Kerr Mcgee 10-Q 2005 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2005

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from _____ to _____

Commission File Number 1-16619

KERR-McGEE CORPORATION

(Exact Name of Registrant as Specified in its Charter)

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

123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102

(Address of Principal Executive Offices and Zip Code)

Registrant's telephone number, including area code (405) 270-1313

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes xNo o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes xNo o

Number of shares of common stock, $1.00 par value, outstanding as of July 31, 2005: 115,364,067.

	KERR-McGEE CORPORATION
	INDEX
		PAGE
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
	Condensed Consolidated Statement of Income for the Three and Six Months Ended June 30, 2005 and 2004	1
	Condensed Consolidated Balance Sheet at June 30, 2005 and December 31, 2004	2
	Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2005 and 2004	3
	Condensed Consolidated Statement of Comprehensive Income and Stockholders’ Equity for the Six Months Ended June 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		34
Item 3. Quantitative and Qualitative Disclosures about Market Risk		53
Item 4. Controls and Procedures		56
Forward-Looking Information		56
PART II - OTHER INFORMATION
Item 1. Legal Proceedings		56
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		57
Item 4. Submission of Matters to a Vote of Security Holders		57
Item 6. Exhibits		58
SIGNATURE		59

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

KERR-McGEE CORPORATION AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENT OF INCOME

(UNAUDITED)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Millions of dollars, except per-share amounts)	2005			2004			2005			2004
Revenues	$	1,850		$	1,091		$	3,567		$	2,200
Costs and Expenses
Costs and operating expenses		556			428			1,077			823
Selling, general and administrative expenses		110			78			202			159
Shipping and handling expenses		50			38			98			76
Depreciation and depletion		308			191			618			381
Accretion expense		8			6			17			13
Asset impairments		1			1			5			14
(Gain) loss an sale of assets		(24	)		4			(46	)		7
Exploration, including dry holes and amortization
of undeveloped leases		121			65			184			116
Taxes, other than income taxes		45			28			92			56
Provision for environmental remediation and restoration,
net of reimbursements		2			4			26			3
Interest and debt expense		81			56			142			113
Total Costs and Expenses		1,258			899			2,415			1,761
		592			192			1,152			439
Other Income (Expense)		(9	)		(7	)		(10	)		(7	)
Income from Continuing Operations before Income Taxes		583			185			1,142			432
Provision for Income Taxes		(211	)		(71	)		(415	)		(163	)
Income from Continuing Operations		372			114			727			269
Loss from Discontinued Operations
(net of income tax benefit of $1, $2, $1 and $3, respectively)		(2	)		(3	)		(2	)		(6	)
Net Income	$	370		$	111		$	725		$	263
Income (Loss) per Common Share
Basic -
Continuing operations	$	2.64		$	1.11		$	4.92		$	2.64
Discontinued operations		(.01	)		(.04	)		(.01	)		(.06	)
Net income	$	2.63		$	1.07		$	4.91		$	2.58
Diluted -
Continuing operations	$	2.61		$	1.05		$	4.79		$	2.48
Discontinued operations		(.01	)		(.04	)		(.01	)		(.06	)
Net income	$	2.60		$	1.01		$	4.78		$	2.42
Dividends Declared per Common Share	$	.05		$	.45		$	.50		$	.90

The accompanying notes are an integral part of this statement.

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KERR-McGEE CORPORATION AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

	June 30,			December 31,
(Millions of dollars)	2005			2004
ASSETS
Current Assets
Cash and cash equivalents	$	324		$	76
Accounts receivable		1,024			963
Inventories		362			329
Derivatives and other current assets		216			195
Deferred income taxes		337			324
Assets associated with properties held for sale		36			-
Total Current Assets		2,299			1,887
Property, Plant and Equipment		17,745			18,984
Less reserves for depreciation, depletion and amortization		(7,423	)		(8,157	)
		10,322			10,827
Investments, Derivatives and Other Assets		614			508
Goodwill and Other Intangible Assets		1,280			1,288
Assets Associated with Properties Held for Sale		662			8
Total Assets	$	15,177		$	14,518

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	546		$	644
Long-term debt due within one year		131			463
Income taxes payable		161			201
Derivative liabilities		800			372
Accrued liabilities		811			825
Liabilities associated with properties held for sale		19			-
Total Current Liabilities		2,468			2,505
Long-Term Debt		6,825			3,236
Noncurrent Liabilities
Deferred income taxes		2,203			2,177
Asset retirement obligations		475			503
Derivative liabilities		585			208
Other		592			571
Liabilities associated with properties held for sale		67			-
Total Noncurrent Liabilities		3,922			3,459
Contingencies and Commitments (Notes 13 and 14)
Stockholders' Equity
Common stock, par value $1 - 500,000,000 and 300,000,000 shares
authorized, 118,523,627 and 152,049,127 shares issued at
June 30, 2005 and December 31, 2004, respectively		119			152
Capital in excess of par value		3,580			4,205
Preferred stock purchase rights		1			2
Retained earnings (accumulated deficit)		(770	)		1,102
Accumulated other comprehensive loss		(641	)		(79	)
Common shares in treasury, at cost - 3,355,596 and 159,856 shares
at June 30, 2005 and December 31, 2004, respectively		(261	)		(8	)
Deferred compensation		(66	)		(56	)
Total Stockholders' Equity		1,962			5,318
Total Liabilities and Stockholders’ Equity	$	15,177		$	14,518

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

The accompanying notes are an integral part of this statement.

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KERR-McGEE CORPORATION AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(UNAUDITED)

	Six Months Ended
	June 30,
(Millions of dollars)	2005			2004
Cash Flows from Operating Activities
Net income	$	725		$	263
Adjustments to reconcile net income to net cash
provided by operating activities -
Depreciation, depletion and amortization		650			407
Deferred income taxes		265			111
Dry hole expense		91			26
Asset impairments		5			14
(Gain) loss on sale of assets		(46	)		7
Accretion expense		17			13
Provision for environmental remediation and restoration,
net of reimbursements		27			7
Other noncash items affecting net income		128			29
Changes in assets and liabilities		(284	)		(169	)
Net Cash Provided by Operating Activities		1,578			708
Cash Flows from Investing Activities
Capital expenditures		(808	)		(433	)
Dry hole costs		(75	)		(26	)
Acquisitions, net of cash acquired (1)		-			43
Proceeds from sales of assets		63			3
Proceeds from sale of investments		-			39
Other investing activities		(21	)		(26	)
Net Cash Used in Investing Activities		(841	)		(400	)
Cash Flows from Financing Activities
Issuance of common stock		159			7
Purchases of treasury stock		(250	)		-
Shares repurchased under the tender offer		(3,975	)		-
Dividends paid		(142	)		(91	)
Repayment of debt		(392	)		(347	)
Proceeds from borrowings		4,250			86
Credit Agreement financing costs		(58	)		-
Settlement of Westport derivatives		(80	)		-
Net Cash Used in Financing Activities		(488	)		(345	)
Effects of Exchange Rate Changes on Cash and Cash Equivalents		(1	)		-
Net Increase (Decrease) in Cash and Cash Equivalents		248			(37	)
Cash and Cash Equivalents at Beginning of Period		76			142
Cash and Cash Equivalents at End of Period	$	324		$	105

(1)   In June 2004, the company completed a merger with Westport Resources Corporation (Westport). In exchange for Westport’s common stock and options, Kerr-McGee issued stock valued at $2.4 billion, options valued at $34 million and assumed debt of $1 billion, for a total of $3.5 billion (net of $43 million of cash acquired).

The accompanying notes are an integral part of this statement.

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KERR-McGEE CORPORATION AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE

INCOME AND STOCKHOLDERS' EQUITY

(UNAUDITED)

(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 Income:
Net income		-			-			263			-			-			-			263
Other comprehensive loss		-			-			-			(200	)		-			-			(200	)
Comprehensive income																				63
Westport merger		49			2,402			-			-			-			(3	)		2,448
Exercise of stock options		1			10			-			-			-			-			11
Restricted stock activity		-			22			-			-			(3	)		(14	)		5
ESOP deferred compensation		-			-			-			-			-			3			3
Tax benefit from stock-based awards		-			2			-			-			-			-			2
Dividends declared ($.90 per share)		-			-			(91	)		-			-			-			(91	)
Balance at June 30, 2004	$	151		$	4,144		$	1,099		$	(245	)	$	(5	)	$	(67	)	$	5,077
Balance at December 31, 2004	$	152		$	4,205		$	1,102		$	(79	)	$	(8	)	$	(54	)	$	5,318
Comprehensive Income:
Net income		-			-			725			-			-			-			725
Other comprehensive loss		-			-			-			(562	)		-			-			(562	)
Comprehensive income																				163
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			156			-			-			-			-			159
Restricted stock activity		1			25			-		��	-			(3	)		(13	)		10
ESOP deferred compensation		-			-			-			-			-			3			3
Tax benefit from stock-based awards		-			21			-			-			-			-			21
Dividends declared ($.50 per share)		-			-			(80	)		-			-			-			(80	)
Balance at June 30, 2005	$	119		$	3,580		$	(770	)	$	(641	)	$	(261	)	$	(65	)	$	1,962

The accompanying notes are an integral part of this statement.

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KERR-McGEE CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2005

1. The Company, Basis of Presentation and Accounting Policies

The Company

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, Trinidad and the Danish and Norwegian sectors of the North Sea. 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 company recently made a number of strategic decisions in an effort to reposition Kerr-McGee as a pure-play exploration and production company and enhance value for its stockholders, as outlined below.  The company expects asset divestitures discussed below to result in gross proceeds in excess of $4 billion. 

·   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. The company is actively pursuing both separation alternatives and expects to determine the timing and manner of separation during the third quarter of 2005. As of August 5, 2005, criteria for reporting the results of the chemical business unit as discontinued operations had not been met.

·   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.

·   In April 2005, the company announced its decision to divest of lower-growth, shorter-life and higher-decline oil and gas properties.  In connection with the divestiture program, in June 2005, the company identified for sale certain oil and gas properties onshore in the United States and in the U.K. sector of the North Sea.  In August 2005, the company entered into agreements to sell all of its North Sea operations.  Information about these transactions in provided in Notes 6 and 17.  In addition, the company is considering for divestiture other selected U.S. onshore properties and Gulf of Mexico shelf properties.  The total combined divestitures are expected to represent approximately 25% to 30% of the company's proved reserves at December 31, 2004 and up to 35% of its average daily production for the first six 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 12 provides additional information regarding this transaction. The tender offer was financed with the net proceeds of borrowings, which are discussed in Note 8, and cash on hand.

·   In May 2005, the Board approved a recommendation to revise the company’s dividend policy to a level consistent with that of other pure-play exploration and production companies. Starting with the second quarter of 2005, the annual dividend was reduced from $1.80 to $.20 per share.

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Basis of Presentation

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.

Certain 2004 amounts included in these condensed consolidated financial statements have been reclassified to conform to the 2005 presentation. The Condensed Consolidated Statement of Income for the three and six months ended June 30, 2004 reflects results of the company’s former forest products operations as discontinued operations. Criteria for classification of the forest products business as discontinued operations were met in the fourth quarter of 2004. Additionally, as discussed in Note 6, the 2005 Condensed Consolidated Balance Sheet and the related Statement of Income include certain adjustments associated with properties that met the criteria for classification as held for sale.

Accounting Policies

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.

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Millions of dollars, except per-share amounts)	2005			2004			2005			2004
Net income, as reported	$	370		$	111		$	725		$	263
Add: stock-based employee compensation expense
included in reported net income, net of taxes		4			2			13			6
Deduct: stock-based compensation expense determined
using a fair-value method, net of taxes		(6	)		(6	)		(22	)		(13	)
Pro forma net income	$	368		$	107		$	716		$	256
Net income per share -
Basic -
As reported	$	2.63		$	1.07		$	4.91		$	2.58
Pro forma		2.61			1.03			4.85			2.51
Diluted -
As reported	$	2.60		$	1.01		$	4.78		$	2.42
Pro forma		2.56			.98			4.68			2.36

The fair value of each option granted in 2005 and 2004 was estimated as of the grant date using the Black-Scholes option pricing model with the following weighted-average assumptions:

	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

In December 2004, the Financial Accounting Standards Board 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, and that the effect on its results of operations will be comparable to the pro forma disclosures under FAS No. 123 presented above.

2. Comprehensive Income

Comprehensive income for the three and six months ended June 30, 2005 and 2004, is as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Millions of dollars)	2005			2004			2005			2004
Net income	$	370		$	111		$	725		$	263
After-tax changes in:
Loss on cash flow hedges		(89	)		(94	)		(548	)		(185	)
Foreign currency translation adjustments		(16	)		(3	)		(14	)		(10	)
Unrealized loss on available-for-sale securities		-			-			-			(5	)
Comprehensive income	$	265		$	14		$	163		$	63

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3. Derivative Instruments

The company is exposed to risk from fluctuations in crude oil and natural gas prices, foreign currency exchange rates and interest rates. To reduce the impact of these risks on earnings and to increase the predictability of its cash flows, the company enters into certain derivative contracts, primarily swaps and collars for a portion of its future oil and 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 are recognized in current earnings as a component of revenues. At June 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 $398 million of such loss into earnings during the next 12 months, assuming no further changes in the fair value of the related contracts.

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 effectively reduce 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 June 30, 2005 was a liability of $84 million.

