Annual report 2005

10-K 1 annualreport2005.htm ANNUAL REPORT 2005 Annual report 2005

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2005

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)

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

Securities registered pursuant to Section 12(b) of the Act:

		NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS		WHICH REGISTERED

Common Stock $1 Par Value		New York Stock Exchange
Preferred Share Purchase Right

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes x No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No x

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 and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

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

Yes x No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $8.8 billion computed by reference to the price at which the common equity was last sold as of June 30, 2005, the last business day of the registrant's most recently completed second fiscal quarter.

The number of shares of common stock outstanding as of February 28, 2006, was 113,776,350.

DOCUMENTS INCORPORATED BY REFERENCE

The definitive Proxy Statement for the 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2005, is incorporated by reference in Part III of this Form 10-K.

KERR-McGEE CORPORATION

PART I

Items 1. and 2. Business and Properties

GENERAL DEVELOPMENT OF BUSINESS

Through predecessors of its affiliates, Kerr-McGee Corporation began operations in 1929 as a privately held company. In 1956, stock of the company’s affiliates began trading publicly on the New York Stock Exchange under the ticker symbol “KMG.” Kerr-McGee's worldwide businesses are consolidated for financial reporting and disclosure purposes. Accordingly, the terms "Kerr-McGee," "the company," “we,”“our” and similar terms are used interchangeably in this Form 10-K to refer to the consolidated group or to one or more of the companies that are part of the consolidated group. The term “Tronox” is used interchangeably in this Form 10-K to refer to Tronox Incorporated, one or more of its subsidiaries or the consolidated group of Tronox Incorporated and its subsidiaries. Tronox is a majority-owned subsidiary holding Kerr-McGee’s chemical business.

Kerr-McGee is one of the largest U.S.-based independent oil and natural gas exploration and production companies, with nearly 1 billion barrels of oil equivalent (boe) of proved reserves as of December 31, 2005. The company’s major producing operations are located onshore in the United States, the U.S. Gulf of Mexico, and offshore China. In addition, we explore for oil and gas in these core areas and in proven hydrocarbon basins worldwide, including the North Slope of Alaska and offshore West Africa, Brazil and Trinidad and Tobago. The company actively acquires leases and concessions and explores for, develops, produces and markets crude oil and natural gas. Our strategy is to enhance value for our stockholders through the development of a well-balanced portfolio of high-quality oil and gas assets that provides a large inventory of repeatable, low-risk exploitation projects and high-potential exploration opportunities.

Strategic Realignment

In 2005, we made a number of strategic decisions in an effort to reposition Kerr-McGee as a pure-play exploration and production company and enhance value for our stockholders, including divestitures of lower-growth or shorter-life and higher-decline oil and gas properties and the separation of the chemical business. In selecting assets for divestiture, our goal was to retain oil and gas assets that offer the greatest stability and growth opportunities, with reduced capital intensity. The 2005 divestiture program provided net proceeds of $4 billion (before cash income taxes), allowing us to reduce debt and return value to stockholders by executing stock repurchases. Proceeds from divesting oil and gas assets, along with net proceeds from an initial public offering (IPO) and borrowings by Tronox, were used to repay debt, including $4.25 billion borrowed in May 2005 primarily to fund a $4 billion tender offer for Kerr-McGee’s common stock.

Going forward, we refined our exploration and production strategy, implementing a three-pronged business plan. The key components of this plan are as follows:

·	Accelerated development of the company’s two major Rocky Mountain natural gas resource plays, the Greater Natural Buttes area in Utah and the Wattenberg field in Colorado

·	Exploration focused on high-impact targets in proven hydrocarbon basins with a track record of delivering world-class discoveries, including the deepwater Gulf of Mexico, the North Slope of Alaska, Brazil and other international areas

·	Creative business development by taking advantage of opportunities to maximize value in the long term through acquisitions, divestitures and strategic partnering

We believe this refined strategy underpins organic growth of production and reserves and adds stability to the company’s financial and operating results.

Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in the company’s 2006 Proxy Statement are not deemed to be filed as part of this Annual Report on Form 10-K.

Asset Divestitures and Tronox Separation

In January 2006, Kerr-McGee announced an agreement to sell its interests in Gulf of Mexico shelf oil and natural gas properties to W&T Offshore, Inc. (W&T) for approximately $1.34 billion in cash, subject to certain adjustments. The transaction, which has an effective date of October 1, 2005 and is subject to customary closing conditions and regulatory approvals, is expected to close during the second quarter of 2006. Had we completed this transaction at the end of 2005, our proved reserves would have been approximately 900 million barrels of oil equivalent (MMboe). Average daily production from the Gulf of Mexico shelf fields at year-end 2005 was approximately 25,000 boe or about 10% of the company’s worldwide production at year-end 2005. The sale of the Gulf of Mexico shelf assets is the final step in our divestiture program initiated in 2005.

In 2005, the company sold its entire North Sea oil and gas business for approximately $3.5 billion in cash (before considering working capital, interest and other adjustments). On September 30, 2005, we completed the sale of our interests in four nonoperated oil and gas fields in the United Kingdom sector of the North Sea and related exploratory acreage and facilities for approximately $566 million. On November 17, 2005, we completed 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 to a subsidiary of A.P Moller - Maersk A/S for a cash purchase price of $2.95 billion. The North Sea oil and gas business included proved reserves of 234 MMboe at closing and produced a daily average of approximately 65,500 boe during the third quarter of 2005, representing approximately 20% of the company’s total production during that period. The results of the North Sea business are reported in our financial statements as a discontinued operation. Additional information about the North Sea divestiture transactions and their financial statement effects is provided in Note 2 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

In the fourth quarter of 2005, we substantially completed our planned divestitures of selected oil and gas properties onshore in the U.S. in several separate transactions, realizing net cash proceeds of $493 million (before cash income taxes). These properties had proved reserves of 51 MMboe and produced a daily average of approximately 7,200 boe during 2005.

In November 2005, we completed the IPO of 17.5 million shares of Tronox Class A common stock, which reduced Kerr-McGee’s equity interest in Tronox to 56.7%. On March 8, 2006, Kerr-McGee’s Board of Directors (the Board) declared a dividend of Tronox’s Class B common stock (the Distribution). Kerr-McGee expects to distribute to its stockholders approximately .20 of a share of Tronox Class B common stock for each outstanding share of Kerr-McGee common stock they own on the record date of March 20, 2006. The Distribution is expected to be completed on March 30, 2006. Upon completion of the Distribution, Kerr-McGee will have no ownership or voting interest in Tronox.

For an expanded discussion of recent business developments, refer to Management’s Discussion and Analysis included in Item 7 of this Annual Report on Form 10-K.

Business Combinations

On June 25, 2004, we completed a merger with Westport Resources Corporation (Westport), an independent exploration and production company with operations onshore in the Rocky Mountain, Mid-Continent and Gulf Coast areas in the U.S. and in the Gulf of Mexico. The merger added 281 MMboe to our proved reserves, including natural gas reserves in the Greater Natural Buttes area in Utah. In exchange for Westport's common stock and options, Kerr-McGee issued stock valued at $2.4 billion, options valued at $34 million and assumed debt of $1 billion, for a total of $3.5 billion (net of $43 million of cash acquired). The fair value assigned to assets acquired and goodwill totaled $4.6 billion. We believe this merger improved the risk profile of our assets by adding low-risk exploitation opportunities and increasing the proportion of U.S. onshore natural gas reserves in our portfolio. For a more detailed description of the Westport merger, see Note 4 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

On August 1, 2001, the company completed the acquisition of all the outstanding shares of common stock of HS Resources, Inc. (HS Resources), an independent oil and gas exploration and production company with activities in the Denver-Julesburg (DJ) Basin, Gulf Coast, Mid-Continent and Northern Rocky Mountain regions of the U.S. Through this acquisition, we added approximately 217 MMboe of proved reserves, primarily consisting of natural gas reserves in the Wattenberg field, and expanded our low-risk exploitation drilling opportunities. The acquisition price totaled $1.8 billion in cash, company stock and assumption of debt.

SEGMENT AND GEOGRAPHIC INFORMATION

The following table provides an overview of our operating performance and the composition of our assets and revenues by segment. As discussed above, the chemical business is conducted by Tronox through its operating subsidiaries. Corporate and other assets presented below include assets of discontinued operations, while revenues relate only to the company’s continuing operations.

(Millions of dollars)	2005		2004		2003		2002			2001

Assets -
Exploration and production	$	11,127	$	10,260	$	5,348	$	4,919		$	4,958
Chemical		1,750		1,543		1,734		1,655			1,631
Corporate and other		1,399		2,715		3,168		3,335			4,487
Total	$	14,276	$	14,518	$	10,250	$	9,909		$	11,076

Revenues -
Exploration and production	$	4,563	$	3,096	$	2,132	$	1,514		$	1,493
Chemical		1,364		1,302		1,157		1,065			1,023
Total	$	5,927	$	4,398	$	3,289	$	2,579		$	2,516

Income (loss) from continuing operations	$	946	$	264	$	155	$	(97	)	$	279

For additional financial information with respect to our operating segments and geographic information, see Note 20 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

EXPLORATION AND PRODUCTION OPERATIONS

Our exploration and production business is focused on achieving value-added per-share growth through exploration, development and strategic acquisition of crude oil and natural gas properties. Our production efforts are concentrated in the U.S. Gulf of Mexico, the U.S. onshore and China. In addition, we explore for oil and gas in these core areas and in proven hydrocarbon trends worldwide, including the North Slope of Alaska and offshore West Africa, Brazil and Trinidad and Tobago.

Reserves

Kerr-McGee’s proved crude oil, condensate, natural gas liquids and natural gas reserves at December 31, 2005, and the changes in net quantities of such reserves for the three years then ended are shown in Note 24 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Estimates of total proved reserves filed with or included in reports to any other federal authority or agency during 2005 are within 5% of amounts shown in this filing.

Estimates of proved reserves and associated future net cash flows are made by the company’s engineers. In 2005, we continued to use the independent reserve engineering firm of Netherland, Sewell & Associates, Inc. (NSAI) to review methods and procedures used by our engineers to estimate December 31, 2005 reserve quantities and future revenue for certain oil and gas properties located in the United States. For additional information with respect to NSAI’s review and the company’s methods and procedures employed in the reserve estimation process, see Note 24 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Oil and Gas Sales Revenues, Production and Prices

The following table summarizes the company's crude oil and natural gas sales volumes and revenues from continuing operations for each of the three years in the period ended December 31, 2005. Sales revenues presented below include the impact of our hedging program.

(Dollars in millions)	2005		2004		2003

Crude oil and condensate (million barrels) -
U.S. Gulf of Mexico		20		22		21
U.S. onshore		13		10		7
China		7		3		1
		40		35		29

Crude oil and condensate sales revenues -
U.S. Gulf of Mexico	$	878	$	645	$	541
U.S. onshore		522		293		188
China		311		92		23
	$	1,711	$	1,030	$	752

Natural gas (billion cubic feet) -
U.S. Gulf of Mexico		138		133		101
U.S. onshore		213		173		129
		351		306		230

Natural gas sales revenues -
U.S. Gulf of Mexico	$	988	$	724	$	493
U.S. onshore		1,350		878		554
	$	2,338	$	1,602	$	1,047

Kerr-McGee’s average daily oil production from continuing operations for 2005 was 109 thousand barrels per day, a 13% increase from 2004. Kerr-McGee’s average realized oil price was $42.89 per barrel for 2005, including the impact of hedges, compared with $29.38 per barrel for 2004. During 2005, average daily natural gas production from continuing operations averaged 962 million cubic feet per day, up 15% from 2004. The 2005 average realized natural gas price was $6.66 per thousand cubic feet (Mcf), including the impact of hedges, compared with $5.24 per Mcf in 2004.

For additional information on average realized sales prices including and excluding the effect of our hedging arrangements, refer to Management’s Discussion and Analysis - Results of Operations by Segment - Exploration and Production in Item 7 of this Annual Report on Form 10-K. Note 22 to the Consolidated Financial Statements included in Item 8 of this report presents the average lifting costs per barrel of oil equivalent.

Developed and Undeveloped Acreage

The following summarizes the company’s developed and undeveloped acreage held through leases, concessions, reconnaissance permits and other interests at December 31, 2005:

	Developed Acreage				Undeveloped Acreage
Location	Gross		Net		Gross		Net

United States -
Onshore		2,798,911		1,626,298		2,314,096		1,190,151
Gulf of Mexico ⁽¹⁾		973,640		383,711		3,438,890		2,112,836
Alaska		-		-		46,418		32,687
		3,772,551		2,010,009		5,799,404		3,335,674

China		22,487		9,015		4,068,586		3,873,216

Other international -
Morocco ⁽²⁾		-		-		27,280,425		13,640,213
Australia		-		-		7,054,946		4,640,959
Bahamas		-		-		5,190,945		3,893,210
Benin		-		-		1,912,346		764,938
Brazil		-		-		1,082,890		408,853
Angola		-		-		1,181,162		295,291
Denmark		-		-		359,904		71,981
Trinidad and Tobago		-		-		159,324		71,696
		-		-		44,221,942		23,787,141
Total		3,795,038		2,019,024		54,089,932		30,996,031

⁽¹⁾	Includes acreage on the Gulf of Mexico shelf. As discussed under -Asset Divestitures and Tronox Separation above, we expect to sell our Gulf of Mexico shelf assets during 2006.

⁽²⁾	Expires in April 2006.

Gross and Net Productive Wells

The number of productive oil and gas wells in which the company had an interest at December 31, 2005 is shown in the following table. These wells include 1,143 gross or 487 net wells associated with improved recovery projects, and 2,532 gross or 2,436 net wells that have multiple completions but are included as single wells.

	Crude Oil				Natural Gas				Total
Location	Gross		Net		Gross		Net		Gross		Net

United States		3,498		2,303		7,531		4,593		11,029		6,896
China		53		21		-		-		53		21
Total		3,551		2,324		7,531		4,593		11,082		6,917

Net Exploratory and Development Wells Drilled

Exploratory and development wells associated with continuing operations that were completed as successful or declared dry holes during the three years ended December 31, 2005 are summarized in the following table:

	Net Exploratory ⁽¹⁾						Net Development ⁽¹⁾
	Productive		Dry Holes		Total		Productive		Dry Holes		Total		Total
2005 - ⁽²⁾
United States		13.8		12.7		26.5		448.7		9.9		458.6		485.1
China		-		2.8		2.8		8.8		-		8.8		11.6
Other international		-		.8		.8		-		-		-		.8
Total		13.8		16.3		30.1		457.5		9.9		467.4		497.5

2004 -
United States		13.6		9.5		23.1		412.7		7.5		420.2		443.3
China		-		1.8		1.8		12.4		-		12.4		14.2
Other international		-		.9		.9		-		-		-		.9
Total		13.6		12.2		25.8		425.1		7.5		432.6		458.4

2003 -
United States		6.7		11.0		17.7		241.6		1.0		242.6		260.3
Other international		-		5.0		5.0		.7		-		.7		5.7
Total		6.7		16.0		22.7		242.3		1.0		243.3		266.0

⁽¹⁾	Net wells represent the company’s fractional working interest in gross wells expressed as the equivalent number of full-interest wells.

⁽²⁾	The 2005 net exploratory well count does not include 6.3 successful net wells drilled in the United States that are currently suspended, nor does it include 1.0 successful net well drilled internationally that will not be used for production.

Wells in Process of Drilling

The following table shows the number of wells drilling and the number of wells suspended or awaiting completion as of December 31, 2005:

	Wells in Process				Wells Suspended or
	of Drilling				Awaiting Completion
	Exploration		Development		Exploration		Development
United States -
Gross		4.0		13.0		38.0		73.0
Net		1.7		4.6		14.5		38.2

China -
Gross		-		4.0		-		1.0
Net		-		1.5		-		.3

Total -
Gross		4.0		17.0		38.0		74.0
Net		1.7		6.1		14.5		38.5

Product Sales and Marketing

Our oil and natural gas production is sold at prevailing market prices. Our reported oil and natural gas sales revenues reflect net realized gains and losses on commodity derivative instruments designated as hedges of our oil and natural gas sales. For further details on such derivative instruments, see section Management’s Discussion and Analysis - Market Risks in Item 7 of this Annual Report on Form 10-K.

Kerr-McGee markets all of its crude oil under a combination of term and spot contracts to refiners, marketers and end users at market-reflective prices. The creditworthiness of each successful bidder is reviewed prior to product delivery. Our single-largest purchaser of U.S. natural gas is Cinergy Marketing & Trading LLC (Cinergy), whose purchases are guaranteed by its parent company, Cinergy Corporation. Purchases by Cinergy represented approximately 50% of total natural gas sales revenues, or 29% of total crude oil and natural gas sales revenues in 2005.

Marketing of the company's natural gas from the Wattenberg and Natural Buttes fields, located in northeastern Colorado and northeastern Utah, respectively, is facilitated through its subsidiary, Kerr-McGee Energy Services Corporation (KMES). KMES is primarily engaged in the sale of the company's natural gas production. To fulfill its direct sales obligations and to fully utilize its contracted transportation capacity, KMES also purchases and markets natural gas from third parties. KMES sells natural gas to a number of customers in the Denver, Colorado, market adjacent to the company's Wattenberg field, and in other markets in the Rocky Mountain area.

In support of our accelerated development program in the Greater Natural Buttes area, we have entered into a Precedent Agreement with Wyoming Interstate Company, LTD (WIC), a subsidiary of El Paso Corporation, whereby we placed a bid for firm transportation capacity of 225,000 million British thermal units per day (MMBtu/d) from the Greater Natural Buttes area to Kanda, Wyoming. WIC plans to build a 128-mile pipeline (the Kanda Lateral project) that will transport natural gas from the Greater Natural Buttes area to Kanda, Wyoming, increasing overall transportation capacity of natural gas out of the Uinta Basin into the interstate pipeline system providing access to the Rocky Mountains, West Coast, Northwestern, Mid-Continent and Midwest markets. The new pipeline is expected to be placed in service in 2008. Until the new pipeline is in service, we are using our existing firm transportation contracts to provide flow assurance for our development program and we also have entered into sales contracts with local distribution companies having firm transportation agreements on existing pipelines.

Exploration and Development Activities

The following table shows a summary of key 2005 data for the company’s operating areas. Production volumes are presented in thousands of barrels of oil equivalent per day (Mboe/d) and exclude production from our discontinued North Sea operations. Reserve volumes are stated in millions of barrels of oil equivalent (MMboe). Additional information regarding oil and condensate and natural gas production, along with average prices realized in 2005, 2004 and 2003 for the company's core geographic areas can be found in Management's Discussion and Analysis - Results of Operations by Segment - Exploration and Production in Item 7 of this Annual Report on Form 10-K.

	Estimated Proved										Realized Sales Price
	Reserves at 12/31/05					2005 Production					Including Hedges
											Oil		Gas
	MMboe		Percentage			Mboe/d		Percentage			$ per Barrel		$ per Mcf

U.S. onshore		582		60	%		133		49	%	$	40.62	$	6.32
U.S. Gulf of Mexico		346		36			118		44			43.79		7.18
U.S. Total		928		96			251		93			42.55		6.66

China		40		4			19		7			44.45		-
Total		968		100	%		270		100	%		42.89		6.66

U.S. Onshore

During 2005, Kerr-McGee continued to capitalize on the Westport and HS Resources acquisitions by successfully expanding its development programs in the U.S onshore, growing 2005 production by 24% compared to 2004, largely due to a full year of production from the Westport properties. In 2005, 61% of our natural gas and 32% of our crude oil and condensate were produced from U.S. onshore areas. Total proved reserves for the U.S. onshore area at year-end 2005 totaled 582 MMboe or 60% of the company’s worldwide proved reserves. Consistent with our strategy to build an asset base weighted toward longer-life assets that provide a more stable production profile and higher degree of predictability, we will continue to invest in the growth of this region. In 2006, the company expects the U.S. onshore area will represent 70% of its natural gas production and 30% of its oil production.

Exploration and production activities in the U.S. onshore area are segregated into two regions, Rocky Mountain and Southern. The Rocky Mountain operations, located in Colorado, North Dakota, Montana, Utah, and Wyoming, consist primarily of low-risk, high-margin resource plays. These assets provide the company with profitable organic growth, long-lived gas reserves and predictable performance. Production from the Rocky Mountain area totaled 77,900 barrels of oil equivalent per day (boe/d), a 34% increase from 2004 levels. Capital investment in the Rocky Mountain division totaled $492 million in 2005 and represented approximately 32% of the company’s total 2005 capital program. Consistent with our business strategy, which is described above under -General Development of Business, 2006 capital spending in this area is expected to increase to approximately $580 million, 44% of our worldwide 2006 exploration and production capital budget.

The Southern operations are primarily focused in Texas, Louisiana, Oklahoma and New Mexico. These assets provide us with stable production performance and predictable cash flow. Production for the Southern region increased in 2005 to 54,800 boe/d, a 15% increase over 2004. The Southern region exploration program also contributed to the region’s growth with a 60% exploration drilling success rate with most wells being located near Kerr-McGee-operated facilities. A total of 15 exploration wells were successful in 2005, many of which have additional development potential.

The following outlines key activities in each of the significant U.S. onshore operating areas.

Rocky Mountain

Greater Natural Buttes area, Uinta County, Utah (82% working interest) - Kerr-McGee obtained an interest in the Greater Natural Buttes area in 2004 as the result of the merger with Westport. At year-end 2005, Kerr-McGee operated approximately 940 wells in the Greater Natural Buttes area and had interests in an additional 500 nonoperated wells. The combined net production rates from this area at year-end 2005 were 900 barrels per day (b/d) of oil and 154 million cubic feet per day (MMcf/d) of gas. The 2005 drilling program was primarily focused on exploitation of the Wasatch and Mesa Verde formations, present throughout our Greater Natural Buttes acreage position. The 2005 development program was largely oriented towards the appraisal of eight core drilling areas and estimating resource potential of the company’s acreage in the area. Kerr-McGee participated in more than 195 wells drilled in 2005 and plans to accelerate this activity in 2006 in order to capitalize on the extensive natural gas resource opportunities in the Wasatch and Mesa Verde formations. Our capital spending budget for the Greater Natural Buttes area exceeds $340 million, dedicated primarily to development drilling activity.

In support of the production operations in Greater Natural Buttes, Kerr-McGee operates over 600 miles of gas gathering pipeline and 30 gas compressors, totaling 36,000 horsepower. The system grew by 12,000 horsepower in 2005. The system has the capacity to deliver 265 MMcf/d of gas via multiple interstate pipeline systems, giving us the ability to service multiple markets. The gathering system will continue to grow in support of the field’s aggressive development program, with a minimum of 12 additional compressor installations planned for 2006. Gross gas production gathered at year-end 2005 was 210 MMcf/d, 18 MMcf/d of which represented third-party volumes.

Wattenberg field, Northeast Colorado (94%) - Kerr-McGee obtained an interest in the Wattenberg field area as the result of the merger with HS Resources, Inc. in 2001. The Wattenberg gas field is located in the DJ Basin in northeast Colorado. Our 2005 net oil and natural gas production from this field was 12,260 b/d and 156 MMcf/d, respectively. During 2005, the company completed more than 360 development projects in the field, including deepenings, fracture stimulations, recompletions and an aggressive infill drilling program.

The drilling activities in 2005 focused on confirming the need for downspacing in the Codell, Niobrara, and J Sand formations. During 2005, we drilled 62 infill wells throughout the field, gathering pressure and production data for use at a Colorado Oil and Gas Conservation Commission (COGCC) spacing hearing, addressing the need for increased drilling density in the Wattenberg field. This effort was ultimately successful. In December 2005, COGCC allowed the revision of Rule 318A which approves downspacing from 40 acres to 20 acres. The rule is scheduled to take effect in March 2006. Because of our large acreage position in the field, this change creates potential for a significant number of new drillsites for 2006.

Also in 2005, we continued the appraisal program, testing a third fracture on producing Codell wells and performing 38 additional tests. This program was successful economically and provided justification for prospective reserve additions.

In support of the ongoing DJ Basin exploitation program, the company continued to successfully integrate the Wattenberg gas gathering system into its operating activities. Approximately 71,000 horsepower is currently being utilized to maintain system pressures for over 1,700 miles of gathering pipeline. Operation and management of the gathering system continues to provide improved reliability and reduced wellhead pressures systemwide. Kerr-McGee now operates more than 3,700 wells in the DJ Basin. Company-operated production represents about 60% of the total system throughput of approximately 240 MMcf/d, 30 MMcf/d of which is processed at our Ft. Lupton plant.

Moxa Arch field, Southwest Wyoming (37%) - Kerr-McGee obtained an interest in the Moxa Arch field area in 2004 as the result of the merger with Westport. We operate approximately 230 wells in the Moxa Arch field and have interests in an additional 140 nonoperated wells. Combined estimated net production from this area at year-end 2005 was approximately 225 b/d of oil and 28 MMcf/d of natural gas. The Moxa Arch field development program continues to provide favorable results in the Frontier and Dakota formations. During 2005, Kerr-McGee participated in 42 operated wells and three nonoperated wells, including one Dakota formation well that had an initial natural gas production rate in excess of five MMcf/d. Development drilling in this area is expected to continue in 2006.

Exploration Activities - During 2005, we participated in 14 exploratory wells in the Rocky Mountain region. We added three producing wells and are awaiting completion of a fourth well in our Wind River Basin Wyoming resource play, with delineation scheduled for 2006. In southwest Wyoming, we completed two gas wells in our Green River Basin Mesa Verde/Lewis resource play and are currently testing a third well. In North Dakota’s Williston Basin, our first horizontal Bakken formation test well was completed as an oil well and we are awaiting completion of another horizontal Bakken well on the northern end of the Elm Coulee field in Richland County, Montana. In the Uinta Basin of Utah, we drilled and completed a gas well in the Mulligan Unit, but severe drilling problems appear to have limited its success. Another test is scheduled for the Mulligan Unit in 2006.

Southern

The Southern region of our U.S. onshore operations had an active drilling program in 2005, participating in 259 development and 26 exploratory wells. Of the 285 wells, 249 were successful and 12 were drilling at year end. The 2005 Southern region exploration program had a 60% success rate with 15 discoveries in 2005, many of which have additional development potential.

Upper Gulf Coast area - In the upper Gulf Coast area, the company is focused primarily on Chambers, Hardin and Liberty counties in Texas. We participated in the drilling of 46 wells during 2005, and plan to continue our drilling program in this area during 2006 with 20 wells planned.

Liberty County, Texas - In 2005, Kerr-McGee expanded its Liberty County property base by drilling eight development wells, five of which were successful, and 12 exploratory wells, eight of which were successful. Three additional wells are planned for 2006. The company’s net production rate from Liberty County properties averaged approximately 5,800 boe/d in 2005.

Chambers County, Texas - In Chambers County, seven of 10 development wells drilled in 2005 were successful, with one drilling at year end. We plan to drill four wells in this area during 2006. Our net 2005 production in this area averaged 1,500 boe/d.

Hardin County, Texas - We expanded our drilling program in Hardin County, Texas, during 2005, drilling four exploration wells, three of which were successful, and two successful development wells. At least five additional wells are planned for 2006. Our net production in Hardin County averaged 300 boe/d, with an end of year net production rate of 1,340 boe/d.

South Texas area - In the south Texas area, Kerr-McGee participated in 61 wells during 2005, including five Wilcox, 43 Frio/Vicksburg and nine Lobo formation wells. In 2006, we plan to drill more than 35 wells in south Texas. Two key locations of focus for us in this area are:

Starr and Hidalgo counties, Texas - Kerr-McGee had an active drilling program in Starr County during 2005. Twenty-eight wells were spud, of which 26 resulted in new production and two were drilling at year end. Average net production in 2005 from Starr and Hidalgo counties was 9,300 boe/d.

Mobil-David field, Texas - The Mobil-David field in Nueces County, Texas, produces from the Howell Hight formation at depths of approximately 12,000 feet. In 2005, we spud nine development wells in this field, seven of which were successful. Average 2005 net production from Mobil-David was 1,200 boe/d.

Mid-Continent/Permian area - In the Mid-Continent/Permian area, Kerr-McGee participated in 178 wells during 2005. At year end, 138 of these wells were producing, six were drilling, 16 were in completion phase, and 16 were sold before completion. This area covers New Mexico, west Texas, northern Louisiana, Oklahoma, and Kansas. Two key locations within the Mid-Continent/Permian area for the company are north Louisiana and Andrews County, Texas.

