
China		50.34			36.38			43.45			36.38
Average		46.26			30.40			42.38			28.85

Natural gas (per thousand cubic feet):
U.S. Gulf of Mexico	$	7.65		$	5.45		$	7.03		$	5.43
U.S. onshore		6.76			5.13			6.29			5.04
Average		7.10			5.25			6.59			5.22

Crude Oil Sales Revenues and Production - Oil sales revenues increased $134 million or 44% in the third quarter of 2005 compared with the same period of 2004 due to higher realized commodity prices, partially offset by slightly lower sales volumes. Average oil prices, including the effect of hedging activity, increased $15.86 per barrel in the third quarter of 2005, contributing $151 million to the increase in oil sales revenues. Third-quarter 2005 oil production of 105 thousand barrels per day (Mbbls/d) was a 5 Mbbls/d decrease from the same 2004 period. This decrease in oil production was primarily due to hurricane-related disruptions in the Gulf of Mexico and U.S. onshore Gulf Coast areas, which impacted oil production by an estimated 12 Mbbls/d in the third quarter of 2005. Partially offsetting the hurricane-related production losses was an 8 Mbbls/d increase due to first oil production from China’s CFD 11-3/5 field in July 2005.

For the first nine months of 2005, oil sales revenues increased $610 million compared with 2004, due to a combination of higher realized prices and increased oil production. The average oil sales price, including the effect of hedging activity, increased $13.53 per barrel compared with the same period in 2004, contributing $415 million to oil sales revenues. Oil production for 2005 increased to 113 Mbbls/d, a 28% increase over 2004. The increase is attributable, in part, to the full year-to-date contribution from former Westport properties that were acquired in June 2004 (15 Mbbls/d). Additionally, start-up of production in China from CFD 11-1 and 11-2 fields in July 2004 and from CFD 11-3/5 field in July 2005 contributed to the increase (15 Mbbls/d). These increases were partially offset by hurricane-related production losses in the Gulf of Mexico and U.S. onshore Gulf Coast areas, estimated at 4 Mbbls/d for the period.

Natural Gas Sales Revenues and Production - Natural gas sales revenues increased $130 million in the third quarter of 2005 compared to 2004 as a result of a $1.85 per thousand cubic feet (Mcf) increase in the average realized price. Higher realized gas prices provided a $160 million increase in gas sales revenues, averaging $7.10 per Mcf (including the impact of hedging activity). Gas production in the third quarter of 2005 was 937 million cubic feet per day (MMcf/d), 62 MMcf/d lower than 2004 third-quarter production, resulting in a $30 million reduction in gas sales revenues. Hurricane-related disruptions in the Gulf of Mexico and U.S. onshore Gulf Coast areas decreased gas production by an estimated 102 MMcf/d in the third quarter of 2005.

Natural gas revenues increased $686 million for the nine months ended September 30, 2005, due to the combined impact of higher commodity prices and increased gas production for the period. The average gas price, including the effect of hedging activity, increased $1.37 per Mcf compared with 2004, contributing an additional $370 million to gas sales revenues. Year-to-date 2005 gas production increased to 990 MMcf/d, 224 MMcf/d higher than 2004. Contributing to the increase was the addition of Westport properties (267 MMcf/d), as well as production from the Gulf of Mexico’s Red Hawk field that began producing in July 2004. These increases in production were partially offset by hurricane-related production losses estimated at 34 MMcf/d, primarily in the Gulf of Mexico.

For the three- and nine-month periods ended September 30, 2005, we recognized hedge ineffectiveness losses of $212 million and $256 million, respectively, associated with commodity derivative instruments designated as hedges of future oil and gas sales. These losses represent the excess of mark-to-market losses on our commodity derivatives over the higher cash flows we expect to realize upon sales of hedged production. Higher ineffectiveness losses in 2005 are due to our expanded hedging program that now extends through 2007, as well as significantly increased commodity prices and widening natural gas basis differentials between NYMEX and actual physical indices.

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 for the fourth quarter of 2005 are expected to be insufficient to cover the associated derivative contracts in place. Consequently, we recognized an unrealized loss of $103 million in the third quarter associated with certain fourth-quarter 2005 derivative contracts assigned to hedge cash flows from sales of Gulf of Mexico natural gas production, although total U.S. natural gas production in the fourth quarter is still expected to exceed volumes covered by hedge instruments. Additionally, realized losses of $22 million associated with September derivative contracts in excess of hedged physical deliveries for that month are reported separately from oil and gas sales revenues. The company currently estimates that fourth quarter 2005 daily oil production from the Gulf of Mexico will average 48-52 Mbbls/d and that natural gas production will average 310-375 MMcf/d. The company believes that it is probable that by January 2006 deliveries in the Gulf of Mexico will resume in sufficient volumes to match its remaining 2006 and 2007 derivative contracts.

Nonhedge derivative losses represent net realized and unrealized gains and losses related to crude oil and natural gas derivative instruments that have not been designated as hedges or that do not qualify for hedge accounting treatment. Such gains and losses primarily relate to certain contracts assumed in connection with the Westport merger. While the company designated Westport’s fixed-price oil and gas swaps as hedges after the merger, costless and three-way collars do 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 will recognize mark-to-market gains and losses in earnings until the collars mature, rather than deferring such amounts in accumulated other comprehensive income (loss). The net fair value of these derivatives at September 30, 2005 was a liability of $130 million.

In the third quarter of 2005, lease operating expense increased $31 million compared with 2004. On a per-unit basis, lease operating expense increased $1.53 per barrel of oil equivalent (boe), from $3.52 per boe in 2004 to $5.05 per boe in 2005. The increase was primarily due to higher cost of property insurance coverage ($14 million), higher nonoperating expenses in the Gulf of Mexico ($7 million) and new production from China’s CFD 11-3/5 field ($3 million). In addition, increased well workover expense and overall inflationary cost increases contributed to higher U.S. onshore operating costs in the third quarter of 2005.

Lease operating expense for the first nine months of 2005 was $321 million, an increase of $133 million compared with 2004. On a per-unit basis, lease operating expense increased $1.04 per boe, from $3.20 per boe in 2004 to $4.24 per boe in 2005. The increase was primarily due to additional operating expenses associated with Westport properties acquired in June 2004 ($81 million) and three fields in Bohai Bay, China, one of which started producing in July 2005 and two in July 2004 ($21 million). Higher cost of property insurance coverage contributed an additional $16 million to the increase in year-to-date lease operating expense. The remaining increase of $15 million was primarily attributable to the company’s nonoperated Gulf of Mexico properties.