The following tables summarize the balance sheet presentation of the company’s derivatives and the related collateral held by counterparties as of June 30, 2005 and December 31, 2004:

	As of June 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	$	68	$	34	$	(673	)	$	(564	)	$	(702	)
Acquired Westport positions		-		-		(120	)		(18	)		(18	)
Cash collateral		24		-		-			-			-
Gas marketing-related derivatives		6		-		(6	)		-			-
Foreign currency forward contracts		7		-		-			-			13
Interest rate swaps		-		-		(1	)		(3	)		-
Other derivatives		3		-		-			-			2
Total derivative contracts	$	108	$	34	$	(800	)	$	(585	)	$	(705	)

	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	$	54	$	12	$	(235	)	$	(188	)	$	(167	)
Acquired Westport positions		1		1		(123	)		(16	)		(7	)
Gas marketing-related derivatives		6		2		(6	)		(2	)		-
Foreign currency forward contracts		20		-		(6	)		-			16
Interest rate swaps		4		-		(1	)		(2	)		-
Other derivatives		3		-		(1	)		-			1
Total derivative contracts	$	88	$	15	$	(372	)	$	(208	)	$	(157	)

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

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The following tables summarize the classification of gain (loss) on derivative instruments in the Condensed Consolidated Statement of Income for the three- and six-month periods ended June 30, 2005 and 2004:

	Three Months Ended									Three Months Ended
	June 30, 2005									June 30, 2004
				Costs and			Other Income						Costs and		Other Income
	Revenues			Expenses			(Expense)			Revenues			Expenses		(Expense)
Hedge Activity:
Oil and gas commodity derivatives	$	(78	)	$	-		$	-		$	(156	)	$	-	$	-
Foreign currency contracts		-			(1	)		-			-			4		-
Interest rate swaps		-			(1	)		-			-			5		-
Other derivatives		-			1			-			-			1		-
Loss on hedge ineffectiveness		(35	)		-			-			-			-		-
Total hedging contracts		(113	)		(1	)		-			(156	)		10		-
Nonhedge Activity:
Oil and gas commodity derivatives -
Kerr-McGee positions		6			-			-			(10	)		-		2
Acquired Westport positions		6			-			-			15			-		-
Gas marketing-related derivatives		2			-			-			2			-		-
DECS call option(1)		-			-			-			-			-		(66	)
Other derivatives		-			-			(1	)		-			-		-
Total nonhedge contracts		14			-			(1	)		7			-		(64	)
Total derivative contracts	$	(99	)	$	(1	)	$	(1	)	$	(149	)	$	10	$	(64	)

	Six Months Ended							Six Months Ended
	June 30, 2005							June 30, 2004
				Costs and		Other Income					Costs and		Other Income
	Revenues			Expenses		(Expense)		Revenues			Expenses		(Expense)
Hedge Activity:
Oil and gas commodity derivatives	$	(115	)	$	-	$	-	$	(217	)	$	-	$	-
Foreign currency contracts		(1	)		-		-		-			8		-
Interest rate swaps		-			-		-		-			9		-
Other derivatives		-			1		-		-			1		-
Loss on hedge ineffectiveness		(44	)		-		-		(1	)		-		-
Total hedging contracts		(160	)		1		-		(218	)		18		-
Nonhedge Activity:
Oil and gas commodity derivatives -
Kerr-McGee positions		14			-		-		(10	)		-		2
Acquired Westport positions		(53	)		-		-		15			-		-
Gas marketing-related derivatives		4			-		-		4			-		(1	)
DECS call option (1)		-			-		-		-			-		(72	)
Other derivatives		-			-		1		-			-		(1	)
Total nonhedge contracts		(35	)		-		1		9			-		(72	)
Total derivative contracts	$	(195	)	$	1	$	1	$	(209	)	$	18	$	(72	)

⁽¹⁾ Other income (expense) for the three- and six-month periods ended June 30, 2004 also includes unrealized gains on Devon Energy Corporation common stock of $66 million and $74 million, respectively.

4. Accounts Receivable Sales

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.

- 9 -

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 or modifying its terms, the company elected to terminate the program by advancing the then outstanding balance of receivables sold of $165 million to the SPE, which in turn used the funds to repay the financial institution. The company then executed an Assignment and Sale Agreement whereby it acquired all outstanding receivables from the SPE in exchange for the forgiveness of all debt owed by the SPE to the company (including the $165 million advance mentioned above). Accounts receivable acquired in this transaction are being collected by the company as they become due.

During the quarters ended June 30, 2005 and 2004, the company sold $105 million and $304 million, respectively, of its pigment receivables, resulting in pretax losses reflected in other income (expense) of $1 million and $3 million, respectively. The company sold $384 million and $541 million of receivables during the first six months of 2005 and 2004, respectively, and had pretax losses of $4 million in each of those periods.

5. Inventories

Major categories of inventories at June 30, 2005 and December 31, 2004 are as follows:

	June 30,		December 31,
(Millions of dollars)	2005		2004
Chemicals and other products	$	249	$	236
Materials and supplies		103		85
Crude oil and natural gas liquids		10		8
Total	$	362	$	329

6. Exchanges, Divestitures and Impairments of Assets

Assets Held for Sale - In connection with the divestiture program discussed in Note 1, the company has identified for sale four packages of oil and gas properties located onshore in the United States and five packages of non-operated properties in the U.K. North Sea. These properties met the criteria for classification as held for sale in June 2005. Accordingly, associated assets and liabilities are classified as such in the accompanying June 30, 2005 Condensed Consolidated Balance Sheet. Based on the company’s expectation of selling prices for these packages less cost to sell in relation to their carrying values, no loss associated with assets held for sale was recognized in the second quarter of 2005. The company expects to close the sales of these properties by the end of the year.  One of the packages identified for sale would result in the sale of the company’s investment in the stock of a foreign subsidiary.  Upon concluding that such sale was likely to occur, the company recognized a tax benefit of $27 million related to the difference between the book and tax bases of its investment in the subsidiary during the second quarter of 2005.

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As discussed in Note 8, the company is required to use 100% of the net cash proceeds from sales of certain assets for debt repayment. Oil and gas properties identified as held for sale are subject to this requirement. Because proceeds from the sale of U.K. oil and gas properties will be remitted to the United States for debt repayment, in connection with classifying such properties as held for sale, the company recognized $11 million of U.S. deferred 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). 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 American Jobs Creation Act of 2004 discussed in Note 7.

In August 2005, the company entered into agreements to sell its North Sea oil and gas business.  Additional information regarding these transactions in provided in note 17.

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.

In the second quarter of 2005, the company sold its 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 field and $27 million in cash. The company recognized a gain of $25 million in connection with this transaction.

Exploratory Drilling Costs - At June 30, 2005, the company had capitalized exploratory drilling costs of approximately $168 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.

Asset Impairments - The chemical - pigment operating unit began production through a new high-productivity oxidation line at the Savannah, Georgia, chloride process pigment plant in January 2004. This new technology results in low-cost, incremental capacity increases through modification of existing chloride oxidation lines and allows for improved operating efficiencies through simplification of hardware configurations and reduced maintenance requirements. The company continues to evaluate the performance of this new oxidation line and expects to determine how the Savannah site might be reconfigured to exploit its capabilities later in 2005. The possible reconfiguration of the Savannah site, if any, could include redeployment or idling of certain assets and reduction of their future useful lives, resulting in the acceleration of depreciation expense and the recognition of other charges. However, the current production demands make it less likely that any existing production lines would be idled in the near term.

7. Income Taxes

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, $200 million of which were repatriated during the quarter ended June 30, 2005, resulting in the recognition of income tax expense of $12 million. The company may repatriate up to an additional $300 million in extraordinary dividends under the provisions of the Act. Management has not yet decided whether, and to what extent, additional amounts of foreign earnings will be repatriated. Accordingly, the accompanying financial statements do not reflect any additional provision for taxes on unremitted foreign earnings, except for the provision of $11 million discussed in Note 6. Additional income tax expense of up to $16 million may be recognized in the quarter ending September 30, 2005, when the company expects to decide whether additional amounts of certain foreign earnings will be repatriated under the provisions of the Act.

- 11 -

The effective tax rate for income from continuing operations for the second quarter of 2005 is 36.2% and includes effects of the following:

·   As discussed in Note 6, during the second quarter of 2005 the company recognized an income tax benefit of $27 million and tax expense of $11 million related to certain oil and gas properties held for sale, resulting in a corresponding increase (decrease) in the second-quarter effective tax rate of (4.6%) and 1.9%, respectively.

·   Income tax expense of $12 million recognized in connection with the repatriation of $200 million in foreign earnings increased the effective tax rate by 2.1%.

8. Debt

Long-term debt consisted of the following at June 30, 2005 and December 31, 2004:

	June 30,			December 31,
(Millions of dollars)	2005			2004
Debentures -
5.25% Convertible subordinated debentures due February 15, 2010
(convertible at $61.08 per share, subject to certain adjustments)	$	-		$	600
7% Debentures due November 1, 2011, net of unamortized debt
discount of $74 and $77 (14.25% effective rate)		176			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, net of discount of $1 for fair
value hedge adjustment in both 2005 and 2004		108			108
5.875% Notes due September 15, 2006 (5.89% effective rate)		307			307
6.625% Notes due October 15, 2007, net of discount of $3 and $2
for fair value hedge adjustment		147			148
6.875% Notes due September 15, 2011, net of unamortized debt discount
of $1 in both 2005 and 2004 (6.90% effective rate)		674			674
6.95% Notes due July 1, 2024, net of unamortized debt discount of $5
in both 2005 and 2004 (7.02% effective rate)		645			645
7.875% Notes due September 15, 2031, net of unamortized debt
discount of $1 and $2 (7.91% effective rate)		499			498
Term Loans -
Variable rate Tranche X term loan due May 24, 2007 (1)		2,000			-
Variable rate Tranche B term loan due in installments through May 24, 2011 (1) (2)		2,250			-
Commercial paper		-			41
Guaranteed Debt of Employee Stock Ownership Plan 9.61% Notes
due in installments through January 2, 2005		-			1
		6,956			3,699
Long-term debt due within one year		(131	)		(463	)
Total	$	6,825		$	3,236

⁽¹⁾   The term loans are subject to certain mandatory prepayment provisions, as more fully described below.

⁽²⁾   The scheduled principal payments on the Tranche B term loan are as follows: twenty quarterly payments of approximately $6 million commencing September 30, 2005, followed by four payments of approximately $534 million quarterly commencing September 30, 2010 through the maturity date.

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The following summarizes the scheduled maturities of our debt at June 30, 2005:

	Scheduled
(Millions of dollars)	Maturities (1)
Six months ending December 31, 2005	$	119
2006		329
2007		2,169
2008		23
2009		23
2010		1,080
Thereafter		3,213
Total	$	6,956

⁽¹⁾   These amounts are inclusive of the unamortized discount on issuance of $81 million and the discount arising from fair value hedge adjustments of $4 million.

In February 2005, the company called for redemption all of the $600 million aggregate principal amount of its 5.25% convertible subordinated debentures due 2010 at a price of 102.625%. Prior to March 4, 2005, the redemption date, all of the debentures were converted by the holders into approximately 9.8 million shares of common stock.

As discussed in Note 12, 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).

		Applicable Interest Rate Margin
		At June 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%

Revolving Facility - The $1.25 billion Revolving Facility provides for borrowings and issuances of letters of credit. The commitment fee payable on the unused portion of the Revolving Facility is currently set at 0.5% annually. At June 30, 2005, no borrowings were outstanding under the Revolving Facility and outstanding letters of credit totaled $70 million. The company had total unused bank and revolving lines of credit of $1.2 billion at June 30, 2005.

Tranche X and Tranche B Term Loans - The term loans were fully funded at closing, with proceeds used to finance the tender offer and to pay fees and expenses associated with the Credit Agreement. From origination through June 30, 2005, the weighted average interest rates on the Tranche X and Tranche B term loans were 5.41% and 5.87%, respectively.

The company may make prepayments on the term loans at any time without penalty. Additionally, the term loans are subject to the following mandatory prepayment provisions:

·   As long as the Tranche X loan is outstanding, 50% of the net cash proceeds, as defined, of certain equity issuances;

- 13 -

·   100% of the net cash proceeds, as defined, from incurrence of certain indebtedness;

·   Subject to certain exceptions, 100% of the net cash proceeds, as defined, from asset disposals; and

·   Annually, a specified percentage of excess cash flow, as defined, ranging from zero to 50%. This prepayment requirement is reduced or eliminated upon repayment of the Tranche X loan and the achievement of a Consolidated Leverage Ratio below specified thresholds. Excess cash flow as calculated under the Credit Agreement is reduced by mandatory prepayments made with the net cash proceeds from asset disposals.

As discussed in Note 17, in August 2005, the company entered into agreements to sell its North Sea oil and gas business.  The net proceeds realized in connection with such sales will be used to repay debt.

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. Additionally, as discussed in Note 16, the company’s obligations under certain of the existing registered debentures and notes are unconditionally guaranteed, jointly and severally, by two of the company’s subsidiaries.

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):

·   Consolidated Leverage Ratio of no more than 4:1 in 2005, 3.75:1 in 2006 and 3.50:1 thereafter

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

·   Asset Coverage Ratio of more than 1.25:1 in 2005, 1.50:1 in 2006 and 1.75:1 thereafter

The company’s current dividend level ($.20 per share annually) is expected to be in compliance with the annual limitation on dividend payments of $50 million.

For the second quarter of 2005, the company had a Consolidated Leverage Ratio of approximately 2:1, a Consolidated Interest Coverage Ratio of 11:1 and an Asset Coverage Ratio of 1.79:1, and was in compliance with its other debt covenants.

9. Exit or Disposal Activities

Following are the changes in the reserve for exit activities during the six months ended June 30, 2005. Except as discussed below, no significant changes in the status of exit or disposal activities occurred during this period.

	Dismantlement			Personnel
(Millions of dollars)	and Closure			Costs			Total
Balance at December 31, 2004	$	10		$	8		$	18
Provisions		1			8			9
Payments / Adjustments		(3	)		(3	)		(6	)
Balance at June 30, 2005	$	8		$	13		$	21

- 14 -

As discussed in Note 1, the company plans to sell or spin off its chemical business unit and divest of 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 6 to 18 months. A total of $34 million will be payable under these programs 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 of these programs, $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. During the second quarter of 2005, the company recognized $7 million as a component of selling, general and administrative expenses in connection with the retention programs. The remaining cost of $27 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.

10. Employee Stock-Based Compensation and Benefit 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.

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 June 30, 2005, no awards have been made under this plan.

Retirement and Postretirement Benefits - The company has both noncontributory and contributory defined-benefit retirement plans and company-sponsored contributory postretirement plans for health care and life insurance. Most employees are covered under the company’s retirement plans, and substantially all U.S. employees may become eligible for postretirement benefits if they reach retirement age while working for the company.