North Louisiana - We own an interest in the Elm Grove field and in the North Louisiana Field Complex, which is comprised of four adjacent fields. Kerr-McGee maintained an active development drilling program in the area, participating in 106 wells, 98 of which were successful and five were drilling at year end. We expect to drill more than 45 wells in this area in 2006. The company’s net production from this area was approximately 5,500 boe/d at year-end 2005.

Andrews County, Texas - In 2005, we continued development of the Andrews Wolfcamp Waterflood in west Texas. Five wells were drilled in 2005 on this company-operated property (average working interest of 98%). Net production in 2005 averaged approximately 2,000 boe/d, the highest daily average production of any annual period since the field was discovered in 1953.

U.S. Gulf of Mexico

Kerr-McGee is one of the largest independent exploration and production companies operating in the Gulf of Mexico, with leases covering more than 4 million gross acres. In 2005, the company maintained its position as one of the largest independent leaseholders in the deepwater Gulf of Mexico with approximately 510 deepwater blocks covering more than 3 million acres (deepwater locations are those in depths of more than 1,000 feet). We believe this extensive acreage position provides a significant competitive advantage in our effort to maintain and develop a high-quality exploration prospect inventory.

Kerr-McGee's Gulf of Mexico region has continued to utilize the company’s competitive advantage, delivering innovative and cost-effective technologies in pursuit of oil and gas resources located in deep water. Kerr-McGee was the first company to utilize floating production spar technology in the Gulf of Mexico on its Neptune development in 1997. We have continued to advance this technology by utilizing improved truss spar designs for our developments at the Nansen, Boomvang and Gunnison discoveries, sanctioned for development in 2000 and 2001. In 2004, the company utilized a new cell spar technology for the Red Hawk development, lowering the threshold for economic development of deepwater reservoirs. Finally, Kerr-McGee’s fourth truss spar was successfully installed in 2005 in preparation for first-quarter 2006 production from the Ticonderoga development, to be followed by Constitution field production in the second quarter.

Gulf of Mexico production represented approximately 50% of the company’s worldwide crude oil and condensate production and 39% of its natural gas production in 2005. Proved reserves for the U.S. Gulf of Mexico area at year-end 2005 totaled 346 MMboe or 36% of Kerr-McGee’s worldwide proved reserves. For 2006, we expect the Gulf of Mexico region to contribute 54% of the company’s total oil production and 29% of its natural gas production.

Development Activities

During 2005, development activity in the deepwater Gulf of Mexico continued at a high level in terms of capital investment, wells drilled and construction activity. Our fourth truss spar was successfully installed to develop the Constitution and Ticonderoga discoveries. To accommodate production from Ticonderoga, the spar’s capacity has been expanded to process 70,000 b/d of oil and 200 MMcf/d of gas. The facility installation was accomplished ahead of schedule and on budget, in spite of hurricane-related disruptions in the Gulf of Mexico. Development drilling was completed and well completion work commenced in 2005. The project remains on schedule, and first production from the Ticonderoga subsea wells was achieved in the first quarter of 2006. First production from the Constitution field is expected in the second quarter of 2006. Kerr-McGee holds a 100% working interest in Constitution and a 50% working interest in Ticonderoga.

In 2005, Kerr-McGee sanctioned participation in a major deepwater development of the Blind Faith field, located in Mississippi Canyon blocks 695 and 696. First oil production is expected in mid-2008. We also sanctioned participation in the development of two exploration satellite discoveries. Dawson Deep, a 2004 discovery on Garden Banks (GB) block 625, where Kerr-McGee has a 25% working interest, is being developed as a tieback to the Gunnison spar. A 2005 discovery on East Breaks (EB) block 599, where Kerr-McGee holds a 33% working interest, is being developed as a tieback to the Boomvang spar.

Development at the Independence Hub, a joint project to develop several gas fields in the ultra-deep waters (defined as greater than 8,000 feet) of the Gulf of Mexico, continued in 2005. The project is expected to be completed by the first quarter of 2007, with first production anticipated by mid-year 2007. Also during 2005, a four-well recompletion program added more than 100 MMcf/d of gross natural gas production at Nansen. One subsea well in the Nansen field was successfully sidetracked and completed. At the end of 2005, we started a multiwell satellite drilling program in the Northwest Nansen field area. The program continued into the first quarter of 2006. The company holds a 50% working interest in the Nansen field. In the Gunnison field, the first of two development wells planned for 2005 was completed and is producing gas at a gross rate of 60 MMcf/d, increasing Gunnison spar production rates to historic peak levels. The second development well, drilled in 2005, was being completed at year end, and came on line in January 2006, at a gross production rate of 20 MMcf/d of gas. Kerr-McGee holds a 50% working interest in the Gunnison field.

Exploration Efforts

The Gulf of Mexico was a major focus of our exploration efforts in 2005. During the year, 23 exploratory wells were drilled on the Gulf of Mexico shelf and in the deep water, resulting in eight discoveries. In the deepwater Gulf of Mexico, we spud nine exploratory wells, with two discoveries at EB 599 #2 and Nansen Northwest (EB 602 #10). The EB 599 discovery will be developed as a tieback to the Boomvang production hub. The Nansen Northwest discovery will be tied back to the Nansen facility and is one of four similar prospects. The other three prospects will be drilled in 2006. 14 exploratory wells were spud on the Gulf of Mexico shelf, resulting in six successful wells. All of the Gulf of Mexico shelf discoveries are part of the divestiture transaction with W&T discussed below under -Gulf of Mexico Shelf.

At the close of the year, Kerr-McGee had contracts in place to assure deepwater drilling rig availability for executing our 2006 and 2007 exploration programs. Securing rig availability is expected to allow the exploration program to be executed as planned.

Deepwater Gulf of Mexico

Gunnison field, Garden Banks block 668 area (50% working interest) - The Gunnison field was sanctioned for development in October 2001, and first production was achieved in December 2003. The Gunnison development incorporates a truss spar in 3,100 feet of water and has seven dry-tree wells and four subsea wells. The first of two development wells drilled in 2005 was completed and produced at an average gross rate of 60 MMcf/d of gas during the year, increasing Gunnison spar production rates to historic peak levels. The second development well is now on line and producing gas at a gross rate of approximately 20 MMcf/d. In addition, the Dawson Deep discovery in GB 625 is being developed as a subsea tieback to the Gunnison spar in 2006. Average gross production from Gunnison in 2005 was 16,700 b/d of oil and 95 MMcf/d of gas.

Nansen field, East Breaks blocks 602, 646, 689, 690 (50%) - The Nansen field was sanctioned for development in March 2000, and first production was achieved in January 2002. Average 2005 gross production was 24,800 b/d of oil and 179 MMcf/d of gas. The Nansen field was developed with a truss spar in 3,700 feet of water and has nine dry-tree wells and three subsea wells tied back to the spar from a subsea cluster. An additional three subsea wells are tied back to the spar from a subsea cluster known as the Navajo area. During 2005, a four-well recompletion program brought natural gas production up to the facility capacity levels of 230 MMcf/d. A sidetrack of one of the subsea wells also was successfully drilled and completed. At the end of 2005, we began a multiwell satellite drilling program in the Northwest Nansen field area, which resulted in one discovery. Drilling of the remaining three prospects is expected during 2006.

Boomvang field, East Breaks blocks 641, 642, 643, 686 and 688 (30%), block 598 (100%), and block 599 (33%) - The Boomvang field was sanctioned for development in July 2000, and first production was achieved in June 2002. The Boomvang field was developed with a truss spar in 3,450 feet of water, and has five dry-tree wells and seven subsea wells tied back to the spar from three subsea clusters. In 2005, Kerr-McGee acquired a 50% interest in EB 598 from Devon Energy Corporation, increasing Kerr-McGee’s working interest in this block to 100%. A satellite exploration well EB 599 #2 was successful and development of this discovery is under way as a tieback to the spar. Additional exploration satellites also are under evaluation. Average 2005 gross production from the Boomvang area was 31,700 b/d of oil and 98 MMcf/d of gas.

Red Hawk field, Garden Banks block 877 (50%) - Development of Red Hawk, a 2001 discovery, was sanctioned in July 2002, utilizing the world’s first cell spar, designed for developing smaller reservoirs in deepwater basins. Located in approximately 5,300 feet of water, the field was developed using two subsea wells tied back to the cell spar. The two wells were completed during 2003 prior to installation of the spar. In 2004, the cell spar and production facilities were installed. The facilities were commissioned and production began in July 2004. Production from Red Hawk was shut-in following Hurricane Rita, although there was no significant damage to the spar. Production is scheduled to resume in March 2006, following downstream pipeline repairs, at a gross rate of approximately 120 MMcf/d of gas, consistent with production levels before the hurricane.

Neptune field, Viosca Knoll block 826, (50%) - Production from the Neptune field began in March 1997 from the world's first floating production spar. Presently, there are 10 dry-tree wells producing through the facility at a water depth of 1,950 feet. Three subsea wells also produced to the spar in 2005. During 2005, a facility upgrade was completed on the Neptune spar platform to accommodate Neptune’s first third-party tieback to the outside-operated Swordfish development. The tieback generates additional revenue and significantly lowers operating cost. The work was completed and increased platform capacity to 100 MMcf/d. At year end, gas throughput had reached expected peak capacity. Average 2005 gross production from Neptune was 6,200 b/d of oil and 40 MMcf/d of gas.

Conger field, Garden Banks block 215 (25%) - First production from the Conger field began in December 2000, from the first of three subsea wells. The three-well subsea development is the first multiwell, 15,000-psi subsea development and is located in approximately 1,500 feet of water. One additional well, a sidetrack of the Garden Banks 215 #6 well, was completed in December 2003. Average 2005 gross production from the Conger field was 20,600 b/d of oil and 75 MMcf/d of gas.

Baldpate field, Garden Banks block 260 (50%) - Average 2005 gross production from the Baldpate field, including the Penn State subsea satellite wells, was 9,900 b/d of oil and 31 MMcf/d of gas. The field is located in 1,690 feet of water and is producing from an articulated compliant tower. A successful exploration well was drilled and completed in late 2003 in Garden Banks 216 (Penn State) and was tied back to the existing Penn State subsea system. Drilling of an additional well (Penn State Deep) is planned for 2006.

Pompano field, Viosca Knoll block 989 area (25%) - Average 2005 gross production from the Pompano field was 9,800 b/d of oil and 17 MMcf/d of gas. During 2005, the A-1 well was successfully sidetracked and came on line in May. Workovers on two other wells were unsuccessful in attempts to re-establish production, resulting in plugging and abandonment of those wells.

Constitution field, Green Canyon blocks 679 and 680 (100%) - The Constitution project was sanctioned for development in January 2004, as Kerr-McGee's fourth truss spar development. To accommodate production from Ticonderoga, which is tied back to the Constitution truss spar, the spar’s capacity has been expanded to process 70,000 b/d of oil and 200 MMcf/d of natural gas. The spar was upended and moored in the summer of 2005 and the topsides were successfully installed in November 2005. Final commissioning and subsea system hookup work is under way. Development drilling on the six dry-tree producing wells was completed in 2005, and well completion work commenced in early 2006. First production is expected during the second quarter of 2006.

Ticonderoga field, Green Canyon block 768 (50%) - The Ticonderoga project was discovered and sanctioned for development in 2004 as a two-well subsea tieback to the Constitution spar. Development drilling and completion work was performed in 2005, with first production achieved in February 2006.

Independence Hub - In 2004, Kerr-McGee sanctioned participation in a joint project to develop several gas fields in the ultra-deep waters of the Gulf of Mexico. The project will consist of a host processing and export facility, which will be located in Mississippi Canyon block 920. This facility will receive production from 10 fields in the area through subsea tieback systems. Kerr-McGee owns interests in three of these fields as follows: Merganser, Atwater Valley block 37 (50% - operator); Vortex, Atwater Valley block 261 (50%); and San Jacinto, Desoto Canyon block 618 (20%). In early 2006, the Millennium drill ship began work to sidetrack and complete the two Merganser producing wells. First production is expected in 2007. Kerr McGee’s anticipated net natural gas production is over 100 MMcf/d.

Blind Faith field, Mississippi Canyon blocks 695 and 696 (37.5%) - In 2005, Kerr-McGee sanctioned participation in the Chevron-operated Blind Faith development. The project will consist of building a host processing and export facility, which will be located in Mississippi Canyon block 650. The facility will be a deep draft semisubmersible and will receive production from three subsea wells drilled from a surface location in block 696. At the end of 2005, engineering for this facility was in progress. The facility will be capable of handling 45,000 b/d of oil and 45 MMcf/d of gas, with first production expected in 2008.

Gulf of Mexico Shelf

In January 2006, Kerr-McGee announced its agreement to sell its interests in Gulf of Mexico shelf oil and natural gas properties to W&T Offshore, Inc. (W&T) for approximately $1.34 billion in cash, subject to certain adjustments. In addition, W&T will assume responsibility for abandonment obligations of approximately $130 million. The transaction has an effective date of October 1, 2005. Closing, which is subject to customary closing conditions and regulatory approvals, is expected to occur in the second quarter of 2006.

Gulf of Mexico shelf development activity in 2005 was concentrated in two fields, South Timbalier 41 and Ship Shoal 214. In the South Timbalier 41 field, where the company owns a 40% working interest, three wells were completed during 2005. The A-2 and B-1 wells were completed in January, with a combined initial gross natural gas production of 43 MMcf/d. The C-1 well was completed in August as an oil well, with initial average gross production of 3,500 b/d of oil and 8 MMcf/d of gas. Additionally, an exploration well in the South Timbalier 41 field was drilled in 2005, extending the field to the east, and the B-2 development well was drilling at year end. In the Ship Shoal 214 field, three development wells were drilled and completed in the first half of 2005, with initial combined gross production of 3,400 b/d of oil and 17 MMcf/d. Kerr-McGee’s average interest in the field is approximately 65%.

A development well drilled in High Island 197 (25% working interest) began producing in September 2005, with initial gross natural gas production of 17 MMcf/d. First production from the Main Pass 95 #3 well (50% working interest) was achieved in July, at an initial gross rate of 17 MMcf/d of gas. A development well in Main Pass 94 (33% working interest) was drilling at the end of the year.

China

China’s Bohai Bay continues to be a core operating area for Kerr-McGee, with a total of eight discoveries made since the company first became involved in the area. Production in China represented 17% of the company’s 2005 worldwide oil production. We expect this area to contribute approximately 16% of the company’s 2006 oil production.

Bohai Bay block 04/36 (81.8% working interest in exploration phase and 40.09% in development and production phases) - Kerr-McGee commenced first production from the CFD 11-1 and CFD 11-2 oil fields in July 2004. Two platform topsides were installed and a floating production, storage and offloading (FPSO) vessel was built in China’s port city of Dalian and then mobilized to the fields in May 2004. Development drilling continued throughout 2005 at the CFD 11-1 field, and the development drilling program was completed at the CFD 11-2 field in 2004. By year-end 2005, a total of 52 wells had been drilled, completed and placed on either production or injection or used for water disposal. Full exploration and development cost recovery for CFD 11-1 was achieved in 2005. Development cost recovery for CFD 11-2 also was achieved during the first quarter of 2006. Kerr-McGee’s average production entitlement was reduced to approximately 37% from levels in excess of 50% due to cost recovery during 2005. Gross production from these fields for 2005 averaged 37,500 boe/d.

China National Offshore Oil Corp. (CNOOC) approved the Overall Development Plan (ODP) for the CFD 11-3 and CFD 11-5 fields in March 2005, and the government sanctioned the project in September 2005. Two of four planned wells in the CFD 11-3 and CFD 11-5 fields came on production ahead of schedule in July 2005. The remaining two wells have since been drilled, completed and placed on production. Two additional development well locations were identified from data acquired while drilling the first four wells. These two wells also were drilled and are currently producing. Production from the CFD 11-3 and CFD 11-5 fields tie back to the CFD 11-1 and CFD 11-2 facilities with full processing of the fluids at the FPSO. Aggregate gross oil production from the six wells was 10,700 b/d at year-end 2005.

Bohai Bay block 05/36 (working interest 76.9% in exploration phase; CFD 11-6/12-1/12-1S development and production phases - 29.2% working interest) - Kerr-McGee sanctioned the CFD 11-6/CFD 12-1/CFD 12-1S unit development in July 2005, followed by CNOOC board approval in August 2005. Formal government approval is expected in the first quarter of 2006. Fabrication and installation of the main jacket is complete and construction of the topsides is in process. The first two wells in the development drilling program were successfully drilled and first production is expected in the fourth quarter of 2006.

Bohai Bay block 09/18 (100% working interest in exploration phase) - One exploration commitment well was drilled in this area in 2005, the CFD 14-5-3. This well was an offset to the CFD 14-5-1 oil discovery in Eocene Shahejie sands. The CFD 14-5-3 encountered a thin oil column, which was deemed to be noncommercial. CNOOC has approved a one-year extension for the exploration phase, subject to government approval, whereby all 550,000 acres will be retained until October 31, 2006. 2-D seismic data was acquired in 2005 to further evaluate this acreage.

Bohai Bay block 09/06 (100% working interest in exploration phase) - The company signed an exploration contract in August 2003 for this 440,000-acre block in Bohai Bay adjacent to the other concessions operated by Kerr-McGee. CFD 14-5-2, an offset to the CFD 14-5-1 discovery well, was drilled in block 09/06 in mid-2005; encountered a thin oil column and was declared unsuccessful. Additional 3-D seismic data was purchased in 2005 to help define future prospectivity of the area.

South China Sea block 43/11 (100% working interest in exploration phase) - In the second quarter of 2005, Kerr-McGee entered into a production sharing contract with CNOOC for block 43/11, which covers 2.4 million undeveloped acres in the South China Sea. The block is located in water depths ranging from 5,000 feet to more than 10,000 feet and is the first deepwater exploration contract the company has entered into with CNOOC. The contract will allow us to leverage our deepwater expertise and build on the existing relationship with CNOOC. 2-D seismic data was acquired across the block during 2005, and is being interpreted to determine prospectivity. If Kerr-McGee enters into the development phase, CNOOC has the right to participate with up to a 51% interest.

Core New Venture Areas

Brazil

BM-C-7 (50%) - Kerr-McGee entered the 161,000-acre BM-C-7 Campos Basin block in December 2003 with a 33 1/3% interest. In 2004, Kerr-McGee participated in an exploratory well on the block, which resulted in a discovery well in the Carapebus sand. Our acreage was subsequently reduced to approximately 133,000 acres. Two additional appraisal wells were drilled in 2005, one of which was production tested at rates up to 1,800 b/d. Kerr-McGee also earned an additional 16 2/3% working interest by paying a disproportionate share of drilling costs on the first appraisal well in 2005, which increased our working interest in the project to 50%. Full field reservoir simulation was initiated during 2005 and development planning for the discovery currently is under way.

BM-C-32 (33%), BM-C-30 (30%), BM-C-29 (100%), BM-ES-24 (30%), BM-ES-25 (40%) - In November 2004, Kerr-McGee acquired an interest in seven blocks, which have since been redesignated as five permit areas located offshore in the prolific Campos and Espírito Santo Basins. The blocks are in shallow to deep water (depths of 200 to 6,600 feet). In the Campos Basin, Kerr-McGee is the operator of BM-C-30 and BM-C-29. Work obligations for the contract areas include the acquisition of 3-D seismic, as well as an eight-well drilling commitment over a four-year period. The first two exploratory wells for BM-C-30 and BM-C-32 are scheduled for second quarter 2006, and the new 3-D seismic for BM-ES-24 was acquired.

Alaska

Kerr-McGee operates 20 leases covering approximately 41,000 acres off the coast of Alaska, northwest of Prudhoe Bay, and two leases onshore west of Kuparuk, covering approximately 5,000 acres. In addition, the company has the right to acquire an interest in 13 additional leases in the area, totaling approximately 48,000 acres. In 2005, Kerr-McGee drilled six wells on its offshore leases in the prolific Alaska North Slope area, including three exploration wells and three appraisal wells. In March 2005, we successfully production tested the Schrader Bluff reservoir at the Nikaitchuq #4 well. The same Schrader Bluff interval was encountered in the Tuvaaq #1 and Kigun #1 wells three miles west of Nikaitchuq #4. Development planning for these discoveries is currently under way.

Angola

In May 2005, Kerr-McGee signed a petroleum contract with Angola to explore in block 10. Block 10 is located offshore from the town of Lobito and covers 1.2 million acres with water depths extending to approximately 3,300 feet. Kerr-McGee has a 25% working interest in this block. Block 10 is operated by Devon Energy Corporation with a 35% working interest. In November 2005, the first block 10 well, Ngueve #1, was a dry hole. A second well, Henda #1, was drilled in early December and found a noncommercial gas accumulation. The fluid and rock samples taken in these two wells currently are being analyzed and the petroleum system will be re-evaluated to determine future prospectivity.

Trinidad and Tobago

Block-3b (45%) - In July 2005, Kerr-McGee and its partner, Primera Oil and Gas Limited, were granted interests in this block, which covers 160,000 acres in water depths ranging from 130 to 3,000 feet. Our obligations include 3-D seismic acquisition, scheduled for second quarter 2006, and two exploration wells, which are anticipated to be drilled in 2007. Kerr-McGee’s original working interest in this block was 75%; however, two transactions reduced our interest to 45%. Mitsubishi Corporation agreed to pay a disproportionate share of the seismic and well program cost in return for an interest in block-3b. Also, BHP Billiton Petroleum (Americas) Inc. conveyed a 25% interest in block-2cREA to Kerr-McGee in exchange for an interest in block-3b.

Block-2cREA (25%) - In August 2005, Kerr-McGee participated in drilling the Gypsy-1 well, which was unsuccessful. We subsequently relinquished our interest in this block.

Other International

Australia

WA 303, WA 304 and WA 305 (50%) - Kerr-McGee has an interest in 6.4 million acres in the deepwater Browse Basin. The first exploratory well, Maginnis, was drilled in early 2003 and was unsuccessful. Kerr-McGee has entered into the second exploration period. Geological studies pursuant to a work commitment are planned for blocks WA 303, WA 304 and WA 305 in 2006. Farm-out efforts are under way.

WA 337 (100%) and WA 339 (50%) - In early 2003, Kerr-McGee acquired an interest in 2.3 million acres in the deepwater Perth Basin. Seismic acquisition was carried out in late 2003, and processing is now complete. The data has been interpreted and the final government reports are being prepared. Kerr-McGee has surrendered its interest in WA 339 and is in the process of marketing its interest in WA 337.

EPP 33 (100%) - In late 2003, Kerr-McGee was granted an interest in 1.3 million acres in the deepwater Otway basin. 2-D seismic survey over the block was acquired in the fourth quarter of 2004. The data has been processed and will be interpreted in 2006. All exploration work commitments and obligations have been met. The exploration term continues from year to year, but no further seismic acquisition is required until 2008. A decision to drill or acquire further seismic data will be made at that time. All exploration phase work commitments and obligations under the terms of the company’s Australia licenses have been completed.

Bahamas

On June 25, 2003, Kerr-McGee signed an exploration contract (with a 100% working interest) on 6.5 million acres in northern Bahamian waters, 90 miles east of the Florida coast in water depths ranging from 650 feet to 7,000 feet. Kerr-McGee completed a speculative seismic acquisition program in 2004. Talisman (Bahamas) Blake Ltd. farmed in for a 25% working interest in 2005. The new seismic data has been processed and a stratigraphic interpretation was conducted. All work obligations established in the contract have been met in this phase. Kerr-McGee has decided to not enter the next exploration phase, which commences in June 2006.

Benin

Block 4 (40%) - Kerr-McGee now owns a 40% working interest in 1.9 million acres offshore Benin. Water depths on this block range from 300 feet to 10,000 feet. In late 2002, Kerr-McGee and Petronas Carigali Overseas Sdn Bhd. (Petronas) entered into a partnership on the block. A two-well drilling program was initiated that year, and both wells found noncommercial amounts of hydrocarbons. Identification of a working petroleum system on Block 4 has been encouraging to the partnership. In April 2005, Kerr-McGee and its partners negotiated a production sharing contract amendment, adding a three-year exploration phase through July 2009. The remaining work commitment requires acquisition of 1,000 square kilometers of 3-D seismic and drilling of an exploratory well. Concurrent with the amendment, Kerr-McGee and Petronas assigned 30% and 10% interest, respectively, to Kosmos Energy Benin HC. Activity in 2006 will include acquiring 3-D seismic, followed by processing and interpretation of that data.

Morocco

Boujdour block (50%) - In October 2001, Kerr-McGee acquired a reconnaissance permit offshore Morocco, which allows the company to perform seismic-related activities for evaluation purposes. In 2004, Kerr-McGee, Kosmos Energy Morocco HC, and Pioneer Natural Resources Morocco Limited entered into a partnership on the block. The reconnaissance permit, by its terms, expires in April 2006.

Nova Scotia, Canada

EL2398 (66 2/3%), EL2399 (100%) and EL2404 (50%) - Poor exploratory results by the industry, along with final geologic and geophysical interpretations of the data over our Nova Scotia blocks, resulted in prospectivity that was not competitive with the rest of Kerr-McGee's exploratory portfolio. In 2005, Kerr-McGee assigned its interest in EL2404 to Norsk Hydro. On December 31, 2005, contracts for EL2398 and EL2399 expired. Kerr-McGee has no remaining interest in Nova Scotia; however, the company owes approximately $8 million for unspent commitments during the license period.

Other Information

Employees - On December 31, 2005, Kerr-McGee and its affiliates had 3,865 employees, 2,110 of whom were employees of Tronox and its subsidiaries.

Competition - Refer to discussion included in Management’s Discussion and Analysis - Operating Environment included in Item 7 of this Annual Report on Form 10-K and Item 1a, Risk Factors.

CHEMICAL OPERATIONS

As part of the strategic plan discussed above under -General Development of Business - Strategic Realignment, in October 2005, the Board approved the separation of Kerr-McGee’s chemical business through the IPO, with the expectation that it would be followed by a distribution of Kerr-McGee’s remaining ownership in Tronox, the chemical business subsidiary, to Kerr-McGee’s stockholders. The IPO of Tronox Class A common stock was completed in November 2005. In connection with the IPO, Kerr-McGee retained a 56.7% equity and an 88.7% voting interest in Tronox. On March 8, 2006, the Board declared a dividend of Tronox’s Class B common stock owned by Kerr-McGee to its stockholders. The Distribution is expected to be completed by the end of the first quarter. Additional information regarding the IPO and the expected Distribution is provided in Item 7 of this Annual Report on Form 10-K, under Separation of Tronox.

Operations of Tronox consist of two segments (pigment and other chemical products) that produce and market inorganic industrial chemicals and heavy minerals through its affiliates, Tronox LLC, Tronox Western Australia Pty. Ltd., Kerr-McGee Pigments GmbH, Kerr-McGee Pigments International GmbH, Tronox Pigments Ltd., Kerr-McGee Pigments (Holland) B.V. and Tronox Pigments (Savannah), Inc. Many of the pigment products are manufactured using proprietary chloride technology developed by the company. Industrial chemicals include titanium dioxide, synthetic rutile, manganese dioxide, boron and sodium chlorate. Heavy minerals produced are ilmenite, natural rutile, leucoxene and zircon.

Titanium Dioxide Pigment

Tronox's primary chemical product is titanium dioxide pigment (TiO₂), a white pigment used in a wide range of products for its exceptional ability to impart whiteness, brightness and opacity. TiO₂ is a critical component of everyday applications, such as coatings, plastics and paper, as well as many specialty products such as inks, foods and cosmetics. Titanium dioxide is widely considered to be superior to alternative white pigments in large part due to its hiding power, which is the ability to cover or mask other materials effectively and efficiently. Titanium dioxide is designed, marketed and sold based on specific end-use applications.

Titanium dioxide pigment is produced using a combination of processes involving the manufacture of base pigment particles, followed by surface treatment, drying and milling (collectively known as finishing). There are two commercial production processes in use: the chloride process and the sulfate process. The chloride process is a newer technology and has several advantages over the sulfate process: it generates less waste, uses less energy, is less labor-intensive and permits the direct recycle of a major process chemical, chlorine, back into the production process. In addition, titanium dioxide produced using the chloride process is preferred for many of the largest end-use applications. As a result, the chloride process currently accounts for substantially all of the titanium dioxide production capacity in North America and approximately 60% of worldwide capacity. The vast majority of titanium dioxide production capacity built since the late 1980s uses the chloride process.