Production and ad valorem taxes are comprised primarily of severance taxes associated with properties located onshore and in state waters in the U.S. These taxes, which usually are based on a percentage of oil and gas sales revenues, increased $9 million in the third quarter of 2005 and $40 million for the first nine months of 2005 as a result of higher commodity prices compared with the respective prior-year periods. Also contributing to the year-to-date increase were higher sales volumes in 2005 compared with 2004. The addition of Westport's properties in 2004 resulted in higher production taxes as a percentage of sales revenues by increasing the proportion of U.S. onshore properties subject to production taxes in our portfolio.

Kerr-McGee records impairment losses when performance analysis and other factors indicate that future net cash flows from production will not be sufficient to recover the carrying amounts of the related assets. In general, such write-downs most often occur on mature properties that are nearing the end of their productive lives or cease production sooner than anticipated. Impairment losses recorded in the first nine months of 2005 and 2004 totaled $5 million and $14 million, respectively. Impairment losses in 2005 related primarily to two U.S. Gulf of Mexico shelf properties that ceased producing in the first quarter. Impairment losses in 2004 related primarily to a U.S. Gulf of Mexico field that experienced premature water breakthrough and ceased production sooner than expected.

We recognized a net gain on disposition of assets of $42 million in the first nine months of 2005, related primarily to two transactions. In the first quarter of 2005, we acquired a 37.5% interest in the Blind Faith discovery in the deepwater Gulf of Mexico from BP Exploration & Production in exchange for our interests in various proved oil and gas properties in the Arkoma basin of southeast Oklahoma. In connection with this transaction, we received $24 million in cash and recognized a $19 million gain on sale based on the percentage of the Arkoma properties' fair value that was received in cash. In the second quarter of 2005, we sold our interests in oil and gas properties in the Table Mountain and Culp Draw fields of Wyoming to Anadarko Petroleum Corporation in exchange for Anadarko’s overriding royalty interests in the Greater Natural Buttes area and $27 million in cash. We recognized a gain of $25 million in connection with this transaction. Partially offsetting these gains was a $6 million loss in the 2005 third quarter related to one U.S. onshore divestiture package held for sale, the carrying value of which was reduced based on estimated fair value less cost to sell. All other assets held for sale are expected to result in gains upon disposition.

Third-quarter 2005 general and administrative expense of $39 million was $7 million higher than 2004. For the first nine months of 2005, general and administrative expense increased $19 million, to $108 million, compared to the prior-year period. General and administrative expense for the three and nine months ended September 30, 2005 includes $6 million and $10 million, respectively, associated with employee retention programs initiated in April 2005. Additional information on these programs is provided under Obligations and Commitments below. Additional expense increases over the corresponding 2004 periods were due to higher cost of employee compensation and benefits, partially offset by higher overhead charge-outs for U.S. onshore and Gulf of Mexico properties.

Transportation expense, representing the costs paid to third-party providers to transport oil and gas production, increased by $1 million in the third quarter of 2005, to $22 million. In early 2005, we began transporting gas from the Rocky Mountain area under a new contract, increasing overall transportation costs. Higher costs associated with the new contract are expected to be offset by increased realized gas prices as a result of greater access to more competitive gas markets. On a per-unit basis, third-quarter 2005 transportation expense was $.93 per boe compared to $.82 per boe in 2004.

In the third quarter of 2005, total exploration expense was $61 million, a decrease of $34 million versus 2004, primarily related to $28 million lower dry hole expense and $7 million lower geological and geophysical costs. For the third quarter of 2005, one unsuccessful Gulf of Mexico exploratory prospect contributed $17 million to dry hole expense, with the remainder primarily associated with exploration activity in Trinidad. Geological and geophysical data acquisition and processing costs decreased $7 million in the third quarter of 2005, with lower spending in the Gulf of Mexico shelf and U.S. onshore areas, partially offset by increased costs in China.

For the first nine months of 2005, total exploration expense was $228 million, an increase of $33 million compared with 2004, primarily due to an increase in dry hole expense of $36 million. Amortization of undeveloped leases also increased by $9 million, largely as a result of additional Westport leases. Geological and geophysical data acquisition and processing costs decreased by $12 million for the nine-month period ended September 30, 2005, as compared to 2004. Increased spending in China and Brazil was offset by lower costs in various international locations and the Gulf of Mexico shelf and U.S. onshore areas.

Capitalized exploratory well costs associated with ongoing exploration and/or appraisal activities may be charged to earnings in a future period if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur. At September 30, 2005, the company had capitalized exploratory well costs of approximately $224 million associated with such ongoing exploration activities, primarily in the deepwater Gulf of Mexico, Alaska, Brazil and China. Capitalized exploratory well costs have increased by $88 million from December 31, 2004 primarily due to additional exploration activities in the Gulf of Mexico ($49 million), Alaska ($44 million) and Brazil ($18 million) partially offset by successful exploration costs in China that were reclassified to proved oil and gas properties.

Marketing revenues were $177 million in the third quarter of 2005, an increase of $79 million over 2004. Marketing revenues for the first nine months of 2005 totaled $447 million, or $180 million higher than 2004. The increase in both periods was primarily the result of higher purchase and resale of natural gas in the Rocky Mountain area and higher natural gas sales prices. Marketing volumes (MMBtu/day) were 262,000 and 209,000 in the third quarter of 2005 and 2004, respectively. For the first nine months of 2005 and 2004, marketing volumes (MMBtu/day) averaged 253,000 and 189,000, respectively. Gas purchase costs increased $76 million for the third quarter of 2005 and $177 million for the first nine months of 2005.

Operating profit for the third quarter of 2005 was $16 million on revenues of $302 million, compared with operating loss of $110 million on revenues of $315 million for the same 2004 period. Of the $13 million decrease in revenues, $46 million was due to decreased sales volumes. This decrease was partially offset by $33 million due to an increase in average selling prices of approximately 13%. Sales volumes were approximately 23,900 tonnes lower primarily due to the tonnes sold from the Savannah sulfate production facility that was shut down during 2004, lower European volumes due to weak economic conditions in Europe combined with lower volumes also experienced in the Americas and Asia/Pacific regions, which saw record sales volumes in the third quarter of 2004. The improvement in operating results is primarily due to shutdown provisions incurred in the third quarter of 2004 of $123 million related to the sulfate-process titanium dioxide pigment production at the Savannah, Georgia facility. The decrease in sales volumes also reduced costs by $40 million, which was partially offset by an increase in manufacturing costs of $22 million due to higher raw material and energy costs and increased maintenance. Selling and administrative costs were $2 million higher, primarily due to an increase in employee incentive compensation related to cash bonuses resulting from improved operating performance during the quarter.