The components of net periodic cost for the second quarter of 2005 and 2004 are as follows:

							Postretirement
	Retirement Plans						Health and Life Plans
	Three Months Ended						Three Months Ended
	June 30,						June 30,
(Millions of dollars)	2005			2004			2005			2004
Net periodic cost -
Service cost	$	9		$	7		$	1		$	-
Interest cost		17			18			4			5
Expected return on plan assets		(26	)		(29	)		-			-
Net amortization -
Prior service cost		2			2			(1	)		1
Net actuarial loss		2			1			1			1
Total net periodic cost	$	4		$	(1	)	$	5		$	7

- 15 -

The components of net periodic cost for the first six months of 2005 and 2004 are as follows:

							Postretirement
	Retirement Plans						Health and Life Plans
	Six Months Ended						Six Months Ended
	June 30,						June 30,
(Millions of dollars)	2005			2004			2005			2004
Net periodic cost -
Service cost	$	18		$	14		$	2		$	1
Interest cost		35			36			8			10
Expected return on plan assets		(52	)		(58	)		-			-
Net amortization -
Prior service cost		4			4			(2	)		1
Net actuarial loss		3			2			2			2
Total net periodic cost	$	8		$	(2	)	$	10		$	14

11. Earnings Per Share

The following tables set forth the computation of basic and diluted earnings per share from continuing operations for the three and six months ended June 30, 2005 and 2004. All options outstanding at June 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 six months ended June 30, 2005. As discussed in Note 8, 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.

	Three Months Ended June 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	$	372		141	$	2.64	$	114		104	$	1.11
Effect of dilutive securities:
5.25% convertible debentures		-		-				6		10
Restricted stock		-		1				-		1
Stock options		-		1				-		-
Diluted earnings per share	$	372		143	$	2.61	$	120		115	$	1.05

	Six Months Ended June 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	$	727		148	$	4.92	$	269		102	$	2.64
Effect of dilutive securities:
5.25% convertible debentures		4		3				11		10
Restricted stock		-		1				-		1
Stock options		-		1				-		-
Diluted earnings per share	$	731		153	$	4.79	$	280		113	$	2.48

- 16 -

12. Capital Stock

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

As discussed in Note 1, in March 2005, the company's Board of Directors authorized a share repurchase program initially set at $1 billion, with an expectation to expand the program as the chemical business separation proceeded. Before terminating this program in connection with the Board's approval of the tender offer discussed below, the company repurchased 3.1 million shares 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 Credit Agreement discussed in Note 8 and cash on hand.

Changes in common stock issued and treasury stock held for the six-month periods ended June 30, 2005 and 2004, are as follows:

	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		268			-
Issuance of restricted stock		448			-
Forfeiture of restricted stock		-			74
Balance at June 30, 2004		150,557			106
Balance at December 31, 2004		152,049			160
Exercise of stock options		2,935			-
Issuance of restricted stock		450			-
Forfeiture of restricted stock		-			51
Shares issued upon conversion of 5.25% debentures		9,818			-
Purchases of treasury shares		-			3,145
Shares repurchased and retired		(46,728	)		-
Balance at June 30, 2005		118,524			3,356

- 17 -

13. Contingencies

The following table summarizes the contingency reserve balances, provisions, payments and settlements for the six-month period ended June 30, 2005, as well as balances, accruals and receipts of environmental cost reimbursements from other parties.

				Reserves for
	Reserves for			Environmental			Reimbursements
(Millions of dollars)	Litigation			Remediation (1)			Receivable
Balance at December 31, 2004	$	39		$	255		$	94
Provisions / Accruals		-			48			21
Payments / Settlements		(15	)		(22	)		(69	)
Balance at June 30, 2005	$	24		$	281		$	46

⁽¹⁾   Provisions for environmental remediation include $1 million related to the company’s former forest products operations reflected in the Condensed Consolidated Statement of Income as a component of loss from discontinued operations, net of taxes.

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

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

·   some sites are in the early stages of investigation, and other sites may be identified in the future;

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

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

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

·   environmental laws and regulations, as well as enforcement policies, are continually changing, and the outcome of court proceedings and discussions with regulatory agencies are inherently uncertain;

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

·   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.

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Environmental Matters

Henderson, Nevada

In 1998, Kerr-McGee Chemical LLC (Chemical), an affiliate of the company, decided to exit the ammonium perchlorate business. At that time, Chemical curtailed operations and began preparation for the shutdown of the associated production facilities in Henderson, Nevada, that produced ammonium perchlorate and other related products. Manufacturing 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 manufacturing 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 Chemical. The ammonium perchlorate produced at the Henderson facility was used primarily in federal government defense and space programs. Perchlorate has been detected in nearby Lake Mead and the Colorado River, which contribute to municipal water supplies in Arizona, southern California and southern Nevada.

Chemical 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, Chemical entered into consent orders with the Nevada Division of Environmental Protection (NDEP) that require Chemical to implement both interim and long-term remedial measures to capture and remove perchlorate from groundwater. In April 2005, Chemical 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, Chemical 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 Chemical 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, which, to date, have not been formally established by 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 Chemical is required to perform.

Financial Reserves - As of June 30, 2005, reserves for environmental remediation at Henderson totaled $37 million. 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, Chemical initiated litigation against the United States seeking contribution for 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, and was the largest consumer of products produced at the plant. The discovery stage of litigation is substantially complete, and the parties have filed certain pretrial motions that are being considered by the court. Although the outcome of the litigation is uncertain, Chemical 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.

In addition, on July 26, 2004, the company was served with a lawsuit, which was filed in the United States District Court for the District of Arizona. The lawsuit, Alan Curtis and Linda Curtis v. City of Bullhead City, et al., in which the company is one of several defendants (the Defendants), alleged various causes of action under a variety of common law theories and federal environmental laws and sought recovery for damages allegedly caused by the alleged exposure to and the migration of various chemical contaminants contained in the Colorado River. The two plaintiffs, who did not sue on behalf of any other party, also sought an order requiring the Defendants to remediate the contamination. On July 18, 2005, the District Court dismissed the lawsuit.

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

At June 30, 2005, the company had received $3 million of cost reimbursement under the insurance policy, and expects additional estimated aggregate cleanup costs of $92 million less the $61 million self-insured retention  to be covered by the policy (for a net amount of $31 million in additional reimbursement).  The company believes that additional reimbursement of approximately $31 million is probable, and, accordingly, the company has recorded a receivable in the financial statements for that amount.

West Chicago, Illinois

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

Closed Facility- Pursuant to agreements reached in 1994 and 1997 among Chemical, the City of West Chicago (the City) and the State regarding the decommissioning of the closed West Chicago facility, Chemical 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 Chemical as a Potentially Responsible Party (PRP) in these four areas. Chemical 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. Chemical 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 has been incorporated in a consent decree, which must be entered by a federal court. The consent decree was lodged with the court in April 2005 and is expected to be approved by the court in due course. 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.

Financial Reserves - As of June 30, 2005, the company had reserves of $109 million for costs related to West Chicago. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time. The amount of the reserve is not reduced by reimbursements expected from the federal government under Title X of the Energy Policy Act of 1992 (Title X) (discussed below).

Government Reimbursement- Pursuant to Title X, the U.S. Department of Energy (DOE) is obligated to reimburse Chemical 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 June 30, 2005, Chemical had been reimbursed approximately $281 million under Title X.

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Reimbursements under Title X are provided by congressional appropriations. Historically, congressional appropriations have lagged Chemical's cleanup expenditures. As of June 30, 2005, the government’s share of costs incurred by Chemical but not yet reimbursed by the DOE totaled approximately $15 million. The company believes receipt of the $15 million government share in due course following additional congressional appropriations is probable and has reflected that amount as a receivable in the accompanying financial statements. The company will recognize recovery of the government's share of future remediation costs for the West Chicago sites as Chemical incurs the cash expenditures.

Milwaukee, Wisconsin

In 1976, Chemical 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 the wood-treatment process. In 1984, EPA designated the Milwaukee wood-treatment facility as a Superfund site under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), listed the site on the NPL and named Chemical a PRP. Chemical 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 ongoing groundwater treatment; therefore, it is not known 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, terms for addressing the tributary creek were agreed upon with EPA, after which Chemical 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. Chemical has not yet agreed with relevant regulatory authorities regarding remedial designs for the lower portion of the tributary creek.

Financial Reserves - As of June 30, 2005, the company had reserves of $6 million for the costs of the remediation work described above. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time.

New Jersey Wood-Treatment Site

Chemical and its ultimate parent were named in 1999 as PRPs under CERCLA at a former wood-treatment site in New Jersey at which EPA is conducting a cleanup. On April 15, 2005, Chemical and its ultimate parent received a letter from EPA asserting that they are liable under CERCLA as former owners or operators 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. Chemical did not operate the site, which had been sold to a third party before Chemical 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 they have been named as such by EPA. The company intends to vigorously defend against EPA’s claim. The company has not recorded a reserve for the site, as it is not possible to reliably estimate the liability, if any, it may have for the site because of the aforementioned uncertainties and the potential existence of other PRPs.

Cushing, Oklahoma

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

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Subsequent regulatory changes required more extensive remediation at the site. In 1990, the affiliate 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 with oversight of the Oklahoma Department of Environmental Quality. Soil remediation to address hydrocarbon contamination is expected to continue for 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.

Additionally, in 1993, the affiliate received a decommissioning license from the Nuclear Regulatory Commission (NRC), the successor to AEC’s licensing authority, to perform certain cleanup of uranium and thorium residuals. All known radiological contamination has been removed from the site and shipped to a licensed disposal facility.

Financial Reserves - As of June 30, 2005, the company had reserves of $15 million for the costs of the ongoing remediation and decommissioning work described above. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time.

Ambrosia Lake, New Mexico

From the late 1950s until 1988, affiliates of the company operated a uranium mining and milling operation at Ambrosia Lake near Grants, New Mexico, pursuant to a license issued by the AEC (now the NRC). When the operation was sold to an unaffiliated third party in 1989, an affiliate of the company 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 the 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, the company’s affiliate 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 non-radiological constituents in the groundwater at the site. The request to cease groundwater treatment, which is being reviewed by the NRC, will be 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.

Financial Reserves - As of June 30, 2005, the company had reserves of $14 million for the costs of the remediation activities described above, including groundwater remediation. This amount includes $8 million added to the reserve in the second quarter of 2005, as a result of the discussions between the current owner and the NRC, and primarily to cover additional costs associated with pond closure, rock placement, and surface water channels. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time.

Los Angeles County, California

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

Financial Reserves - As of June 30, 2005, the company had environmental reserves of $24 million for this project. Although actual costs may differ from current estimates, the amount of any revisions in remediation costs cannot be reasonably estimated at this time.

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Other Sites

In addition to the sites described above, the company is responsible for environmental costs related to certain other sites. These sites relate primarily to wood-treating, chemical production, landfills, mining and oil and gas production and refining distribution and marketing. As of June 30, 2005, the company had remaining reserves of $76 million for the environmental costs in connection with 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.

Litigation and Claims

Coal Supply Contract

An affiliate of the company entered into a coal supply contract with Peabody Coaltrade, Inc. (“PCI”) in February 1998. In 1998, the company 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 company agreed to guarantee performance under the contract. PCI has notified the company of a threatened default by the assignee under the coal supply contract and that PCI may seek to hold the company 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.

CNR Contract

In 2002, an affiliate of the company 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.

Forest Products Litigation

Between 1999 and 2001, Chemical and its parent company were 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. Chemical has executed settlement agreements that are expected to resolve substantially all of the 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 Chemical and its affiliates on behalf of approximately 5,100 claimants in connection with Chemical’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 Chemical 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 Chemical in connection with a former wood-treatment plant located in Texarkana, Texas. In addition, on January 3, 2005, February 16, 2005, and March 11, 2005, 32 lawsuits were filed against Chemical 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. Chemical has resolved approximately 1,490 of the Hattiesburg claims pursuant to a settlement reached in April 2003, which has resulted in aggregate payments by Chemical of approximately $600,000.

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Chemical and its affiliates believe 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 are vigorously defending against them. The company has not provided a reserve for these lawsuits because, at this time, it cannot reasonably determine the probability of a loss, and the amount of loss, if any, cannot be reasonably estimated. The company believes that the ultimate resolution of the forest products litigation will not have a material adverse effect on the company.

Kemira

In 2000, Chemical acquired its titanium dioxide production facility in Savannah, Georgia, from Kemira Pigments Oy, a Finnish company, and its parent, Kemira, Oyj (together, “the Sellers”). After acquiring the facility, the company discovered that certain matters associated with environmental conditions and plant infrastructure were not consistent with representations made by the Sellers. Chemical sought recovery for breach of representations and warranties in a proceeding before the London Court of International Arbitration (LCIA). On May 9, 2005, Chemical received notice from the LCIA that the LCIA had found in favor of Chemical as to liability with respect to certain of the claims. The LCIA still must determine the amount of damages, and, in that regard, Chemical is seeking in excess of $40 million in damages, together with interest, costs and attorney fees. 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.

Other Matters

The company and/or its affiliates are parties to a number of legal and administrative proceedings involving environmental and/or other matters pending in various courts or agencies. In the ordinary course of its business, the company experiences disputes with federal, state, tribal and other regulatory authorities, as well as with private parties, regarding royalty payments. These disputes, individually and in the aggregate, are not expected to have a material adverse effect on the company. There are also proceedings associated with facilities currently or previously owned, operated or used by the company’s affiliates and/or their predecessors, some of which include claims for personal injuries and property damages. Current and former operations of the company’s affiliates also involve management of regulated materials and are subject to various environmental laws and regulations. These laws and regulations will obligate the company’s affiliates 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. Similar environmental regulations exist in foreign countries in which the company’s affiliates operate.

14. Commitments

In 2005, the company entered into additional drilling rig commitments to assure availability for executing our deepwater Gulf of Mexico drilling programs through the end of 2006. The company’s commitments under these arrangements total $246 million, a portion of which 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 $39 million and expect to incur $9 million of associated expenditures in 2005 and a total of $30 million in 2006 and 2007.

As of June 30, 2005, the company had outstanding letters of credit totaling $98 million (including letters of credit issued under the Revolving Facility discussed in Note 8).

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15. Business Segments

The company has three reportable segments: oil and gas exploration and production, production and marketing of titanium dioxide pigment, and production and marketing of other chemical products. As discussed in Note 1, the company is pursuing alternatives for the separation of its chemical business unit.