Tronox produces TiO₂ pigment at five production facilities located in four countries. The company believes its facilities are well-situated to serve its global customer base. Two of the facilities are located in the United States and one facility in each of Australia, Germany and the Netherlands. The company owns its facilities in Germany and the Netherlands, and the land under these facilities is held pursuant to long-term leases. The domestic facilities are owned and the company holds a 50% undivided interest in the Australian facility.

The following table summarizes the production capacity by location and process.

TiO₂ Capacity

As of January 1, 2006

(Gross tonnes per year)

Facility	Capacity	Process

Hamilton, Mississippi	225,000	Chloride
Savannah, Georgia	110,000	Chloride
Kwinana, Western Australia ⁽¹⁾	110,000	Chloride
Botlek, Netherlands	72,000	Chloride
Uerdingen, Germany	107,000	Sulfate
Total	624,000

⁽¹⁾	Reflects 100% of the production capacity of the pigment plant, which is owned 50% by the company and 50% by our joint venture partner.

The company's subsidiary, Tronox Western Australia Pty. Ltd., has a 50% undivided interest in all the assets that comprise the operations conducted in Australia under the Tiwest joint venture arrangement and is severally liable for 50% of associated liabilities. The remaining 50% undivided interest is held by Tronox’s joint venture partner, Ticor Pty. Ltd. The joint venture partners operate a chloride process titanium dioxide plant located in Kwinana, Western Australia, as well as a mining venture in Cooljarloo, Western Australia, and a synthetic rutile processing facility in Chandala, Western Australia.

The joint venture partners mine heavy minerals from 8,513 hectares (21,036 acres) under a long-term mineral lease from the State of Western Australia, for which each joint venture partner holds a 50% undivided interest. Tronox’s 50% undivided interest in the properties’ remaining in-place proven and probable reserves is 5.1 million tonnes of heavy minerals contained in 197 million tonnes of sand averaging 2.6% heavy minerals. The valuable heavy minerals are composed of 61.0% ilmenite, 10.0% zircon, 4.6% natural rutile and 3.3% leucoxene, with the remaining 21.1% of heavy minerals having limited market value.

Heavy-mineral concentrate from the mine is processed at a 750,000 tonne-per-year dry separation plant, for which each joint venture partner holds a 50% undivided interest. Some of the recovered ilmenite is upgraded at a nearby synthetic rutile facility, which has a capacity of 225,000 tonnes per year. Synthetic rutile is a high-grade titanium dioxide feedstock. All of the synthetic rutile feedstock for the 110,000-tonne per year titanium dioxide plant located at Kwinana, Western Australia is provided by the Chandala processing facility. Production of feedstock in excess of the plant’s requirements is sold to third parties, as well as to the company's other facilities, for the portion not already owned, as part of the feedstock requirement for titanium dioxide at Tronox’s other facilities.

Information regarding Tronox’s 50% undivided interest in heavy-mineral reserves, production and average prices for the three years ended December 31, 2005, is presented in the following table. Mineral reserves in this table represent the estimated quantities of proven and probable ore that, under presently anticipated conditions, may be profitably recovered and processed for the extraction of their mineral content. Future production of these resources depends on many factors, including market conditions and government regulations.

Heavy-Mineral Reserves, Production and Prices

(Thousands of tonnes)	2005		2004		2003

Proven and probable reserves		5,145		5,570		5,970
Production		300		302		294
Average market price (per tonne)	$	182	$	161	$	152

The primary raw materials used to produce titanium dioxide are various types of titanium-bearing ores, including ilmenite, natural rutile, synthetic rutile, titanium-bearing slag and leucoxene. The company generally purchases ores under multiyear agreements from a variety of suppliers in Australia, Canada, India, Norway, South Africa, Ukraine and the United States. Approximately 85% of the synthetic and natural rutile used by Tronox’s facilities is obtained from the operations under the Tiwest joint venture arrangement.

The global market in which the company's titanium dioxide business operates is highly competitive. The company actively markets its TiO₂ utilizing primarily direct sales, but also through a network of agents and distributors. In general, products produced in a given market region will be sold there to minimize logistical costs. However, Tronox actively exports products, as required, from its facilities in the United States, Europe, and Australia to other market regions.

Titanium dioxide applications are technically demanding, and the company utilizes a strong technical sales and services organization to carry out its marketing efforts. Technical sales and service laboratories are strategically located in major market areas, including the United States, Europe and the Asia-Pacific region. The products produced by Tronox compete on the basis of price and product quality, as well as technical and customer service.

Other Chemical Products

The other segment within the chemical operations consists of electrolytic operations.

Electrolytic Products - Tronox’s Hamilton, Mississippi, facility includes a 130,000 tonne-per-year sodium chlorate facility. Sodium chlorate is used in the environmentally preferred chlorine dioxide process for bleaching pulp. The pulp and paper industry accounts for over 95% of the market demand for sodium chlorate. The company estimates that its share of the North American sodium chlorate capacity is approximately 6%.

Tronox produces electrolytic manganese dioxide (EMD) and boron trichloride at its Henderson, Nevada, facility. Annual production capacity is 27,000 tonnes for EMD and 525 tonnes for boron trichloride. Boron trichloride is used in the production of pharmaceuticals and in the manufacture of semiconductors. EMD is a major component of alkaline batteries. Tronox’s estimated global capacity share is 8% with the U.S. market accounting for approximately one third of global demand for EMD. Demand is being driven by the need for alkaline batteries for portable electronic devices.

Tronox also produces lithium manganese oxide (LMO) and lithium vanadium oxide (LVO) at its Soda Springs, Idaho, facility. Annual production capacity is 300 tonnes. Both of these materials are the primary raw materials for the developing lithium-metal-polymer battery market. LVO is produced exclusively under a tolling arrangement for Avestor, a joint venture in which Kerr-McGee owns a 50% interest.

Other Information

Research and Development - Research and development is an integral component of Tronox’s business strategy. Enhancing our product portfolio with high quality, market-focused product development is key in driving business from the customer perspective.

Tronox has approximately 70 scientists, chemists, engineers and skilled technicians to provide the technology (products and processes) for the business. The product development personnel have a high level of expertise in the plastics industry and polymer additives, the coatings industry and formulations, surface chemistry, material science, analytical chemistry and particle physics. The majority of scientists supporting the research and development efforts are located in Oklahoma City, Oklahoma.

Employees - On December 31, 2005, Tronox and its affiliates had 2,110 employees. Approximately 1,050 or 50% of these employees were represented by chemical industry collective bargaining agreements in the United States and Europe.

Competition - The global market in which the titanium dioxide business operates is highly competitive. Worldwide, Tronox believes that it is one of only five companies that use proprietary chloride process technology for production of titanium dioxide pigment. Based on gross sales volumes, Tronox estimates that these companies accounted for approximately 70% of the global market share in 2005, and that Tronox's market share represented approximately 13%. Cost efficiency and product quality, as well as technical and customer service, are key competitive factors for titanium dioxide producers.

STORED POWER

Kerr-McGee owns a 50% interest in Avestor, a joint venture formed in 2001 to produce and commercialize a solid-state lithium-metal-polymer battery. Compared with traditional lead-acid batteries, Avestor’s no-maintenance battery offers superior performance at one-third the size, one-fifth the weight and two to four times the life. The batteries also provide an environmentally preferred alternative since they contain no acid or liquid that may spill or leak. Avestor sold 7,500 batteries in 2005, which were produced at its plant near Montreal, Canada. A four-fold increase to 30,000 batteries is forecasted for 2006, followed by more than 50,000 batteries in the 2007 forecast. Battery quality and performance continue to be carefully monitored and evaluated as production rates increase. Battery sales and customer feedback indicate strong demand in the North American telecommunications industry, the initial target market. The European telecommunications market is also being developed with market trials planned in 2006, and sales expected to begin in 2007. The strong demand from the telecommunications sector has pushed plans for entry into other sectors (industrial and electric utility applications) into 2009. With production capabilities growing, Avestor expects to achieve a break-even operating cash position in the latter part of 2006, and anticipates sales matching current single line plant capacity in 2007.

GOVERNMENT REGULATIONS AND ENVIRONMENTAL MATTERS

The company's affiliates are subject to extensive regulation by federal, state, local and foreign governments. The production and sale of crude oil and natural gas are subject to special taxation by federal, state, local and foreign authorities and regulation with respect to allowable rates of production, exploration and production operations, calculations and disbursements of royalty payments, and environmental matters. Additionally, governmental authorities regulate the generation and treatment of waste and air emissions at the operations and facilities of the company's affiliates. At certain operations, the company's affiliates also comply with certain worldwide, voluntary standards such as ISO 9002 for quality management and ISO 14001 for environmental management, which are standards developed by the International Organization for Standardization, a nongovernmental organization that promotes the development of standards and serves as an external oversight for quality and environmental issues.

Environmental Matters

Federal, state and local laws and regulations relating to environmental protection affect almost all company operations. Under these laws, the company's affiliates are or may be required to obtain or maintain permits and/or licenses in connection with their operations. In addition, these laws require the company's affiliates to remove or mitigate the effects on the environment of the disposal or release of certain chemical, petroleum, low-level radioactive and other substances at various sites. Operation of pollution-control equipment usually entails additional expense. Some expenditures to reduce the occurrence of releases into the environment may result in increased efficiency; however, most of these expenditures produce no significant increase in production capacity, efficiency or revenue.

During 2005, direct capital and operating expenditures related to environmental protection and cleanup of operating sites totaled $57 million. Additional expenditures totaling $71 million were applied against liabilities for environmental remediation and restoration. It is difficult to estimate the total direct and indirect costs to the company and its affiliates of government environmental regulations; however, presently it is expected that in 2006, Tronox and its subsidiaries will incur $18 million in direct capital expenditures, $45 million in operating expenditures and $78 million in expenditures applied against reserves established at December 31, 2005. Additionally, it is estimated that in 2007 Tronox will incur $22 million in direct capital expenditures, $43 million in operating expenditures and $47 million in expenditures applied against established reserves. In addition to expenditures by Tronox and its subsidiaries, Kerr-McGee expects to pay $12 million and $9 million in 2006 and 2007, respectively, which have been reserved for at December 31, 2005.

The company and its affiliates are parties to a number of legal and administrative proceedings involving environmental matters and/or other matters pending in various courts or agencies. These include proceedings associated with businesses and facilities currently or previously owned, operated or used by the company's affiliates and/or their predecessors, and include claims for personal injuries, property damages, breach of contract, injury to the environment, including natural resource damages, and non-compliance with permits. The 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 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 and/or released. Some of these sites have been designated Superfund sites by the U.S. Environmental Protection Agency (EPA) pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) and are listed on the National Priority List (NPL).

The company provides for costs related to environmental 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 matters because, among other reasons:

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

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

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

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

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

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

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

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

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

The company believes that currently it has reserved adequately for the reasonably estimable costs of contingencies. However, additions to the reserves may be required as additional information is obtained that enables the company to better estimate its liabilities, including any liabilities at sites now under review. The company cannot reliably estimate the amount of future additions to the reserves at this time. Additionally, there may be other sites where the company has potential liability for environmental-related matters but for which the company does not have sufficient information to determine that the liability is probable and/or reasonably estimable. We have not established reserves for such sites.

For additional discussion of environmental matters, see Legal Proceedings included in Item 3, Management's Discussion and Analysis - Environmental Matters included in Item 7, and Note 16 to the Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K.

AVAILABILITY OF REPORTS AND GOVERNANCE DOCUMENTS

Kerr-McGee makes available at no cost on its Internet web site, www.kerr-mcgee.com, its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports as soon as reasonably practicable after the company electronically files or furnishes such reports to the SEC. Interested parties should refer to the Investor Relations link on the company's web site. In addition, the company's Code of Business Conduct and Ethics, Code of Ethics for The Chief Executive Officer and Principal Financial Officers, Corporate Governance Guidelines and the charters for the Board of Directors' Audit Committee, Executive Compensation Committee, and Corporate Governance and Nominating Committee, all of which were adopted by the company's Board of Directors, can be found on the company's web site under the Corporate Governance link. The company will provide these governance documents in print to any stockholder who requests them. Any amendment to, or waiver of, any provision of the Code of Ethics for the Chief Executive Officer and Principal Financial Officers and any waiver of the Code of Business Conduct and Ethics for directors or executive officers will be disclosed on the company's web site under the Corporate Governance link.

On May 23, 2005, Luke R. Corbett, Chairman and Chief Executive Officer of the company, certified to the New York Stock Exchange that he was not aware of any violation by the company of the New York Stock Exchange's corporate governance listing standards. In addition, the company filed as exhibits to the company's Form 10-K for the year ended December 31, 2005 the certifications required under section 302 of the Sarbanes-Oxley Act of 2002.

Item 1a. Risk Factors

In addition to the risks identified in Management's Discussion and Analysis included in Item 7 of this Annual Report on Form 10-K, investors should consider carefully the following risks:

Volatile product prices and markets could adversely affect results of operations and cash flows of the company.

The company's results of operations and cash flows are highly dependent upon the prices of and demand for oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future, and the prices received by the company for its oil and gas production are dependent upon numerous factors that are beyond its control. These factors include, but are not limited to:

·	Worldwide supply and consumer product demand

·	Governmental regulations and taxes

·	The price and availability of alternative fuels

·	The level of imports and exports of oil and gas

·	Actions of the Organization of Petroleum Exporting Countries

·	The political and economic uncertainty of foreign governments

·	International conflicts and civil disturbances

·	The overall economic environment

The company uses commodity derivative instruments as a means of balancing price uncertainty and volatility with the company's financial and investment requirements. Nevertheless, a sustained period of sharply lower commodity prices could have material adverse effects on the company, including:

·	Curtailment or deferral of exploration and development projects

·	Reduction in the level of economically viable proved reserves

·	Reduction of the discounted future net cash flows relating to the company's proved oil and gas reserves

·	Reduced ability of the company to maintain or grow its future production through future investment in exploration, exploitation and acquisition activities

·	Reduced ability of the company to access capital

The commodity derivative instruments also may prevent the company from realizing the benefit of price increases above the levels reflected in such contracts. In addition, the commodity derivative instruments may expose the company to the risk of financial loss in certain circumstances, including, but not limited to, instances in which:

·	Production is less than the volumes covered by the derivative instruments

·	Basis differentials widen substantially from the prices established by these arrangements

·	The counter-parties to commodity price and basis differential risk management contracts fail to perform as required by the contracts

The company's debt may limit its financial flexibility.

The company uses both short- and long-term debt to finance its operations. The level of the company's debt could affect the company in important ways, including:

·	A portion of the company's cash flow from operations may be applied to the payment of principal and interest and may not be available for other purposes.

·	Ratings of the company's debt and other obligations vary from time to time and impact the cost, terms, conditions and availability of financing.

·	Covenants associated with debt arrangements require the company to meet financial and other tests that may affect its flexibility in planning for and reacting to changes in its business, including possible acquisition, exploration and development opportunities.

·	The company's ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited.

·	The company may be at a competitive disadvantage to similar companies that have less debt.

Failure to fund continued capital expenditures and to replace oil and gas reserves could adversely affect results of operations of the company.

The future success of the company's oil and gas business depends upon its ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. The company will be required to expend capital to replace its reserves and to maintain or increase production levels. The company believes that, after considering the amount of its debt, it will have sufficient cash flow from operations, available drawings under its credit facilities and other debt financings to fund capital expenditures. However, if these sources are not sufficient to enable the company to fund necessary capital expenditures, its ability to find and develop oil and gas reserves may be adversely affected and its interests in some of its oil and gas properties may be reduced or forfeited. Further, if oil and gas prices increase, finding costs for additional reserves could also increase, making it more difficult to replace reserves on an economic basis.

Oil and gas exploration, development and production operations involve substantial capital costs and are subject to various economic risks.

The company's oil and gas operations are subject to the economic risks typically associated with exploration, development and production activities. In conducting exploration activities, unanticipated pressure or irregularities in formations, miscalculations or accidents may cause exploration activities to be unsuccessful, and even where oil and gas are discovered it may not be possible to produce or market the hydrocarbons on an economically viable basis. Drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which may be beyond the company's control, including unexpected drilling conditions, weather conditions, compliance with environmental and other governmental requirements and shortages or delays in the delivery of equipment and services. The occurrence of any of these or similar events could result in a partial or total loss of investment in a particular property.

The company operates in foreign countries and is subject to political, economic and other uncertainties.

The company conducts operations in foreign countries and may expand its foreign operations in the future. Operations in foreign countries are subject to political, economic and other uncertainties, including, but not limited to:

·	The risk of war, acts of terrorism, revolution, border disputes, expropriation, renegotiation or modification of existing contracts, import, export and transportation regulations and tariffs

·	Taxation policies, including royalty and tax increases and retroactive tax claims

·	Exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over the company's international operations

·	Exposure to movements in foreign currency exchange rates, because the U.S. dollar is the functional currency for the company's international operations, except for the company's European chemical operations, for which the euro is the functional currency

·	Laws and policies of the United States affecting foreign trade, taxation and investment

·	The possibility of being subject to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States

Foreign countries occasionally have asserted rights to land, including oil and gas properties, through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to the company by another country, the company's interests could be lost or could decrease in value. Various regions of the world have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might assume a substantially more hostile attitude toward foreign investment. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. The company seeks to manage these risks by, among other things, focusing much of its international exploration efforts in areas where it believes the existing government is stable and favorably disposed towards United States exploration and production companies.

Competition is intense, and companies with greater financial, technological and other resources may be better able to compete.

The oil and gas exploration and production business is highly competitive. In addition to competing with other independent oil and gas producers (i.e., companies not engaged in petroleum refining and marketing operations), the company competes with large, integrated, multinational oil and gas companies. These companies may have greater resources, which may give them various advantages when responding to market conditions.

The company's business involves many operating risks that may result in substantial losses. Insurance may not be adequate to completely protect the company against these risks.

The company's operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and gas, including, but not limited to: fires; natural disasters; explosions; formations with abnormal pressures; marine risks such as currents, capsizing, collisions and hurricanes; adverse weather conditions; casing collapses, separations or other failures, including cement failure; uncontrollable flows of underground gas, oil and formation water; surface cratering; and environmental hazards such as gas leaks, chemical leaks, oil spills and discharges of toxic gases.

Any of these risks can cause substantial losses, including: injury or loss of life; damage to and destruction of property, natural resources and equipment; pollution and other environmental damage; regulatory investigations and penalties; suspension of operations; and repair and remediation costs.

To help protect against these and other risks, the company maintains insurance coverage against some, but not all, potential losses. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm the company's financial condition and results of operations.

Oil and gas reserve information is estimated.

The company's estimates of proved oil and gas reserves are based on internal reserve data prepared by the company's engineers. Petroleum reserve estimation is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in a direct or exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend on a number of variable factors and assumptions, including:

·	Historical production trends from a particular area are representative of future performance

·	Data gathered for purposes of reserve estimation, such as well logs and cores, are representative of average reservoir properties

·	Assumed effects of regulation by governmental agencies

·	Assumptions concerning future oil and gas prices, future development, operating and abandonment costs and capital expenditures

·	Estimates of future severance and excise taxes and workover and remedial costs

Estimates of reserves prepared or audited by different engineers using the same data, or by the same engineers at different times, may vary substantially. Actual production, revenues and expenditures with respect to the company's reserves will likely vary from estimates, and the variance may be material. The company mitigates the risks inherent to reserve estimation through a comprehensive reserve administration process. The reserve administration process includes review by independent reserve engineers, Netherland, Sewell & Associates, Inc. (NSAI), of the company's processes and methods for estimating reserves. In 2005, NSAI’s procedures and methods review covered approximately 75% of the company's proved reserves at year end.

The company is subject to complex laws and regulations, including environmental and safety regulations, that can adversely affect the cost, manner, or feasibility of doing business.

The company's operations and facilities are subject to certain federal, state, tribal and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and gas, and the production of chemicals, as well as environmental and safety matters. These laws and regulations include, among other things, land use restrictions; drilling bonds, performance bonds and other financial responsibility requirements; spacing of wells; unitization and pooling of properties; habitat and endangered species protection, reclamation and remediation, and other environmental protection; protection and preservation of historic, archaeological and cultural resources; safety precautions; regulations governing the operation of chemical manufacturing facilities; regulation of discharges, emissions, disposal and waste-related permits; operational reporting; and taxation. In addition, the continuing development of housing and other surface uses in or near the company’s onshore operations, and associated zoning and similar regulations, may affect the company’s ability to explore for, produce and transport oil and gas. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations, inability to obtain necessary regulatory approvals, or a failure to comply with existing legal requirements may harm the company's business, results of operations and financial condition.

The company may be required to make large and unanticipated capital expenditures to comply with environmental and other governmental regulations. Under these laws and regulations, the company could be liable for personal injuries; property and natural resource damages; oil spills and releases or discharges of hazardous materials; well reclamation costs; remediation and cleanup costs and other governmental sanctions, such as fines and penalties; and other environmental damages.

The company's operations could be significantly delayed or curtailed and its costs of operations could significantly increase beyond those anticipated as a result of regulatory requirements or restrictions. We are not able to predict the ultimate cost of compliance with these requirements or their effect on our operations.

Costs of environmental liabilities and regulation could exceed estimates.

The company and its affiliates are parties to a number of legal and administrative proceedings involving environmental and/or other matters pending in various courts or agencies. These include proceedings associated with facilities currently or previously owned, operated or used by the company's affiliates and/or their predecessors, and include claims for personal injuries, property damages, injury to the environment, including natural resource damages, and noncompliance with permits. The current and former operations of the company's affiliates also involve management of regulated materials that are subject to various environmental laws and regulations. These laws and regulations 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 disposed of or released. Some of these sites have been designated Superfund sites by the Environmental Protection Agency pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980.

The company provides for costs related to environmental matters 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 matters for the reasons described above under -Government Regulations and Environmental Matters.

Although management currently believes that it has established appropriate reserves for cleanup costs, costs may be higher than anticipated and the company could be required to record additional reserves in the future.

The company's oil and gas marketing activities may expose it to claims from royalty owners.

In addition to marketing its oil and gas production, the company's marketing activities generally include marketing oil and gas production for royalty owners. Over the past several years, royalty owners have commenced litigation against a number of companies in the oil and gas production business claiming that amounts paid for production attributable to the royalty owners' interest violated the terms of the applicable leases and laws in various respects, including the value of production sold, permissibility of deductions taken and accuracy of quantities measured. The company could be required to make payments as a result of such litigation, and the company's costs relating to the marketing of oil and gas and payment of royalties may increase as new cases are decided and the law in this area continues to develop.

The company is subject to lawsuits and claims.

A number of lawsuits and claims are pending against the company and its affiliates, some of which seek large amounts of damages. Although management currently believes that none of the lawsuits or claims will have a material adverse effect on the company's financial condition or liquidity, litigation is inherently uncertain, and the lawsuits and claims could have an unexpected material adverse effect on the company in future periods.

Item 1b. Unresolved Staff Comments

The company has no outstanding or unresolved SEC staff comments.

Item 3. Legal Proceedings

A. On December 28, 2005, an affiliate of the company, Kerr-McGee Oil & Gas Onshore LP (formerly known as Westport Oil and Gas Company, L.P.), received a letter from the Environmental Protection Agency (EPA) alleging that the affiliate constructed well pads and associated roads and pipelines in a wetland adjacent to the Hams Fork River in Wyoming without obtaining necessary permits. A meeting between the company and EPA has been scheduled to discuss the matter. No formal demand has been made by EPA.

B. On November 14, 2005, the company received a letter from the United States Department of Justice (DOJ) alleging that the company violated certain air quality and permitting regulations at the Cottonwood and Ouray compressor stations in Uintah County, Utah, which were operated by Westport Oil and Gas Company, L.P. prior to Westport’s merger with Kerr-McGee. No formal demand has been made by the DOJ.

C. On September 8, 2003, the Environmental Protection Division of the Georgia Department of Natural Resources issued a unilateral Administrative Order to one of our consolidated subsidiaries, Tronox Pigments (Savannah) Inc., claiming that Tronox’s Savannah plant exceeded emission allowances provided for in the facility's Title V air permit. On September 19, 2005, the Environmental Protection Division rescinded the Administrative Order and filed a Withdrawal of Petition for Hearing on Civil Penalties. Accordingly, the proceeding on administrative penalties has been dismissed. However, the Environmental Protection Division's most recent actions do not resolve the alleged violations, and representatives of Tronox Pigments (Savannah) Inc., the Environmental Protection Division and EPA are engaged in discussions to resolve the existing air permit disputes and potential civil penalties.

D. For a discussion of other legal proceedings and contingencies, reference is made to Management's Discussion and Analysis - Environmental Matters included in Item 7 and Note 16 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K, both of which are incorporated herein by reference.

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

None submitted during the fourth quarter of 2005.

Executive Officers of the Registrant

The following is a list of executive officers, their ages, and their positions and offices as of March 1, 2006:

Name	Age	Office

Luke R. Corbett	59	Director since 1995, Chairman and Chief Executive Officer of the company since May 1999 and from 1997 to 1999; Chief Executive Officer from February to May 1999; President and Chief Operating Officer from 1995 to 1997. Currently, Director, OGE Energy Corp. and Noble Corporation.

Kenneth W. Crouch	62	Executive Vice President since March 2003; Senior Vice President (oil and gas exploration and production) from 1998 to 2003; previously Senior Vice President responsible for oil and gas exploration. Joined the company in 1974.

David A. Hager	49	Chief Operating Officer since 2005. Senior Vice President (oil and gas exploration and production) from 2003 to 2005; Vice President of Exploration and Production from 2002 to 2003; Vice President of Gulf of Mexico and Worldwide Deepwater Exploration and Production from 2001 to 2002; Vice President of Worldwide Deepwater Exploration and Production from 2000 to 2001; Vice President of International Operations, 2000; previously Vice President of Gulf of Mexico operations. Joined Sun Oil Co., predecessor of Oryx Energy Company, in 1981. Oryx and Kerr-McGee merged in 1999.

Gregory F. Pilcher	45	Senior Vice President, General Counsel and Corporate Secretary since 2000; Vice President, General Counsel and Corporate Secretary from 1999 to 2000; Deputy General Counsel for Business Transactions from 1998 to 1999; Associate/Assistant General Counsel for Litigation and Civil Proceedings from 1996 to 1998. Joined Kerr-McGee in 1992.

Robert M. Wohleber	55	Senior Vice President and Chief Financial Officer since 1999. Previously held various positions at the Freeport-McMoRan group of companies, including Senior Vice President and Chief Financial Officer of Freeport-McMoRan Inc. and President, Chief Executive Officer and Director of Freeport-McMoRan Sulphur. Currently, Director, Tronox Incorporated.

Richard C. Buterbaugh	51	Vice President of Corporate Planning since July 2005; Vice President of Investor Relations from 1998 to 2005; Director of Investor Relations from 1996 to 1998; Staff Director of Corporate Business Development from 1989 to 1996. Joined Kerr-McGee in 1989.


George D. Christiansen		61		Vice President, Safety and Environmental Affairs since 1998; Vice President of Environmental Assessment and Remediation from 1996 to 1998; previously Vice President of Minerals Exploration, Hydrology and Real Estate. Joined the company in 1968.

Alonzo J. Harris	47	Vice President and Chief Information Officer since July 2005; Vice President of Information Management and Technology from 2003 to 2005; Director of Information Management and Technology for the Oil & Gas unit from 2001 to 2003; Manager of Exploration and Production Information Management Technology from 1999 to 2001. Joined Sun Oil Co., predecessor of Oryx Energy Company, in 1982. Oryx and Kerr-McGee merged in 1999.

Fran G. Heartwell	59	Vice President of Human Resources since 2003; Vice President of Human Resources, Kerr-McGee Worldwide Corporation, from January to March 2003; Director of Human Resources, Kerr-McGee Oil & Gas, from 2002 to 2003; Vice President of Human Resources and Administration, Oryx Energy Company, from 1995 until the 1999 merger of Oryx and Kerr-McGee.

Charles A. Meloy	45	Vice President of Exploration and Production since July 2005; Vice President of Gulf of Mexico Exploration, Production and Development from 2004 to 2005; Vice President and Managing Director of Kerr-McGee North Sea (U.K.) Limited from 2002 to 2004; Vice President of Gulf of Mexico Deep Water from 2000 to 2002; Joined Sun Oil Co., predecessor of Oryx Energy Company, in 1982; Oryx and Kerr-McGee merged in 1999.