For the first nine months of 2005, operating profit was $80 million on revenues of $944 million, compared with an operating loss of $89 million on revenues of $870 million in the respective prior-year period. The improvement in operating results for the first nine months of 2005 compared with the same 2004 period was primarily attributable to the shutdown provisions incurred in 2004 of $123 million related to the Savannah facility, combined with higher average sales prices in 2005. Revenues increased $74 million, or 9%, for the first nine months of 2005, of which $113 million resulted from higher average sales prices and was offset by $39 million due to lower pigment sales volumes of approximately 20,200 tonnes. The decreased sales volume also resulted in $38 million lower manufacturing and transportation costs. These improvements were partially offset by higher average product costs of $56 million due to higher raw material and energy costs and increased costs resulting from production maintenance. Selling and administrative costs were also higher by $10 million compared to the same period in 2004, primarily due to an increase in employee incentive compensation related to cash bonuses resulting from improved operating performance for the year.

For the nine months ended September 30, 2005, operating loss was $6 million on revenues of $73 million, compared with an operating loss of $2 million on revenues of $70 million in the same 2004 period. The $4 million increase in operating loss for the first nine months of 2005 resulted from a net $11 million environmental provision (net of expected insurance reimbursement of $21 million) incurred in the first quarter of 2005 related primarily to ammonium perchlorate remediation associated with the company's Henderson, Nevada, operations. This charge was partially offset by improved operations at the company’s Henderson, Nevada, electrolytic manganese dioxide manufacturing facility compared to the prior year.

In October 2005, the Board approved the separation of the chemical business through an initial public offering (IPO) of shares of Class A common stock of Tronox, the company’s wholly-owned subsidiary. An amended registration statement was filed with the Securities and Exchange Commission (SEC) relating to the proposed IPO and is currently under review by the SEC. Assuming the review is completed and the registration statement is declared effective by the SEC, the company expects to complete the IPO in the fourth quarter of 2005. Following the IPO, Kerr-McGee will continue to hold a controlling interest in Tronox through ownership of Tronox’s Class B common stock. We expect to distribute those shares to Kerr-McGee stockholders during 2006 through a spinoff, splitoff or a combination of those transactions (Distribution). It is expected that Tronox will be included in our consolidated financial statements through the Distribution date. The Distribution is subject to certain conditions, including receipt of a favorable tax opinion, necessary regulatory approvals and approval by the company’s Board of Directors of the final form, structure and other terms of any transaction to effect the Distribution.

Prior to the completion of the IPO, Kerr-McGee will transfer subsidiaries that conduct Kerr-McGee’s chemical business to Tronox. Some of these subsidiaries previously were engaged in the production of ammonium perchlorate, the manufacturing of thorium, 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. Additional discussion regarding environmental obligations is provided below.

Historically, employees of Kerr-McGee’s chemical business participated in stock-based compensation, pension and postretirement plans established by Kerr-McGee. It is expected that in connection with the IPO, Tronox will issue stock-based awards to certain of its employees and non-management directors, while unvested Kerr-McGee stock options and restricted stock held by employees of Tronox will be converted to Tronox stock-based awards on the effective date of the Distribution. 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. The anticipated effects of the separation on our obligations for employee benefits are more fully discussed below.

Obligations for Environmental Remediation -Tronox and its subsidiaries will be subject to obligations for environmental remediation and restoration associated with the chemical business currently in operation, as well as with former operations described above. The carrying value of liabilities associated with such operations is $239 million as of September 30, 2005. Tronox and its subsidiaries also are expected to have contingent obligations of such current and former operations for which no liability is recognized as of September 30, 2005 because the loss is not considered probable or is not estimable. Discussion of the company’s material environmental obligations and other contingencies is provided in Note 16 to our consolidated financial statements included in Part 1 of this Form 10-Q.

Upon completion of the IPO, Kerr-McGee is expected to agree to reimburse Tronox for a portion of the environmental costs incurred and paid by Tronox and its subsidiaries during the seven-year period following the IPO, to the extent such costs, net of any reimbursements received from insurers or other parties, exceed the carrying value of reserves at the time of the IPO. The reimbursement obligation extends to costs incurred 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. The company’s reimbursement obligation will be reflected in our Consolidated Balance Sheet at its estimated fair value at the time of origination. The estimated fair value will be determined considering expected cash outflows pursuant to the reimbursement obligation, their timing and probability of payment.

To meet our short- and long-term liquidity requirements, we expect to fund capital expenditures, debt payments and working-capital requirements through cash on hand, cash generated from operating activities, the sales of assets, issuance of debt and/or borrowings under our $1.25 billion revolving credit facility. Based on the company's forecast of cash flows and liquidity, the company believes that it has and will continue to have the financial resources and liquidity to meet future cash requirements. Included in that forecast are expected proceeds from the separation of the chemical business unit and sales of selected oil and gas properties and other assets which are expected to be realized during the fourth quarter of 2005. We expect these asset divestitures to result in net cash proceeds of approximately $4.4 billion, which will be used for debt reduction and other corporate purposes. We plan to reduce debt by approximately $3.8 billion in the fourth quarter, using proceeds of the planned divestitures discussed under Overview and Recent Developments above and cash flow from operating activities which has been underpinned by an expanded oil and gas hedging program. Additional information regarding our commodity derivative instruments is provided in Item 3, Quantitative and Qualitative Disclosures about Market Risk.

The company had negative working capital of $1.4 billion at September 30, 2005; however, this is not indicative of a lack of liquidity, as the company maintains sufficient current assets to settle current liabilities when due. Our working capital position is significantly affected by current liabilities associated with our financial derivatives. At September 30, 2005, the company had recorded approximately $2.2 billion of net current derivative liabilities for contracts that will effectively adjust the cash flows to be realized upon the sale of our future oil and gas production. Because those sales have not yet occurred, the associated accounts receivable are not yet reflected in our Condensed Consolidated Balance Sheet, while derivative assets and liabilities are reflected in the Condensed Consolidated Balance Sheet at their estimated fair values. Because of the high degree of volatility in oil and natural gas commodity markets and increased volume of outstanding commodity derivative contracts, our working capital position will be continually affected by changes in the fair value of derivative instruments.