Segment performance is evaluated based on operating profit (loss), which represents the results of continuing operations before considering interest and debt expense, 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) for each of the company's business segments for the three and six months ended June 30, 2005 and 2004.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Millions of dollars)	2005			2004			2005			2004
Revenues
Exploration and production	$	1,494		$	765		$	2,877		$	1,599
Chemical - Pigment		331			303			642			555
Chemical - Other		25			23			48			46
Total Revenues	$	1,850		$	1,091		$	3,567		$	2,200
Operating Profit (Loss)
Exploration and production	$	686		$	263		$	1,341		$	593
Chemical - Pigment		32			14			64			21
Chemical - Other		2			-			(7	)		(3	)
Total Operating Profit		720			277			1,398			611
Interest and debt expense		(81	)		(56	)		(142	)		(113	)
Corporate expenses		(45	)		(26	)		(89	)		(57	)
Provision for environmental remediation and
restoration, net of reimbursements (1)		(2	)		(3	)		(15	)		(2	)
Other income (expense) (2)		(9	)		(7	)		(10	)		(7	)
Income from Continuing Operations
before Income Taxes	$	583		$	185		$	1,142		$	432

⁽¹⁾   Includes provisions, net of reimbursements, related to sites with no ongoing operations or various businesses in which the company’s affiliates are no longer engaged; for example, the refining and marketing of oil and gas and associated petroleum products, and the mining and processing of uranium and thorium. See Note 13.

⁽²⁾   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 $8 million and $10 million during the three months ended June 30, 2005 and 2004, respectively, and $15 million and $19 million during the six months ended June 30, 2005 and 2004, respectively. The carrying value of the company’s investment in Avestor at June 30, 2005 and December 31, 2004, was $82 million and $60 million, respectively.

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16. Condensed Consolidating Financial Information

The company’s 5.875% Notes due 2006, 6.875% Notes due 2011, 6.95% Notes due 2024 and 7.875% Notes due 2031, for a total principal amount of $2.1 billion, have been fully and unconditionally guaranteed, on a joint and several basis, by Kerr-McGee Chemical Worldwide LLC and Kerr-McGee Rocky Mountain Corporation. Additionally, Kerr-McGee Corporation has guaranteed all indebtedness of its subsidiaries. As a result of these guarantee arrangements, the company is required to present condensed consolidating financial information.

The following tables present condensed consolidating financial information for (a) Kerr-McGee Corporation, the parent company, (b) the guarantor subsidiaries and (c) the nonguarantor subsidiaries. The guarantor subsidiaries include Kerr-McGee Chemical Worldwide LLC and Kerr-McGee Rocky Mountain Corporation, wholly-owned subsidiaries of Kerr-McGee Corporation. Other income (expense) in the Condensed Consolidating Statement of Income for all periods presented includes equity interest in income (loss) of subsidiaries.

Kerr-McGee Corporation and Subsidiary Companies

Condensed Consolidating Statement of Income

For the Three Months Ended June 30, 2005

	Kerr-McGee			Guarantor			Non-Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues	$	-		$	274		$	1,576		$	-		$	1,850
Costs and Expenses
Costs and operating expenses		-			168			389			(1	)		556
Selling, general and administrative expenses		-			-			110			-			110
Shipping and handling expenses		-			3			47			-			50
Depreciation and depletion		-			30			278			-			308
Accretion expense		-			-			8			-			8
Asset impairments		-			-			1			-			1
Gain on sale of assets		-			-			(24	)		-			(24	)
Exploration, including dry holes and amortization
of undeveloped leases		-			2			119			-			121
Taxes, other than income taxes		-			7			38			-			45
Provision for environmental remediation
and restoration, net of reimbursements		-			3			(1	)		-			2
Interest and debt expense		72			3			101			(95	)		81
Total Costs and Expenses		72			216			1,066			(96	)		1,258
		(72	)		58			510			96			592
Other Income (Expense)		424			120			160			(713	)		(9	)
Income from Continuing Operations
before Income Taxes		352			178			670			(617	)		583
Benefit (Provision) for Income Taxes		18			(21	)		(208	)		-			(211	)
Income from Continuing Operations		370			157			462			(617	)		372
Loss from Discontinued Operations,
net of taxes		-			-			(2	)		-			(2	)
Net Income	$	370		$	157		$	460		$	(617	)	$	370

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Kerr-McGee Corporation and Subsidiary Companies

Condensed Consolidating Statement of Income

For the Three Months Ended June 30, 2004

	Kerr-McGee			Guarantor			Non-Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues	$	-		$	216		$	875		$	-		$	1,091
Costs and Expenses
Costs and operating expenses		-			109			320			(1	)		428
Selling, general and administrative expenses		1			-			77			-			78
Shipping and handling expenses		-			2			36			-			38
Depreciation and depletion		-			30			161			-			191
Accretion expense		-			-			6			-			6
Asset impairments		-			-			1			-			1
Loss on sale of assets		-			-			4			-			4
Exploration, including dry holes and
amortization of undeveloped leases		-			3			62			-			65
Taxes, other than income taxes		-			9			19			-			28
Provision for environmental remediation
and restoration, net of reimbursements		-			7			(3	)		-			4
Interest and debt expense		26			10			70			(50	)		56
Total Costs and Expenses		27			170			753			(51	)		899
		(27	)		46			122			51			192
Other Income (Expense)		206			16			21			(250	)		(7	)
Income from Continuing Operations
before Income Taxes		179			62			143			(199	)		185
Provision for Income Taxes		(68	)		(23	)		(56	)		76			(71	)
Income from Continuing Operations		111			39			87			(123	)		114
Loss from Discontinued Operations,
net of taxes		-			-			(3	)		-			(3	)
Net Income	$	111		$	39		$	84		$	(123	)	$	111

- 27 -

Kerr-McGee Corporation and Subsidiary Companies

Condensed Consolidating Statement of Income

For the Six Months Ended June 30, 2005

	Kerr-McGee			Guarantor			Non-Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues	$	-		$	554		$	3,013		$	-		$	3,567
Costs and Expenses
Costs and operating expenses		-			324			754			(1	)		1,077
Selling, general and administrative expenses		-			-			202			-			202
Shipping and handling expenses		-			6			92			-			98
Depreciation and depletion		-			58			560			-			618
Accretion expense		-			1			16			-			17
Asset impairments		-			-			5			-			5
Gain on sale of assets		-			-			(46	)		-			(46	)
Exploration, including dry holes and amortization
of undeveloped leases		-			4			180			-			184
Taxes, other than income taxes		-			16			76			-			92
Provision for environmental remediation
and restoration, net of reimbursements		-			16			10			-			26
Interest and debt expense		114			9			197			(178	)		142
Total Costs and Expenses		114			434			2,046			(179	)		2,415
		(114	)		120			967			179			1,152
Other Income (Expense)		814			130			218			(1,172	)		(10	)
Income from Continuing Operations
before Income Taxes		700			250			1,185			(993	)		1,142
Benefit (Provision) for Income Taxes		25			(42	)		(398	)		-			(415	)
Income from Continuing Operations		725			208			787			(993	)		727
Loss from Discontinued Operations,
net of taxes		-			-			(2	)		-			(2	)
Net Income	$	725		$	208		$	785		$	(993	)	$	725

Kerr-McGee Corporation and Subsidiary Companies

Condensed Consolidating Statement of Income

For the Six Months Ended June 30, 2004

	Kerr-McGee			Guarantor			Non-Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues	$	-		$	427		$	1,773		$	-		$	2,200
Costs and Expenses
Costs and operating expenses		-			219			605			(1	)		823
Selling, general and administrative expenses		1			-			158			-			159
Shipping and handling expenses		-			4			72			-			76
Depreciation and depletion		-			60			321			-			381
Accretion expense		-			1			12			-			13
Asset impairments		-			1			13			-			14
Loss on sale of assets		-			-			7			-			7
Exploration, including dry holes and
amortization of undeveloped leases		-			7			109			-			116
Taxes, other than income taxes		-			17			39			-			56
Provision for environmental remediation
and restoration, net of reimbursements		-			6			(3	)		-			3
Interest and debt expense		54			19			139			(99	)		113
Total Costs and Expenses		55			334			1,472			(100	)		1,761
		(55	)		93			301			100			439
Other Income (Expense)		477			9			50			(543	)		(7	)
Income from Continuing Operations
before Income Taxes		422			102			351			(443	)		432
Benefit (Provision) for Income Taxes		(159	)		(37	)		(135	)		168			(163	)
Income from Continuing Operations		263			65			216			(275	)		269
Loss from Discontinued Operations,
net of taxes		-			-			(6	)		-			(6	)
Net Income	$	263		$	65		$	210		$	(275	)	$	263

- 28 -

Kerr-McGee Corporation and Subsidiary Companies

Condensed Consolidating Balance Sheet

June 30, 2005

	Kerr-McGee		Guarantor		Non-Guarantor
(Millions of dollars)	Corporation		Subsidiaries		Subsidiaries		Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1	$	-	$	323	$	-		$	324
Intercompany receivables		70		-		-		(70	)		-
Accounts receivable		-		127		897		-			1,024
Inventories		-		2		360		-			362
Derivatives and other current assets		1		7		208		-			216
Deferred income taxes		-		33		304		-			337
Assets associated with properties held for sale		-		-		36		-			36
Total Current Assets		72		169		2,128		(70	)		2,299
Property, Plant and Equipment - Net		-		1,962		8,360		-			10,322
Investment in Subsidiaries		6,516		688		-		(7,204	)		-
Investments, Derivatives and Other Assets		70		20		604		(80	)		614
Goodwill and Other Intangible Assets		-		350		930		-			1,280
Assets Associated with Properties Held for Sale		-		-		662		-			662
Total Assets	$	6,658	$	3,189	$	12,684	$	(7,354	)	$	15,177

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Intercompany borrowings	$	20		$	505	$	1,394	$	(1,919	)	$	-
Accounts payable		6			44		496		-			546
Long-term debt due within one year		23			-		108		-			131
Derivative liabilities		-			6		794		-			800
Accrued liabilities		18			206		748		-			972
Liabilities associated with properties held for sale		-			-		19		-			19
Total Current Liabilities		67			761		3,559		(1,919	)		2,468
Long-Term Debt		6,352			-		473		-			6,825
Noncurrent Liabilities
Deferred income taxes		(5	)		480		1,728		-			2,203
Derivative liabilities		-			1		584		-			585
Other noncurrent liabilities		-			230		838		(1	)		1,067
Liabilities associated with properties held for sale		-			-		67		-			67
Total Noncurrent Liabilities		(5	)		711		3,217		(1	)		3,922
Stockholders' Equity		244			1,717		5,435		(5,434	)		1,962
Total Liabilities and Stockholders' Equity	$	6,658		$	3,189	$	12,684	$	(7,354	)	$	15,177

- 29 -

Kerr-McGee Corporation and Subsidiary Companies

Condensed Consolidating Balance Sheet

December 31, 2004

	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		757		-			963
Inventories		-		5		324		-			329
Derivatives and other current assets		4		24		167		-			195
Deferred income taxes		2		13		309		-			324
Total Current Assets		8		248		1,689		(58	)		1,887
Property, Plant and Equipment - Net		-		1,947		8,880		-			10,827
Investment in Subsidiaries		6,306		645		-		(6,951	)		-
Investments, Derivatives and Other Assets		17		24		547		(80	)		508
Goodwill and Other Intangible Assets		-		351		937		-			1,288
Assets Associated with Properties Held for Sale		-		-		8		-			8
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		521		-			644
Long-term debt due within one year		354			-		109		-			463
Derivative liabilities		6			71		295		-			372
Accrued liabilities		10			203		813		-			1,026
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		1,634		-			2,177
Derivative liabilities		-			59		149		-			208
Other noncurrent liabilities		-			224		853		(3	)		1,074
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

- 30 -

Kerr-McGee Corporation and Subsidiary Companies

Condensed Consolidating Statement of Cash Flows

For the Six Months Ended June 30, 2005

							Non-
	Kerr-McGee			Guarantor			Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Cash Flows from Operating Activities
Net income	$	725		$	208		$	785		$	(993	)	$	725
Adjustments to reconcile net income to net cash
provided by (used in) operating activities-
Depreciation, depletion and amortization		-			59			591			-			650
Deferred income taxes		(2	)		1			266			-			265
Dry hole expense		-			-			91			-			91
Asset impairments		-			-			5			-			5
Gain on sale of assets		-			-			(46	)		-			(46	)
Accretion expense		-			1			16			-			17
Provision for environmental remediation
and restoration, net of reimbursements		-			16			11			-			27
Equity in earnings of subsidiaries		(771	)		(130	)		-			901			-
Other noncash items affecting net income		(17	)		38			13			94			128
Changes in assets and liabilities		11			53			(346	)		(2	)		(284	)
Net Cash Provided by (Used in)
Operating Activities		(54	)		246			1,386			-			1,578
Cash Flows from Investing Activities
Capital expenditures		-			(66	)		(742	)		-			(808	)
Dry hole costs		-			-			(75	)		-			(75	)
Proceeds from sales of assets		-			-			63			-			63
Other investing activities		-			-			(21	)		-			(21	)
Net Cash Used in Investing Activities		-			(66	)		(775	)		-			(841	)
Cash Flows from Financing Activities
Issuance of common stock		159			-			-			-			159
Purchases of treasury stock		(250	)		-			-			-			(250	)
Shares repurchased under the tender offer		(3,975	)		-			-			-			(3,975	)
Dividends paid		(142	)		-			-			-			(142	)
Repayment of debt		(350	)		-			(42	)		-			(392	)
Proceeds from borrowings		4,250			-			-			-			4,250
Credit Agreement financing costs		(58	)		-			-			-			(58	)
Increase (decrease) in intercompany
notes payable		419			(180	)		(239	)		-			-
Settlement of Westport derivatives		-			-			(80	)		-			(80	)
Net Cash Provided by (Used in)
Financing Activities		53			(180	)		(361	)		-			(488	)
Effects of Exchange Rate Changes on Cash
and Cash Equivalents		-			-			(1	)		-			( 1	)
Net Increase in Cash and Cash Equivalents		(1	)		-			249			-			248
Cash and Cash Equivalents at Beginning of Period		2			-			74			-			76
Cash and Cash Equivalents at End of Period	$	1		$	-		$	323		$	-		$	324