Christina M. Poos	36	Vice President and Treasurer since November 2004; Vice President and Treasurer for Kerr-McGee Worldwide Corporation from September to November 2004; Assistant Corporate Controller from February 2004 to September 2004; Manager of Financial Reporting from November 2002 to February 2004; Previously Director of Accounting, Foodbrands America Incorporated (a division of IBP, Inc., a food products company) from June 2000 to September 2002.

J. Michael Rauh	56	Vice President and Controller since 2002 and from 1987 to 1996; Vice President and Treasurer from 1996 to 2002. Joined the company in 1981. Currently, Director, Tronox Incorporated.

John F. Reichenberger	53	Vice President, Deputy General Counsel and Assistant Secretary since 2000; Assistant Secretary and Deputy General Counsel from 1999 to 2000; Deputy General Counsel from 1998 to 1999; previously Associate General Counsel for Remediation and Risk Management and Claims. Joined the company in 1985.

There are no family relationships between any of the executive officers.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

The company makes certain forward-looking statements in this Annual Report on Form 10-K that are subject to risks and uncertainties. These statements regarding the company's or management's intentions, beliefs or expectations, or that otherwise speak to future events, are based on the information currently available to management. These forward-looking statements include those statements preceded by, followed by or that otherwise include the words "believes," "expects," "anticipates," "intends," "estimates," "projects," "target," “budget,” "goal," "plans," "objective," “outlook,” "should" or similar words. In addition, any statements regarding possible commerciality, development plans, capacity expansions, drilling of new wells, ultimate recoverability of reserves, future production rates, future cash flows and changes in any of the foregoing are forward-looking statements. 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 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, 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 in areas where Kerr-McGee operates, trade and regulatory matters, general economic conditions, and other factors and risks discussed herein and in the company's other SEC filings, and many such factors and risks are beyond Kerr-McGee's ability to control or predict. Forward-looking statements are not guarantees of performance. Actual results and developments may differ materially from those expressed or implied in this Annual Report on Form 10-K. Readers are cautioned not to place any undue reliance on any forward-looking statements. Forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Kerr-McGee undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. For such statements, Kerr-McGee claims the protection of the safe harbor for "forward-looking statements" set forth in the Private Securities Litigation Reform Act of 1995.

PART II

Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters

Kerr-McGee common stock is listed for trading on the New York Stock Exchange and at year-end 2005 was held by approximately 19,200 Kerr-McGee stockholders of record and Oryx, HS Resources and Westport owners, who have not yet exchanged their stock. The ranges of market prices and dividends declared per share of Kerr-McGee common stock were as follows during the last two years:

	Market Prices								Dividends
	2005				2004				per Share
	High		Low		High		Low		2005		2004

Quarter Ended -
March 31	$	83.30	$	55.38	$	53.39	$	46.92	$	.45	$	.45
June 30		82.09		68.24		56.00		47.05		.05		.45
September 30		98.83		74.76		58.67		50.49		.05		.45
December 31		98.00		79.85		63.24		55.57		.05		.45

Cash dividends have been paid by Kerr-McGee continuously since 1941, and totaled $153 million in 2005 and $205 million in 2004. Following the approval of the Board of Directors in May 2005, the company reduced the annual dividend from $1.80 to $.20 per share starting with the July 2005 dividend payment. We currently expect that cash dividends will continue to be paid in the future, consistent with the current dividend policy.

Information required under Item 201(d) of Regulation S-K relating to the company’s securities authorized for issuance under equity compensation plans is included in Item 12 of this Annual Report on Form 10-K.

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 December 31, 2005. In January 2006, the Board of Directors approved a $1 billion stock repurchase program. Assuming a per-share acquisition cost of $100, we expect to repurchase 10 million shares in the open market under this program. As of March 14, 2006, approximately 3.3 million shares of Kerr-McGee’s stock had been repurchased at an aggregate cost of $347 million.

Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid per Share ⁽¹⁾	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs

October 1-31, 2005	11,150	$83.07	-	$ -
November 1-30, 2005	92,386	52.94	-	-
December 1-31, 2005	6,100	89.10	-	-
Total	109,636	$58.02	-	$ -

⁽¹⁾	Includes 24,500 shares purchased in the open market for the matching contributions to the Kerr-McGee Corporation Savings Investment Plan and 85,136 shares delivered to the company by employees in satisfaction of withholding taxes and upon forfeiture of restricted shares.

Item 6. Selected Financial Data

Information regarding selected financial data required in this item is presented in the schedule captioned “Five-Year Financial Summary” included in Item 8 of this Annual Report on Form 10-K.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis

Executive Overview

Overview of Business - Kerr-McGee Corporation is one of the largest U.S.-based independent oil and gas exploration and production companies, with nearly 1 billion barrels of oil equivalent of proved reserves as of December 31, 2005. The company’s major producing operations are located onshore in the United States, the U.S. Gulf of Mexico, and offshore China. In addition, we explore for oil and gas in these core areas and in proven hydrocarbon basins worldwide, including the North Slope of Alaska and offshore West Africa, Brazil and Trinidad and Tobago. In November 2005, we completed an initial public offering (IPO) of a 43.3% equity interest in Tronox, a subsidiary that holds Kerr-McGee’s chemical business, and plan to distribute our remaining equity interest in Tronox to Kerr-McGee’s stockholders on March 30, 2006. This transaction will complete the transformation of Kerr-McGee to a pure-play exploration and production company.

Our strategy is to enhance value for our stockholders through the development of a well-balanced portfolio of high-quality oil and gas assets that provides a large inventory of repeatable, low-risk exploitation projects and high-potential exploration opportunities. Consistent with this strategy, in June 2004, we completed a merger with Westport Resources Corporation (Westport), adding 281 million barrels of oil equivalent (MMboe) to our proved reserves (76% natural gas). We believe the Westport merger enhanced the balance of our portfolio by adding low-risk onshore exploitation opportunities. In 2005, we initiated a divestiture program intended to high grade our oil and gas portfolio to focus on assets that offer the greatest stability and growth opportunities, weighted toward longer-life, less capital-intensive properties. Upon completion of the divestiture program, we believe we will have a portfolio of oil and gas properties that will provide consistent, repeatable results from identified projects for many years to come.

In 2005, Kerr-McGee also implemented a three-pronged business plan with the following key components:

·	Accelerated development of the company’s two major Rocky Mountain natural gas resource plays, the Greater Natural Buttes area in Utah and the Wattenberg field in Colorado

·	Exploration focused on high-impact targets in proven hydrocarbon basins with a track record of delivering world-class discoveries, including the deepwater Gulf of Mexico, the North Slope of Alaska, Brazil and other international areas

·	Creative business development by taking advantage of opportunities to maximize value in the long term through acquisitions, divestitures and strategic partnering

The Natural Buttes and the Wattenberg fields are our key U.S. onshore assets, with almost 400 MMboe of proved reserves, as well as additional identified resource potential. We believe accelerated development of our U.S. onshore properties will generate sustainable per-share growth of reserves, production and cash flow with greater predictability. With strong base performance generated by our accelerated development program, any success in the exploration program will yield meaningful incremental reserve and value growth for Kerr-McGee’s stockholders.

Operating Highlights - Significant operational highlights since year-end 2004 include the following:

·	A 14% increase in average production rates, to 270 thousand barrels of oil equivalent per day (Mboe/d), despite disruptions caused by hurricanes

·	Capital investment of $1.8 billion, the largest exploration and production capital program in company history

·	Proved reserve additions of nearly 160 million boe from our exploration and development drilling programs

Accelerated development drilling program in the Natural Buttes field, increasing the number of company-operated rigs from five to eight over the course of the year. As a result, net production from the field reached record rates in the second half of the year. Net production from this field was approximately 160 million cubic feet of natural gas equivalent per day at year-end 2005, a 30% increase over year-end 2004. We also have accelerated development activities in the Wattenberg field.

·	Successful appraisal and pending development of the Chinook discovery on the BM-C-7 block in the Campos Basin offshore Brazil. Kerr-McGee holds a 50% working interest in the field and will take over operatorship during the development and production phases.

·	Successful exploration and appraisal drilling results on the North Slope of Alaska at the Nikaitchuq discovery. Planning is under way for possible development sanctioning, with Kerr-McGee holding a 70% working interest as operator of the field.

Installation of the company’s sixth spar in the deepwater Gulf of Mexico at the Constitution and Ticonderoga discoveries. Production from Ticonderoga began in February 2006 at gross daily rates of 20 thousand barrels of oil (Mbbl) and 15 million cubic feet (MMcf) of natural gas. We expect to ramp up production from the field during 2006, ultimately reaching gross peak daily rates of about 65 Mbbl of oil and 100 MMcf of natural gas in early 2007. Kerr-McGee holds a 100% working interest in Constitution and a 50% working interest in Ticonderoga.

·	First production from the CFD 11-3 and 11-5 fields in China’s Bohai Bay in July 2005, operated by Kerr-McGee with a 40.1% working interest

·	Development sanctioning for the Blind Faith field in the deepwater Gulf of Mexico. First production is expected in mid-2008, with initial daily production estimated at gross rates of 30 Mbbls of oil and 30 MMcf of gas. Kerr-McGee holds a 37.5% working interest in the project.

Successful recovery from one of the worst hurricane seasons in U.S. history. Production from the Gulf of Mexico has resumed to approximately 90% of capacity by early 2006. Our facilities currently are capable of full production capacity and we expect to resume full rates by the end of first quarter 2006, as third-party-operated pipelines and infrastructure damage is repaired.

Divestitures - As part of the divestiture program initiated in 2005, we sold our North Sea oil and gas business and selected oil and gas assets onshore in the U.S., realizing net proceeds of $4 billion (before cash income taxes). We expect to complete the divestiture program by the end of the second quarter 2006 with the sale of our Gulf of Mexico shelf oil and gas properties for approximately $1.34 billion in cash, subject to certain adjustments. The transaction has an effective date of October 1, 2005 and is subject to customary closing conditions and regulatory approvals. Had we completed this transaction at the end of 2005, our proved reserves would have been approximately 900 MMboe.

Financial Highlights - Significant financial highlights since year-end 2004 include the following:

·	Record revenues generated by the oil and gas business (excluding revenues associated with gas marketing activities and discontinued operations) of $3.8 billion, 40% higher than 2004

·	Income from continuing operations of $946 million (or $7.22 per common share), more than a three-fold increase over 2004

·	Cash flows provided by operating activities of $3.1 billion, $1.1 billion higher than 2004

Share repurchases totaling $4.2 billion in 2005, including a $4 billion tender offer that reduced shares outstanding at year-end 2004 by 28%. An additional $1 billion share repurchase program was approved by the Board of Directors (the Board) in January 2006 and is being executed through open market purchases.

·	Completion of the Tronox IPO, reducing our equity interest in Tronox to 56.7%

Net reduction in the principal amount of outstanding debt of $801 million from January 1, 2005 through March 10, 2006 (or approximately $1.4 billion excluding $550 million borrowed by Tronox in connection with the IPO that will be derecognized with the distribution of our remaining equity interest in Tronox, as discussed below)

Challenges - Kerr-McGee also faced some significant challenges in 2005. Hurricanes throughout the summer and fall forced us to evacuate our offshore facilities several times during the year. Two Category 5 hurricanes, Katrina and Rita, shut in virtually all production in the Gulf of Mexico, as well as along the Texas/Louisiana Gulf Coast, and resulted in massive damage to production facilities, pipelines and onshore infrastructure. Kerr-McGee’s offshore facilities suffered very little direct damage; however, the loss of pipelines and other infrastructure resulted in the prolonged shut-in of much of our production in the Gulf of Mexico and the Gulf Coast. As a result, almost 6.5 MMboe of production (approximately 18 Mboe per day annualized) was deferred during 2005.

Our exploration program did not achieve the level of success we would have expected in 2005. In the Gulf of Mexico, we spud nine deepwater wells with two discoveries. In the International/New Ventures exploration program, we conducted additional delineation work and appraisal drilling in Brazil at the Chinook discovery, as well as in Alaska at the Nikaitchuq discovery. This work resulted in substantial increases in the estimated resource potential for these discoveries. We also drilled two wells in Angola and one in Trinidad and Tobago, which were unsuccessful. Despite the mixed results, we believe our exploration strategy, focused on proven world-class hydrocarbon basins, will yield long-term success. This is evidenced by promising discoveries in both Alaska and Brazil, which currently are under evaluation for future development, and the extensive inventory of ongoing projects in the Gulf of Mexico.

The company also is facing significant challenges with respect to the cost and availability of key goods and services. As commodity prices have improved, the demand and cost for drilling and production services and equipment have increased substantially. While we effectively procured the necessary materials and services to carry out our drilling programs at a reasonable cost, the cost level for oil-field goods and services increased which, combined with higher storm-related property insurance costs, resulted in higher per-unit production costs. Managing these costs and securing the necessary materials and services to execute our 2006 drilling program will be a critical challenge.

Separation of Tronox

As part of the strategic plan discussed under -Executive Overview above, in October 2005, the Board approved the separation of Kerr-McGee’s chemical business through an IPO, with the expectation that it would be followed by a distribution of Kerr-McGee’s remaining ownership in Tronox, the chemical business subsidiary, to Kerr-McGee’s stockholders. The IPO of 17.5 million shares of Tronox Class A common stock was completed in November 2005. Concurrent with the IPO, Tronox, through its wholly-owned subsidiaries, issued $350 million in aggregate principal amount of 9.5% senior unsecured notes due 2012 and borrowed $200 million under a six-year senior secured credit facility. Pursuant to the terms of the Master Separation Agreement (MSA), Tronox distributed to Kerr-McGee the net proceeds from the IPO of $225 million, as well as the net proceeds from the borrowings of approximately $535 million and cash on hand in excess of $40 million.

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

The following discussion outlines certain effects of the expected Distribution.

Environmental Obligations - Under the terms of the MSA, Kerr-McGee transferred to Tronox the subsidiaries holding and operating Kerr-McGee’s chemical business. Some of these subsidiaries previously were engaged in the production of ammonium perchlorate, the manufacturing of thorium compounds, treatment of forest products, the refining and marketing of petroleum products, the mining, milling and processing of nuclear materials and other businesses. These subsidiaries are subject to environmental obligations associated with their current and former operations. Under the terms of the MSA, Kerr-McGee agreed to reimburse Tronox for 50% of the environmental remediation costs incurred and paid by Tronox and its subsidiaries, to the extent such costs, net of any reimbursements received from insurers or other parties, exceed the carrying value of Tronox’s environmental reserves as of November 28, 2005. Notwithstanding the foregoing, Kerr-McGee is not obligated to reimburse Tronox if such excess expenditures at any individual site are $200,000 or less, or for any remediation costs incurred and paid by Tronox after November 28, 2012. This seven-year reimbursement obligation extends to costs incurred and paid at any site associated with any of the former businesses and operations of Tronox and is limited to a maximum aggregate reimbursement of $100 million for all covered sites. Additionally, Kerr-McGee is not obligated to reimburse Tronox for amounts paid to third parties in connection with tort claims or personal injury lawsuits, or for costs incurred and paid by Tronox in excess of the lowest cost response, as defined in the MSA.

Because Tronox is a consolidated subsidiary of Kerr-McGee as of December 31, 2005, the Consolidated Balance Sheet reflects Tronox’s liabilities for environmental remediation and restoration costs that are probable and estimable ($224 million, as presented below). The Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K do not include any effects of the reimbursement obligation discussed above between the parties within the consolidated group. It is expected that upon completion of the Distribution, Tronox no longer will be a consolidated subsidiary of Kerr-McGee, at which time Kerr-McGee will recognize a liability associated with its reimbursement obligation. The liability will initially be measured at its estimated fair value. The recognition of this liability will result in a commensurate decrease in retained earnings.

The following table presents reserves for environmental contingencies and the related reimbursements receivable from the U.S. government and insurers at December 31, 2005. Additional information about environmental and other contingencies is provided in Note 16 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K and under -Environmental Matters below.

	Reserves for
	Environmental		Reimbursements
(Millions of dollars)	Remediation		Receivable

Tronox	$	224	$	57
Other Kerr-McGee		44		-
Balance at December 31, 2005	$	268	$	57

Employee Compensation and Benefits - Historically, employees of the company’s chemical business and other subsidiaries transferred to Tronox participated in stock-based compensation, pension and postretirement plans established by Kerr-McGee. At the date of the Distribution, certain Kerr-McGee stock-based awards held by Tronox employees will be forfeited and replaced with stock-based awards of comparable value issued by Tronox. Tronox also is expected to establish pension and postretirement plans for its U.S. employees and assume the benefit obligations associated with its current and former employees following the Distribution. Kerr-McGee also will transfer trust assets to the newly established Tronox U.S. pension plan necessary to fund the transferred obligation in compliance with applicable regulatory requirements. Additional information regarding the anticipated effects of the separation on the company’s obligations for pension and postretirement health and welfare benefits is provided below under -Critical Accounting Policies - Benefit Plans.

Operating Environment

Commodity Markets - Prices for oil and natural gas were sustained at record or near-record levels throughout 2005. Supply and geopolitical uncertainties, coupled with one of the most active U.S. tropical storm seasons in recent history, resulted in significant price volatility and historically high commodity prices. Prices for West Texas Intermediate (WTI) crude oil averaged approximately $57 per barrel for the year, compared to an average price of about $41 per barrel in 2004. At the beginning of 2005, the price of crude oil was below $50 per barrel and steadily increased through the first half of the year, peaking at levels of nearly $70 per barrel during the third quarter, following weather-related supply disruptions in the Gulf of Mexico and U.S. Gulf Coast due to two Category 5 hurricanes. In 2005, crude oil prices were driven by industry supply concerns resulting from both short-term weather-related disruption and infrastructure damage, as well as longer-term concerns regarding the industry’s ability to meet growing world demand. In addition, continued geopolitical instabilities in major producing areas, including the Middle East, Nigeria and Venezuela, contributed to market volatility and higher oil prices. The year ended with the WTI crude oil price at just over $61 per barrel.

U.S. natural gas pricing also was strong throughout the year, with New York Mercantile Exchange (NYMEX) futures trading at or above $5.75 per million British thermal units (MMBtu). During 2005 the North American gas market was driven by fundamental uncertainties regarding the industry’s ability to maintain supply in line with increasing demand. This uncertainty, combined with weather-related supply disruptions in Gulf of Mexico and Gulf Coast producing regions, resulted in historically high prices and extreme volatility. Despite historically high inventories, natural gas pricing remained strong going into the winter season, reaching a peak of about $15.40 per MMBtu in December, before moderating to end the year at about $11.25 per MMBtu. NYMEX natural gas prices averaged approximately $9 per MMBtu in 2005, 46% higher than in 2004. In early March 2006, natural gas prices decreased to under $7 per MMBtu. The outlook for the commodity markets in 2006 indicates continued volatility. Many experts expect prices for both oil and gas to moderate somewhat, but remain at high levels relative to recent history.

To mitigate uncertainties related to oil and gas price fluctuations, Kerr-McGee enters into derivatives to hedge prices realized upon the sale of its future oil and gas production. Details of the company’s commodity derivatives are provided in the -Market Risks section below.

Industry Environment and Competition - The oil and gas industry is highly competitive. We compete with a large number of other oil and gas companies for attractive acquisition, exploration, exploitation and development opportunities. We add to our proved reserves through successful exploration and development, application of new technologies to improve recovery from existing fields and acquisitions. We believe we have a well-balanced portfolio of high-quality oil and gas assets that provides a large inventory of repeatable, low-risk exploitation projects and high-potential exploration opportunities. Additionally, we make significant investment in skilled personnel and technology to successfully execute our exploration, development and exploitation activities and identify tactical acquisition and trade opportunities.

Our oil and gas asset portfolio includes major positions in two large resource plays, the Greater Natural Buttes area in Utah and the Wattenberg field in Colorado, which provide an ongoing source of predictable proved reserve addition opportunities and organic production growth, complementing our exploration program. We focus our exploration efforts in basins where working commercial hydrocarbon systems are known to exist, such as the deepwater Gulf of Mexico. We believe facilities we operate in the deepwater Gulf of Mexico provide Kerr-McGee with a significant competitive advantage by enabling us to efficiently employ a hub-and-spoke concept of satellite exploration and exploitation of nearby opportunities. Another competitive strength for the company is our ability to profitably develop smaller offshore oil and gas discoveries that might have previously been considered uneconomic.

Due to higher recent commodity prices, the industry is facing significant challenges in the cost and availability of key goods and services. Costs for drilling rigs and well services have increased markedly during 2005, and continue to increase in 2006. In many instances, there are not enough drilling rigs or materials to meet demand, regardless of price. To address this challenge, Kerr-McGee has employed its supply chain management expertise both to control costs and to ensure the execution of its exploration and development programs. For example, we have executed multiyear contracts to secure deepwater drilling rigs to carry out our exploration and development programs for 2006 and much of 2007.

The availability of personnel with critical skills also is a major industry concern. The combination of industry demographics, with many experienced personnel now nearing retirement, and strong demand for petro-technical personnel, has resulted in a tight, highly competitive labor market. The company utilizes a combination of competitive compensation and benefits, along with challenging and rewarding work assignments, to remain an attractive employer for critical petro-technical personnel.

Results of Operations - Consolidated

The following discussion presents an analysis of results of consolidated operations, with additional analysis of segment operations included under -Results of Operations by Segment.

Revenues - As discussed under -Operating Environment and Outlook above, oil and gas prices have been rising in recent years, reaching record or near-record levels in 2005. Favorable market conditions contributed to revenue growth, although higher prices realized by the company on sales of oil and natural gas were partially offset by realized losses on our hedging contracts. Of the $1.5 billion revenue increase in 2005, $1 billion reflects higher average realized sales prices for oil and natural gas (including the effects of hedging). Oil and gas sales volumes also increased in each of the last two years, primarily as a result of the contribution from Westport properties acquired in June 2004, and from new fields in China which started producing in July 2004 and July 2005. In 2005, these production increases were partially offset by production losses as a result of hurricane activity in the third quarter and by the fourth-quarter divestitures of certain noncore assets onshore in the U.S. Gas marketing sales revenues increased by $385 million in 2005 and $121 million in 2004, reflecting increased marketing activity and higher natural gas prices. The increases in gas marketing revenues were largely offset by higher gas purchase costs, as described in the Costs and Operating Expenses section below.

As a result of the 2005 oil and gas property divestitures and the pending sale of our Gulf of Mexico shelf properties, we expect our 2006 production to decline. We expect 2006 production from continuing operations on a boe basis to be 5-11% lower than 2005, primarily reflecting the effect of completed and pending property divestitures, partially offset by new production from our Constitution/Ticonderoga development. The following is a summary of the components of changes in consolidated revenues over the three-year period ended December 31, 2005, with additional analysis provided in the section -Results of Operations by Segment that follows:

(Millions of dollars)	2005		2005 vs. 2004			2004		2004 vs. 2003			2003

*Revenues*	$	5,927	$	1,529		$	4,398	$	1,109		$	3,289
Increase (decrease) in -
Oil and gas sales revenues due to changes in realized prices			$	1,036				$	318
Oil and gas sales revenues due to volume changes				381					515
Hedge ineffectiveness, overhedge positions and nonhedge
derivative losses				(344	)				(18	)
Other exploration and production revenues
(primarily marketing)				394					149
Pigment sales revenues due to changes in realized prices				136					16
Pigment sales revenues due to volume changes				(78	)				114
Other chemical segment revenues				4					15
Total change in revenues			$	1,529				$	1,109

Costs and Operating Expenses - Costs and operating expenses increased more than 25% in each of the last two years. Increased third-party natural gas marketing activity in the Rocky Mountain area and the higher cost of natural gas contributed to operating cost increases, largely offsetting higher gas marketing revenues, as discussed above. Lease operating expenses increased due to the Westport acquisition in June 2004 impacting half-year 2004 results and full-year 2005 results coupled with higher costs associated with oilfield goods and services and property insurance coverage. As discussed in the Revenues section above, our production volumes from continuing operations are expected to be lower in 2006. However, lease operating expenses may not decline by a rate commensurate with the expected production decline due to inflationary trends in the cost of services and equipment, and other factors.

In recent years, Tronox experienced an increase in average per-tonne pigment production costs, largely due to rising costs of raw materials and energy. This trend increased pigment production costs in each of the last two years, although in 2005, such cost increases were more than offset by reduced operating expenses due to lower sales volumes following the September 2004 shutdown of Tronox's sulfate production at its Savannah, Georgia, plant. Despite the shutdown, 2004 pigment sales volumes were 9% higher than in 2003 because of strong market conditions, contributing to the $120 million increase in Tronox's pigment costs and operating expenses in 2004.

The 2004 costs and operating expenses included charges of $30 million for severance and employee benefit costs, inventory revaluation and other asset write-downs associated with the closure of the Savannah plant. Costs and operating expenses in 2003 included $28 million for employee-related severance and benefits, inventory obsolescence and other costs related to the shutdown of Tronox’s Mobile, Alabama, plant.

Factors contributing to changes in costs and operating expenses are summarized below, with additional analysis provided in the section -Results of Operations by Segment that follows.

(Millions of dollars)	2005		2005 vs. 2004			2004		2004 vs. 2003		2003

*Costs and operating expenses*	$	2,304	$	510		$	1,794	$	378	$	1,416
Increase (decrease) in -
Lease operating expense			$	143				$	106
Gas purchase costs				382					127
Pigment costs and operating expenses				(6	)				120
Costs associated with plant shutdowns				(31	)				5
Other costs and operating expenses				22					20
Total change in costs and operating expenses			$	510				$	378

Selling, General and Administrative Expenses - The following summarizes the components of changes in selling, general and administrative expenses over the three-year period ended December 31, 2005:

(Millions of dollars)	2005		2005 vs. 2004		2004		2004 vs. 2003			2003

*Selling, general and administrative expenses*	$	455	$	130	$	325	$	(25	)	$	350
Increase (decrease) in -
Incentive compensation, including stock-based awards			$	52			$	32
Employee retention programs				23				-
Advisory, legal and other costs associated with strategic realignment				28				-
Cost of work force reduction programs				5				(47	)
Insurance coverage and adjustments for self-insured risks				12				(7	)
Other selling, general and administrative expenses				10				(3	)
Total change in selling, general and administrative
expenses			$	130			$	(25	)

In 2005, expense associated with stock-based awards increased $32 million, $17 million of which related to our performance unit awards and $15 million to restricted stock and stock options. Generally, stock-based compensation expense was higher in 2005 because of the increased value of Kerr-McGee’s stock. The per-unit liability associated with performance unit awards increased as a result of Kerr-McGee’s higher total stockholder return relative to selected peer companies. Additionally, the number of outstanding performance units was higher in 2005, following the January 2005 grant. The remaining $20 million increase in incentive compensation is related to our bonus program, which provides eligible employees with an annual payment if specified business goals are met. Higher expense associated with this program reflects Kerr-McGee’s improved performance in 2005.

As discussed under -Executive Overview above, in 2005, we made a number of strategic decisions, including divestiture of certain exploration and production assets and the separation of Tronox. In April 2005, in connection with the planned exit activities, we initiated employee retention programs with an aggregate cost of $34 million, designed to provide an incentive to certain employees to remain with the company over a stated period ranging from six to 18 months. We recognized expense of $23 million under these programs in 2005. Additionally, in connection with the strategic realignment, we incurred $28 million in advisory, legal and other costs, $13 million of which was associated with the Tronox separation.

The decrease in selling, general and administrative expenses of $25 million in 2004 was mainly attributable to certain 2003 expenses that did not reoccur, partially offset by higher incentive compensation costs. In 2003, we initiated a work force reduction program and recorded a total charge of $53 million, of which $48 million was included as a component of selling, general and administrative expenses and $5 million was included in other categories of operating expenses.

Shipping and Handling Expenses - Shipping and handling expenses for 2005, 2004 and 2003 were $145 million, $128 million and $96 million, respectively, with increases relating primarily to our oil and gas production operations. An analysis of transportation and shipping and handling expenses is provided under -Results of Operations by Segment below.

Depreciation and Depletion - The increase in depreciation and depletion expense from 2004 to 2005 is primarily the result of the Westport merger in June 2004, which contributed to increased production at higher per-unit depreciation and depletion cost. Increased production from certain fields in China's Bohai Bay also contributed to higher depreciation and depletion expense. The 2004 increase reflects the impact of the Westport merger and accelerated depreciation associated with the shutdown of Tronox’s sulfate production facility at its Savannah, Georgia, plant.