Repurchases of Common Stock and Related Financing - As discussed under Overview and Recent Developments, 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 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 modified "Dutch Auction" self 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 terms of the tender offer provided for the company to determine the lowest per-share price within the range that would enable it to buy up to $4 billion of its common stock based on the number of shares tendered and the prices specified by the tendering stockholders. Under the tender offer, which expired on May 18, 2005, approximately 138.9 million shares were properly tendered at a price of $85 per share and not withdrawn. Since the number of shares tendered exceeded 43.5 million, purchases of shares by the company were made based on a proration factor of 33.64%. In accordance with applicable securities laws, 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 $5.5 billion credit agreement (Credit Agreement) discussed below and cash on hand.

In connection with the tender offer, the company entered into the 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 (Revolving Facility). In satisfaction of one of the closing conditions, we repaid all outstanding indebtedness under the $1.5 billion revolving credit agreement previously in effect and terminated the agreement. No penalties were incurred in connection with the early termination.

Interest on amounts borrowed under the Credit Agreement is payable, at our election, at an alternate base rate (ABR) or a Eurodollar rate, in each case as defined in the Credit Agreement, plus a margin, as summarized below. The applicable margin may vary based on the company’s Consolidated Leverage Ratio, as defined in the Credit Agreement, and other specified events and conditions. The Consolidated Leverage Ratio determined pursuant to the terms of the Credit Agreement is based on the company's total funded debt and its earnings over a period of four consecutive quarters before considering interest, taxes, depreciation, depletion and amortization, noncash exploration expense and other specified noncash items (EBITDAX).

Guarantee and Collateral Provisions - The company’s obligations under the Credit Agreement are (a) unconditionally guaranteed, jointly and severally, by certain of the company’s domestic subsidiaries and (b) secured by a perfected first priority security interest, subject to existing liens and customary exceptions and to the rights of the company’s existing bondholders to be equally and ratably secured, in a substantial portion of the company’s tangible and intangible assets located in the United States (excluding assets relating to the company’s chemical business), and all of the capital stock of specified direct and indirect subsidiaries (limited, in the case of foreign subsidiaries, to 66% of the capital stock of the company’s first tier foreign subsidiaries). To the extent required under the terms of the company’s existing indentures, all obligations under previously unsecured bonds became equally and ratably secured with the company’s obligations under the Credit Agreement.

As discussed in Note 10 to the Condensed Consolidated Financial Statements included in Item 1, Part I to this Form 10-Q, in September 2005, we received consent from a majority of noteholders to amend the indenture governing certain of our registered notes. The supplemental indenture, which became effective as of September 21, 2005, provides for the release of the company's chemical business subsidiary, 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.

Debt Covenants - The terms of the Credit Agreement provide for customary representations and warranties, affirmative and negative covenants, and events of default. Specifically, the Credit Agreement limits our ability to incur or secure other debt, make investments, sell assets, pay dividends and repurchase stock. Additionally, the company’s ability to make capital expenditures (including dry hole costs) is limited by the provisions of the Credit Agreement to $2.35 billion in any given year. The company also is required to maintain compliance with the following financial covenants (in each case, as defined in the Credit Agreement):

For the third quarter of 2005, the company had a Consolidated Leverage Ratio of 1.7:1, a Consolidated Interest Coverage Ratio of approximately 11:1 and an Asset Coverage Ratio of 1.92:1, and was in compliance with its other debt covenants. Based on total debt outstanding as of September 30, 2005, the company’s EBITDAX, as defined in the Credit Agreement, would have to decline by over 40% from the level incurred over the most recent four quarters, before the Consolidated Leverage Ratio would increase above 4:1. While a significant decline in commodity prices will reduce the company’s EBITDAX, our hedging program provides sufficient certainty of earnings and cash flows to make it unlikely in the near term that EBITDAX could decline below levels necessary to maintain compliance with the leverage ratio covenant. Additionally, based on current estimates of the present value of future cash flows (supported by the company’s hedging program), together with expected near-term debt reduction plans, management expects to continue to meet the asset coverage requirements under the Credit Agreement. The company also expects to be in compliance with the annual limitation on dividend payments of $50 million, based on the current dividend level of $.20 per share annually.

Credit Ratings - In rating the company’s debt, rating agencies consider our financial and operating risk profile by analyzing our debt levels, growth profile, cost structure, oil and gas reserve replacement ratios, capital expenditure requirements, contingencies, dividend policy and any other factors they deem relevant that could potentially impact our ability to service debt. In response to the company’s April 2005 announcement of our intention to commence the tender offer and increase leverage in the near term, our credit ratings were downgraded and are no longer investment grade. The following table provides a summary of our senior unsecured debt ratings by selected rating agencies as of March 31, 2005, and subsequent to the downgrades:

As a result of the downgrades, the company’s borrowing costs increased. Additionally, as discussed below, certain counterparties to our derivative instruments required us to post cash collateral. Further, we had an accounts receivable monetization program under which selected qualifying customer accounts receivable of the company’s chemical - pigment business were sold 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. The program provided for termination upon a ratings downgrade below specified levels. Under that provision, 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. The ratings downgrades in April 2005 triggered the program termination event. 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 have subsequently been collected by the company.

Certain of our counterparties require margin deposits if unrealized losses on derivative instruments exceed limits established with individual counterparty institutions. Consequently, the company may be required from time to time to post collateral in the form of cash or letters of credit. As a result of our credit rating being lowered in April 2005, we were required to post cash collateral with one of our counterparties. However, our collateral requirements to date have not been significant. Future collateral requirements will depend on changes in the fair value of outstanding derivatives and other factors.