- 31 -

Kerr-McGee Corporation and Subsidiary Companies

Condensed Consolidating Statement of Cash Flows

For the Six Months Ended June 30, 2004

							Non-
	Kerr-McGee			Guarantor			Guarantor
(Millions of dollars)	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Cash Flows from Operating Activities
Net income	$	263		$	65		$	210		$	(275	)	$	263
Adjustments to reconcile net income to net cash
provided by (used in) operating activities -
Depreciation, depletion and amortization		-			64			343			-			407
Deferred income taxes		15			8			88			-			111
Dry hole expense		-			-			26			-			26
Asset impairments		-			1			13			-			14
Loss on sale of assets		-			-			7			-			7
Accretion expense		-			1			12			-			13
Provision for environmental remediation
and restoration, net of reimbursements		-			7			-			-			7
Equity in losses (earnings) of subsidiaries		(272	)		(4	)		-			276			-
Other noncash items affecting net income		-			-			29			-			29
Changes in assets and liabilities		(30	)		12			(150	)		(1	)		(169	)
Net Cash Provided by (Used in)
Operating Activities		(24	)		154			578			-			708
Cash Flows from Investing Activities
Capital expenditures		-			(67	)		(366	)		-			(433	)
Dry hole costs		-			-			(26	)		-			(26	)
Proceeds from sale of investments		-			-			39			-			39
Proceeds from sales of assets		-			-			3			-			3
Other investing activities		(16	)		-			33			-			17
Net Cash Used in Investing Activities		(16	)		(67	)		(317	)		-			(400	)
Cash Flows from Financing Activities
Issuance of common stock		7			-			-			-			7
Repayment of debt		-			-			(347	)		-			(347	)
Proceeds from borrowings		-			-			86			-			86
Increase (decrease) in intercompany
notes payable		125			(87	)		(38	)		-			-
Dividends paid		(91	)		-			-			-			(91	)
Net Cash Provided by (Used in)
Financing Activities		41			(87	)		(299	)		-			(345	)
Effects of Exchange Rate Changes on Cash
and Cash Equivalents		-			-			-			-			-
Net Increase in Cash and Cash Equivalents		1			-			(38	)		-			(37	)
Cash and Cash Equivalents at Beginning of Period		2			-			140			-			142
Cash and Cash Equivalents at End of Period	$	3		$	-		$	102		$	-		$	105

17. Subsequent Event

In August 2005, the company entered into agreements to sell its North Sea oil and gas business for cash proceeds of $3.5 billion. The company expects to complete these transactions in the fourth quarter and realize net cash proceeds of approximately $3 billion. Net proceeds from the sales will be used for debt repayment. The transactions, which are subject to customary closing conditions and approval by appropriate government agencies, include:

·   The sale of the company’s interests in four non-operated fields and related exploratory acreage and facilities in the North Sea, and

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

- 32 -

The North Sea business includes proved reserves of approximately 231 million barrels of oil equivalent at June 30, 2005 and produced a daily average of 78 thousand barrels of oil equivalent during the second quarter, representing approximately 21% of the company’s production. For the first six months of 2005, the company’s North Sea operations contributed $377 million to operating profit of the company’s exploration and production segment.

Results of the company’s North Sea operations will be included in the company’s consolidated financial statements through the closing date and are expected to be classified as a discontinued operation in the third quarter of 2005. The following table presents a summary of assets and liabilities associated with the company’s North Sea business at June 30, 2005 (certain of which are presented as held for sale in the accompanying Condensed Consolidated Balance Sheet):

	June 30,
(Millions of dollars)	2005
Current Assets	$	342
Long-Term Assets		1,742
Current Liabilities		(365	)
Noncurrent Liabilities		(702	)
Net Investment	$	1,017

- 33 -

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

Overview and Recent Developments

Kerr-McGee Corporation is one of the largest U.S.-based independent oil and gas exploration and production companies and the world's third-largest producer and marketer of titanium dioxide pigment in terms of volumes produced. 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).

We recently 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, as discussed below. The company expects asset divestitures discussed below to result in gross proceeds in excess of $4 billion.

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. The company is actively pursuing both separation alternatives and expects to determine the timing and manner of separation during the third quarter of 2005. As of August 5, 2005, criteria for reporting the results of the chemical business unit as discontinued operations had not been met.

Divestitures of Oil and Gas Assets-In April 2005, the company announced its decision to divest of lower-growth, shorter-life and higher-decline oil and gas properties. In connection with the divestiture program, the company identified for sale four packages of oil and gas properties located onshore in the United States and five packages of non-operated properties in the U.K. North Sea. We expect to close the sales of these properties by the end of the year. These properties met the criteria for classification as held for sale in June 2005. Accordingly, associated assets and liabilities are classified as such in the company’s June 30, 2005 Condensed Consolidated Balance Sheet.

In August 2005, the company entered into agreements to sell its North Sea oil and gas business for cash proceeds of $3.5 billion. The company expects to complete these transactions in the fourth quarter and realize net cash proceeds of approximately $3 billion. Net proceeds from the sales will be used for debt repayment. The transactions, which are subject to customary closing conditions and approval by appropriate government agencies, include:

·   The sale of the company’s interests in four non-operated fields and related exploratory acreage and facilities in the North Sea, and

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

The North Sea business includes proved reserves of approximately 231 million barrels of oil equivalent at June 30, 2005 and produced a daily average of 78 thousand barrels of oil equivalent during the second quarter, representing approximately 21% of the company’s production. For the first six months of 2005, the company’s North Sea operations contributed $377 million to operating profit of the company’s exploration and production segment.  Note 17 to the condensed consolidated financial statements presents a summary of assets and liabilities associated with the company's North Sea business at June 30, 2005. 

In addition to assets identified for sale as discussed above, the company's other selected U.S. onshore properties and Gulf of Mexico shelf properties are also being considered for divestiture. The total combined divestitures are expected to represent approximately 25% to 30% of the company’s proved reserves at December 31, 2004 and up to 35% of its average daily production for the first six months of 2005. With the divestitures of these properties, we expect the average life of the company’s oil and gas reserves to increase. Proved developed reserves are expected to continue to represent approximately 65% of total proved reserves. However, the actual impact of any asset 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.

- 34 -

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 reduce debt associated with the tender offer in the range of $3.5 billion to $4.5 billion during the next two years, using proceeds of the planned divestitures discussed above and cash flow which has been underpinned by an expanded oil and gas hedging program for 2005 through 2007.

Expanded Hedging Program-To increase the predictability of cash flows, we expanded our hedging program in April 2005 and, as of June 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 planned divestitures) and approximately 50% of its 2007 expected eligible production. Eligible production excludes oil production in China and gas production from the North Sea. Additional information regarding our commodity price risk management activities is included in Item 3, Quantitative and Qualitative Disclosures about Market Risk.

Revised Dividend Policy-In May 2005, the Board approved a recommendation to revise the company’s dividend policy to a level consistent with that of other pure-play exploration and production companies. Starting with the second quarter 2005, the annual dividend was reduced from $1.80 to $.20 per share.

- 35 -

Results of Consolidated Operations

The following table summarizes revenues and segment operating profit with a reconciliation to consolidated net income for the three and six months ended June 30, 2005 and 2004:

	Three Months Ended									Six Months Ended
	June 30,									June 30,
(Millions of dollars)	2005			2004			Percent Change			2005			2004			Percent Change
Revenues	$	1,850		$	1,091			70	%	$	3,567		$	2,200			62	%
Segment operating profit (1) -
Exploration and production	$	686		$	263			161	%	$	1,341		$	593			126	%
Chemical -
Pigment		32			14						64			21
Other		2			-						(7	)		(3	)
Total Chemical		34			14			143	%		57			18			217	%
Total segment operating profit		720			277			160	%		1,398			611			129	%
Interest and debt expense		(81	)		(56	)					(142	)		(113	)
Corporate expenses		(45	)		(26	)					(89	)		(57	)
Environmental provisions, net of reimbursements		(2	)		(3	)					(15	)		(2	)
		592			192						1,152			439
Other income (expense)		(9	)		(7	)					(10	)		(7	)
Provision for income taxes		(211	)		(71	)					(415	)		(163	)
Income from continuing operations		372			114			226	%		727			269			170	%
Loss from discontinued operations, net of taxes (2)		(2	)		(3	)					(2	)		(6	)
Net Income	$	370		$	111			233	%	$	725		$	263			176	%
Net Income per Common Share:
Basic	$	2.63		$	1.07			146	%	$	4.91		$	2.58			90	%
Diluted		2.60			1.01			157	%		4.78			2.42			98	%

⁽¹⁾   Segment operating profit represents results of continuing operations before considering general corporate expenses, interest and debt expense, environmental provisions related to sites with no ongoing operations or businesses in which the company’s affiliates are no longer engaged, other income (expense) and income taxes.

⁽²⁾   Loss from discontinued operations reflects results of the company’s former forest products operations. Criteria for classification of the forest products business as discontinued operations were met in the fourth quarter of 2004.

Second Quarter 2005 vs. Second Quarter 2004

General - Income from continuing operations for the second quarter of 2005 was $372 million, representing an increase of $258 million over 2004. The increase is primarily due to $443 million higher segment operating profit, partially offset by increases in income tax expense, interest and debt expense and corporate expenses of $140 million, $25 million and $19 million, respectively. Total segment operating profit for the second quarter of 2005 was $720 million, compared with $277 million for 2004. The increase of $443 million, 95% of which was generated by our exploration and production segment, is primarily attributable to an increase in consolidated revenues of $759 million, partially offset by higher costs and operating expenses of $128 million, higher depreciation and depletion expense of $117 million and a $56 million increase in exploration expense. Analysis of operating profit for each of our segments is provided under Results of Operations by Segment that follows.

Revenues - Significant factors contributing to the increase in consolidated revenues are summarized below. Higher sales volumes of crude oil and natural gas compared to the second quarter of 2004 are largely due to our merger with Westport Resources Corp. (Westport) on June 25, 2004, and the start of production in the Bohai Bay area of China and from the Red Hawk field in the deepwater Gulf of Mexico in the 2004 third quarter.

- 36 -

	Three Months Ended June 30,
(Millions of dollars)	2005		2005 vs. 2004			2004
Revenues	$	1,850	$	759		$	1,091
Increase (decrease) in:
Oil and gas sales revenues due to changes in realized prices			$	434
Oil and gas sales revenues due to volume changes				264
Other exploration and production segment revenues				31
Pigment sales revenues due to changes in realized prices				48
Pigment sales revenues due to volume changes				(20	)
Other chemical segment revenues				2
Total change in revenues			$	759

Interest and Debt Expense - In May 2005, the company entered into a credit agreement for three credit facilities with an aggregate commitment of $5.5 billion, as more fully discussed under Financial Condition and Liquidity. Interest and debt expense for the second quarter of 2005 related to borrowings and commitments under the new credit agreement was $28 million (including amortization of costs of obtaining financing). Financing costs of $58 million were capitalized when incurred and will be amortized to interest expense over the term of the related facilities. If borrowings are repaid in accordance with their scheduled maturities, associated amortization will increase interest expense by $9 million in the second half of 2005 and $17 million in 2006. Expense recognition will be accelerated if the borrowings are repaid earlier than scheduled.

Corporate Expenses - Corporate expenses for the second quarter of 2005 increased $19 million compared with 2004. Approximately $10 million of the increase represented cost of professional services incurred in connection with the company’s consideration of strategic alternatives. Additionally, corporate expenses for the 2005 second quarter include $2 million recognized in connection with employee retention programs initiated in April 2005. These programs are discussed under Obligations and Commitments below.

Provision for Income Taxes - Second-quarter 2005 income tax expense was $211 million, reflecting an effective tax rate of 36.2%. For the same 2004 period, income tax expense was $71 million, resulting in an effective tax rate of 38.4%. The increase in income from continuing operations before income taxes was the primary contributor to the overall increase in income tax expense. The 2.2% lower effective rate for 2005 second quarter included the net effect of the following:

·   As discussed under Overview and Recent Developments, the company has identified for sale certain oil and gas properties in the U.K. sector of the North Sea. One of the packages identified for sale would result in the sale of the company’s investment in the stock of a foreign subsidiary. Upon concluding that such sale was likely to occur, the company recognized a tax benefit of $27 million related to the difference between the book and tax bases of its investment in the subsidiary. Additionally, as discussed under Financial Condition and Liquidity below, provisions of the new credit agreement require us to use 100% of the net cash proceeds from sales of certain assets for debt repayment. Because proceeds from the sale of U.K. oil and gas properties will be remitted to the United States for debt repayment, in connection with classifying such properties as held for sale, the company recognized $11 million of U.S. deferred 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 $27 million tax benefit and the $11 million provision resulted in a corresponding increase (decrease) in the second-quarter 2005 effective tax rate of (4.6%) and 1.9%, respectively.

·   As discussed below, in the second quarter of 2005 we recognized income tax expense of $12 million associated with the repatriation of foreign earnings under the provisions of the American Jobs Creation Act of 2004, which increased the effective tax rate by 2.1%.

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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, $200 million of which were repatriated during the quarter ended June 30, 2005, resulting in recognition of income tax expense of $12 million. The company may repatriate up to an additional $300 million in extraordinary dividends under the provisions of the Act. Management has not yet decided whether, and to what extent, additional amounts of foreign earnings will be repatriated. Accordingly, the second quarter financial statements do not reflect any provision for taxes on unremitted foreign earnings, except for the provision of $11 million discussed above. Additional income tax expense of up to $16 million may be recognized in the quarter ending September 30, 2005, when the company expects to decide whether additional amounts of certain foreign earnings will be repatriated under the provisions of the Act. 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.

Year-to-Date 2005 vs. Year-to-Date 2004

General - Income from continuing operations for the first six months of 2005 was $727 million, an increase of 170% over the $269 million for the prior-year period. Higher total segment operating profit of $787 million, partially offset by a higher provision for income taxes ($252 million), increased corporate expenses ($32 million) and interest and debt expense ($29 million), contributed to the increase. For the six-month period ended June 30, 2005, total segment operating profit was $1.4 billion compared with $611 million for the same 2004 period, with 95% of the total increase arising from operations of our exploration and production segment. The increase in total segment operating profit was driven by an increase in revenues of $1.4 billion, partially offset by increases in costs and operating expenses, depreciation and depletion and exploration expense of $254 million, $237 million and $68 million, respectively. Analysis of operating profit for each of our segments is provided under Results of Operations by Segment below.

Revenues - Revenues for the six-month period ended June 30, 2005 increased 62% over the prior-year period. The main contributing factors are summarized below, with additional analysis provided under Results of Operations by Segment.