The following table presents the components of changes in depreciation and depletion expense over the last three years:

(Millions of dollars)	2005		2005 vs. 2004			2004		2004 vs. 2003		2003

*Depreciation and depletion*	$	952	$	110		$	842	$	310	$	532
Increase (decrease) in -
Oil and gas depletion due to change in depletion rates			$	110				$	123
Oil and gas depletion due to change in sales volumes				92					114
Chemical segment accelerated depreciation				(71	)				71
Other depreciation				(21	)				2
Total change in depreciation and depletion			$	110				$	310

Asset Impairments - Asset impairment charges totaled $17 million in 2005, $28 million in 2004 and $14 million in 2003. Our chemical - pigment segment incurred an asset impairment charge of $8 million in 2004 (related to the shutdown of the sulfate-process titanium dioxide pigment production at the Savannah, Georgia, plant). The remaining asset impairment charges relate to our exploration and production operations and are discussed in more detail under -Results of Operations by Segment - Exploration and Production.

Gain (Loss) on Sale of Assets - Net gains (losses) on sale of assets in 2005, 2004 and 2003 were $211 million, $(29) million, and $30 million, respectively. The 2005 gains on sale included $166 million associated with the divestitures of noncore oil and gas properties as part of the company’s strategic realignment, with the remaining gains of $45 million related to certain exchanges of interests in oil and gas properties. Additional discussion of gains and losses for the last three years is provided under -Results of Operations by Segment - Exploration and Production.

Exploration Expense - An analysis of changes in exploration expense is provided under -Results of Operations by Segment - Exploration and Production.

Taxes Other than Income Taxes - Taxes other than income taxes totaled $202 million, $144 million and $94 million in 2005, 2004 and 2003, respectively, and includes $156 million, $104 million and $53 million, respectively, for oil and gas production and ad valorem taxes. Because oil and gas production taxes are generally determined as a percentage of oil and gas sales revenues, they fluctuate with changes in oil and gas sales volumes and realized prices. Oil and gas production and ad valorem taxes increased $52 million in 2005 and $51 million in 2004 when compared to the prior-year periods due to higher sales volumes primarily as a result of the Westport merger and higher realized prices. Taxes other than income taxes also include payroll and other taxes, which did not significantly change over the three-year period.

Provision for Environmental Remediation and Restoration - Provision for environmental remediation and restoration (before considering accruals for cost reimbursements) totaled $73 million, $100 million and $92 million in 2005, 2004 and 2003, respectively, and resulted primarily from encountering increased contaminated soil volumes and a change in prior estimates of remediation costs, including costs associated with construction and operation of groundwater remediation systems. Accruals for environmental cost reimbursements from the U.S. government and insurers totaled $35 million, $14 million and $32 million in 2005, 2004 and 2003, respectively. The changes in cost reimbursements are due primarily to changes in estimated remediation costs at Tronox's Henderson, Nevada, plant that are covered by an insurance policy. Our environmental obligations and the associated cost reimbursements are discussed in greater detail under -Environmental Matters below and in Note 16 to the Condensed Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

In the first quarter of 2006, Tronox recognized a receivable of $21 million as a result of a settlement of its claims against the United States, which was documented in a consent decree approved by the court on January 13, 2006. This reimbursement was received by Tronox in February 2006.

Interest and Debt Expense - Interest and debt expense for 2005, 2004 and 2003 was $253 million, $244 million and $250 million, respectively. As discussed below, a portion of 2005 interest and debt expense is reported in income from discontinued operations (net of tax) in connection with the divestiture of the company’s North Sea oil and gas business. Including amounts reported in income from discontinued operations, our total 2005 interest and debt expense was $345 million, $101 million higher than in 2004. This increase is primarily the result of $1.1 billion higher average outstanding debt in 2005, in addition to $19 million higher expense associated with interest rate swaps designated to hedge the fair value of our debt. These increases in interest and debt expense were partially offset by $15 million higher capitalized interest driven by increased qualifying capital expenditures.

In May 2005, in connection with the tender offer to repurchase Kerr-McGee’s stock, 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. Provisions of the credit agreement required the company to use 100% of the net after-tax cash proceeds from sales of certain assets for debt repayment. Because our North Sea assets were subject to this requirement, $92 million of interest expense on debt that was required to be repaid upon their sale is classified as a component of income from discontinued operations. The amount of interest and debt expense allocated to discontinued operations is based on approximately $3.1 billion of the company’s obligations under the term loans that were repaid during 2005 with the net after-tax cash proceeds from the sale of the North Sea oil and gas business. Interest expense was allocated to discontinued operations beginning in May 2005, to coincide with initial borrowings under the term loans that required mandatory prepayments.

Total interest and debt expense associated with borrowings under the $5.5 billion credit agreement was $169 million in 2005, including $46 million in financing costs (in each case including amounts allocated to discontinued operations). In connection with this credit agreement, we incurred financing costs of $58 million, which were initially capitalized when incurred. Of the total $58 million, $8 million was amortized to interest and debt expense and $50 million was written off to loss on early repayment and modification of debt in 2005 and in the first quarter of 2006, as discussed below.

The 2004 decrease in interest and debt expense of $6 million was due to an increase in capitalized interest and higher realized gains on interest rate swaps designated to hedge the fair value of our debt. For additional information regarding the interest rate swap arrangements, refer to the -Market Risks section below.

Loss on Early Repayment and Modification of Debt - The following presents information regarding charges incurred in connection with early repayment of debt and modification of the terms of certain debt instruments. Information related to 2006 reflects charges associated with certain financing activities that occurred through February 28, 2006.

	Debt Issue		Unamortized		Transaction
(Millions of dollars)	Costs		Discount		Costs		Total

Year ended December 31, 2005 -
Prepayment of term loans (1)	$	38	$	-	$	-	$	38
Consent solicitation costs (2)		-		-		4		4
	$	38	$	-	$	4	$	42

Quarter ended March 31, 2006 -
Termination of the revolving credit facility (1)	$	12	$	-	$	-	$	12
Early redemption of 7% debentures (3)		-		69		-		69
	$	12	$	69	$	-	$	81

⁽¹⁾

As discussed under -Financial Condition and Liquidity, by the end of 2005, we fully repaid $4.25 billion of term loan borrowings under the $5.5 billion credit agreement, which resulted in the write-off of unamortized debt issuance costs associated with the facilities. The credit agreement, which was terminated in January 2006, also included a $1.25 billion five-year revolving credit facility. Unamortized debt issuance costs associated with the revolving credit facility ($12 million) were written off in connection with the termination of the credit agreement.

⁽²⁾

The modification to the indenture terms for certain notes payable provided for the release of the company’s chemical business subsidiary, Tronox Worldwide LLC, as a guarantor of the notes in connection with the Tronox IPO. Additional information about this modification to the indenture terms is provided in Note 10 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

⁽³⁾	In February 2006, we used cash on hand to redeem the 7% debentures due 2011 at face value of $250 million.

Other Income (Expense) - The components of other income (expense) are presented in the table below.

(Millions of dollars)	2005			2004			2003

Gain on sale of nonoperating interest in gas
processing facility ⁽¹⁾	$	120		$	-		$	-
Equity in net losses of equity method investees ⁽²⁾		(19	)		(26	)		(33	)
Net foreign currency transaction loss		(2	)		(13	)		(5	)
Gain on sale of Devon stock ⁽³⁾		-			9			17
Interest income		10			4			2
Loss on accounts receivables sales and other		(5	)		(8	)		(6	)
Total	$	104		$	(34	)	$	(25	)

⁽¹⁾	We owned an interest in the Javelina gas processing facility through our 40% ownership of Javelina Company and Javelina Pipeline Company. This investment was accounted for using the equity method of accounting. We sold our investment in Javelina in November 2005 for cash proceeds of $159 million.

⁽²⁾

Equity in net losses of equity method investees relate primarily to our investment in the Avestor joint venture formed in 2001 to develop lithium-metal-polymer batteries, partially offset by equity in net earnings of Javelina in 2005 and 2004. Additional information about Avestor operations is provided in Items 1 and 2, Business and Properties - Segment and Geographic Information - Stored Power.

⁽³⁾	In December 2003, we sold a portion of our investment in Devon shares classified as available for sale, resulting in a pretax gain of $17 million. The remaining shares classified as available for sale were sold in January 2004 for a pretax gain of $9 million.

Benefit (Provision) for Income Taxes - The effective tax rates for continuing operations were 34% for both 2005 and 2004 and (11)% for 2003. In 2003, we recognized an income tax benefit of $15 million on pretax income from continuing operations of $140 million. This unusual relationship between income taxes and pretax earnings is primarily due to a federal tax audit settlement for $59 million less than the previously established provision. Excluding this settlement, the 2003 effective tax rate for continuing operations was 31%.

Income from Discontinued Operations - As part of our divestiture program discussed under -Executive Overview, we sold our North Sea oil and gas business in 2005, realizing cash proceeds of $3.3 billion (net of cash transferred to the purchasers and transaction costs) and pretax gain on sale of $2.2 billion. Income from discontinued operations for 2005, 2004 and 2003 reflects income from operations of the North Sea business, partially offset by operating losses of Tronox’s discontinued forest products operations, as summarized in Note 2 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Cumulative Effect of Change in Accounting Principle - We recognized a loss of $35 million (net of income tax benefit of $18 million), upon adoption of Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations” on January 1, 2003.

Results of Operations by Segment

The following table summarizes operating profit (loss) of our reportable business segments, with a reconciliation to consolidated income from continuing operations for each of the last three years, followed by discussion and analysis of operating results for each segment.

(Millions of dollars)	2005			2004			2003

Segment operating profit (loss) (1) -
Exploration and production	$	1,755		$	973		$	649
Chemical -
Pigment		100			(80	)		(13	)
Other		(6	)		(2	)		(23	)
Total chemical		94			(82	)		(36	)

Unallocated expenses -
Interest and debt expense		(253	)		(244	)		(250	)
Loss on early repayment and modification of debt		(42	)		-			-
Corporate expenses		(201	)		(130	)		(151	)
Environmental provisions, net of reimbursements		(23	)		(82	)		(47	)
Other income (expense)		104			(34	)		(25	)
Benefit (provision) for income taxes		(487	)		(137	)		15
Minority interest, net of taxes		(1	)		-			-
Total unallocated expenses		(903	)		(627	)		(458	)
Income from continuing operations	$	946		$	264		$	155

Income from continuing operations per common share -
Basic	$	7.22		$	2.09		$	1.55
Diluted		7.07			2.08			1.54

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

Our results of operations for all periods presented included certain items affecting comparability between periods. Because of their nature and amount, these items are identified separately to help explain the changes in segment operating profit and income from continuing operations before income taxes between periods, as well as to help distinguish the underlying trends for the company’s core businesses. These items are listed in the following table and, to the extent material, are discussed under -Results of Operations - Consolidated and -Results of Operations by Segment - Exploration and Production and - Chemical below.

(Millions of dollars)	2005			2004			2003

Included in total segment operating profit -
Plant shutdown costs and accelerated depreciation	$	-		$	(122	)	$	(45	)
Environmental provisions		(15	)		(4	)		(13	)
Asset impairments		(17	)		(28	)		(14	)
Gain (loss) associated with assets held for sale		211			(29	)		30
Gain (loss) on hedge ineffectiveness		(206	)		4			(1	)
Nonhedge derivative loss		(38	)		(23	)		-
Insurance premium adjustment		-			(16	)		-
Employee retention programs		(16	)		-			-
Costs associated with work force reduction programs		-			(2	)		(35	)
Other		-			-			(19	)
Subtotal		(81	)		(220	)		(97	)

Included in unallocated expenses -
Environmental provisions, net of reimbursements		(23	)		(82	)		(47	)
Foreign currency losses		(2	)		(13	)		(5	)
Gain on sale of Devon stock		-			9			17
Employee retention programs		(9	)		-			-
Costs associated with work force reduction programs		(6	)		-			(18	)
Loss on early repayment and modification of debt		(42	)		-			-
Cost of separating the Chemical business		(13	)		-			-
Gain on sale of nonoperating interest in gas processing facility		120			-			-
Other		(14	)		(4	)		(12	)

Items affecting comparability	$	(70	)	$	(310	)	$	(162	)

EXPLORATION AND PRODUCTION

Segment Operating Profit

Revenues, operating costs and expenses relating to the production, sale and marketing of crude oil, condensate and natural gas are shown in the following table. This information excludes results for the North Sea business reported as a discontinued operation.

(Millions of dollars)	2005			2004			2003

Revenues, excluding marketing revenues	$	3,759		$	2,677		$	1,834
Operating costs and expenses -
Lifting costs:
Lease operating expense		437			294			188
Production and ad valorem taxes		156			104			53
Total lifting costs		593			398			241

Depreciation, depletion and amortization		838			636			399
Accretion expense (abandonment obligations)		22			18			15
Asset impairments		17			20			14
Loss (gain) on sale of assets		(211	)		29			(30	)
General and administrative expense		171			122			113
Transportation expense		92			74			51
Gas gathering, pipeline and other expenses		109			84			62
Exploration expense		377			324			327
Total operating costs and expenses		2,008			1,705			1,192

Operating profit, excluding net marketing margin		1,751			972			642

Marketing - gas sales revenues		804			419			298
Marketing - gas purchase cost (including transportation)		(800	)		(418	)		(291	)
Net marketing margin		4			1			7

Total operating profit	$	1,755		$	973		$	649

Operating profit for all periods presented includes certain items affecting comparability between periods. Because of their nature and amount, these items are identified separately to help explain the changes in operating profit between periods, as well as to help distinguish the underlying trends for the segment’s core business. These items are listed in the following table and, to the extent material, are discussed in the analysis of operating profit components that follows:

(Millions of dollars)	2005			2004			2003

Asset impairments	$	(17	)	$	(20	)	$	(14	)
Gain (loss) associated with assets held for sale		211			(29	)		30
Gain (loss) on hedge ineffectiveness		(206	)		4			(1	)
Nonhedge derivative loss		(38	)		(23	)		-
Insurance premium adjustment		-			(12	)		-
Employee retention programs		(15	)		-			-
Costs associated with work force reduction programs		-			(1	)		(14	)
Environmental provisions		(4	)		-			-
Other		-			(4	)		(14	)
Items affecting comparability	$	(69	)	$	(85	)	$	(13	)

Revenues

Revenues, production statistics and average prices received from sales of crude oil, condensate and natural gas are shown in the following table (exclusive of discontinued operations):

(Millions of dollars, except per-unit amounts)	2005			2004			2003

Revenues -
Crude oil and condensate sales	$	1,711		$	1,030		$	752
Natural gas sales		2,338			1,602			1,047
Gain (loss) on hedge ineffectiveness		(206	)		4			(1	)
Loss on overhedge positions		(119	)		-			-
Nonhedge derivative losses		(38	)		(23	)		-
Gas marketing activities		804			419			298
Processing, gathering and other revenues		73			64			36
Total	$	4,563		$	3,096		$	2,132

Production -
Crude oil and condensate (thousands of barrels per day):
U.S. Gulf of Mexico		55			60			57
U.S. onshore		35			28			20
China		19			8			2
Total		109			96			79

Natural gas (MMcf per day):
U.S. Gulf of Mexico		377			364			277
U.S. onshore		585			472			352
Total		962			836			629

Total equivalent barrels of oil (thousands of barrels per day)		270			236			183

Average sales prices (excluding hedges) -
Crude oil and condensate (per barrel):
U.S. Gulf of Mexico	$	50.58		$	37.97		$	29.14
U.S. onshore		47.68			37.63			27.42
China		44.45			32.37			29.66
Average		48.57			37.41			28.72

Natural gas (per Mcf):
U.S. Gulf of Mexico	$	8.24		$	6.25		$	5.60
U.S. onshore		7.64			5.92			4.87
Average		7.87			6.06			5.19

Average realized sales prices (including hedges) -
Crude oil and condensate (per barrel):
U.S. Gulf of Mexico	$	43.79		$	29.43		$	26.12
U.S. onshore		40.62			28.43			26.23
China		44.45			32.37			29.66
Average		42.89			29.38			26.24

Natural gas (per Mcf):
U.S. Gulf of Mexico	$	7.18		$	5.44		$	4.88
U.S. onshore		6.32			5.08			4.31
Average		6.66			5.24			4.56

Crude Oil Revenues and Production - Oil sales revenues increased $681 million or 66% in 2005 compared with 2004 due to a combination of higher realized commodity prices and higher sales volumes. Average oil prices, including the effect of hedging activity, increased $13.51 per barrel in 2005, resulting in a $539 million increase in oil sales revenues. Oil production of 109 thousand barrels per day (Mbbls/d) in 2005 increased by 13 Mbbls/d over 2004 levels. The increase in 2005 production volumes was primarily due to a full year of production from China’s CFD 11-1 and CFD 11-2 fields (8 Mbbls/d) and from China’s CFD 11-3/11-5 field (3 Mbbls/d), which began production in July 2005. Also contributing to the increase were Westport properties that were acquired in late June 2004 (8 Mbbls/d). These increases were partially offset by hurricane-related production losses (3 Mbbls/d) in the Gulf of Mexico and U.S. onshore Gulf Coast areas and the divestiture of noncore U.S. onshore properties in 2005 (4 Mbbls/d).

Oil sales revenues increased $278 million in 2004 compared with 2003, due to a combination of higher sales volumes and higher realized prices. The 2004 production volume increase was primarily due to the contribution of Westport assets acquired in late June 2004 (14 Mbbls/d) and the sale of various noncore properties during 2003. In addition, China’s CFD 11-1 and CFD 11-2 fields, which started production in July 2004, and the Gulf of Mexico’s Gunnison field, which began production in the fourth quarter of 2003, contributed to the increase. The higher volumes in 2004 accounted for $168 million of the increase in revenues. The average realized price, including the effect of hedging activity, increased $3.14 per barrel, adding $110 million to sales revenues in 2004.

Natural Gas Revenues and Production - Natural gas sales revenues increased 46% or $736 million in 2005 compared with 2004 as a result of a $1.42 per thousand cubic feet (Mcf) increase in the average realized price, combined with a 15% increase in gas production. Higher realized prices in 2005 increased revenues by $497 million. Gas production in 2005 was 962 million cubic feet per day (MMcf/d), 126 MMcf/d above 2004 annual production, contributing an additional $239 million in gas sales revenues. Gas production increased in 2005, primarily as a result of a full year of production from Westport fields (191 MMcf/d) and higher production from the Red Hawk and Nansen fields in the deepwater Gulf of Mexico (32 MMcf/d). These increases were partially offset by hurricane-related production losses (75 MMcf/d) that occurred in the Gulf of Mexico and U.S. onshore Gulf Coast areas, along with the divestiture of U.S. onshore properties (23 MMcf/d).

Natural gas sales revenues in 2004 were $555 million higher than in 2003, primarily as a result of a 33% increase in production, combined with a $.68 per Mcf increase in the average realized price. Gas production in 2004 averaged 836 MMcf/d, 207 MMcf/d above 2003 average annual production, contributing an additional $347 million in natural gas sales revenues. Gas production increased as a result of additional production from Westport fields, which contributed approximately 197 MMcf/d in 2004. In addition, new production from deepwater Gulf of Mexico fields, primarily Red Hawk and Gunnison, offset declines that occurred in the U.S. onshore area. Higher realized prices provided an additional $208 million in natural gas sales revenues in 2004, averaging $5.24 per Mcf, including the impact of hedging activities.

Processing, Gathering and Other Revenues - Other revenues include gas processing plant sales and gathering system revenues primarily in the U.S. onshore area. Gas marketing activities in the Rocky Mountain area are discussed separately below.

Processing, gathering and other revenues totaled $73 million in 2005, an increase of $9 million over 2004, resulting primarily from higher gas processing revenues from the company’s nonoperated ownership interest in a Wattenberg-area gas plant, driven by higher U.S. commodity prices.

Processing, gathering and other revenues increased by $28 million in 2004 from $36 million in 2003. The increase is primarily the result of higher U.S. natural gas prices favorably impacting sales generated from the company’s ownership interest in gas processing plants and gathering systems in Louisiana and Colorado.

Gains (Losses) Associated with Commodity Derivatives - Gains and losses on derivatives designated as hedges of forecasted oil and gas sales are deferred in accumulated other comprehensive income (loss) and reclassified into earnings when the hedged sales transactions affect earnings. Gains and losses associated with hedge ineffectiveness and nonhedge derivatives are recognized in current earnings as a component of revenues.

In 2005, we recognized hedge ineffectiveness losses of $206 million associated with commodity derivative instruments designated as hedges of future oil and gas sales. These losses represent the excess of mark-to-market losses on our commodity derivatives over the higher cash flows we expect to realize upon sales of hedged production. Increased ineffectiveness losses in 2005 are due to our expanded hedging program that now extends through 2007, as well as significantly higher commodity prices and widening differentials between NYMEX forward prices (which underpin our derivative instruments) and expected future oil and gas sales prices.

As a result of two major hurricanes in the Gulf of Mexico late in the third quarter of 2005, the company’s physical deliveries to certain sales indices for the period from September to December 2005 were insufficient to cover the associated derivative instruments assigned to those areas. Consequently, we recognized a $119 million “overhedge” loss (reported separately from oil and gas sales revenues) for realized losses on certain natural gas hedges assigned to the Gulf of Mexico.

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

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

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

For further discussion of the company's derivative activities, see Note 9 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. A full description of outstanding derivative positions at December 31, 2005, both hedge and nonhedge, is included in -Market Risks section below.

Lease Operating Expense

During 2005, lease operating expense increased $143 million or 49% compared with 2004. On a per-unit basis, lease operating expense increased $1.02 per boe, from $3.42 per boe in 2004 to $4.44 per boe in 2005. The increase was primarily due to additional operating expenses associated with Westport properties acquired in June 2004 ($89 million), and China’s CFD 11-3/11-5 field and CFD 11-1 and 11-2 fields that started producing in July 2005 and July 2004, respectively ($21 million). In addition, property insurance expense and hurricane-related repairs increased $24 million in 2005 compared to the prior year. The remaining increase was primarily attributable to our nonoperated U.S. Gulf of Mexico shelf properties, as well as overall U.S. inflationary increases to the cost of services and equipment.

Lease operating expense for 2004 was $294 million, an increase of $106 million compared with 2003. On a per-unit basis, lease operating expense increased $.61 per boe, from $2.81 per boe in 2003 to $3.42 per boe in 2004. The increase was primarily due to additional operating expenses associated with Westport fields ($66 million), startup production costs at China’s CFD 11-1 and CFD 11-2 fields, and higher expense in the Gulf of Mexico deepwater related to an operating lease for platform infrastructure at the Gunnison field. A charge of $12 million in 2004, or $.14 per boe, for a property insurance premium adjustment primarily associated with higher industry losses due to Hurricane Ivan also contributed to the year-over-year increase.

Production and Ad Valorem Taxes

Production and ad valorem taxes are comprised primarily of production-based severance and ad valorem taxes associated with properties located onshore and in state waters in the U.S. These taxes, which are usually based on a percentage of oil and gas sales revenues, increased $52 million in 2005 as a result of higher commodity prices and higher sales volumes compared with 2004.

Production and ad valorem taxes of $104 million in 2004 were $51 million higher than 2003 primarily due to higher commodity prices and higher sales volumes. The addition of Westport’s properties in 2004 resulted in higher production taxes as a percentage of sales revenues compared to 2003 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 for 2005 was $838 million, a $202 million increase over 2004. Contributing to the increase was additional DD&A expense associated with the Westport properties acquired in June 2004 ($181 million), as well as higher production from China’s CFD 11-1, CFD 11-2, CFD 11-3 and CFD11-5 fields ($31 million). This increase was partially offset by lower DD&A in the Gulf of Mexico region primarily, driven by the decrease in production volumes. On a per-unit basis, DD&A expense increased from $7.39 per boe in 2004 to $8.51 per boe in 2005, primarily reflecting the Westport merger, which had a higher acquisition cost per boe than our historical DD&A rate.

DD&A expense of $636 million for 2004 increased $237 million over the prior year, primarily caused by additional DD&A expense for the acquired Westport properties ($206 million). On a per-unit basis, DD&A increased from $5.97 per boe in 2003 to $7.39 per boe in 2004, reflecting the impact of the Westport merger.

Asset Impairments and Gain (Loss) on Sale 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 2005, 2004 and 2003 totaled $17 million, $20 million and $14 million, respectively. Impairment losses in 2005 related primarily to a U.S. onshore property in Texas where unsuccessful drilling resulted in a reduction in proved undeveloped reserves ($10 million) and two U.S. Gulf of Mexico shelf properties that ceased producing in the first quarter. Impairment losses in 2004 related primarily to a U.S. Gulf of Mexico field that experienced premature water breakthrough and ceased production sooner than expected. The 2003 impairments related to mature oil and gas producing assets in the U.S. onshore and Gulf of Mexico shelf areas.

The company recognized a net gain of $211 million on sales of oil and gas properties during 2005, related primarily to the divestiture of noncore U.S. onshore properties. A total of $435 million in cash was received in 2005 for the sale of our interests in certain oil and gas properties located in the Powder River basin, South Texas, Permian Basin/Mid-Continent and Barnett Shale areas, resulting in a net gain of $149 million. Also, as part of our business development activities, 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 $26 million in cash and recognized a $21 million gain on the trade, based on the percentage of the Arkoma properties’ fair value that was received in cash. In addition, we sold our interest in certain oil and gas properties in the Table Mountain and Culp Draw fields of Wyoming to Anadarko Petroleum Corporation in exchange for Anadarko’s overriding interest in the Greater Natural Buttes area and $27 million in cash. We recognized a gain of $24 million in connection with this transaction.

The company recognized a net loss on sales of oil and gas properties of $29 million in 2004. The loss was associated primarily with the conveyance of the company’s interest in a nonproducing Gulf of Mexico field to a participating partner ($25 million). In addition, losses of $6 million and gains of $2 million were recognized on sales of noncore properties in the Gulf of Mexico shelf and U.S. onshore areas.

A net gain on sales of oil and gas properties of $30 million was recognized in 2003 upon conclusion of the company’s 2002 divestiture program in the U.S. and for the sale of the company’s interest in the South China Sea (Liuhua field) and other noncore U.S. properties.

General and Administrative Expense

On a per-unit basis, general and administrative expense was $1.74 per boe for 2005, an increase of $.32 per boe compared with 2004. Total 2005 general and administrative expense of $171 million was $49 million higher than 2004. General and administrative expense in 2005 included a $15 million charge primarily associated with employee retention programs, compared with $4 million for 2004 employee retention costs. Additional information on these programs is provided under -Results of Operations-Consolidated above. Additional general and administrative expense increases over 2004 were due to higher cost of employee compensation, primarily related to a full year of personnel costs associated with the Westport merger, higher incentive-based compensation costs and increased benefits costs. These increases were partially offset by higher overhead charge-outs for U.S. onshore and Gulf of Mexico properties.

General and administrative expense in 2004 was $9 million higher than in 2003. Contributing to this increase was higher incentive compensation and pension costs, as well as additional administrative and personnel costs associated with the Westport merger ($8 million). The increase in 2004 was partially offset by lower costs as compared to 2003, associated with the 2003 work force reduction program and the employee stock ownership plan.

Transportation Expense

Transportation expense, representing the costs paid to third-party shippers to transport oil and gas production, increased by $18 million during 2005, to $92 million. In early 2005, we began transporting gas from the Rocky Mountain area under a new contract, increasing overall transportation costs. Higher costs associated with the new contract are expected to be offset by higher realized gas prices as a result of greater access to more competitive gas markets. In addition, a full year of transportation associated with Westport properties increased 2005 costs ($18 million). On a per-unit basis, 2005 transportation expense was $.93 per boe compared to $.85 per boe in 2004.

Transportation expense in 2004 of $74 million was $23 million, or 45% higher than 2003. The increase was due to additional transportation costs associated with Westport properties ($11 million) and the new production from the deepwater Gulf of Mexico Red Hawk and Gunnison fields. On a per-unit basis, 2004 transportation expense was $.85 per boe, a 12% increase over 2003.