Operating Activities - The $1.2 billion increase in cash flows from operating activities during the first nine months of 2005 over 2004 is primarily attributable to higher average realized oil and gas sales prices and higher sales volumes. On a barrel of oil equivalent basis, average daily oil and gas production in 2005 was 21% higher than in 2004 as a result of the Westport merger and the start of new production in China, as discussed above under Results of Operations by Segment - Exploration and Production. Average realized sales prices on a barrel of oil equivalent basis (including the effect of our hedging program) increased by 42%, from $29.16 in 2004 to $41.26 in 2005. Additionally, 2005 cash flows from operating activities were favorably affected by $22 million lower expenditures for environmental remediation and an increase of $26 million in receipts of environmental cost reimbursements. These increases in operating cash flows were partially offset by higher cash outflows for costs and operating expenses, production taxes, general and administrative and interest expense. Upon completion of the divestiture of our North Sea oil and gas business, we expect that cash flows from operating activities will decline. As discussed below, we also expect cash requirements for capital expenditures to decline. Summarized information related to this business and its relative size to the company is provided under Overview and Recent Developments.

	Nine Months Ended
	September 30,
(Millions of dollars)	2005			2004
Capital expenditures -
Exploration and production (including dry hole costs)	$	(1,346	)	$	(805	)
Chemical - Pigment		(47	)		(56	)
Chemical - Other		(5	)		(7	)
Corporate and other		(12	)		(10	)
Total capital expenditures (including dry hole costs)		(1,410	)		(878	)
Acquisitions, net of cash acquired		-			43
Proceeds from sale of North Sea oil and gas assets		547			-
Proceeds from dispositions of other assets		68			50
Other investing activities		(7	)		(31	)
Total net cash used in investing activities	$	(802	)	$	(816	)

Capital expenditures in 2005 increased primarily as a result of approximately $270 million higher capital spending associated with Westport properties focused largely on exploitation and development activities in the Rockies, increased expenditures on the company's exploratory and developmental drilling in the Gulf of Mexico and exploratory drilling in Alaska and Brazil. Additionally, capital expenditures for the first nine months of 2005 and 2004 included expenditures of approximately $180 million and $90 million, respectively, associated with our North Sea oil and gas business. Upon completion of the possible divestitures discussed under Overview and Recent Developments, we expect capital requirements associated with our drilling program to decline. The extent of the decline will depend upon the composition of the properties divested.

Cash flows from investing activities for the nine months ended September 30, 2005 included cash proceeds of $547 million from the sale of our interests in four nonoperated fields and related exploratory acreage and facilities in the North Sea. The divestiture of our North Sea oil and gas business is expected to be completed in November 2005 with the sale of stock of our wholly-owned subsidiary, Kerr-McGee (G.B.) Ltd., and other affiliated entities for cash consideration of approximately $3 billion. In addition, by the end of 2005, we expect to realize proceeds from the proposed initial public offering of Tronox, the sale of our nonoperating interest in the Javelina gas processing and fractionation facility and divestitures of selected oil and gas properties in the U.S. These transactions are expected to result in aggregate net cash proceeds of approximately $4.4 billion, which will be used for debt reduction and other corporate purposes. The timing and magnitude of cash flows associated with the divestitures will depend on the market conditions, the composition of assets divested and transaction terms.

Proceeds from dispositions of other assets for 2005 include $51 million received in connection with two exchange transactions. In the first quarter of 2005, we acquired a 37.5% interest in the Blind Faith discovery in the deepwater Gulf of Mexico from BP Exploration & Production in exchange for the company's interests in various proved oil and gas properties in the Arkoma basin of southeast Oklahoma. We received cash of $24 million in connection with this transaction. In the second quarter of 2005, we received cash of $27 million in connection with the exchange of the company's interests in certain U.S. onshore properties for overriding royalty interests in the Greater Natural Buttes area. The 2004 proceeds from dispositions of other assets include $39 million realized upon the sale of Devon Energy Corporation common stock.

	Nine Months Ended
	September 30,
(Millions of dollars)	2005			2004

Proceeds of borrowings, net of related transaction costs	$	4,192		$	900
Cash received upon exercises of employee stock options		206			34
Repurchases of common stock, including transaction costs		(4,225	)		-
Payment of dividends		(148	)		(137	)
Repayment of debt		(998	)		(1,278	)
Cash paid for modification of debt		(9	)		-
Settlement of Westport derivatives		(134	)		(45	)
Total cash used in financing activities	$	(1,116	)	$	(526	)

In 2005, we spent $4.2 billion to repurchase 49.8 million shares of the company’s common stock in connection with two share repurchase programs approved by the Board, as more fully discussed above under Repurchases of Common Stock and Related Financing. The repurchases were financed with the net proceeds of borrowings and cash on hand. No additional repurchases can be made under these programs. As discussed above, in September 2005, we completed the sale of certain oil and gas assets in the North Sea. In connection with the sale, we made prepayments of $600 million on the term loans, of which approximately $504 million represented a payment in satisfaction of our mandatory prepayment requirement associated with asset sales and the remaining $96 million represented an optional prepayment. As discussed above, we expect to realize additional proceeds from planned divestitures by the end of 2005. Assuming the divestiture transactions are completed as expected, we plan to repay approximately $3.8 billion of debt in the fourth quarter of 2005 using a portion of the net proceeds from planned divestitures, including the separation of Tronox, and cash flow from operating activities. Pro forma for such repayment, scheduled maturities of our debt would be $307 million in 2006 and $150 million in 2007. Refer to Pending Separation of Tronox for discussion of borrowings expected to be incurred by Tronox concurrent with its initial public offering.

As discussed under Financial Condition and Liquidity - Repurchases of Common Stock and Related Financing - Guarantee and Collateral Provisions, in September of 2005, we received noteholders’ consent to amend the indenture governing certain of our registered notes. In connection with this transaction, we paid $5 million to consenting noteholders for consent execution and $4 million in third-party consent solicitation costs. Assuming the initial public offering of Tronox is completed in the fourth quarter, we will pay an additional $13 million to the noteholders upon the release of Tronox Worldwide LLC as the guarantor of the notes, as provided by the amended terms of the indenture.

While cash used to pay dividends during the first nine months of 2005 was higher than in 2004 primarily due to 48.9 million shares issued in the Westport merger in June 2004, we expect our cash requirements for future dividend payments to decline based on the lower number of shares outstanding following the tender offer completed in May 2005 and due to the reduction in the quarterly per-share dividend from $.45 to $.05. Assuming the number of shares outstanding at September 30, 2005 remains unchanged (116 million shares) and based on our current dividend payment policy, we expect to pay approximately $6 million in dividends during the fourth quarter of 2005 and approximately $23 million in 2006.