	Six Months Ended June 30,
(Millions of dollars)	2005		2005 vs. 2004		2004
Revenues	$	3,567	$	1,367	$	2,200
Increase (decrease) in:
Oil and gas sales revenues due to changes in realized prices			$	733
Oil and gas sales revenues due to volume changes				519
Other exploration and production segment revenues				26
Pigment sales revenues due to changes in realized prices				80
Pigment sales revenues due to volume changes				7
Other chemical segment revenues				2
Total change in revenues			$	1,367

Interest and Debt Expense - As mentioned in the preceding discussion of results of operations for the second quarter, interest and debt expense increased as a result of additional borrowings under the credit agreement closed on May 24, 2005, which were used to fund the $4 billion tender offer and repay certain then outstanding indebtedness. The $29 million increase in interest and debt expense in 2005 is predominantly the result of interest expense and amortization of debt issuance costs associated with the new financing. Additional information regarding borrowings incurred in May 2005 is provided under Financial Condition and Liquidity.

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Corporate Expenses - The year-to-date increase in corporate expenses of $32 million is due primarily to approximately $11 million higher cost of employee compensation and benefits and $10 million of consulting and other costs incurred in 2005 in connection with the company’s consideration of strategic alternatives. Employee compensation expense increased in part due to $2 million recognized in connection with the employee retention programs implemented in April 2005, as discussed under Obligations and Commitments below, and $6 million higher expense associated with performance unit awards. The per-unit liability associated with these awards increased as a result of the higher market price of our common stock, since ultimate payout is based on Kerr-McGee’s total shareholder return as compared to selected peer companies. Additionally, the number of outstanding performance units increased following the January 2005 grant.

Provision for Income Taxes - Higher income tax expense for the six-month period ended June 30, 2005 of $252 million is the result of the increase in pretax income from continuing operations, partially offset by a reduction in the effective tax rate of 1.4%, from 37.7% in the prior-year period to 36.3% in 2005. The primary reasons for the lower effective tax rate in 2005 are discussed above in the analysis of results of operations for the second quarter of 2005 compared to the prior-year quarter.

Results of Operations by Segment -

Exploration and Production

Segment Operating Profit

Revenues, operating costs and expenses, and marketing activities associated with the exploration and production segment are shown in the following table.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Millions of dollars)	2005			2004			2005			2004
Revenues, excluding marketing revenues	$	1,356		$	678		$	2,607		$	1,430
Operating costs and expenses:
Lifting costs:
Lease operating expense		146			82			288			171
Production and ad valorem taxes		34			18			64			33
Total lifting costs		180			100			352			204
Depreciation, depletion and amortization		278			160			559			322
Accretion expense		8			7			17			13
Asset impairments		1			1			5			14
(Gain) loss associated with assets held for sale		(24	)		4			(46	)		7
General and administrative expense		43			35			73			66
Transportation expense		36			25			71			52
Exploration expense		121			65			184			116
Gas gathering, pipeline and other expenses		27			19			52			44
Total operating costs and expenses		670			416			1,267			838
Operating profit, excluding net marketing margin		686			262			1,340			592
Marketing - Gas sales revenues		138			87			270			169
Marketing - Gas purchase costs (including transportation)		(138	)		(86	)		(269	)		(168	)
Net marketing margin		-			1			1			1
Total Operating Profit	$	686		$	263		$	1,341		$	593

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Revenues

Revenues, production statistics and average prices realized from sales of crude oil, condensate and natural gas are shown in the following table.

	Three Months Ended					Six months Ended
	June 30,					June 30,
(Millions of dollars, except per-unit amounts)	2005			2004		2005			2004
Revenues -
Crude oil and condensate sales	$	700		$	338	$	1,379		$	699
Natural gas sales		653			317		1,260			688
Gas marketing activities		138			87		270			169
Other revenues		26			18		51			39
Nonhedge derivative gains (losses)		12			5		(39	)		5
Loss on hedge ineffectiveness		(35	)		-		(44	)		(1	)
Total	$	1,494		$	765	$	2,877		$	1,599
Production -
Crude oil and condensate (thousands of barrels per day):
U.S. Gulf of Mexico		60			57		61			57
U.S. onshore		36			20		36			19
North Sea		62			64		65			66
China		17			-		19			-
Total		175			141		181			142
Natural gas (million cubic feet per day):
U.S. Gulf of Mexico		452			314		432			321
U.S. onshore		571			334		584			328
North Sea		95			92		95			102
Total		1,118			740		1,111			751
Total equivalent barrels of oil (thousands of boe per day)		361			264		366			267
Average sales prices (excluding hedges) -
Crude oil and condensate (per barrel):
U.S. Gulf of Mexico	$	47.26		$	35.31	$	46.12		$	34.15
U.S. onshore		44.26			32.43		42.68			31.33
North Sea		48.24			34.19		46.84			32.06
China		42.85			-		40.46			-
Average		46.55			34.40		45.07			32.80
Natural gas (per thousand cubic feet):
U.S. Gulf of Mexico	$	7.11		$	6.23	$	6.84		$	6.01
U.S. onshore		6.54			5.63		6.11			5.57
North Sea		4.54			3.61		5.35			4.05
Average		6.60			5.63		6.33			5.55
Average realized sales prices (including hedges) -
Crude oil and condensate (per barrel):
U.S. Gulf of Mexico	$	42.55		$	28.08	$	41.96		$	28.42
U.S. onshore		39.56			25.50		38.51			25.68
North Sea		45.10			26.40		44.27			26.45
China		42.85			-		40.46			-
Average		42.90			26.97		41.93			27.14
Natural gas (per thousand cubic feet):
U.S. Gulf of Mexico	$	6.91		$	5.16	$	6.77		$	5.42
U.S. onshore		6.35			4.58		6.04			4.96
North Sea		4.54			3.61		5.35			4.05
Average		6.42			4.70		6.27			5.03

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Crude Oil Sales Revenues and Production - Oil sales revenues increased $362 million or 107% in the second quarter of 2005 compared with the same period of 2004 due to a combination of higher realized commodity prices and increased oil production. Second-quarter 2005 oil production of 175 thousand barrels per day (Mbbls/d) represented an increase of 24% over the same 2004 period. Contributing to the increase was the addition of Westport properties in late June 2004 (25 Mbbls/d), as well as production from China's CFD 11-1/11-2 fields in Bohai Bay, which began producing in July 2004 (17 Mbbls/d). The North Sea production decreased slightly from the second quarter of 2004 due to declines at the Harding, Tullich and Leadon fields. These declines were largely offset by strong development drilling results at the Gryphon field. Average oil prices, including the effect of hedging activity, increased $15.93 per barrel in the second quarter of 2005, contributing an additional $260 million to oil sales revenues.

For the first six months of 2005, oil sales revenues increased $680 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 $14.79 per barrel compared with the same period in 2004, contributing an additional $485 million to oil sales revenues. Oil production for 2005 increased to 181 Mbbls/d, a 27% increase over the same 2004 period. The addition of former Westport properties (25 Mbbls/d) and start-up of production from China's CFD 11-1/11-2 fields (19 Mbbls/d) were the primary contributors to the increase.

Natural Gas Sales Revenues and Production - Natural gas sales revenues increased $336 million in the second quarter of 2005 compared to the same period of 2004 as a result of a 51% increase in gas production, combined with a $1.72 per thousand cubic feet (Mcf) increase in the average realized price, including hedging. Gas production in the second quarter of 2005 was 1,118 million cubic feet per day (MMcf/d), 378 MMcf/d higher than 2004 second-quarter production, contributing an additional $162 million in gas sales revenues. Gas production increased as a result of the Westport merger, as well as increased drilling activity since the closing of the transaction, contributing approximately 388 MMcf/d in the second quarter of 2005. In addition, the Red Hawk field in the deepwater Gulf of Mexico, which began producing in July 2004, largely offset declines that occurred in other Gulf of Mexico and U.S. onshore fields. Higher realized gas prices provided an additional $174 million in gas sales revenues, averaging $6.42 per Mcf (including the impact of hedging activity).

Natural gas revenues increased $572 million for the six months ended June 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 $1.24 per Mcf compared with the same period in 2004, contributing an additional $248 million to gas sales revenues. Year-to-date 2005 gas production increased to 1,111 MMcf/d, 360 MMcf/d higher than the same period in 2004. Contributing to the increase was the addition of Westport properties (395 MMcf/d), as well as production from the Red Hawk field. These increases in production were partially offset by declines that occurred in other Gulf of Mexico and U.S. onshore fields.

Other Revenues - Other revenues include gas processing plant and gathering system revenues in the U.S. onshore area, along with oil tariffs and non-equity oil and gas sales in the U.K. Gas marketing activities in the Rocky Mountain area are discussed below.

Other revenues were $8 million higher in the second quarter of 2005 as compared to the same period in 2004. The increase was primarily due to $4 million higher revenues generated from the resale of non-equity gas and oil tariffs in the North Sea. In addition, higher U.S. commodity prices increased gas processing revenues from the company's non-operated ownership interest in a Wattenberg-area gas plant by $2 million.

For the six-month period ended June 30, 2005, other revenues were $12 million higher in comparison to the same period in 2004, resulting primarily from $6 million higher revenues generated from the resale of non-equity gas in the North Sea and $5 million higher gas processing revenues from the company's non-operated ownership interest in a Wattenberg-area gas plant driven by higher U.S. commodity prices.

Hedge Ineffectiveness and Nonhedge Derivative Losses - For the three- and six-month periods ended June 30, 2005, we recognized ineffectiveness losses of $35 million and $44 million, respectively, associated with our 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. Ineffectiveness losses in 2005 are due to our expanded hedging program that now extends through 2007, as well as increased commodity prices and somewhat greater basis differentials between NYMEX and actual physical indices.

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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 effectively reduce 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 June 30, 2005 was a liability of $84 million.

For further discussion of the company’s derivative activities see Note 3 to the accompanying condensed consolidated financial statements and information included below in Item 3, Quantitative and Qualitative Disclosures about Market Risk.

Lease Operating Expense

In the second quarter of 2005, lease operating expense increased $64 million compared with 2004. On a per-unit basis, lease operating expense increased $.95 per barrel of oil equivalent (boe), from $3.45 per boe in 2004 to $4.40 per boe in 2005. The increase was primarily due to additional operating expenses associated with Westport properties ($37 million) and new production from China's CFD 11-1/11-2 fields ($9 million). North Sea lease operating expense also increased in the second quarter of 2005 in comparison to 2004 ($13 million) due to timing of crude oil sales at the Leadon field, well workover expense at the Janice field and higher manpower costs at the non-operated Harding field. Additional costs were also incurred in the Gulf of Mexico area related to a combination of increased well workover activity, new field production and higher operating expense for non-operated properties.

Lease operating expense for the first six months of 2005 was $288 million, an increase of $117 million compared with the same period of 2004. On a per-unit basis, lease operating expense increased $.82 per boe, from $3.52 per boe in 2004 to $4.34 per boe in 2005. The increase was primarily due to additional operating expenses associated with Westport properties ($72 million) and new production from China's CFD 11-1/11-2 fields ($18 million). Additionally, North Sea lease operating expense increased by $16 million in 2005 as compared to 2004, primarily due to higher well workover costs at the Janice field, higher manpower costs at the non-operated Harding field and increased fuel expense at the Leadon field. The remaining increase in the year-to-date lease operating expense was attributable to our Gulf of Mexico operations, where costs increased primarily due to higher well workover expense, hurricane Ivan-related repairs and cost associated with new field production.

Production and Ad Valorem Taxes

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 $16 million in the second quarter of 2005 and $31 million for the first six months of 2005, as a result of higher commodity prices and higher sales volumes compared with the respective prior year periods. The addition of Westport's properties 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.

Depreciation, Depletion and Amortization (DD&A)

DD&A expense of $278 million for the second quarter of 2005 increased $118 million over 2004, primarily caused by additional DD&A expense for the Westport properties acquired in June 2004 ($101 million) and new production from China's CFD 11-1/11-2 fields ($13 million). In addition, higher DD&A expense was incurred in the North Sea due to a change in the producing field mix. On a per-unit basis, DD&A expense increased from $6.75 per boe in the second quarter of 2004 to $8.35 per boe in 2005, primarily reflecting the impact of the Westport merger, which had a higher acquisition cost per boe than our historical asset base.

- 42 -

DD&A expense for the first six months of 2005 was $559 million, a $237 million increase from the same period in 2004. Contributing to the increase was higher expense for the Westport properties

($202 million) and new production from China's CFD 11-1/11-2 fields ($27 million). In addition, slightly higher DD&A expense was incurred in the North Sea and in the Gulf of Mexico shelf areas. On a per-unit basis, DD&A expense increased from $6.63 per boe in 2004 to $8.42 per boe in 2005.

Asset Impairments and Gain/Loss on Sales of Assets

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 six 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 $46 million in the first half 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, the company sold its 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 field and $27 million in cash. The company recognized a gain of $25 million in connection with this transaction.

General and Administrative Expense

Second-quarter 2005 general and administrative expense of $43 million was $8 million higher than the same period of 2004. Per-unit general and administrative expense was $1.32 per boe in the second quarter of 2005, a decrease of $.15 per boe compared with 2004. For the first six months of 2005, general and administrative expense was $7 million higher compared to the same period in 2004. The per-unit rate of $1.10 per boe for the 2005 year-to-date period decreased by $.26 per boe compared with 2004. The increases in general and administrative expense for the three and six months ended June 30, 2005 over the corresponding 2004 periods were primarily due to higher cost of employee compensation and benefits and increased contract services costs. Employee compensation expense for the 2005 periods includes $4 million associated with employee retention programs initiated in April 2005. Additional information on these programs is provided under Obligations and Commitments below. Additional production from Westport properties without commensurate increases in general and administrative costs improved 2005 per-unit metrics.

Transportation Expense

Transportation expense, representing the costs paid to third-party providers to transport oil and gas production, increased by $11 million in the second quarter of 2005, to $36 million. The increase was primarily due to additional transportation costs associated with Westport properties of $7 million. In addition, 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. In the North Sea, transportation expense associated with higher production rates from the Gryphon field also increased for the period. On a per-unit basis, second-quarter 2005 transportation expense was $1.09 per boe compared to $1.04 per boe in 2004.