Exploration Expense

(Millions of dollars)	2005			2004			2003

Exploration costs ⁽¹⁾	$	48		$	43		$	36
Geological and geophysical costs		66			78			54
Dry hole expense		172			152			173
Amortization of undeveloped leases		92			59			64
Sales of unproved properties		(1	)		(8	)		-
Total exploration expense	$	377		$	324		$	327

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

In 2005, total exploration expense was $377 million, an increase of $53 million compared with 2004, primarily due to an increase in amortization of undeveloped leases of $33 million. Individual undeveloped leases with an original acquisition cost of greater than $2 million are reviewed periodically for impairment based on the company’s current exploration plans. As a result of this review and in light of our refocused exploration strategy, we recognized additional amortization of undeveloped leases of $25 million associated with certain deepwater Gulf of Mexico acreage in 2005. In addition, as a result of unsuccessful exploration efforts in Angola in the fourth quarter of 2005, we recognized a partial impairment of $8 million associated with our Angola interests. Higher dry hole expense of $20 million also contributed to the increase in exploration expense, partially offset by lower geological and geophysical costs of $12 million.

Exploration expense in 2004 was $3 million lower than in 2003, primarily as a result of lower dry hole costs, lower amortization of undeveloped leases and a gain on sale of unproved properties. The gain on sale of unproved properties related primarily to reimbursement of past exploration costs by new partners purchasing an interest in our Morocco activities.

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 December 31, 2005, the company had capitalized costs of approximately $208 million associated with such ongoing exploration activities, primarily in the deepwater Gulf of Mexico, Alaska, Brazil and China. Additional information regarding deferred exploratory drilling costs is included in Note 23 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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 Rocky Mountain production.

Marketing revenue was $804 million in 2005, $419 million in 2004 and $298 million in 2003, an increase of $385 million and $121 million, respectively, between periods. The increase in both 2005 and 2004 was the result of higher purchase and resale of third-party natural gas in the Rocky Mountain area and higher natural gas prices. Increased gas purchase costs of $382 million and $127 million in 2005 and 2004, respectively, largely offset the increase in revenues. Third-party marketing volumes (MMBtu/day) were 293,000 in 2005, 210,000 in 2004, and 178,000 in 2003.

CHEMICAL

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

(Millions of dollars)	2005			2004			2003

Revenues -
Pigment	$	1,267		$	1,209		$	1,079
Other		97			93			78
Total	$	1,364		$	1,302		$	1,157

Operating profit (loss) -⁽¹⁾
Pigment	$	100		$	(80	)	$	(13	)
Other		(6	)		(2	)		(23	)
Total	$	94		$	(82	)	$	(36	)

Titanium dioxide pigment production
(thousands of tonnes)		537			549			532

⁽¹⁾	Operating profit (loss) does not include litigation provisions and environmental provisions, net of reimbursements, related to various businesses in which the company’s affiliates are no longer engaged, such as the mining and processing of uranium and thorium and other businesses.

Operating profit (loss) for all periods presented includes certain items affecting comparability between periods. Because of their nature and amount, these items are identified separately to help explain the changes in operating profit (loss) between periods, as well as to help distinguish the underlying trends for the segment’s core businesses. These items are listed in the following table and, to the extent material, are discussed in the analysis of operating profit that follows:

(Millions of dollars)	2005			2004			2003

Included in chemical - pigment operating profit (loss) -
Plant shutdown costs and accelerated depreciation	$	-		$	(122	)	$	(44	)
Asset impairments		-			(8	)		-
Insurance premium adjustment		-			(4	)		-
Environmental provisions		-			(1	)		(1	)
Employee retention programs		(1	)		-			-
Cost associated with work force reduction programs		-			(1	)		(18	)
Other		-			4			(4	)

Included in chemical - other operating loss -
Plant shutdown costs and accelerated depreciation		-			-			(1	)
Environmental provisions		(11	)		(3	)		(12	)
Cost associated with work force reduction programs		-			-			(3	)
Other		-			-			(1	)
Items affecting comparability	$	(12	)	$	(135	)	$	(84	)

Chemical - Pigment - Revenues increased $58 million, or 5%, in 2005 to $1.267 billion from $1.209 billion in 2004. The increase in revenues resulted from an increase in average sales prices of approximately 12%, contributing $136 million. This increase was partially offset by lower sales volumes decreasing revenues by $78 million. Sales volumes for 2005 were approximately 6% lower than in the prior year due primarily to the tonnes sold from the Savannah sulfate production facility that was shut down during 2004 and due to reduced volumes in the Asia/Pacific region resulting from increased volumes in the latter part of 2004 in advance of announced price increases and an unplanned temporary two week shutdown of Tronox’s Australian pigment plant in the fourth quarter of 2005 necessitated by a shutdown of a third-party process gas supplier. Approximately $4 million of the increase in average sales prices in 2005 was due to the effect of foreign currency exchange rates and the remainder due to price increases resulting from improved market conditions.

Revenues increased $130 million, or 12%, in 2004 to $1.209 billion from $1.079 billion in 2003. Of the total increase, $114 million was due to increased sales volumes and $16 million resulted from an increase in average sales prices. Sales volumes for 2004 were approximately 9% higher than in the prior year due primarily to strong market conditions. Approximately half of the increase in average sales prices in 2004 was due to the effect of foreign currency exchange rates and the remainder due to price increases resulting from improved market conditions.

The chemical - pigment operating unit had an operating profit of $100 million in 2005, compared with an operating loss of $80 million in 2004. The improvement in operating results in 2005 was primarily attributable to the shutdown provisions incurred in 2004 of $123 million related to the Savannah facility and $7 million related to the Mobile facility, combined with higher average sales prices in 2005. The $58 million increase in revenues in 2005 was partially offset by an increase in selling, general and administrative expenses of $11 million over 2004. Selling, general and administrative expenses were higher in 2005 compared to 2004, primarily due to an increase in employee incentive compensation (including stock-based compensation), largely as a result of improved operating performance for the year. Decreased sales volumes in 2005 resulted in $55 million lower manufacturing costs, which were partially offset by higher average product costs of $56 million due to higher raw material and energy costs.

The chemical - pigment operating unit recorded an operating loss of $80 million in 2004, compared with an operating loss of $13 million in 2003. The 2004 operating loss was primarily the result of shutdown provisions totaling $105 million (including an $8 million charge for asset impairment) for the sulfate-process titanium dioxide pigment production at the Savannah, Georgia, facility and additional charges at that facility of $18 million for accelerated depreciation of other plant assets that are no longer in service. In addition, operating results for 2004 were negatively impacted by $7 million of costs incurred in connection with the continued efforts to close the synthetic rutile plant in Mobile, Alabama, compared to a $47 million plant closure provision recognized in 2003 for this facility. Additionally, operating results in 2003 were negatively impacted by a $23 million charge for work force reduction and other compensation costs. These charges had the effect of reducing operating profit by $130 million in 2004 and $70 million in 2003. The $130 million increase in revenues in 2004 resulting from higher volume and sales prices was offset by an increase of $125 million in production costs due to higher volume ($73 million) and costs ($52 million including the effects of foreign currency exchange rate changes) and an increase in shipping and handling costs and selling, general and administrative expenses of $13 million over 2003. Additional information related to the shutdowns of the Savannah and Mobile facilities is included in Note 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Chemical - Other - Operating loss for 2005 was $6 million on revenues of $97 million, compared with operating loss of $2 million on revenues of $93 million in 2004. The increase in revenues of $4 million was due primarily to increased sales of electrolytic manganese dioxide and lithium manganese oxide. Operating performance declined primarily due to higher environmental costs of $8 million resulting from a net $11 million environmental provision (net of expected insurance reimbursement of $21 million) incurred in the first quarter of 2005, related primarily to ammonium perchlorate remediation associated with Tronox’s Henderson, Nevada, operations. In addition, selling, general and administrative expenses were higher primarily due to an increase in employee incentive compensation related to cash bonuses and non-cash stock-based awards resulting from improved operating performance for the year. These higher costs were partially offset by improved operations in 2005 at Tronox’s Henderson, Nevada, electrolytic manganese dioxide (EMD) manufacturing facility which incurred higher costs in 2004 when production recommenced after being temporarily curtailed in late 2003.

Operating loss for 2004 was $2 million on revenues of $93 million, compared with operating loss of $23 million on revenues of $78 million in 2003. The increase in revenues of $15 million was primarily due to an increase in electrolytic sales due primarily to the full year of operations at the company's EMD manufacturing operation in Henderson, Nevada (see further discussion below). Improved operating performance was primarily due to the full year of operations at the EMD facility, lower environmental costs in 2004 of $9 million compared to 2003, and the work force reduction and other compensation charges recognized in 2003 that did not reoccur in 2004.

During the third quarter of 2003, Tronox LLC placed its EMD manufacturing operation in Henderson, Nevada, on standby to reduce inventory levels because of the harmful effect of low-priced imports on the company's EMD business. In response to the pricing activities of importing companies, Tronox LLC filed a petition for the imposition of anti-dumping duties with the U.S. Department of Commerce International Trade Administration and the U.S. International Trade Commission on July 31, 2003. In its petition, the company alleged that manufacturers in certain countries export EMD to the United States in violation of the U.S. anti-dumping laws and requested that the U.S. Department of Commerce apply anti-dumping duties to the EMD imported from such countries. The Department of Commerce found probable cause to believe that manufacturers in the specified countries engaged in dumping and initiated an anti-dumping investigation with respect to such manufacturers. Partly as a result of the anti-dumping petition, demand for U.S. EMD product increased, and the plant resumed operations in December 2003. The company withdrew its anti-dumping petition in February 2004, but continues to monitor market conditions.

Financial Condition and Liquidity

The following table provides certain information useful in the analysis of the company’s financial condition and liquidity at December 31, 2005, 2004 and 2003 and on a pro forma basis assuming certain 2006 transactions were completed on December 31, 2005. Pro forma information reflects (i) the February 2006 redemption of $250 million principal amount of 7% debentures due 2011 and the associated after-tax loss on redemption of $45 million, representing a write-off of unamortized discount; and (ii) the Distribution of Kerr-McGee’s remaining 56.7% ownership interest in Tronox, resulting, on a pro forma basis, in elimination of Tronox’s assets and liabilities and the associated minority interest from Kerr-McGee’s consolidated accounts, with a corresponding reduction in stockholders’ equity of approximately $300 million. These transactions are more fully discussed below.

(Millions of dollars)	2005 Pro forma			2005			2004			2003

Current ratio ⁽¹⁾		0.6 to 1			0.8 to 1			0.8 to 1			0.8 to 1
Cash and cash equivalents	$	734		$	1,053		$	76		$	142
Debt repayment obligations due within one year		306			308			463			574
Unused capacity under revolving lines of credit ⁽²⁾		1,184			1,400			1,550			1,360
Total debt		2,403			3,133			3,699			3,655
Stockholders’ equity and minority interest	$	3,770		$	4,327		$	5,318		$	2,636
Debt to total capitalization ⁽³⁾		39	%		42	%		41	%		58	%
Variable-rate debt to total debt (4)		19	%		20	%		25	%		14	%

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

⁽²⁾	Reflects utilization to support outstanding letters of credit. No revolving borrowings were outstanding at December 31, 2005.

⁽³⁾	Capitalization is determined as total debt plus total stockholders’ equity and minority stockholders’ interest in net assets of Tronox.

⁽⁴⁾	Fixed-rate debt with interest rate swaps to variable rate is treated as floating rate debt.

Overview

Kerr-McGee operates with the philosophy that over a five-year period our capital expenditures and dividends should be funded by cash generated from operations. On a cumulative basis, the cash generated from operations for the past five years has exceeded the company’s capital expenditures (excluding cash spent for acquisitions) and dividend payments. Debt and equity transactions are utilized for acquisition opportunities and short-term needs due to timing of cash flow. Additionally, as part of the strategic realignment of our business in 2005, discussed above under -Executive Overview, we realized significant cash flows from asset divestitures, which were used for debt repayment, share repurchases and other corporate purposes.

Sources and Uses of Cash - We expect that our main uses of cash in 2006 will consist of capital and operating expenditures, debt repayments, interest and income taxes, share repurchases and dividend payments. Our 2006 exploration and production capital spending budget is $1.3 billion. In addition, we budgeted $300 million for exploration expense, which includes estimated noncash amortization of undeveloped leases of $70 million. We also plan to spend $1 billion on share repurchases pursuant to the program authorized by our Board of Directors (the Board) in January 2006, and approximately $22 million on dividend payments (based on shares outstanding at December 31, 2005, reduced by the anticipated effect of the share repurchase program). Our expected 2006 debt repayments total approximately $560 million, which includes the scheduled maturities of our debt and the February 2006 redemption of the $250 million 7% debentures due 2011. Additionally, in March 2006 the company expects to pay approximately $350 million of income taxes associated with the fourth quarter 2005-divestiture transactions. In the second half of 2006, we expect to pay income taxes of approximately $350 million associated with the pending sale of our Gulf of Mexico shelf assets, yielding net after-tax cash flows of approximately $925 million, less reduction for post-effective date cash flows generated from these properties. As a result of completed and pending divestiture transactions, our 2006 oil and natural gas production is expected to be approximately 25% to 30% lower than in 2005 (including production from our discontinued North Sea business), although we expect that operating cash inflows will be sufficient to fund our cash requirements for operating and capital expenditures.

As discussed under -Executive Overview above, during 2005, we added almost 160 MMboe of proved reserves from our exploration and development programs and sold 295 MMboe of proved reserves. The divestitures were consistent with Kerr-McGee’s strategic plan to high grade its oil and gas portfolio by divesting of lower-growth, shorter-life or higher-decline properties. Exploration and development related reserve additions were balanced across the company’s operations, with approximately 40% of newly-added reserves from the U.S. Gulf of Mexico, 48% from U.S. onshore and 12% from areas outside the U.S.

As a result of the divestitures executed in 2005, Kerr-McGee’s proved reserve base has shifted to longer-lived natural gas reserves. Economic runs used to generate the company’s 2005 standardized measure of future discounted net cash flows indicate that approximately 72% of the company proved reserves will be produced over a ten-year time horizon, compared to 76% from the 2004 measure. Future cash flows from our upstream asset portfolio follow a time horizon which is logically similar to the production of our proved reserves, with 77% of future net cash flows realized over a ten-year time horizon, compared to 79% from the 2004 standardized measure of future discounted net cash flows. Changes in the standardized measure of future net cash flows as a result of reserve additions and dispositions during 2005 are presented in Note 25 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. As noted therein, as a result of reserves added via extensions, discoveries and revisions in 2005, the company’s future net cash flows increased by approximately $2.9 billion, while sales of reserves in place reduced future net cash flows by $4 billion.

Outlook - To meet our short- and long-term liquidity requirements, we expect to fund capital expenditures, debt payments, share repurchase programs and working-capital needs through a combination of cash on hand, cash generated from operating activities, proceeds from sale 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 estimated proceeds from the sale of our Gulf of Mexico shelf oil and gas properties, which is expected to close in the second quarter of 2006, pending certain regulatory approvals. We plan to use the net cash proceeds from this sale for debt reduction and other corporate purposes, including share repurchases.

Over the long term, the company’s primary source of funds has been from operating cash flows, which could be adversely affected by declines in oil and natural gas prices, which can be volatile, as discussed under -Operating Environment and Outlook. Our hedging program is intended to partially mitigate variability in operating cash flows caused by fluctuations in oil and natural gas prices. At December 31, 2005, commodity derivatives covered approximately 75% and 80%, respectively, of our expected 2006 U.S. oil and gas production (in each case excluding volumes from our Gulf of Mexico shelf properties) and approximately 50% of our expected 2007 U.S. production. The portion of our projected production subject to commodity derivative instruments is determined by management and may change in future periods in response to market conditions, level of leverage and our operational needs. Additional information regarding our commodity derivative instruments is provided below under -Market Risks - Commodity Price Risk. If operating cash flows decline, the company may reduce its capital expenditure program, draw upon its revolving credit facility and/or consider selective long-term borrowings or equity issuances. As presented in the table above, pro forma for the Tronox separation and debt redemption that occurred in February 2006, Kerr-McGee would have had cash on hand of $734 million at year-end 2005 and unused capacity under its revolving line of credit of $1.2 billion. Additionally, the company has available, to issue and sell, a total of $1 billion of debt securities, common or preferred stock, or warrants under its shelf registration with the Securities and Exchange Commission, which was last updated in February 2002.

Working Capital Position - The company had negative working capital of $682 million at December 31, 2005; however, this is not indicative of a lack of liquidity, as the company maintains sufficient current assets to settle current liabilities when due. Our working capital position is significantly affected by current liabilities associated with our financial derivatives. At December 31, 2005, the company had recorded approximately $1.4 billion of net current derivative liabilities for contracts that will effectively adjust the cash flows to be realized upon the sale of our future oil and gas production. Because those sales have not yet occurred, the associated accounts receivable are not yet reflected in our Consolidated Balance Sheet, while derivative assets and liabilities are reflected in the 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.

Credit Ratings - In rating the company’s debt, rating agencies consider our financial and operating risk profile by analyzing our debt levels, growth profile, cost structure, oil and gas reserve replacement ratios, capital expenditure requirements, contingencies, dividend policy and any other factors they deem relevant that could potentially impact our ability to service debt. In response to the company’s April 2005 announcement of our intention to commence the tender offer and increase leverage in the near term (which is discussed below), our credit ratings were downgraded. 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		December 31, 2005
Standard & Poor’s		BBB-		BB+
Moody’s Investors Service		Baa3		Ba3

As a result of the downgrades, the company’s borrowing costs increased. Further, as discussed under Off-Balance Sheet Arrangements below, the ratings downgrades in April 2005 triggered a program termination event for the accounts receivable monetization program.

Credit Facilities and Debt Covenants - In January 2006, Kerr-McGee closed on a $1.25 billion unsecured revolving credit agreement. The facility is available to provide support for commercial paper and for general corporate purposes. Interest on amounts borrowed under the credit agreement is payable, at the company’s election, at an alternate base rate (ABR) or a Eurodollar rate, in each case as defined in the credit agreement. The initial margin applicable to Eurodollar borrowings is 125 basis points and may vary from 50 to 150 basis points depending on Kerr-McGee’s credit rating.

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

·	Consolidated Leverage Ratio of no more than 3.5:1

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

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

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

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

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

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

·	Consolidated Interest Coverage Ratio of at least 2:1

·	Limitation on Capital Expenditures

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

Cash Flows

The following provides selected cash flow information for the years ended December 31, 2005, 2004 and 2003. Unless indicated otherwise, discussion of cash flows reflects the company’s continuing and discontinued operations. Cash flows associated with discontinued operations are related primarily to the company’s North Sea oil and gas business, which was sold in 2005.

(Millions of dollars)	2005			2004			2003

Net cash provided by operating activities	$	3,103		$	2,050		$	1,518
Net cash provided by (used in) investing activities		2,081			(1,262	)		(951	)
Net cash used in financing activities		(4,210	)		(851	)		(520	)

Operating Activities - The $1.1 billion increase in cash flows from operating activities in 2005 over 2004 is primarily attributable to higher average realized oil and gas sales prices, with higher oil and gas sales volumes also contributing to the increase. Average realized sales prices on a barrel of oil equivalent basis (including the effect of our hedging program) increased by 41%, from $29.49 in 2004 to $41.50 in 2005, resulting in an increase in oil and natural gas sales revenues of approximately $1.5 billion. Additionally, 2005 cash flows from operating activities were favorably affected by $28 million lower expenditures for environmental remediation, an increase of $22 million in environmental cost reimbursements and $34 million lower contributions to the company’s pension and postretirement benefit plans (primarily due to $26 million of discretionary contributions made to the U.K. pension plan in 2004). These increases in operating cash flows were partially offset by higher cash outflows for income taxes ($316 million) and interest ($98 million), as well as higher operating expenditures. Higher operating expenditures reflect primarily higher oil and gas production volumes and rising costs of services and equipment within the oil and gas industry. Additionally, in 2005 the company spent approximately $30 million on advisory, consulting and legal services and employee compensation associated with its strategic realignment. This includes payments made to employees under retention programs initiated in April 2005, in anticipation of asset divestitures and the separation of the chemical business.

We expect completed and pending divestitures to result in lower cash flows from operating activities in future periods, although our cash outflows for capital expenditures and dividend payments also are expected to decline. Our North Sea oil and gas business sold in 2005 and our Gulf of Mexico shelf properties which we expect to sell in the second quarter of 2006 contributed approximately $1.2 billion to 2005 cash flows from operating activities, while the contribution of Tronox operations approximated $200 million (in each case before considering income taxes).

Cash flows from operating activities in 2004 increased by $532 million over 2003. Our merger with Westport in June 2004 contributed to a 15% increase in oil and gas production on a barrel of oil equivalent basis over 2003. Average prices realized upon the sale of oil and gas, including hedging activities, increased by 13%. The combined effect of these factors contributed significantly to the 2004 increase in cash flows from operating activities. Additionally, in 2004, our environmental cash expenditures, net of reimbursements received, were lower compared to the prior year. These positive effects on cash flows from operating activities were partially offset by higher contributions made to postretirement and pension plans and higher expenditures for operating costs primarily due to the Westport merger.

Investing Activities and 2006 Capital Spending Budget - As discussed under -Executive Overview above, our strategic plan includes divestitures of lower-growth or shorter-life and higher-decline oil and gas properties. Execution of this component of our strategy in 2005 yielded net proceeds of $4 billion, which, along with the net proceeds from the separation of the chemical business, were used to repay debt, including $4.25 billion borrowed in May 2005 primarily to fund the $4 billion tender offer for Kerr-McGee’s common stock, as discussed under -Financing Activities below. Significant sources (uses) of cash associated with investing activities were as follows for the last three years:

(Millions of dollars)	2005			2004			2003

Capital expenditures -
Continuing exploration and production operations ⁽¹⁾	$	(1,589	)	$	(1,096	)	$	(949	)
Discontinued North Sea oil and gas business ⁽¹⁾		(228	)		(134	)		(101	)
Tronox operations		(88	)		(92	)		(97	)
Corporate and other		(15	)		(18	)		(15	)
Total capital expenditures ⁽¹⁾		(1,920	)		(1,340	)		(1,162	)
Acquisitions, net of cash acquired		-			43			(110	)
Net proceeds from sale of North Sea oil and gas business		3,305			-			-
Proceeds from dispositions of other assets		704			23			304
Other investing activities		(8	)		12			17
Total net cash provided by (used in) investing activities	$	2,081		$	(1,262	)	$	(951	)

⁽¹⁾	Includes dry hole costs.

Capital Expenditures - Capital expenditures in 2005 increased from the prior year, primarily as a result of approximately $320 million higher capital spending associated with Westport properties focused largely on development activities in the Greater Natural Buttes area and Northern areas of the Rocky Mountains. Capital spending in the Gulf of Mexico also increased by approximately $190 million in 2005, due primarily to facility expenditures at Blind Faith, development drilling activities at our discoveries in the Atwater Valley area and higher development expenditures for Constitution/Ticonderoga, partially offset by lower development drilling costs at Red Hawk and lower leasehold acquisition costs. Additional exploratory appraisal drilling in Alaska also contributed to the increase in 2005 capital expenditures. Information about the status of our exploration and development activities is provided under Items 1 and 2 of this Annual Report on Form 10-K, Business and Properties - Exploration and Production Operations - Exploration and Production Activities.

Exploration and production capital spending in 2004 was higher than in the prior year primarily due to the additional exploitation and development activities following the Westport merger in late June 2004 and higher development and exploratory drilling expenditures in China, partially offset by lower dry hole costs.

The following table presents our 2006 capital budget for exploration and development activities by region:

(Millions of dollars)	Est. 2006		Percent of Total

Budgeted capital expenditures by region -
Rocky Mountains	$	580		44	%
Southern		170		13
Deepwater Gulf of Mexico		400		30
International / New venture areas		150		11
Other		20		2
Total budgeted capital expenditures	$	1,320		100	%

In addition, we have budgeted $300 million for exploration expenses, which includes estimated noncash amoritization of undeveloped leases of $70 million. The company’s 2006 capital program reflects our redefined strategy in terms of capital allocation towards accelerating development opportunities and focused exploration primarily in the deepwater Gulf of Mexico and other proven hydrocarbon basins.

The 2006 capital program provides for increased funding for exploitation-type development activity in the U.S. onshore area, with $750 million in planned capital spending, more than half of the total capital budget. Capital investment in the Rocky Mountain region is heavily weighted toward accelerated development of the Natural Buttes and Wattenberg fields, where we plan to drill over 540 exploitation wells. In our Southern region, we plan to drill approximately 100 development wells in the south Texas, Mid-Continent and Gulf Coast areas, focused on development drilling in the Frost field in south Texas and along the Texas/Louisiana Gulf Coast, and infill drilling in the Mocane-Laverne field.

A significant portion of the $400 million in capital budgeted for the Gulf of Mexico will be invested in our major projects, such as the Blind Faith development ($135 million) and completion of the Constitution/ Ticonderoga development ($50 million), where first production was achieved in the first quarter of 2006. Other deepwater Gulf of Mexico investments will focus on the Atwater Valley area ($80 million), with the development of our discoveries at Merganser, Vortex and San Jacinto.

We plan to spend approximately $150 million in capital in our international and new venture locations, focused primarily in Brazil, Alaska and China. We also have budgeted $150 million for exploration dry hole expenditures in 2006. Exploration drilling activity will be focused primarily in the Gulf of Mexico, Brazil and China.

The company has the right to explore undeveloped acreage in certain foreign countries, including Angola, Australia, China, Benin, Bahamas, Brazil, Denmark, Morocco and Trinidad and Tobago, under contractual arrangements that typically require the company to execute an agreed-upon work program. We plan to invest approximately $180 million in capital and exploration expenditures in these international areas in 2006, and do not believe that future commitments under these contractual arrangements will have a material impact on our liquidity. Overall, the vast majority of our operations are based in the U.S., benefiting from a stable operating and political environment. Based on our current plans, we do not contemplate a significant near-term change in the overall geographic distribution of our operations or our risk profile. Recent exploration success could result in an expansion of our oil production operations to Brazil, should the discovery in this country be sanctioned for development by the Board. Further exploration success in Brazil or other international areas, followed by development and production activities, could expose the company to additional risks, including the ability to secure equipment and hire experienced labor, working with foreign contractors and governments, less stable operating environments and certain political risks. Additional information related to risks associated with operating in foreign countries is provided in Item 1a of this Annual Report on Form 10-K. In addition, specific work commitments associated with international exploration locations, if significant, are discussed under Items 1 and 2, Business and Properties - Exploration and Production Operations - Exploration and Production Activities.

Proceeds from Dispositions of Assets - In 2005, we sold our North Sea oil and gas business in several transactions, realizing aggregate cash proceeds of $3.5 billion. The net proceeds of $3.3 billion reflect $171 million of cash on hand acquired by the purchasers at closing and $45 million of transaction costs.

As part of the 2005 divestiture program, we sold certain noncore oil and gas properties onshore in the United States to various purchasers in several unrelated transactions, realizing aggregate proceeds (net of transaction costs) of $497 million. In November 2005, we sold our nonoperating interest in the Javelina gas processing facility for $156 million. Additionally, proceeds from disposition of assets include $51 million received in connection with two exchange transactions, where Kerr-McGee exchanged its interests in certain noncore oil and gas properties for an interest in the Blind Faith discovery in the deepwater Gulf of Mexico and overriding royalty interest in the Greater Natural Buttes area. These transactions are discussed in more detail above, under -Results of Operations by Segment - Exploration and Production - Asset Impairments and Gain (Loss) on Sale of Assets. In 2003, we divested certain oil and gas properties and other assets, generating proceeds of $304 million. These proceeds were used primarily to pay down debt.

Acquisitions - In June 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. In 2003, we invested $110 million in selected oil and gas property acquisitions for an additional interest in the U.K. Gryphon and South Gryphon fields and an onshore property acquisition in South Texas.