In 2005 and 2004, we paid $134 million and $45 million, respectively, to settle certain derivative instruments assumed in the Westport merger in June 2004. These instruments extend through 2006 and had a net liability fair value at September 30, 2005 of $136 million, including $6 million payable for September settlements. Future settlement values may be higher or lower than the estimated fair value of unsettled contracts at September 30, 2005 and will be determined based on reference commodity prices in effect in the period of settlement.

In the normal course of business, the company enters into purchase obligations, contracts, leases and borrowing arrangements. As part of our project-oriented exploration and production business, we routinely enter into contracts for certain aspects of a project, such as engineering, drilling and subsea work. These contracts are generally not unconditional obligations; thus, the company accrues for the value of work done at any point in time, a portion of which is billed to partners. In 2005, the company entered into additional drilling rig commitments to assure availability for executing our drilling program. The company’s commitments under these arrangements total $601 million, $52 million of which relates to rig utilization in 2005, $441 million in 2006-2007, $38 million in 2008-2009 and $70 million thereafter. A portion of expenditures under these commitments will be billed to other working interest partners once actual utilization is known. The company also has entered into additional international exploration licenses, which carry work commitments of approximately $31 million, and expects to incur $16 million of associated expenditures in 2005 and a total of $15 million in 2006 and 2007.

As discussed above under Overview and Recent Developments, the company plans to separate its chemical business unit and divest of selected oil and gas properties. In April 2005, in connection with planned exit activities, the company initiated employee compensation programs designed to provide an incentive to certain employees to remain with the company over a stated period ranging from six to 18 months. The total cost of the retention programs is expected to be $34 million, assuming all participating employees meet the service and other conditions (and before considering any awards that may be made in future periods upon successful disposition of certain assets, as discussed below). The cost associated with these programs is generally recognized as the related services are provided by the participating employees. Under the plan covering employees of the chemical business unit, awards totaling $2 million are payable upon the earlier of the disposition of the chemical business or the end of a one-year service period. Additional payments may be due to certain employees upon successful disposition of the chemical business or divestiture of certain oil and gas assets.

In December 2004, the Financial Accounting Standards Board (FASB) issued Statement No. 123 (revised 2004), “Share-Based Payment” (FAS No. 123R), which replaces FAS No. 123 and supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” FAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim period after June 15, 2005, with early adoption encouraged. In April 2005, the Securities SEC amended its rules to allow public companies more time to implement the standard. Following the SEC’s rule, the company intends to implement FAS No. 123R effective January 1, 2006. We plan to adopt the standard 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. We expect that the adoption will not have a material effect on our financial condition and cash flows. The company is evaluating the effect of implementation on its results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (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. FIN No. 47 is effective for the company as of December 31, 2005. We are evaluating the effect of implementation and at this time do not expect it to have a material effect on our financial statements.

In April 2005, the FASB issued a FASB Staff Position FAS 19-1, "Accounting for Suspended Well Costs" (FSP FAS 19-1) which amends FASB Statement No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." FSP FAS 19-1 requires the continued capitalization of drilling costs if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. The FSP provides a number of indicators that can assist an entity in evaluating whether sufficient progress is being made in assessing the reserves and economic viability of the project and includes new disclosure requirements with respect to capitalized exploratory drilling costs. The company adopted FSP FAS 19-1 effective July 1, 2005. The adoption had no effect on our financial statements. Disclosures required by the FSP were provided in the notes to the consolidated financial statements included in our latest annual report on Form 10-K.

The company is exposed to a variety of market risk, including credit risk, changes in oil and gas commodity prices, foreign currency exchange rates and interest rates. We address these risks through a controlled program of risk management that includes the use of insurance and derivative financial instruments. In addition to information included in this section, see Note 5 to the Condensed Consolidated Financial Statements included in Item 1, Part I of this Form 10-Q for discussion of the company’s derivatives and hedging activities.

The company is exposed to market risk fluctuations in crude oil and natural gas prices. To increase the predictability of its cash flows and support capital expenditure plans, the company periodically enters into financial derivative instruments that generally fix the commodity prices to be received for a portion of the company’s future oil and gas production. We expanded our hedging program in April 2005 and, as of September 30, 2005, had costless collars and fixed-priced swaps covering at least 75% of the company’s 2005 and 2006 expected eligible production (after the possible divestitures) and approximately 50% of its 2007 expected eligible production. Eligible production excludes oil production in China.

	October - December 2005					2006					2007
	Average Contract Price ($/Barrel)		Average Daily Volume (Barrels)			Average Contract Price ($/Barrel)		Average Daily Volume (Barrels)			Average Contract Price ($/Barrel)		Average Daily Volume (Barrels)
Crude Oil (WTI) -
Hedge:
Fixed price swaps	$	29.23		3,000	(a)		-		-			-		-
	$	50.62		18,500		$	53.14		18,781		$	51.45		27,250

Costless collars	$	28.50 - $31.89		14,000	(b)	$	27.00 - $30.58		19,000	(b)		-		-
	$	42.40 - $57.75		24,000		$	45.00 - $65.58		18,288		$	45.00 - $61.43		18,000

Nonhedge:
Three-way collars(1)	$	25.00 - $28.23		5,000	(a)	$	25.00 - $28.65		2,000	(a)		-		-
Three-way average floor	$	20.93				$	20.88
				64,500					58,069					45,250

Crude Oil (Brent) -
Hedge:
Fixed price swaps	$	47.06		28,500		$	53.05		12,512		$	49.91		12,750

Costless collars	$	40.02 - $54.98		26,000		$	43.00 - $62.51		30,512		$	43.00 - $60.11		12,750
				54,500					43,024					25,500

	October - December 2005					2006					2007
	Average Contract Price ($/MMBtu)		Average Daily Volume (MMBtu)			Average Contract Price ($/MMBtu)		Average Daily Volume (MMBtu)			Average Contract Price ($/MMBtu)		Average Daily Volume (MMBtu)
Natural Gas (NYMEX) -
Hedge:
Fixed price swaps	$	4.42		55,000	(a)		-		-			-		-
	$	7.54		293,261		$	7.53		196,000		$	7.03		265,000

Costless collars	$	5.00 - $6.25		280,000	(b)	$	4.75 - $ 5.50		340,000	(b)		-		-
	$	6.58 - $9.32		308,424		$	6.00 - $10.80		197,000		$	6.00 - $9.03		265,000

Nonhedge:
Costless collars	$	4.09 - $5.57		60,000	(a)		-		-			-		-

Three-way collars (1)		-		-		$	4.00 - $6.00		20,000	(a)		-		-
Three-way average floor						$	3.04
				996,685					753,000					530,000