For the first six months of 2005, transportation expense of $71 million was $19 million higher compared with 2004, primarily due to the contribution of Westport properties ($13 million), as well as the new Rocky Mountain area gas transportation contract. On a per-unit basis, the year-to-date 2005 transportation expense was $1.07 per boe, a $.01 per boe increase from 2004.

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Exploration Expense

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(Millions of dollars)	2005		2004		2005			2004
Exploration costs (1)	$	18	$	16	$	30		$	26
Geological and geophysical costs		16		18		32			38
Dry hole expense		71		18		91			26
Amortization of undeveloped leases		16		13		32			26
Sales of unproved properties		-		-		(1	)		-
Total exploration expense	$	121	$	65	$	184		$	116

⁽¹⁾   Exploration costs include delay rentals, cost of retaining and carrying unproved properties and exploration department overhead.

In the second quarter of 2005, total exploration expense was $121 million, an increase of $56 million over 2004, primarily related to $53 million higher dry hole expense. Three unsuccessful Gulf of Mexico exploratory wells in the 2005 second quarter contributed $40 million to dry hole expense, with the remainder primarily associated with China and Alaska. Amortization of undeveloped leases also increased by $3 million, mainly as a result of additional Westport leases. Geological and geophysical data acquisition and processing costs decreased $2 million in the second quarter of 2005, with lower spending in the international exploration areas of Morocco, Trinidad and the Bahamas, as well as other new venture areas. This decrease in international spending was partially offset by increased geological and geophysical expense in the deepwater Gulf of Mexico and U.K. North Sea areas. Exploration activity associated with Westport properties contributed approximately $10 million to the second-quarter 2005 exploration expense.

For the first six months of 2005, total exploration expense was $184 million, an increase of $68 million compared with 2004, primarily due to an increase in dry hole expense of $65 million. Amortization of undeveloped leases also increased by $6 million, largely as a result of additional Westport leases. Geological and geophysical data acquisition and processing costs decreased by $6 million for the six-month period ended June 30, 2005, as compared to 2004. Increased spending in the U.S. onshore area was offset by lower costs in various international locations and the Gulf of Mexico. Exploration activity associated with Westport properties contributed approximately $18 million to 2005 year-to-date exploration expense.

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 June 30, 2005, the company had capitalized exploratory well costs of approximately $168 million associated with such ongoing exploration activities, primarily in the deepwater Gulf of Mexico, Alaska, Brazil and China.

Gas Marketing Activities

Kerr-McGee purchases third-party natural gas for aggregation and sale with the company's own production in the Rocky Mountain area. In addition, we have transportation capacity to markets in the Midwest to facilitate sale of natural gas outside the immediate vicinity of our production.

Marketing revenue was $138 million in the second quarter of 2005, an increase of $51 million over 2004 attributable to higher volumes of purchase and resale of third-party natural gas in the Rocky Mountain area and higher natural gas prices. Gas purchase costs increased $52 million in the second quarter of 2005 compared with 2004. Marketing volumes (MMBtu/day) were 241,000 and 182,000 in the second quarter of 2005 and 2004, respectively. Year-to-date, marketing revenues and associated gas purchase costs totaled $270 million and $269 million, respectively, in each case reflecting a $101 million increase from the same 2004 period as a result of higher gas volumes marketed and higher prices. For the first six months of 2005 and 2004, marketing volumes (MMBtu/day) averaged 249,000 and 178,000, respectively.

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Results of Operations by Segment -

Chemical

Chemical segment revenues, operating profit (loss) and pigment production volumes are shown in the following table:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(Millions of dollars)	2005		2004		2005			2004
Revenues -
Pigment	$	331	$	303	$	642		$	555
Other		25		23		48			46
Total	$	356	$	326	$	690		$	601
Operating profit (loss) -
Pigment	$	32	$	14	$	64		$	21
Other		2		-		(7	)		(3	)
Total	$	34	$	14	$	57		$	18
Titanium dioxide pigment production
(thousands of tonnes)		130		143		264			279

Chemical - Pigment

Operating profit for the second quarter of 2005 was $32 million on revenues of $331 million, compared with operating profit of $14 million on revenues of $303 million for the same 2004 period. Of the $28 million increase in revenues, $48 million was due to an increase in average selling prices of approximately 17% due to stronger market conditions. This increase was partially offset by $20 million due to decreased sales volumes. Sales volumes were approximately 11,000 tonnes lower primarily due to the tonnes sold from the Savannah sulfate production facility that was shutdown during 2004. The increase in revenues was partially offset by a $3 million increase in manufacturing costs and a $7 million increase in selling and administrative costs primarily due to an increase in employee incentive compensation related to cash bonuses resulting from improved performance during the quarter.

For the first six months of 2005, operating profit was $64 million on revenues of $642 million, compared with operating profit of $21 million on revenues of $555 million in the respective prior-year period. The improvement in operating profit for the first six months of 2005 compared with the same 2004 period was primarily attributable to both higher average sales prices and sales volumes, which were driven by strong market conditions. Revenues increased $87 million, or 16%, for the first six months of 2005, of which $80 million resulted from higher average sales prices and $7 million was due to higher pigment sales volumes of approximately 4,000 tonnes. The improved revenues were partially offset by higher average product costs of $25 million due to higher process chemical costs and increased costs resulting from scheduled production maintenance and upgrades. Increased sales volume also resulted in $9 million higher manufacturing and transportation costs. Selling and administrative costs were also higher by $8 million compared to the same period in 2004 primarily due to an increase in employee incentive compensation related to cash bonuses resulting from improved performance for the year.

The company continues to operate its new high-productivity oxidation line for chloride-process titanium dioxide pigment production at the Savannah facility. This project, if successful, will substantially increase chloride production capability at a reduced asset intensity level. The company continues to evaluate the performance of this new oxidation line and expects to determine how the Savannah site might be reconfigured to exploit its capabilities later in 2005. The possible reconfiguration of the Savannah site, if any, could include redeployment or idling of certain assets and reduction of their future useful lives, resulting in the acceleration of depreciation expense and the recognition of other charges. However, the current production demands make it less likely that any existing production lines would be idled in the near term.

- 45 -

Chemical - Other

Operating profit in the second quarter of 2005 was $2 million on revenues of $25 million, compared with an operating profit of nil on revenues of $23 million in the same 2004 period. This improvement is primarily the result of improved operations at the company’s Henderson, Nevada, electrolytic manganese dioxide manufacturing facility compared to the prior year.

For the six months ended June 30, 2005, operating loss was $7 million on revenues of $48 million, compared with an operating loss of $3 million on revenues of $46 million in the same 2004 period. The $4 million increase in operating loss for the first six months of 2005 resulted from a net $11 million environmental provision (net of expected insurance reimbursement of $19 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. 

Financial Condition and Liquidity

The following provides certain information useful in the analysis of the company's financial condition and liquidity.

	June 30,			December 31,
(Millions of dollars)	2005			2004
Current ratio (1)		0.9 to 1			0.8 to 1
Cash and cash equivalents	$	324		$	76
Debt repayment obligations due within one year		131			463
Unused capacity under bank and revolving lines of credit		1,230			1,550
Total debt		6,956			3,699
Stockholders’ equity	$	1,962		$	5,318
Debt to total capitalization (2)		78	%		41	%

⁽¹⁾   Represents a ratio of current assets to current liabilities. 

⁽²⁾   Total capitalization is determined as total debt plus stockholders' equity.

	Six Months Ended
	June 30,
(Millions of dollars)	2005			2004
Net cash provided by operating activities	$	1,578		$	708
Capital expenditures, including dry hole costs	$	(883	)	$	(459	)

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 oil and gas properties which are expected to be realized over the next two years. We plan to reduce debt in the range of $3.5 billion to $4.5 billion during that period, using proceeds of the planned divestitures discussed under Overview and Recent Developments above and cash flow which has been underpinned by an expanded oil and gas hedging program for 2005 through 2007. 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 $169 million at June 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 affected by current assets and liabilities associated with our financial derivatives. At June 30, 2005, the company had recorded approximately $725 million 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.

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Since December 31, 2004, the percentage of debt to total capitalization increased from 41% to 78%. Significant 2005 transactions affecting our capital structure and the level of leverage are summarized below:

	Increase (Decrease) in
(Millions of dollars)	Total Debt			Total Equity
Repayment of debt	$	(392	)	$	-
Conversion of 5.25% debentures to common stock		(600	)		593
Exercises of employee stock options		-			159
Gross proceeds from borrowings		4,250			-
Repurchases of common stock		-			(4,225	)

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).

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		Applicable Interest Rate Margin
		At June 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%

Revolving Facility - The $1.25 billion Revolving Facility provides for borrowings and issuances of letters of credit. The commitment fee payable on the unused portion of the Revolving Facility is currently set at 0.5% annually. At June 30, 2005, no borrowings were outstanding under the Revolving Facility and outstanding letters of credit totaled $70 million.

Tranche X and Tranche B Term Loans- The term loans were fully funded at closing, with proceeds used to finance the tender offer and to pay fees and expenses associated with the Credit Agreement, which totaled $58 million. From origination through June 30, 2005, the weighted average interest rates on the Tranche X and Tranche B term loans were 5.41% and 5.87%, respectively.

We may make prepayments on the term loans at any time without penalty. Additionally, the term loans are subject to the following mandatory prepayment provisions:

·   As long as the Tranche X loan is outstanding, 50% of the net cash proceeds, as defined, of certain equity issuances;

·   100% of the net cash proceeds, as defined, from incurrence of certain indebtedness;

·   Subject to certain exceptions, 100% of the net cash proceeds, as defined, from asset disposals; and

·   Annually, a specified percentage of excess cash flow, as defined, ranging from zero to 50%. This prepayment requirement is reduced or eliminated upon repayment of the Tranche X loan and the achievement of a Consolidated Leverage Ratio below specified thresholds.

Excess cash flow as calculated under the Credit Agreement is reduced by mandatory prepayments made with the net cash proceeds from asset dispositions. Based on our current forecast of cash flows for the second half of 2005 and assuming application of the net proceeds from asset divestitures to repay debt under the Credit Agreement, we estimate that no payments will be due in 2006 under the excess cash flow prepayment provision.

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.

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):

·   Consolidated Leverage Ratio of no more than 4:1 in 2005, 3.75:1 in 2006 and 3.50:1 thereafter

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

·   Asset Coverage Ratio of more than 1.25:1 in 2005, 1.50:1 in 2006 and 1.75:1 thereafter

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For the second quarter of 2005, the company had a Consolidated Leverage Ratio of approximately 2:1, a Consolidated Interest Coverage Ratio of 11:1 and an Asset Coverage Ratio of 1.79:1, and was in compliance with its other debt covenants. Based on total debt outstanding as of June 30, 2005, the company’s EBITDAX, as defined in the Credit Agreement, would have to decline by almost 50% 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 14, 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:

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

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 or modifying its terms, the company elected to terminate the program by advancing the then outstanding balance of receivables sold of $165 million to the SPE, which in turn used the funds to repay the financial institution participating in the program. The company then executed an Assignment and Sale Agreement whereby it acquired all outstanding receivables from the SPE in exchange for the forgiveness of all debt owed by the SPE to the company (including the $165 million advance mentioned above). Accounts receivable acquired in this transaction are being collected by the company as they become due.

The company may be required from time to time to post collateral in the form of cash or letters of credit. Certain of our counterparties require margin deposits if unrealized losses on derivative instruments exceed limits established with individual counterparty institutions. As a result of our credit rating being lowered in April 2005, we were required to post cash collateral with one of our counterparties, which totaled $24 million as of June 30, 2005. Future collateral requirements will depend on changes in the fair value of outstanding derivatives.

Cash Flows

The following provides selected cash flow information for the six-month periods ended June 30, 2005:

	Six Months Ended
	June 30,						Percentage
(Millions of dollars)	2005			2004			Change
Net cash provided by operating activities	$	1,578		$	708			123	%
Net cash used in investing activities		(841	)		(400	)		110	%
Net cash used in financing activities		(488	)		(345	)		41	%

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Operating Activities - The $870 million increase in cash flows from operating activities during the first six 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 37% higher than in 2004 as a result of the Westport merger and the start of new production in the third quarter of 2004, 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 39%, from $28.58 in 2004 to $39.75 in 2005. The increase in operating cash flows from higher revenues was partially offset by higher cash outflows for costs and operating expenses, production taxes, general and administrative and interest expenses. Additionally, as discussed under Credit Ratings above, in April 2005 we terminated our accounts receivable sales program for the chemical - pigment business. In connection with the program termination, we used $165 million to repurchase pigment receivables. Following the program termination, all receivables arising from pigment sales are collected from customers as they become due, resulting in slower receivables turnover compared to 2004.

Investing Activities - Significant uses and sources of cash associated with investing activities were as follows:

	Six Months Ended
	June 30,
(Millions of dollars)	2005			2004
Capital expenditures -
Exploration and production (including dry hole costs)	$	(843	)	$	(410	)
Chemical - Pigment		(28	)		(38	)
Chemical - Other		(3	)		(5	)
Corporate and other		(9	)		(6	)
Total capital expenditures (including dry hole costs)		(883	)		(459	)
Acquisitions, net of cash acquired		-			43
Proceeds from dispositions of assets		63			42
Other investing activities		(21	)		(26	)
Total net cash used in investing activities	$	(841	)	$	(400	)

Capital expenditures in 2005 reflect, in part, capital spending associated with Westport properties, increased expenditures on the company's Constitution/Ticonderoga development and exploratory drilling in Alaska. Upon completion of the planned divestitures 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.

Proceeds from dispositions of 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 field. The 2004 proceeds from dispositions of assets consists primarily of $39 million in proceeds realized upon the sale of Devon Energy Corporation common stock. Our remaining investment in Devon common stock was disposed of in the third quarter of 2004.

In June of 2004, we completed our merger with Westport, which was financed by issuing our common stock and assuming Westport’s debt obligations and, therefore, did not affect investing cash flows, except for Westport cash balances of $43 million acquired in the merger.

With planned asset divestitures discussed above under Overview and Recent Developments, we expect proceeds from asset disposals to represent a significant source of cash in 2005 and 2006. The timing and magnitude of cash flows associated with such divestitures will depend on the market conditions, the composition of assets divested and other transaction terms. As discussed under Financial Condition and Liquidity - Tranche X and Tranche B Term Loans, pursuant to the mandatory prepayment provisions of the Credit Agreement, the net after-tax proceeds from asset disposals will be used for debt repayment.