Financing Activities - The following provides a summary of significant components of cash used in financing activities in 2005, 2004 and 2003, as well as selected information about financing activities that did not require the use of cash:

(Millions of dollars)	2005			2004			2003

Proceeds from Kerr-McGee term loan borrowings	$	4,250		$	686		$	31
Proceeds from Tronox borrowings		550			-			-
Cash received upon exercises of employee stock options		225			55			-
Sale of Tronox stock		225			-			-
Repayment of term loan borrowings		(4,250	)		-			-
Repayment of other Kerr-McGee debt		(501	)		(1,278	)		(369	)
Repurchases of common stock under the tender offer		(3,975	)		-			-
Purchases of treasury stock		(250	)		-			-
Payment of dividends		(153	)		(205	)		(181	)
Settlement of Westport derivatives		(238	)		(101	)		-
Debt issuance costs and other		(93	)		(8	)		(1	)
Total cash used in financing activities	$	(4,210	)	$	(851	)	$	(520	)
Noncash financing activities -
48.9 million shares of common stock and 1.9 million stock
options issued in connection with the Westport merger	$	-		$	2,448		$	-
Increase (decrease) in debt associated with -
Conversion of 5.25% debentures to common stock		(600	)		-			-
Debt assumed in the Westport merger		-			1,046			-
Debt redemption with Devon stock		-			(330	)		-

Repurchases of Common Stock - In March 2005, the Board authorized a share repurchase program initially set at $1 billion, with an expectation to expand the program as the chemical business separation proceeded. 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. On April 18, 2005, the company commenced a 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. We exercised our 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 discussed below and cash on hand. In January 2006, the Board authorized an additional $1 billion share repurchase program. As of March 14, 2006, approximately 3.3 million shares had been repurchased under this program in the open market, for a total cost of $347 million.

Tronox IPO - As discussed under -Separation of Tronox above, during November 2005, the company completed the IPO of 17.5 million shares of Tronox Class A common stock. In connection with the IPO, Tronox originated borrowings with an aggregate principal amount of $550 million and paid debt issuance costs of $11 million. Tronox distributed to Kerr-McGee the net proceeds from the IPO of $225 million, the net proceeds from the borrowings of approximately $535 million and cash on hand in excess of $40 million.

In September 2005, Kerr-McGee received consent from a majority of the holders of Kerr-McGee’s registered notes to release Tronox Worldwide LLC from the guarantee of the notes upon an IPO by Tronox Worldwide LLC, or upon a spinoff or splitoff of Tronox Worldwide LLC, or its parent, Tronox Incorporated. In connection with the consent solicitation and the subsequent amendment of the indenture governing the notes, Kerr-McGee paid aggregate consent and release fees to noteholders of $18 million and third-party transaction costs of $4 million.

Debt Activity - In connection with the tender offer discussed above, Kerr-McGee entered into a credit agreement consisting of a $2 billion two-year term loan, a $2.25 billion six-year term loan and a $1.25 billion five-year revolving credit facility. The term loans were fully funded at closing, with proceeds used primarily to finance the tender offer and to pay fees and expenses associated with the credit agreement ($58 million). Under the credit agreement, the company was subject to mandatory prepayment provisions, including required prepayments with 100% of the net cash proceeds, as defined, from asset disposals. Pursuant to this mandatory prepayment provision, we repaid $4 billion of term loan borrowings with the net after-tax proceeds from the sale of our North Sea oil and gas business, our interest in the Javelina gas processing facility, and the funds distributed to us by Tronox in connection with the IPO, as discussed above. We also made optional prepayments and scheduled principal payments totaling $250 million. By the end of 2005, all borrowings under the credit agreement were repaid and the agreement was terminated on January 9, 2006. In addition to term loan repayments, we paid $501 million upon scheduled maturities of other debt.

In 2004, we repaid $1.3 billion of debt, including debt assumed in the Westport merger. The $245 million balance outstanding under the Westport revolving credit facility at the date of the merger was repaid upon completion of the merger and the facility was terminated on July 13, 2004. We also redeemed the 8.25% Westport notes assumed in the merger for $786 million (including a make-whole premium of $100 million) and paid $247 million for scheduled repayments and maturities of our debt. On July 1, 2004, we issued 6.95% notes due 2024 for net proceeds of $636 million. Proceeds from the notes issuance were used to redeem the 8.25% Westport notes discussed above. In August 2004, Kerr-McGee redeemed its debt exchangeable for common stock (DECS) upon maturity by distributing 8.4 million shares of Devon Energy Corporation stock.

Employee Stock Options - As a result of the increased market price of our common stock in 2005, employee stock option exercises increased substantially compared to the prior year. At December 31, 2005, approximately 4.8 million options were outstanding, of which 2.1 million were exercisable with a weighted average exercise price of $54.59 per share.

Dividends - Through the first quarter of 2005, we paid a quarterly dividend at a rate of $.45 per share, or $1.80 annually. In May 2005, the Board revised the company’s dividend policy to a level more consistent with that of other pure-play exploration and production companies. Starting with the July 2005 dividend payment, the quarterly dividend was reduced to $.05 per share (or $.20 annually).

Settlement of Westport derivatives - In 2005 and 2004, we paid $238 million and $101 million, respectively, to settle certain derivative instruments assumed in the Westport merger in June 2004. Such settlements are considered to be a part of financing activities because the associated derivative instruments included an other-than-insignificant financing element at the acquisition date. These instruments extend through 2006 and had a net liability fair value at December 31, 2005 of $70 million, including $11 million payable for December settlements. Future settlement values may be higher or lower than the estimated fair value of unsettled contracts at December 31, 2005, and will be determined based on reference commodity prices in effect in the period of settlement.

Off-Balance Sheet Arrangements

During 2001 and 2000, the company identified certain financing needs that it determined would be best handled by off-balance sheet arrangements with unconsolidated, special-purpose entities. Three leasing arrangements were entered into for financing the company’s working interest obligations for production platforms and related equipment at three company-operated fields in the Gulf of Mexico. The leases have provided a tax-efficient method of financing a portion of these major development projects. Also, in 2000, the company entered into an accounts receivable monetization program to sell its receivables from certain pigment customers. While in effect, the program provided an attractive low-cost source of liquidity. As discussed below, the program was terminated in 2005.

Environmental Reimbursement Obligation - Reference is made to discussion included under -Separation of Tronox.

Spar Platform Leases - During 2001, the company entered into a leasing arrangement for its interest in the production platform and related equipment for the Gunnison field in the Garden Banks area of the Gulf of Mexico. This leasing arrangement is similar to two arrangements entered into in 2000 for the Nansen and Boomvang fields in the East Breaks area of the Gulf of Mexico. In each of these three arrangements, we entered into lease commitments with separate business trusts that were created to construct independent spar production platforms for each field development. Under the terms of the agreements, our share of construction costs for the platforms was initially financed by synthetic lease credit facilities between the trust and groups of financial institutions for $149 million, $137 million and $78 million for Gunnison, Nansen and Boomvang, respectively, with the company making lease payments sufficient to pay interest at varying rates on the financings. Upon completion of the construction phase, separate business trusts with third-party equity participants acquired the assets and became the lessor/owner of the platforms and related equipment. The company and these trusts have entered into operating leases for the use of the spar platforms and related equipment. Under this type of financing structure, the company leases the platforms under operating lease agreements, and neither the platform assets nor the related debt is recognized in the company’s Consolidated Balance Sheet.

In conjunction with the operating lease agreements, the company has guaranteed that the residual values of the Nansen, Boomvang and Gunnison platforms at the end of the operating leases shall be equal to at least 10% of their fair market value at the inception of the lease. For Nansen and Boomvang, the guaranteed values are $14 million and $8 million, respectively, in 2022, and for Gunnison, the guaranteed value is $15 million in 2024. Estimated future minimum annual rentals under these leases and the residual value guarantees are shown in the table of contractual obligations below.

Accounts Receivable Monetization Program - Through April 2005, we had an accounts receivable monetization program with a maximum availability of $165 million. Under the terms of the program, selected qualifying customer accounts receivable arising from sales of titanium dioxide pigment by Tronox were sold to a special-purpose entity (SPE), which in turn sold an undivided ownership interest in the receivables to a third-party multiseller commercial paper conduit sponsored by an independent financial institution. Tronox sold, and retained an interest in, excess receivables to the SPE as over-collateralization for the program. The retained interest in sold receivables was subordinate to, and provided credit enhancement for, the conduit’s ownership interest in the SPE’s receivables, and was available to the conduit to pay certain fees or expenses due to the conduit, and to absorb credit losses incurred on any of the SPE’s receivables in the event of program termination. 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 multiseller 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 under -Financial Condition and Liquidity above, Kerr-McGee’s senior unsecured debt was downgraded, triggering program termination. As opposed to liquidating the program over time in accordance with its terms, we entered into an agreement to terminate the program by repurchasing the then outstanding balance of receivables sold of $165 million. Repurchased accounts receivable were collected by us later in 2005.

Sale-Leaseback Transactions - During 2003 and 2002, the company entered into sale-leaseback arrangements with General Electric Capital Corporation (GECC) covering assets associated with a gas-gathering system in the Wattenberg field. The 2002 operating lease agreements have an initial term of five years, with two 12-month renewal options, and we may elect to purchase the equipment at specified amounts after the end of the fourth year. The 2003 operating lease agreement has an initial term of four years, with two 12-month renewal options. In the event we do not purchase the equipment and it is returned to GECC, we may be required to make payments in connection with residual value guarantees ranging from $35 million at the end of the initial terms to $27 million at the end of the last renewal option. Estimated future minimum annual rentals under this agreement and the residual value guarantee are shown in the table of contractual obligations below.

Other - In addition, the company has entered into certain indemnification agreements related to title claims, environmental matters, litigation and other claims. The company has recorded no material obligations in connection with its indemnification agreements. At December 31, 2005, outstanding letters of credit totaled $114 million (including $34 million issued by Tronox). Most of these letters of credit have been granted by financial institutions to support international drilling commitments, environmental remediation activities and insurance agreements. As of February 28, 2006, outstanding letters of credit totaled $144 million, which includes $40 million associated with Tronox.

Obligations and Commitments

In the normal course of business, the company enters into purchase obligations, contracts, leases and borrowing arrangements. The company has no debt guarantees for third parties. 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 generally are 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. Commitments and obligations of Kerr-McGee and Tronox as of December 31, 2005, are summarized in the following table:

(Millions of dollars)	Payments due by period
					2007		2009		After
Type of Obligation	Total		2006		-2008		-2010		2010

Obligation and commitments of Kerr-McGee -
Long-term debt, including current portion^{(1) (2)}	$	2,682	$	307	$	150	$	-	$	2,225
Operating leases for Nansen, Boomvang
and Gunnison		559		28		54		54		423
Other operating leases		200		49		63		32		56
Drilling rig commitments		749		226		428		52		43
Gas purchase and transportation contracts		269		120		49		37		63
Other purchase obligations		213		113		100		-		-
Leased equipment residual value guarantees		72		-		35		-		37
Subtotal		4,744		843		879		175		2,847

Obligation and commitments of Tronox -
Long-term debt, including current portion⁽²⁾		550		2		4		4		540
Operating leases		48		8		14		10		16
Ore contracts		642		162		303		137		40
Other purchase obligations		360		86		140		96		38
Subtotal		1,600		258		461		247		634

Total	$	6,344	$	1,101	$	1,340	$	422	$	3,481

⁽¹⁾	Principal amounts represent future payments and exclude the unamortized discount on issuance of $94 million and the net fair value hedge adjustments of $5 million. Amounts due after 2010 include $250 million principal amount of 7% debentures due 2011, which we redeemed in February 2006.

⁽²⁾	Excludes future interest payments

Market Risks

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 Notes 1 and 9 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K for discussions of the company’s derivatives and hedging activities.

Commodity Price Risk

Our oil and natural gas production is generally sold at prevailing market prices, thus exposing us to the risk of variability of our revenues and operating cash flows. To reduce the impact of these risks on earnings and to increase the predictability of its cash flows, the company enters into certain derivative instruments that generally fix the commodity prices to be received for a portion of its future oil and gas production. The company utilizes derivative instruments as a means of balancing cash flow requirements for debt repayment and its capital programs. At year-end 2004, commodity derivatives covered approximately 50% of our then-projected 2005 oil and gas production. In April 2005, in connection with the company’s decision to initiate the $4 billion tender offer and increase leverage, as discussed above under -Financial Condition and Liquidity - Cash Flows - Repurchases of Common Stock, we expanded our hedging program. At December 31, 2005, costless collars and fixed-priced swaps covered approximately 75% and 80%, respectively, of our expected 2006 U.S. oil and gas production (in each case after the expected divestiture of our Gulf of Mexico shelf properties) and approximately 50% of our expected 2007 U.S. production. A higher hedge ratio provides for greater predictability of cash flows and supports capital expenditure plans, but limits the extent to which we can benefit from increases in market prices for oil and natural gas. A risk management committee consisting of senior executives, including the CEO, develops Kerr-McGee’s hedging strategy. In setting hedge targets, the committee evaluates various factors, including debt management targets, liquidity, exploration and development opportunities, cash flow modeling under various price scenarios and the overall growth strategy for the company.

At December 31, 2005, outstanding commodity-related derivatives had a net liability fair value of $2 billion. The fair value of these derivative instruments was determined based on prices actively quoted, generally NYMEX 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 production is sold. Net after-tax losses on oil and gas derivatives in accumulated other comprehensive loss were $1.1 billion at December 31, 2005, and related to a portion of the company’s expected production through 2007. During the next 12 months, we expect to reclassify net after-tax losses of $617 million from accumulated other comprehensive loss into earnings, assuming no further changes in the fair value of the related contracts. Net realized oil and gas hedging losses associated with continuing operations totaled $655 million, $533 million and $215 million in 2005, 2004 and 2003, respectively. The losses offset the higher oil and natural gas prices realized on the physical sale of crude oil and natural gas. Reference is made to the section -Results of Operations by Segment - Exploration and Production, which provides average realized oil and gas sales prices excluding and including the effect of our hedging program, as well as additional information on the effect of derivative instruments on our consolidated financial statements and our election to discontinue hedge accounting effective March 1, 2006.

At December 31, 2005, the following commodity-related derivatives were outstanding.

	2006					2007
	Average Contract Price ($/Barrel)		Average Daily Volume (Barrels)			Average Contract Price ($/Barrel)		Average Daily Volume (Barrels)
Crude Oil (WTI) -
Hedge:
Fixed price swaps	$	53.14		18,781		$	51.44		27,250

Costless collars	$	27.00 - $30.58		19,000	^(a)		-		-
	$	45.00 - $65.60		18,288		$	45.00 - $61.42		18,000

Nonhedge:
Three-way collars⁽¹⁾	$	25.00 - $28.65		2,000	^(b)		-		-
Three-way average floor	$	20.88
				58,069					45,250

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

^(b)	Acquired in 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 $4.12/barrel of price protection if the WTI price falls below $20.88/barrel in the case of its 2005 crude oil three-way collars ($25.00 - $20.88).

	2006					2007
	Average Contract Price ($/MMBtu)		Average Daily Volume (MMBtu)			Average Contract Price ($/MMBtu)		Average Daily Volume (MMBtu)
Natural Gas (NYMEX) -
Hedge:
Fixed price swaps	$	7.57		110,000		$	7.03		20,000

Costless collars	$	4.75 - $ 5.50		240,000	^(a)		-		-
	$	6.00 - $10.78		120,000		$	6.00 - $8.98		155,000

Nonhedge:
Fixed price swaps	$	7.50		86,000		$	7.03		245,000

Costless collars	$	4.75 - $ 5.50		100,000	^(a)		-		-
	$	6.00 - $10.83		77,000		$	6.00 - $9.10		110,000

Three-way collars ⁽¹⁾	$	4.00 - $ 6.00		20,000	^(b)		-		-
Three-way average floor	$	3.04
				753,000					530,000

Basis Swaps vs. NYMEX -
Hedge:
CIG ⁽²⁾	$	1.03		39,890		$	0.39		20,000
NWPL ⁽³⁾	$	1.04		57,575			-		-

Nonhedge:
CIG	$	2.07		45,123			-		-
NWPL	$	1.75		10,603		$	0.20		15,000

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

^(b)	Acquired in 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.

Foreign Currency Exchange Rate Risk

The U.S. dollar is the functional currency for the company’s international operations, except for its European chemical operations, for which the euro is the functional currency. Following the divestiture of the company’s North Sea oil and gas business in November 2005, the company’s risk exposure to changes in foreign currency exchange rates arises mainly from Tronox’s European operations. As discussed under -Separation of Tronox, we expect to complete the separation of Tronox by the end of the first quarter of 2006. The company does not believe that its current level of foreign currency risk exposure is material to its results of operations and cash flows and expects the existing exposure to be further reduced following the Tronox separation. Accordingly, the company does not maintain material foreign currency derivative positions.

Interest Rate Risk

Debt Obligations - 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. 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, we do not expect the impact of changes 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 debt obligations outstanding at December 31, 2005:

																						Fair
																There-						Value
(Millions of dollars)	2006			2007			2008			2009			2010			After ⁽²⁾			Total ⁽³⁾			12/31/05

Fixed-rate debt -
Principal amount	$	-		$	-		$	-		$	-		$	-		$	2,575		$	2,575		$	2,763
Weighted-average
interest rate		-	%		-	%		-	%		-	%		-	%		7.47	%		7.47	%

Variable-rate debt ⁽¹⁾-
Principal amount	$	309		$	152		$	2		$	2		$	2		$	190		$	657		$	657
Weighted-average
interest rate		7.30	%		7.53	%		6.57	%		6.57	%		6.57	%		6.57	%		7.13	%

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

⁽²⁾	Includes $250 million in aggregate principal amount of our 7% debentures due 2011 which we redeemed in February 2006.

⁽³⁾	Principal amounts represent future payments and exclude the unamortized discount of $94 million and the net fair value hedge adjustments of $5 million.

Interest Rate Derivatives - At December 31, 2005, Kerr-McGee was a party to interest rate swaps designated as hedges against the change in fair value of the related debt as a result of interest rate changes. The swaps had an aggregate notional amount of $457 million and a net liability fair value of $5 million.

Critical Accounting Policies

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates, judgments and assumptions regarding matters that are inherently uncertain and that ultimately affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Generally, accounting rules do not involve a selection among alternatives, but involve a selection of the appropriate policies for applying the basic principles. Interpretation of the existing rules must be made on how the specifics of a given rule apply to the company.

The more significant reporting areas impacted by management’s judgments and estimates are exploratory drilling costs, crude oil and natural gas proved reserve estimation, recoverability of long-lived assets, accounting for business combinations, accounting for derivative instruments, environmental remediation, tax accruals and benefit plans. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, legal counsel, actuaries, environmental studies and historical experience in similar matters. Actual results could differ materially from those estimates, as additional information becomes known.

Exploratory Drilling Costs

Kerr-McGee follows the successful efforts method of accounting for its oil and gas exploration and development activities. Exploration expenses, including geological and geophysical costs and exploratory dry holes, are charged against earnings. Costs of successful exploratory wells and related production equipment are capitalized and amortized using the unit-of-production method on a field-by-field basis as oil and gas is produced. The successful efforts method reflects the inherent unpredictability of exploring for oil and gas. This accounting method may yield significantly different operating results than the full-cost method.

Under the successful efforts method, the cost of drilling an exploratory well is capitalized pending determination of whether proved reserves can be attributed to the discovery. In the case of onshore wells and offshore wells in relatively shallow water, that determination usually can be made upon or shortly after cessation of exploratory drilling operations. However, such determination may take longer in other areas (particularly deepwater exploration and international locations) depending upon, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional future appraisal drilling to determine whether the discovery is sufficient to support an economic development plan, and the requirement for government sanctioning in certain international locations. As a consequence, the company has capitalized costs associated with exploratory wells on its Consolidated Balance Sheet at any point in time that may be charged to earnings in a future period if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur. At December 31, 2005, we had capitalized exploratory drilling costs of approximately $208 million associated with ongoing exploration activities, primarily in the deepwater Gulf of Mexico, Alaska, Brazil and China. Additional information regarding the amount of capitalized exploratory drilling costs and changes during the last three years is presented in Note 23 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Proved Oil and Gas Reserves

The company’s estimates of proved oil and gas reserves are prepared by Kerr-McGee’s engineers using available geological and reservoir data, as well as production performance data. The U.S. Securities and Exchange Commission has defined proved reserves as the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with “reasonable certainty” to be recoverable in future years from known reservoirs under existing economic and operating conditions. Even though our engineers are knowledgeable and follow authoritative guidelines for estimating proved reserves, they must make a number of subjective determinations based on professional judgments in developing the company’s reserve estimates. Such estimates are reviewed annually and revised, either upward or downward, as warranted by additional data. Revisions of previous estimates can occur due to, among other things, changes in reservoir performance, commodity prices, economic conditions and governmental regulations. The company mitigates the inherent risks associated with reserve estimation through a comprehensive reserves administration process. See Note 24 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K for additional information concerning the reserve administration process, revisions to reserve estimates in each of the last three years, and the use of independent third-party engineers.

Oil and gas reserve estimates impact our financial statements in two important ways. First, proved reserves are used to calculate depreciation and depletion rates for capitalized costs associated with our proved oil and gas properties (i.e., depreciation and depletion expense is based on the percentage of proved reserves depleted in the current year). If previously estimated reserves for a particular oil and gas field are revised downward, depreciation and depletion rates will increase in the future. Conversely, increased reserve estimates will cause depreciation and depletion rates to decline. Second, proved reserves are used to calculate expected future cash flows for impairment test purposes whenever events or changes in circumstances indicate that an impairment loss may have occurred. We monitor our oil and gas properties for impairment based on current period operating results and reserve revisions, which may indicate that the carrying amount of a particular oil and gas field is not recoverable. All else being equal, downward revisions of previous reserve estimates increase the likelihood that an impairment loss may be recognized. In general terms, impairment losses historically recognized by the company resulted from either downward reserve revisions due to changes in reservoir performance or fields that ceased production sooner than anticipated. Factors contributing to impairment losses on oil and gas properties recognized during each of the last three years are discussed above under -Results of Operation by Segment - Exploration and Production.

Impairment of Assets

A long-lived asset is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying amount may be greater than its future net cash flows. Such evaluations involve a significant amount of judgment, since the results are based on estimated future events, such as sales prices for oil, gas or chemicals; costs to produce these products; estimates of future oil and gas production; development costs and the timing thereof; economic and regulatory climates and other factors. The need to test an asset for impairment may result from significant declines in sales prices, downward revisions to previous oil and gas reserve estimates, increases in operating costs, and changes in environmental or abandonment regulations. Assets held for sale are reviewed for potential loss on sale when the company commits to a plan to sell and thereafter while the asset is held for sale. Losses are measured as the difference between fair value less costs to sell and the asset’s carrying value. Estimates of anticipated sales prices are judgmental and subject to revision in future periods, although initial estimates typically are based on sales prices for similar assets and other valuation data. The company cannot predict when or if future impairment charges will be required for held-for-use assets or intangibles, or whether losses associated with held-for-sale properties will be recognized.

Business Combinations

Purchase Price Allocation - In connection with a business combination, the company is required to assign the cost of the acquisition to assets acquired and liabilities assumed and record deferred taxes for any differences between the assigned values and tax bases of assets and liabilities. Any excess of purchase price over the amounts assigned to assets and liabilities is recorded as goodwill. Most assets and liabilities are recorded in the opening balance sheet at their estimated fair values. We use all available information to make these fair value determinations, including information commonly considered by our engineers in valuing individual oil and gas properties and sales prices for similar assets. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and loss carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. In 2005, the company completed its analysis of Westport merger-date tax basis, which resulted in a reduction of net deferred tax liabilities by $35 million and a commensurate decrease in goodwill, due to higher than initially estimated tax basis. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.

Goodwill - In connection with our acquisition of HS Resources in 2001 and our merger with Westport in 2004, we recorded a total of $1.2 billion of goodwill for the excess of the purchase price over the value assigned to individual assets acquired and liabilities assumed. The company is required to assess goodwill for impairment annually, or more often as circumstances warrant. The first step of that process is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. If the estimated fair value is greater than the carrying amount of the reporting unit, then no impairment loss is required. The company completed its most recent annual goodwill impairment test as of June 30, 2005, with no impairment indicated. Although we cannot predict when or if goodwill will be impaired in the future, impairment charges may occur if we are unable to replace the value of our depleting asset base or if other adverse events (for example, lower sustained oil and gas prices) reduce the fair value of the associated reporting unit.

Derivative Instruments

We are 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 increase the predictability of its cash flows, from time to time we enter into certain derivative contracts, primarily swaps and collars for a portion of our oil and gas production, forward contracts to buy and sell foreign currencies, and interest rate swaps. Kerr-McGee accounts for all its derivative instruments in accordance with FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS No. 133). The commodity, foreign currency and interest rate contracts are measured at fair value and recorded as assets or liabilities in the Consolidated Balance Sheet. We have elected, under the provisions of FAS No. 133, to apply hedge accounting to the majority of our oil and gas commodity derivatives, which has the effect of deferring unrealized gains and losses on these instruments in equity, as a component of accumulated other comprehensive income (loss), until such time as the hedged production is sold. Alternatively, as permitted by FAS No. 133, we could elect to recognize the unrealized gains and losses in current-period earnings, which would have resulted in significant earnings volatility in periods preceding the physical sale of oil and gas. If we had elected to apply this alternative treatment, an additional after-tax unrealized loss of $1.1 billion would have been recognized in earnings prior to December 31, 2005. Our chosen accounting method has no bearing on the company’s liquidity or our total debt to total capitalization ratio because, in either case, stockholder’s equity is reduced by the unrealized loss.

Effective March 1, 2006, we elected to discontinue hedge accounting for our commodity derivatives. Refer to -Results of Operations by Segment - Exploration and Production - Revenues for information about the expected effects of this election on our financial statements.

Environmental Remediation and Other Contingency Reserves

Management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for environmental remediation, litigation and other contingent matters. Provisions for such matters are charged to expense when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. Estimates of environmental liabilities, which include the cost of investigation and remediation, are based on a variety of matters, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number of factors could significantly change our estimate of environmental remediation costs, such as changes in laws and regulations, or changes in their interpretation or administration, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental or other contingent matters and actual costs may vary significantly from the company's estimates. Before considering reimbursements of the company's environmental costs discussed below, we provided $84 million, $106 million and $94 million for environmental remediation and restoration costs in 2005, 2004 and 2003, respectively, including provisions related to our former forest products business reflected as a component of income from discontinued operations.

To the extent costs of investigation and remediation are recoverable from the U.S. government, from insurers under certain insurance policies or other parties, and such recoveries are deemed probable, the company records a receivable. In considering the probability of receipt, we evaluate our historical experience with receipts, as well as our claim submission experience. At December 31, 2005, estimated recoveries of environmental costs recorded in the Consolidated Balance Sheet totaled $57 million. Provisions for environmental remediation and restoration in the Consolidated Statement of Operations were reduced by estimated recoveries of $35 million, $14 million and $32 million in 2005, 2004 and 2003, respectively.

For additional information about contingencies, refer to the -Environmental Matters section that follows and Note 16 to the Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K.

Tax Accruals

The company has operations in several countries around the world and is subject to income and similar taxes in these countries. The estimation of the amounts of income tax to be recorded by the company involves interpretation of complex tax laws and regulations, evaluation of tax audit findings and assessment of how the foreign taxes affect domestic taxes. Although the company’s management believes its tax accruals are adequate, differences may occur in the future, depending on the resolution of pending and new tax matters.

Benefit Plans

Kerr-McGee provides defined benefit retirement plans for eligible employees in the U.S. and accounts for these plans in accordance with FAS No. 87, “Employers’ Accounting for Pensions.” We also provide certain postretirement health care and life insurance benefits and account for the related plans in accordance with FAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Additionally, Tronox sponsors retirement plans for its employees in Germany and the Netherlands. The various assumptions used and the attribution of the costs to periods of employee service are fundamental to the measurement of net periodic cost and obligations for pension and other postretirement benefits under the plans we sponsor. The discussion that follows concentrates on our benefit plans for U.S. employees, based on their relative significance to our consolidated financial statements as compared to foreign plans sponsored by Tronox.

Assumptions - The following are considered significant assumptions related to our U.S. retirement plans and the health and welfare postretirement plans:

·	Long-term rate of return (applies to funded plans only)

·	Discount rate

·	Rate of compensation increases

·	Health care cost trend rate (applies to health and welfare postretirement plans only)

Assumptions used to measure the benefit obligations and the net period cost for each of the last three years are summarized in Note 15 to our Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K. Other factors considered in developing actuarial valuations include inflation rates, retirement rates, mortality rates and other factors. Assumed inflation rates are based on an evaluation of external market indicators. Retirement rates are based primarily on actual plan experience.