Basis Swaps vs. NYMEX -
Hedge:
CIG (2)	$	0.60		48,587		$	0.42		21,233		$	0.39		20,000	(5)
NWPL (3)	$	0.61		55,951		$	0.35		19,932		$	0.20		15,000	(6)
HSC (4)	$	0.13		23,587			-		-			-		-

Nonhedge:
CIG	$	0.73		40,435			-		-			-		-
NWPL	$	0.68		2,527			-		-			-		-
HSC	$	0.24		23,370			-		-			-		-

The fair value of the company’s oil and gas commodity derivative instruments was determined based on prices actively quoted, generally NYMEX and Dated Brent prices. 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. Gains and losses on derivatives designated as cash flow hedges are deferred in accumulated other comprehensive income (loss) and reclassified into earnings when the hedged forecasted transactions affect earnings. Net after-tax losses on oil and gas derivatives in accumulated other comprehensive loss were $1.7 billion at September 30, 2005, and related to a portion of the company’s expected production through 2007. During the next 12 months, the company expects to reclassify net after-tax losses of $1.1 billion from accumulated other comprehensive loss into earnings, assuming no further changes in the fair value of the related contracts. This excludes $171 million of net after-tax losses associated with derivatives of our North Sea oil and gas business, which will be recognized in income from discontinued operations, as a component of gain on sale, in connection with the expected completion of the divestiture transactions in November 2005.

The company is exposed to changes in interest rates, primarily as a result of its debt obligations. The fair value of our fixed-rate debt is affected by changes in market interest rates. To manage this risk, historically, we entered into interest rate swap agreements to effectively change the interest paid on a portion of our fixed-rate debt to a variable rate. No significant changes in our interest rate swap positions have occurred since December 31, 2004. Our variable-rate debt exposes us to the risk of higher interest cost if market interest rates increase. Based on the current mix of variable- and fixed-rate debt and our debt repayment plans, we do not expect the impact of changes in interest rates to be material to our earnings or cash flows.

The U.S. dollar is the functional currency for the company’s international operations, except for its European chemical operations, for which the euro is the functional currency. The company’s risk exposure to changes in foreign currency exchange rates arises primarily from its European chemical operations and exploration and production operations in the North Sea. As discussed under Overview and Recent Developments, we expect to complete the divestiture of our North Sea operations in November 2005 and are pursuing the separation of all of our chemical operations. The company does not believe that its current level of foreign currency risk exposure is material to its results of operations and cash flows and expects the existing exposure to be further reduced following the planned divestitures. Accordingly, the company does not maintain material foreign currency derivative positions.

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of the company's management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the company's disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures are effective in alerting them in a timely manner to material information relating to the company (including its consolidated subsidiaries) required to be included in the company's periodic SEC filings.

Statements in this quarterly report regarding the company's or management's intentions, beliefs or expectations, or that otherwise speak to future events, are “forward-looking statements.”Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Accordingly, future results and developments discussed in these statements may be affected by numerous factors and risks, such as the accuracy of the assumptions that underlie the statements, the timing, manner and success of the planned separation of Kerr-McGee’s chemical business and the divestiture of certain oil and gas properties, the success of the oil and gas exploration and production program, drilling risks, the market value of Kerr-McGee's products, uncertainties in interpreting engineering data, demand for consumer products for which Kerr-McGee's businesses supply raw materials, the financial resources of competitors, changes in laws and regulations, the ability to respond to challenges in international markets, including changes in currency exchange rates, political or economic conditions, trade and regulatory matters, general economic conditions, and other factors and risks identified in the Risk Factors section of the company's latest Annual Report on Form 10-K and other SEC filings. Actual results and developments may differ materially from those expressed in this quarterly report.

On September 8, 2003, the Environmental Protection Division (EPD) of the Georgia Department of Natural Resources issued a unilateral Administrative Order to our subsidiary, Kerr-McGee Pigments (Savannah) Inc., claiming that the Savannah plant exceeded emission allowances provided for in the facility's Title V air permit. On September 19, 2005, the EPD rescinded the Administrative Order and filed a Withdrawal of Petition for Hearing on Civil Penalties. Accordingly, the proceeding on administrative penalties has been dismissed. However, the EPD’s most recent actions do not resolve the alleged violations, and representatives of the company, EPD and the U.S. Environmental Protection Agency are engaged in discussions to resolve the existing air permit disputes and potential civil penalties. The company believes that penalties, if any, related to this matter will not have a material adverse effect on the company.

	Exhibit No.
	4.1	Supplemental Indenture, dated September 21, 2005, amending the Indenture, dated as of August 1, 2001, between Kerr-McGee and Citibank, filed as Exhibit 99.1 to the current report on Form 8-K dated September 27, 2005, and incorporated herein by reference.

	10.1	Sale and Purchase Agreement between Kerr-McGee North Sea (U.K.) Limited (“KM North Sea”) and Centrica Resources Limited (“Centrica”), dated August 6, 2005, pursuant to which KM North Sea agreed to sell its non-operating interest in the Skene field assets to Centrica.

	10.2	Sale and Purchase Agreement between KM North Sea and Centrica, dated August 6, 2005, pursuant to which KM North Sea agreed to sell its non-operating interest in the Buckland field assets to Centrica.

	10.3	Letter Agreement between KM North Sea and Centrica dated August 30, 2005, amending (i) the Sale and Purchase Agreement between KM North Sea and Centrica, dated August 6, 2005, pursuant to which KM North Sea agreed to sell its nonoperating interest in the Skene field assets to Centrica and (ii) the Sale and Purchase Agreement between KM North Sea and Centrica, dated August 6, 2005, pursuant to which KM North Sea agreed to sell its nonoperating interest in the Buckland field assets to Centrica.

	10.4	Sale and Purchase Agreement between KM North Sea and Talisman North Sea Limited (“Talisman”), dated September 30, 2005, pursuant to which KM North Sea agreed to sell its nonoperating interest in the Andrew field assets to Talisman.

	10.5	Sale and Purchase Agreement between Kerr-McGee Oil (U.K.) Limited (“KM Oil”) and Centrica, dated August 6, 2005, pursuant to which KM Oil agreed to sell its nonoperating interest in the Brae field assets to Centrica.