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Financing Activities - The following provides a summary of significant components of cash used in financing activities for the six-month periods ended June 30, 2005 and 2004:

	Six Months Ended
	June 30,
(Millions of dollars)	2005			2004
Proceeds of borrowings, net of related transaction costs	$	4,192		$	86
Cash received upon exercises of employee stock options		159			7
Repurchases of common stock, including transaction costs		(4,225	)		-
Payment of dividends		(142	)		(91	)
Repayment of debt		(392	)		(347	)
Settlement of Westport derivatives		(80	)		-
Total cash used in financing activities	$	(488	)	$	(345	)

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 a result of increased market price of our common stock in 2005, employee stock option exercises increased substantially compared to the prior year. Based on the price of our common stock at June 30, 2005, all 3.2 million exercisable options held by our employees and non-employee directors were in-the-money as of that date.

While cash used to pay dividends during the first six months of 2005 was higher than 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 June 30, 2005 remains unchanged (115 million shares) and based on our current dividend payment policy, we expect to pay approximately $12 million in dividends during the second half of 2005.

In 2005, we paid $80 million to settle certain derivative instruments assumed in the Westport merger. These instruments extend through 2006 and had a net liability value at June 30, 2005 of $88 million, including $4 million payable for June settlements. Future settlement values may be higher or lower than the estimated fair value of unsettled contracts at June 30, 2005 and will be determined based on reference commodity prices in effect in the period of settlement.

Obligations and Commitments

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, subsea work, etc. 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, in connection with its exploration and production operations, the company has entered into additional  international exploration licenses which carry work commitments of approximately $39 million and expects to incur $9 million of associated expenditures in 2005 and a total of $30 million in 2006 and 2007. Also, the company has entered into additional drilling rig commitments to assure availability for executing our deepwater Gulf of Mexico drilling programs through the end of 2006. The company’s commitments under these arrangements total $246 million, a portion of which will be billed to other working interest partners once actual utilization is known.

As discussed above under Financial Condition and Liquidity,in May 2005 we incurred additional borrowings under the Credit Agreement, which affected the total amount of outstanding debt and expected contractual maturities. Information on contractual maturities of our debt outstanding at June 30, 2005 is provided below in the Interest Rate Risk section of Item 3.

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As discussed above under Overview and Recent Developments, the company plans to sell or spin off 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 6 to 18 months.  A total of $34 million will be payable under these programs 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.

New/Revised Accounting Standards

In December 2004, the FASB issued Statement No. 123 (revised 2004), “Share-Based Payment” (FAS No. 123R), which replaces FAS No. 123 and supersedes APB No. 25. FAS No. 123R requires all share-based payments to employees, 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 and Exchange Commission (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, and that the effect on its results of operations will be comparable to the pro forma disclosures under FAS No. 123 presented in Note 1 to the accompanying Condensed Consolidated Financial Statements.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk.

The company is exposed to a variety of market risks, 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 3 to the Condensed Consolidated Financial Statements included in Item 1, Part I of this Form 10-Q for discussions of the company’s derivatives and hedging activities.

Commodity Price Risk

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 June 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 planned divestitures) and approximately 50% of its 2007 expected eligible production. Eligible production excludes oil production in China and gas production from the North Sea.

At June 30, 2005, the following commodity-related derivatives were outstanding related to (i) the company’s hedging program and (ii) Westport’s derivative positions in place at the merger date.

	July - 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	$	45.85		24,250		$	53.05		12,512		$	49.91		12,750
Costless collars	$	39.67 - $53.68		23,250		$	43.00 - $62.51		30,512		$	43.00 - $60.11		12,750
				47,500					43,024					25,500

(a)   Acquired in the Westport merger.

(b)   Placed by Kerr-McGee in connection with the Westport merger.

(1)   These derivatives function similar to a costless collar, with the exception that if the WTI price falls below the three-way floor, the company loses price protection. For example, the company only has $4.07/barrel of price protection if the WTI price falls below $20.93/barrel in the case of its 2005 crude oil three-way collars ($25.00 - $20.93).

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	July - 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)		-		-			-		-
	$	7.18		267,631		$	7.53		196,000		$	7.03		265,000
Costless collars	$	5.00 - $6.25		280,000	(b)	$	4.75 - $ 5.50		340,000	(b)		-		-
	$	6.38 - $8.62		297,712		$	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
				960,343					753,000					530,000
Basis Swaps vs. NYMEX -
Hedge:
CIG (2)	$	0.65		71,794		$	0.85		1,233			-		-
NWPL (3)	$	0.63		66,726		$	0.79		4,932			-		-
HSC(4)	$	0.13		46,794			-		-			-		-
Nonhedge:
CIG	$	0.73		80,218		$	0.39		20,000		$	0.39		20,000	(5)
NWPL	$	0.68		5,014		$	0.20		15,000		$	0.20		15,000	(6)
HSC	$	0.18		26,685			-		-			-		-

(a)   Acquired in the Westport merger.

(b)   Placed by Kerr-McGee in connection with the Westport merger.

(1)   These derivatives function similar to a costless collar, with the exception that if the NYMEX price falls below the three-way floor, the company loses price protection. For example, the company only has $.96/MMBtu of price protection if the NYMEX price falls below $3.04/MMBtu in the case of its 2006 natural gas three-way collars ($4.00 - $3.04).

(2)   Colorado Interstate Gas pipeline index.

(3)   Northwest Pipeline Rocky Mountain index.

(4)   Houston Ship Channel index.

(5)   These basis swaps continue until June 30, 2008.

(6)   These basis swaps continue until December 31, 2008.

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 $720 million at June 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 $398 million from accumulated other comprehensive loss into earnings, assuming no further changes in the fair value of the related contracts.

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Interest Rate Risk

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 a 100-basis-point change in interest rates to be material to our earnings or cash flows.

The table below presents principal amounts and related weighted-average interest rates by maturity date for the company’s long-term debt obligations outstanding at June 30, 2005. All borrowings are in U.S. dollars. As discussed above under Financial Condition and Liquidity in Item 2, certain of the company’s variable-rate term loans are subject to mandatory prepayment provisions upon occurrence of specified events.

	Years of Maturity																					Fair
																There-						Value at
(Millions of dollars)	2005			2006			2007			2008			2009			after			Total (2)			6/30/05
Fixed-rate debt -
Principal amount	$	-		$	-		$	-		$	-		$	-		$	2,225		$	2,225		$	2,348
Weighted-average
interest rate		-			-			-			-			-			7.15	%		7.15	%
Variable-rate debt (1) -
Principal amount	$	120		$	329		$	2,172		$	23		$	23		$	2,149		$	4,816		$	4,816
Weighted-average
interest rate		8.75	%		6.46	%		5.43	%		5.79	%		5.79	%		5.79	%		5.75	%

⁽¹⁾   Includes fixed-rate debt with interest rate swaps to variable rate.

⁽²⁾   Principal amounts represent future payments and exclude the unamortized discount on issuance of $81 million and the discount arising from fair value hedge adjustments of $4 million.

Foreign Currency Exchange Rate Risk

Periodically, the company enters into forward contracts to buy and sell foreign currencies. Certain of these contracts (purchases of euro, Australian dollars and British pound sterling, and sales of euro) have been designated and have qualified as cash flow hedges of the company’s operating and capital expenditure requirements. These contracts generally have durations of less than three years. The resulting changes in fair value of these contracts are recorded in accumulated other comprehensive income (loss).

Following are the notional amounts at the contract exchange rates and weighted-average contractual exchange rates for contracts to purchase (sell) foreign currencies. Contract values for contracts open at June 30, 2005 are based on the estimated forward exchange rates in effect at quarter-end. All amounts are U.S. dollar equivalents.

(Millions of dollars,	Notional			Weighted-Average
except average contract rates)	Amount			Contract Rate
Open contracts at June 30, 2005 -
Maturing in 2005 -
British pound sterling	$	90			1.6980
Euro		67			1.2934
Australian dollar		5			.7509
Euro		(102	)		1.3100
Maturing in 2006 -
Australian dollar		2			.7629
Euro		(9	)		1.2850

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Item 4. Controls and Procedures.

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. There was no change in the company's internal control over financial reporting that occurred during the second quarter of 2005 that has materially affected or is reasonably likely to materially affect the company’s internal control over financial reporting.

Forward-Looking Information

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.

PART II - OTHER INFORMATION

Item 1.Legal Proceedings.

A. In 2002, Tiwest Pty. Ltd., an Australian joint venture that produces titanium dioxide and in which Chemical indirectly has a 50% interest, received a complaint and notice of violation from the Department of Environmental Waters and Catchment Protection in Western Australia alleging violations of the Australian Environmental Protection Act (1986). This matter concerned an alleged chlorine release at the facility. Tiwest Pty. Ltd. defended the proceeding in the Court of Petty Sessions, Perth, Western Australia, and on March 26, 2004, the Court found in favor of Tiwest Pty. Ltd. The Department appealed the Court's decision, and, on June 30, 2005, the Supreme Court of Western Australia dismissed the Department’s appeal.

B. On September 15, 2004, the Missouri Attorney General issued to Kerr-McGee Chemical LLC, a notice of violation of the Missouri Clean Water Act. The notice alleges the discharge of untreated contaminants from Kerr-McGee Chemical LLC's plant in Springfield, Missouri to the City of Springfield sanitation system and the Little Sac River. The Attorney General is requesting a civil penalty of $375,000, the performance of an environmental assessment and natural resource damages, which the Missouri Department of Natural Resources currently estimates to be $500,000. The contractor performing the decommissioning work at the plant at the time of the alleged discharge has acknowledged its contractual obligation to indemnify Kerr-McGee Chemical LLC for costs, damages or fines resulting from its actions. An agreement in principle has been reached with the State of Missouri to resolve this matter, and the contractor has agreed to pay all amounts due under the agreement.

C. For a discussion of other legal proceedings and contingencies, reference is made to Note 13 to the Condensed Consolidated Financial Statements included in Item 1, Part I of this quarterly report on Form 10-Q, which is incorporated herein by reference.

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

Issuer Purchases Of Equity Securities

The following table summarizes the company’s repurchases of equity securities registered under Section 12 of the Securities Exchange Act of 1934 that occurred in the quarter ended June 30, 2005.

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 (b)		Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (b)
April 1-30, 2005		5,050	$	52.06		-	$	-
May 1-31, 2005		46,744,739		84.99		46,727,763		-
June 1-30, 2005		23,386		74.15		-		-
Total		46,773,175	$	84.99		46,727,763	$	-

^(a)   Includes 24,200 shares purchased in the open market for the matching contributions to Kerr-McGee Corporation Savings Investment Plan, 21,212 shares delivered to the company by the employees in satisfaction of withholding taxes and upon forfeiture of restricted shares and 46.7 million shares purchased in connection with the tender offer discussed below.

^(b)   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 and not withdrawn at a price of $85 per share. 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.

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

The 2005 annual meeting of stockholders was held on May 10, 2005 and, after adjournment, recalled to order on June 7, 2005. The following matters were voted upon at the 2005 annual meeting:

(1)   Stockholders ratified the appointment of Ernst & Young LLP as the company’s independent auditors for 2005. There were 135,863,830 votes for the proposal; 1,920,696 votes against the proposal; and 8,231,648 abstentions.

(2)   Stockholders approved the 2005 Long Term Incentive Plan. There were 125,938,919 votes for the proposal; 18,758,075 votes against the proposal; and 8,882,318 abstentions.

(3)   Stockholders approved an amendment to the Amended and Restated Certification of Incorporation to increase the authorized number of shares of common stock from 300,000,000 to 500,000,000. There were 125,938,919 votes for the proposal; 11,609,107 votes against the proposal; and 8,468,139 abstentions.

(4)   Stockholders did not approve a stockholder proposal to establish an Office of the Board of Directors. There were 10,094,397 votes for the proposal; 97,170,448 votes against the proposal; and 8,923,532 abstentions.

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(5)   The following directors were elected with the following vote totals.

	Votes	Votes
	In Favor	Withheld
William F. Wallace	139,760,561	8,332,992
Ian L. White-Thomson	139,731,797	8,361,756

Item 6.Exhibits.

Exhibit No.
3.1	Amended and Restated Certificate of Incorporation of Kerr-McGee Corporation, filed as Exhibit 4.1 to the company's Registration Statement on Form S-4/A dated June 18, 2001, and incorporated herein by reference.
3.2	Certificate of Amendment to Amended and Restated Certificate of Incorporation, filed as Exhibit 3.1 to the company’s Current Report on Form 8-K dated May 12, 2005, and incorporated herein by reference.
3.3	Amended and Restated ByLaws of Kerr-McGee Corporation, filed as Exhibit 3.1 to the company’s Current Report on Form 8-K dated April 14, 2005, and incorporated herein by reference.
10.1	Guarantee and Collateral and Collateral Trust Agreement, dated May 24, 2005, made by Kerr-McGee Corporation and certain of its subsidiaries, in favor of JPMorgan Chase Bank, N.A., as Collateral Agent, filed as Exhibit 99.1 to the company’s Current Report on Form 8-K dated May 27, 2005, and incorporated herein by reference.
10.2	Credit Agreement, dated May 18, 2005, by and among Kerr-McGee Corporation, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, Lehman Commercial Paper Inc., as Syndication Agent, and The Royal Bank of Scotland PLC, ABN Amro Bank N.V., Bank of America, N.A., Calyon New York Branch and Citicorp North America, Inc., as Documentation Agents and the several lenders from time to time parties thereto, filed as Exhibit 99.1 to the Company's Form 8-K filed May 19, 2005, and incorporated herein by reference.
10.3	Retirement Benefit Preservation Agreement, dated July 18, 2005, between Kerr-McGee Corporation and Luke R. Corbett, filed as Exhibit 99.2 to the company’s Current Report on Form 8-K dated July 18, 2005, and incorporated herein by reference.
10.4	Retirement Benefit Preservation Agreement, dated July 18, 2005, between Kerr-McGee Corporation and Kenneth W. Crouch, filed as Exhibit 99.3 to the company’s Current Report on Form 8-K dated July 18, 2005, and incorporated herein by reference.
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.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

KERR-McGEE CORPORATION

Date: August 8, 2005	By:	/s/ John M. Rauh
		John M. Rauh
		Vice President and Controller
		and Chief Accounting Officer

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