	10.6	Sale and Purchase Agreement between KM Denmark Overseas ApS (“KM Denmark”) and Centrica Canada Limited (“Centrica Canada”), dated August 6, 2005, pursuant to which KM Denmark agreed to sell 100% of the stock of Kerr-McGee Canada Limited (“KM Canada”) to Centrica Canada.

	10.7	Sale and Purchase Agreement between KM Denmark, Alnery No. 2524 Limited (“Maersk”), the Company and A.P. Moller-Maersk A/S, dated August 7, 2005, pursuant to which KM Denmark agreed to sell all of the company’s remaining North Sea assets through the sale of 100% of the stock of Kerr-McGee (G.B.) Limited and Kerr-McGee Norway AS to Maersk.

	10.8	Sale and Purchase Agreement between KM North Sea and Amerada Hess Limited (“Hess”), dated September 30, 2005, pursuant to which KM North Sea agreed to sell its nonoperating interest in the UKCS License 103 Area W to Hess.

	10.9	Amendment No. 1 to the Kerr-McGee Corporation Supplemental Executive Retirement Plan Amended and Restated Effective as of February 26, 1999, dated October 19, 2005.

	31.1	Certification pursuant to Securities Exchange Act Rule 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification pursuant to Securities Exchange Act Rule 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Delaware	73-1612389
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

	Assumptions				Weighted-Average
	Risk-Free	Expected	Expected	Expected	Fair Value of
	Interest Rate	Dividend Yield	Life (years)	Volatility	Options Granted
2005	3.9%	3.5%	6.0	27.4%	$12.50
2004	3.5	3.6	5.8	22.6	8.63

(Millions of dollars)		Gross Proceeds
Completed Divestiture Transactions -
September	Nonoperated North Sea fields	$ 554	(1)
November	Nonoperating interest in gas processing facility	156

Expected Divestiture Transactions -
Fourth quarter	Remaining oil and gas operations in the North Sea	$2,950	(2)
Fourth quarter	Selected oil and gas properties onshore in the U.S.	476	(2)

		Applicable Interest Rate Margin
		At September 30, 2005		Over the Term
	Maturity	ABR	Eurodollar	ABR	Eurodollar
Revolving Facility	May 2010	1.25%	2.25%	0.25 - 1.25%	1.25 - 2.25%
Tranche X Term Loan	May 2007	1.25%	2.25%	1.25%	2.25%
Tranche B Term Loan	May 2011	1.50%	2.50%	1.25 - 1.50%	2.25 - 2.50%


(Millions of dollars)		Gross Proceeds
Completed Divestiture Transactions -
September	Nonoperated North Sea fields	$	554	(1)
November	Nonoperating interest in gas processing facility		156

Expected Divestiture Transactions -
Fourth quarter	Remaining oil and gas operations in the North Sea	$	2,950	(2)
Fourth quarter	Selected oil and gas properties onshore in the U.S.		476	(2)

	Scheduled
(Millions of dollars)	Maturities		(1)

Fourth quarter of 2005	$	116	(2)
2006		323
2007		1,570	(3)
2008		23
2009		23
2010		1,080
Thereafter		3,210
Total	$	6,345

			Debt Issue
	Transaction		Costs
(Millions of dollars)	Costs		Written Off		Total

Tranche X term loan repayment	$	-	$	5	$	5
Consent solicitation costs		4		-		4
Loss on early repayment and modification of debt	$	4	$	5	$	9

			Amount of Prepayment
Period	Assets Divested		Mandatory		Optional		Total
			(Millions of dollars)
September		Nonoperated North Sea fields	$	504	$	96	$	600
November		Nonoperating interest in gas processing facility		111		39		150
			$	615	$	135	$	750

	Dismantlement			Personnel
(Millions of dollars)	and Closure			Costs			Total

Balance at December 31, 2004	$	10		$	8		$	18
Provisions		-			18			18
Payments / Adjustments		(4	)		(5	)		(9	)
Balance at September 30, 2005	$	6		$	21		$	27

				Reserves for
	Reserves for			Environmental			Reimbursements
(Millions of dollars)	Litigation			Remediation ⁽¹⁾			Receivable

Balance at December 31, 2004	$	39		$	255		$	94
Provisions / Accruals		-			73			29
Payments / Settlements		(15	)		(49	)		(70	)
Balance at September 30, 2005	$	24		$	279		$	53

	North Sea		Percent
	Business		of Total
Proved reserves at December 31, 2004
(millions of barrels of oil equivalent)		242		20	%
For the nine months ended September 30, 2005:
Average daily production -
Crude oil and condensate (thousands of barrels per day)		62		36	%
Natural gas (millions of cubic feet per day)		81		8	%
Energy equivalent volumes produced (thousands of barrels
of oil equivalent per day)		76		21	%

	Increase (Decrease) in
(Millions of dollars)	Total Debt			Total Equity
Repurchases of common stock	$	-		$	(4,225	)
Conversion of 5.25% debentures to common stock		(600	)		593
Exercises of employee stock options		-			206
Gross proceeds from borrowings		4,250			-
Repayment of debt -
Maturity of 5.375% Notes		(350	)		-
Paydown on term loans		(606	)		-
Scheduled payments and maturities of other debt		(42	)		-

	March 31, 2005	September 30, 2005
Standard & Poor’s	BBB-	BB+
Moody’s Investors Service	Baa3	Ba3

	Years of Maturity																					Fair
																There-						Value at
(Millions of dollars)	2005			2006			2007			2008			2009			after			Total ⁽²⁾			9/30/05

Fixed-rate debt -
Principal amount	$	-		$	-		$	-		$	-		$	-		$	2,225		$	2,225		$	2,386
Weighted-average
interest rate		-			-			-			-			-			7.15	%		7.15	%

Variable-rate debt ⁽¹⁾-
Principal amount	$	114		$	329		$	1,572		$	23		$	23		$	2,149		$	4,210		$	4,210
Weighted-average
interest rate		9.40	%		6.77	%		6.10	%		6.31	%		6.31	%		6.31	%		6.35	%


Period	Total Number of Shares Purchased ^(a)		Average Price Paid per Share ^(a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs

July 1-31, 2005		13,606	$	71.27		-	$	-
August 1-31, 2005		6,145		50.60		-		-
September 1-30, 2005		15,935		78.64		-		-
Total		35,686	$	71.00		-	$	-

Date: November 9, 2005	By:	/s/ John M. Rauh
		John M. Rauh
		Vice President and Controller
		and Chief Accounting Officer