The following table shows the impact of changes in the primary assumptions used in actuarial calculations associated with our pension and other postretirement benefits for the year ended December 31, 2005:

	Pension Benefits ⁽¹⁾						Other Postretirement Benefits

	Net Periodic			Projected			Net Periodic			Accumulated
	Cost			Benefit			Cost			Postretirement
(Millions of dollars)	(Benefit)			Obligation			(Benefit)			Benefit Obligation

Increase of 0.5% in -
Discount rates	$	(1	)	$	(64	)	$	(1	)	$	(15	)
Expected return on plan assets		(6	)		-			-			-
Rate of compensation increase		2			14			-			1

Decrease of 0.5% in -
Discount rates	$	1		$	71		$	1		$	16
Expected return on plan assets (2)		6			-			-			-
Rate of compensation increase		(2	)		(14	)		-			(1	)

Change in health care cost trend rate of 1% -
Increase	$	-		$	-		$	1		$	14
Decrease		-			-			(1	)		(12	)

⁽¹⁾

The sensitivity analysis reflects only the impact of assumption changes on our U.S. qualified retirement plan. While Kerr-McGee sponsors other retirement plans for its U.S. employees, the year-end 2005 projected benefit obligation for the U.S. qualified retirement plan represented 93% of the total projected benefit obligation for all U.S. retirement plans.

⁽²⁾	If the actual return on plan assets was one percent lower than the expected return on plan assets, our expected cash contributions to our pension and other postretirement benefit plans would not significantly change.

Long-term rate of return - In forming the long-term rate of return assumption, we take into account the expected earnings on funds already invested, earnings on contributions expected to be received in the current year and earnings on reinvested returns. The long-term rate of return estimation methodology for U.S. plans is based on a capital asset pricing model using historical data. An expected return analysis is performed which incorporates the current portfolio allocation, historical asset-class returns and an assessment of expected future performance using asset-class risk factors.

When calculating expected return on plan assets for U.S. pension plans, the company uses a market-related value of assets that spreads asset gains and losses (differences between actual return and expected return) over five years on a straight-line basis. For example, in 2005, total expected return on assets of the U.S. qualified pension plan was $96 million, compared with an actual return of $49 million. The difference of $47 million will affect net periodic pension cost in years 2006 through 2010. As of December 31, 2005, the amount of net investment losses on U.S. pension assets that did not yet affect net periodic pension cost was $56 million. As these deferred investment losses are recognized during future years in the market-related value of assets, they will result in cumulative increases in net periodic pension cost of $5 million in 2007 through 2010.

Discount rate - We select a discount rate assumption for our U.S. qualified pension plan and our postretirement health and life plans using the results of a cash flow matching analysis based on projected cash flows for the plans. The discount rates selected for year-end 2005 and 2004 were 5.50% and 5.75%, respectively. The decrease in the discount rate increased the projected benefit obligation for our U.S. qualified retirement plan by $33 million and the accumulated postretirement benefit obligation for our health and welfare plans by approximately $8 million. In accordance with accounting standards currently in effect, recognition of a portion of such actuarial losses is deferred and recognized over the average remaining service period of participating employees expected to receive benefits under the plan.

Rate of compensation increases - Kerr-McGee determines this assumption based on its long-term plans for compensation increases specific to employee groups covered and expected economic conditions. The assumed rate of salary increases includes the effects of merit increases, promotions and general inflation.

Health care cost trend rate - The health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. The company chooses an initial medical trend rate and an ultimate medical trend rate, as well as the number of years it will take to move between the two rates.

Unrecognized Gains (Losses) and Prior Service Cost - As discussed above, accounting standards currently in effect provide for deferring the recognition of certain gains and losses resulting from changes in actuarial assumptions and from experience different from that assumed (such as the difference between the actual and expected return on plan assets discussed above). Similarly, a portion of increases or reductions in the benefit obligations attributable to plan participants’ prior service arising from a plan amendment also is deferred. At December 31, 2005, unrecognized net actuarial losses and unrecognized net prior service cost for our U.S. pension and other postretirement plans totaled $340 million and $29 million, respectively. Following accounting guidance currently in effect, these unrecognized items will be amortized to net periodic cost over the remaining service period of plan participants expected to receive benefits under the plan (or over the remaining service period to full eligibility of participating employees for unrecognized prior service cost associated with the health and life postretirement plans). The average amortization period for unrecognized net actuarial losses and prior service costs is expected to be between 8 and 14 years. Amortization of unrecognized items to net periodic cost in 2006 is estimated to be $15 million, before taking into account the effects of the Distribution. Following the transfer of the benefit obligations and assets to Tronox in connection with the Distribution, as discussed below, amortization of unrecognized items is expected to be lower.

FASB Project - The Financial Accounting Standards Board (FASB) has recently initiated a project that is expected to result in issuing a new accounting standard later in 2006. Assuming the provisions of the final standard are consistent with decisions reached by the FASB to date, the standard will require recognition on the balance sheet of unrecognized items discussed above, with an offsetting change in accumulated other comprehensive income (loss) in equity. This initial stage of the FASB project is not expected to affect the measurement of the net periodic cost. The result of such accounting policy will be the recognition on the balance sheet of the over or (under) funded status of the plans (or the difference between the benefit obligation and the fair value of plan assets, if any). Had this accounting policy been in effect at December 31, 2005, Kerr-McGee would have recognized additional liabilities associated with its U.S. benefit plans of $341 million (in addition to an additional minimum pension liability of $28 million already recognized as of that date), reduction in deferred tax liabilities of $119 million and an increase in accumulated other comprehensive loss of $222 million.

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

Environmental Matters

The company's affiliates are subject to various environmental laws and regulations in the United States and in the foreign countries in which they operate. Under these laws, the company's affiliates are or may be required to obtain or maintain permits and/or licenses in connection with their operations. In addition, under these laws, the company's affiliates are or may be required to remove or mitigate the effects on the environment of the disposal or release of certain chemical, petroleum, low-level radioactive and other substances at various sites. Environmental laws and regulations are becoming increasingly stringent, and compliance costs are significant and will continue to be significant in the foreseeable future. There can be no assurance that such laws and regulations or any environmental law or regulation enacted in the future will not have a material effect on the company.

Sites at which the company's affiliates have environmental responsibilities include sites that have been designated as Superfund sites by the U.S. Environmental Protection Agency (EPA) pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), as amended, and that are included on the National Priority List (NPL). As of December 31, 2005, the company's affiliates had received notices that they had been named potentially responsible parties (PRP) with respect to 13 existing EPA Superfund sites on the NPL that require remediation. The company does not consider the number of sites for which its affiliates have been named a PRP to be the determining factor when considering the company's overall environmental obligation. Decommissioning and remediation obligations, and the attendant costs, vary substantially from site to site and depend on unique site characteristics, available technology and the regulatory requirements applicable to each site. Additionally, the company's affiliates may share liability at some sites with numerous other PRPs, and the law currently imposes joint and several liability on all PRPs under CERCLA. The company's affiliates also are obligated to perform or have performed remediation or remedial investigations and feasibility studies at sites that have not been designated as Superfund sites by EPA. Such work is frequently undertaken pursuant to consent orders or other agreements.

Current Businesses

The company's affiliates are subject to numerous international, federal, state and local laws and regulations relating to environmental protection. In the United States, these include the Federal Water Pollution Control Act, commonly known as the Clean Water Act, the Clean Air Act and the Resource Conservation and Recovery Act (RCRA). These laws and regulations govern, among other things, the amounts and types of substances and materials that may be released into the environment; the issuance of permits in connection with exploration, drilling and production activities; the release of emissions into the atmosphere; and the discharge and disposition of waste materials. Environmental laws and regulations also govern offshore oil and gas operations, the implementation of spill prevention plans, the reclamation and abandonment of wells and facility sites, and the remediation and monitoring of contaminated sites. The company's chemical affiliates are subject to a broad array of international, federal, state and local laws and regulations relating to environmental protection, including the Clean Water Act, the Clean Air Act, CERCLA and RCRA. These laws require these affiliates to undertake various activities to reduce air emissions, eliminate the generation of hazardous waste, decrease the volume of wastewater discharges and increase the efficiency of energy use.

Former Businesses

The company's affiliates historically have held interests in various businesses in which they are no longer engaged. Such businesses include the refining and marketing of oil and gas and associated petroleum products, the mining and processing of uranium and thorium, the production of ammonium perchlorate, the treatment of forest products and other activities. Although the company's affiliates are no longer engaged in certain businesses, residual obligations may still exist, including obligations related to compliance with environmental laws and regulations, including the Clean Water Act, the Clean Air Act, CERCLA and RCRA. These laws and regulations require the company’s affiliates to undertake remedial measures at sites of current or former operations or at sites where waste was disposed. For example, company affiliates are required to conduct decommissioning and environmental remediation at certain refineries, distribution facilities and service stations they previously owned and/or operated. Company affiliates also are required to conduct decommissioning and remediation activities at sites where they were involved in the exploration, production, processing and/or sale of uranium or thorium compounds and at sites where they were involved in the production and sale of ammonium perchlorate. Additionally, the company's chemical affiliate is decommissioning and remediating its former wood-treatment facilities.

Environmental Costs

Expenditures for environmental protection and cleanup for each of the last three years and for the three-year period ended December 31, 2005, are as follows:

(Millions of dollars)	2005		2004		2003		Total

Expenditures applied against
environmental reserves	$	71	$	99	$	104	$	274
Recurring expenses		45		37		39		121
Capital expenditures		12		9		14		35
Total	$	128	$	145	$	157	$	430

In addition to past expenditures, reserves have been established for the remediation and restoration of active and inactive sites where it is probable that future costs will be incurred and the liability is reasonably estimable. For environmental sites, the company considers a variety of matters when setting reserves, including the stage of investigation; whether EPA or another relevant agency has ordered action or quantified cost; whether the company has received an order to conduct work; whether the company participates as a PRP in the Remedial Investigation/Feasibility Study (RI/FS) process and, if so, how far the RI/FS has progressed; the status of the record of decision by the relevant agency; the status of site characterization; the stage of the remedial design; evaluation of existing remediation technologies; the number and financial condition of other potential PRPs; and whether the company reasonably can evaluate costs based upon a remedial design and/or engineering plan.

After the remediation work has begun, additional accruals or adjustments to previous cost estimates may be made based on any number of developments, including revisions to the remedial design; unanticipated construction problems; identification of additional areas or volumes of contamination; inability to implement a planned engineering design or to use planned technologies and excavation methods; changes in costs of labor, equipment and/or technology; any additional or updated engineering and other studies; and weather conditions.

As of December 31, 2005, the company's financial reserves for all active and inactive sites totaled $268 million. This includes $84 million added to the reserves in 2005 for active and inactive sites. In the Consolidated Balance Sheet, $178 million of the total reserve is classified as noncurrent liabilities-other, and the remaining $90 million is included in accrued liabilities. Management believes that currently the company has reserved adequately for the reasonably estimable costs of known environmental contingencies. However, additional reserves may be required in the future due to the previously noted uncertainties. Additionally, there may be other sites where the company has potential liability for environmental-related matters but for which the company does not have sufficient information to reasonably estimate the liability and/or determine that the liability is probable. The company has not established reserves for such sites.

The following table reflects the company's portion of the known estimated costs of investigation and/or remediation that are probable and estimable. The table summarizes EPA Superfund NPL sites where the company and/or its affiliates have been notified it is a PRP under CERCLA and other sites for which the company had financial reserves recorded at year-end 2005. In the table, aggregated information is presented for certain sites that are individually not significant (each has a remaining reserve balance of less than $10 million). Amounts reported in the table for the West Chicago sites are not reduced for actual or expected reimbursement from the U.S. government under Title X of the Energy Policy Act of 1992 (Title X), described in Note 16 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Similarly, amounts reported for the Henderson, Nevada, site do not reflect reimbursements received or receivable from the insurer.

			Remaining
		Total Expenditures Through 2005	Reserve Balance at December 31, 2005	Total
Location of Site	Stage of Investigation/Remediation	(Millions of dollars)
EPA Superfund sites on National Priority List (NPL)
West Chicago, Ill. Vicinity areas	Remediation of thorium tailings at Residential Areas and Reed-Keppler Park is substantially complete. Cleanup of thorium tailings at Kress Creek and Sewage Treatment Plant is ongoing.	$ 141	$75	$ 216

Milwaukee, Wis.	Completed soil cleanup at former wood-treatment facility and began cleanup of offsite tributary creek. Groundwater remediation and cleanup of tributary creek is continuing.	41	4	45

Other sites	Sites where the company has been named a PRP, including landfills, wood-treating sites, a mine site and an oil recycling refinery. These sites are in various stages of investigation/remediation.	32	12	44
		214	91	305
Sites under consent order, license or agreement, not on EPA Superfund NPL
West Chicago, Ill. Former manufacturing facility	Excavation, removal and disposal of contaminated soils at former thorium mill is substantially complete. The site will be used for moving material from the Kress Creek and Sewage Treatment Plant remediation sites. Surface restoration and groundwater monitoring and remediation are expected to continue for approximately 10 years.	446	12	458

Los Angeles County, Cal.	Excavation, removal and disposal of soils contaminated with wastes from oil and gas production is ongoing.	20	23	43

Cushing, Okla.	Excavation, removal and disposal of thorium and uranium residuals was substantially completed in 2004. Investigation of and remediation addressing hydrocarbon contamination is continuing.	147	12	159

Henderson, Nev.	Groundwater treatment to address ammonium perchlorate contamination is being conducted under consent decree with Nevada Department of Environmental Protection.	124	37	161

Ambrosia Lake, New Mexico	Uranium mill tailings and selected pond sediments consolidated and capped onsite. A request to end groundwater treatment and a decommissioning plan for impacted soils are under review by the Nuclear Regulatory Commission.	28	11	39

Other sites	Sites related to wood-treatment, chemical production, landfills, mining, and oil and gas refining, distribution and marketing. These sites are in various stages of investigation/remediation.	308	82	390
		1,073	177	1,250
	Total	$1,287	$268	$1,555

The company has not recorded in the financial statements potential reimbursements from governmental agencies or other third parties, except for amounts due from the U.S. government under Title X for costs incurred by the company on its behalf and recoveries under certain insurance policies. If recoveries from third parties, other than recovery from the U.S. government under Title X and recoveries under certain insurance policies become probable, they will be disclosed but will not generally be recorded in the financial statements until received.

Sites specifically identified in the table above are discussed in Note 16 to the Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K. Discussion in Note 16 of the West Chicago, Illinois; Henderson, Nevada; Los Angeles County, California; Ambrosia Lake, New Mexico; Milwaukee, Wisconsin; and Cushing, Oklahoma, sites is incorporated herein by reference and made fully a part hereof.

New/Revised Accounting Standards

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

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

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

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

In 2005, the FASB initiated a project titled “Postretirement Benefit Obligations Other than Pensions,” which is expected to result in the issuance of a new accounting standard later in 2006. The possible effects of the expected standard on our consolidated balance sheet is discussed above under -Critical Accounting Policies - Benefit Plans - FASB Project.

Item 7a. Quantitative and Qualitative Disclosure about Market Risk

For information required under this section, see Management’s Discussion and Analysis - Market Risks included in Item 7 of this Annual Report on Form 10-K.

Item 8. Financial Statements and Supplementary Data

Index to the Consolidated Financial Statements	PAGE

Management’s Report on Internal Control over Financial Reporting	74
Report of Independent Registered Public Accounting Firm
on Internal Control over Financial Reporting	75
Report of Independent Registered Public Accounting Firm
on Consolidated Financial Statements	76
Consolidated Statement of Income for the years ended
December 31, 2005, 2004 and 2003	77
Consolidated Balance Sheet at December 31, 2005 and 2004	78
Consolidated Statement of Cash Flows for the years ended
December 31, 2005, 2004 and 2003	79
Consolidated Statement of Comprehensive Income and Stockholders’ Equity
for the years ended December 31, 2005, 2004 and 2003	80
Notes to Consolidated Financial Statements	81

Index to Supplementary Data

Five-Year Financial Summary	151
Five-Year Operating Summary	152

Index to the Financial Statement Schedules

Schedule II - Valuation Accounts and Reserves	162

All other schedules are omitted because they are either not applicable or the information is presented in the financial statements or the notes to the financial statements.

Management’s Report on Internal Control over Financial Reporting

The management of Kerr-McGee Corporation (the company) is responsible for establishing and maintaining adequate internal control over financial reporting. The company’s internal control over financial reporting is a process designed under the supervision of the company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the company’s financial statements for external purposes in accordance with accounting principles generally accepted in the U.S.

As of December 31, 2005, management assessed the effectiveness of the company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that the company maintained effective internal control over financial reporting as of December 31, 2005, based on those criteria.

Ernst & Young, LLP, the independent registered public accounting firm that audited the Consolidated Financial Statements of the company included in this Annual Report on Form 10-K, has issued an attestation report on management’s assessment of the effectiveness of the company’s internal control over financial reporting as of December 31, 2005. The report, which expresses unqualified opinions on management’s assessment and on the effectiveness of the company’s internal control over financial reporting as of December 31, 2005, is included under the heading “Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting.”

(Luke R. Corbett)	(Robert M. Wohleber)
Luke R. Corbett	Robert M. Wohleber
Chief Executive Officer	Senior Vice President and
	Chief Financial Officer

March 14, 2006

Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting

The Board of Directors and Stockholders

Kerr-McGee Corporation

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Kerr-McGee Corporation maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Kerr-McGee Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Kerr-McGee Corporation maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Kerr-McGee Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2005 consolidated financial statements of Kerr-McGee Corporation and our report dated March 14, 2006, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Oklahoma City, Oklahoma

March 14, 2006

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements

The Board of Directors and Stockholders

Kerr-McGee Corporation

We have audited the accompanying consolidated balance sheets of Kerr-McGee Corporation as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income and stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index in Item 8. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Kerr-McGee Corporation at December 31, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

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

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Kerr-McGee Corporation’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 14, 2006, expressed an unqualified opinion thereon.

/S/ ERNST & YOUNG LLP

Oklahoma City, Oklahoma

March 14, 2006

Consolidated Statement of Income

(Millions of dollars, except per-share amounts)	2005			2004			2003

Revenues	$	5,927		$	4,398		$	3,289
Costs and Expenses
Costs and operating expenses		2,304			1,794			1,416
Selling, general and administrative expenses		455			325			350
Shipping and handling expenses		145			128			96
Depreciation and depletion		952			842			532
Accretion expense		23			19			15
Asset impairments		17			28			14
(Gain) loss on sale of assets		(211	)		29			(30	)
Exploration, including exploratory dry holes and
amortization of undeveloped leases		377			324			327
Taxes other than income taxes		202			144			94
Provision for environmental remediation and restoration,
net of reimbursements		38			86			60
Interest and debt expense		253			244			250
Loss on early repayment and modification of debt		42			-			-
Total Costs and Expenses		4,597			3,963			3,124
		1,330			435			165
Other Income (Expense)		104			(34	)		(25	)

Income from Continuing Operations before Income Taxes		1,434			401			140
Benefit (Provision) for Income Taxes		(487	)		(137	)		15
Minority Interest, net of taxes		(1	)		-			-
Income from Continuing Operations		946			264			155
Income from Discontinued Operations, net of taxes (Note 2)		2,265			140			99
Cumulative Effect of Change in Accounting Principle,
net of taxes		-			-			(35	)
Net Income	$	3,211		$	404		$	219

Income per Common Share
Basic -
Continuing operations	$	7.22		$	2.09		$	1.55
Discontinued operations		17.29			1.11			.98
Cumulative effect of change in accounting principle		-			-			(.35	)
Net income	$	24.51		$	3.20		$	2.18

Diluted -
Continuing operations	$	7.07		$	2.08		$	1.54
Discontinued operations		16.84			1.10			.97
Cumulative effect of change in accounting principle		-			-			(.34	)
Net income	$	23.91		$	3.18		$	2.17

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

Consolidated Balance Sheet

(Millions of dollars)	2005		2004
ASSETS
Current Assets
Cash and cash equivalents	$	1,053	$	76
Accounts receivable		1,069		825
Inventories		352		314
Derivatives and other current assets		194		151
Deferred income taxes		581		327
Assets held for sale (Note 2)		-		194
Total Current Assets		3,249		1,887

Property, Plant and Equipment - Net		9,275		9,073
Deferred Charges, Derivatives and Other Assets		508		484
Intangible Assets		78		91
Assets Held for Sale (Note 2)		5		1,786
Goodwill		1,161		1,197
Total Assets	$	14,276	$	14,518

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	727		$	607
Long-term debt due within one year		308			463
Income taxes payable		473			138
Derivative liabilities		1,508			350
Accrued liabilities		915			755
Liabilities associated with assets held for sale (Note 2)		-			192
Total Current Liabilities		3,931			2,505

Long-Term Debt		2,825			3,236

Noncurrent Liabilities
Deferred income taxes		1,524			1,727
Asset retirement obligations		345			336
Derivative liabilities		663			208
Other		661			571
Liabilities associated with assets held for sale (Note 2)		-			617
Total Noncurrent Liabilities		3,193			3,459

Contingencies and Commitments (Notes 16 and 17)

Minority Interest in Tronox (Note 3)		212			-

Stockholders’ Equity
Common stock, par value $1.00 - 500,000,000 and 300,000,000
shares authorized, 119,668,552 and 152,049,127 shares
issued at December 31, 2005 and 2004, respectively		120			152
Capital in excess of par value		3,702			4,205
Preferred stock purchase rights		1			2
Retained earnings		1,704			1,102
Accumulated other comprehensive loss		(1,079	)		(79	)
Common stock in treasury, at cost - 3,456,918 and 159,856 shares
at December 31, 2005 and 2004, respectively		(266	)		(8	)
Deferred compensation		(67	)		(56	)
Total Stockholders’ Equity		4,115			5,318

Total Liabilities and Stockholders’ Equity	$	14,276		$	14,518

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

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

Consolidated Statement of Cash Flows

(Millions of dollars)	2005			2004			2003

Cash Flows from Operating Activities
Net income	$	3,211		$	404		$	219
Adjustments to reconcile net income to net cash
provided by operating activities -
Depreciation, depletion and amortization		1,177			1,124			814
Deferred income taxes		83			108			156
Unrealized losses on derivatives		200			12			5
Dry hole expense		185			161			181
Noncash stock-based compensation and ESOP expense		54			25			42
Asset impairments		17			36			14
Gain on sale of the North Sea oil and gas business		(2,240	)		-			-
(Gain) loss on sale of assets		(327	)		20			(40	)
Loss on early repayment and modification of debt		42			-			-
Accretion expense		30			30			25
Cumulative effect of change in accounting principle		-			-			35
Provision for environmental remediation
and restoration, net of reimbursements		49			92			62
Other noncash items affecting net income		116			147			97
Changes in assets and liabilities: ⁽¹⁾
(Increase) decrease in accounts receivable		(232	)		(236	)		45
(Increase) decrease in inventories		(66	)		83			22
Decrease in deposits, prepaids and other assets		7			48			12
Increase (decrease) in accounts payable,
derivatives and accrued liabilities		390			136			(57	)
Increase in income taxes payable		418			4			16
Other		(11	)		(144	)		(130	)
Net cash provided by operating activities		3,103			2,050			1,518

Cash Flows from Investing Activities
Capital expenditures		(1,751	)		(1,262	)		(981	)
Dry hole costs		(169	)		(78	)		(181	)
Acquisitions, net of cash acquired ⁽²⁾		-			43			(110	)
Net proceeds from sale of the North Sea oil and gas business		3,305			-			-
Proceeds from sale of assets		704			23			304
Other investing activities		(8	)		12			17
Net cash provided by (used in) investing activities		2,081			(1,262	)		(951	)

Cash Flows from Financing Activities ⁽²⁾
Issuance of common stock upon exercise of stock options		225			55			-
Sale of Tronox stock		225			-			-
Purchases of treasury stock		(250	)		-			-
Repurchases of common stock under the tender offer		(3,975	)		-			-
Dividends paid		(153	)		(205	)		(181	)
Repayment of debt		(4,751	)		(1,278	)		(369	)
Proceeds from borrowings		4,800			686			31
Debt issuance costs and other		(71	)		(8	)		(1	)
Cash paid for modification of debt		(22	)		-			-
Settlement of Westport derivatives		(238	)		(101	)		-
Net cash used in financing activities		(4,210	)		(851	)		(520	)

Effects of Exchange Rate Changes on Cash and Cash Equivalents		3			(3	)		5
Net Increase (Decrease) in Cash and Cash Equivalents		977			(66	)		52
Cash and Cash Equivalents at Beginning of Year		76			142			90
Cash and Cash Equivalents at End of Year	$	1,053		$	76		$	142

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

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

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

Consolidated Statement of Comprehensive Income and Stockholders’ Equity
(Millions of dollars)	Common Stock			Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Deferred Compensation and Other			Total Stockholders’ Equity
Balance at December 31, 2002	$	100		$	1,687		$	886		$	(62	)	$	-		$	(75	)	$	2,536
Comprehensive Income:
Net income		-			-			219			-			-			-			219
Other comprehensive income		-			-			-			17			-			-			17
Comprehensive income																				236
Stock option exercises		-			1			-			-			-			-			1
Issuance of employee stock-based
awards, net of forfeitures		1			21			-			-			(1	)		(20	)		1
Amortization of deferred compensation cost		-			-			-			-			-			10			10
ESOP deferred compensation and other		-			(1	)		4			-			(1	)		32			34
Dividends declared ($1.80 per share)		-			-			(182	)		-			-			-			(182	)
Balance at December 31, 2003		101			1,708			927			(45	)		(2	)		(53	)		2,636
Comprehensive Income:
Net income		-			-			404			-			-			-			404
Other comprehensive loss		-			-			-			(34	)		-			-			(34	)
Comprehensive income																				370
Westport merger		49			2,402			-			-			-			(3	)		2,448
Stock option exercises		2			53			-			-			-			-			55
Issuance of employee stock-based
awards, net of forfeitures		-			24			-			-			(6	)		(23	)		(5	)
Amortization of deferred compensation cost		-			-			-			-			-			18			18
ESOP deferred compensation and other		-			-			(1	)		-			-			7			6
Tax benefit from stock-based awards		-			18			-			-			-			-			18
Dividends declared ($1.80 per share)		-			-			(228	)		-			-			-			(228	)
Balance at December 31, 2004		152			4,205			1,102			(79	)		(8	)		(54	)		5,318
Comprehensive Income:
Net income		-			-			3,211			-			-			-			3,211
Other comprehensive loss		-			-			-			(1,000	)		-			-			(1,000	)
Comprehensive income																				2,211
Gain on sale of Tronox stock (Note 3)		-			19			-			-			-			-			19
Shares issued upon conversion of debt		10			583			-			-			-			-			593
Purchases of treasury shares		-			-			-			-			(250	)		-			(250	)
Shares repurchased and retired		(47	)		(1,410	)		(2,517	)		-			-			(1	)		(3,975	)
Stock option exercises		4			221			-			-			-			-			225
Issuance of employee stock-based
awards, net of forfeitures		1			52			-			-			(8	)		(50	)		(5	)
Amortization of deferred compensation cost		-			-			-			-			-			32			32
ESOP deferred compensation		-			-			-			-			-			7			7
Tax benefit from stock-based awards		-			32			-			-			-			-			32
Dividends declared ($.60 per share)		-			-			(92	)		-			-			-			(92	)
Balance at December 31, 2005	$	120		$	3,702		$	1,704		$	(1,079	)	$	(266	)	$	(66	)	$	4,115

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

(Millions of dollars)	2005			2004			2003

Foreign currency translation adjustments	$	(56	)	$	29		$	56
Net losses on cash flow hedges		(939	)		(69	)		(31	)
Available-for-sale securities		-			(5	)		(1	)
Minimum pension liability adjustments		(6	)		11			(7	)
Minority interest		1			-			-
Other comprehensive income (loss)	$	(1,000	)	$	(34	)	$	17

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

Notes to Consolidated Financial Statements

1. The Company and Significant Accounting Policies

The Company

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

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

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

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

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

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

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

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

Significant Accounting Policies

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

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

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

Reclassifications - Certain prior year amounts have been reclassified to conform with the current year presentation and to present the company’s former North Sea oil and gas business and forest products business as discontinued operations. Unless indicated otherwise, information presented in the footnotes to the financial statements relates only to the company’s continuing operations.

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

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

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

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

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

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

Property, Plant and Equipment

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

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

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

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

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

Asset Exchanges - Effective July 1, 2005, the company adopted Statement of Financial Accounting Standards No. 153, “Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29” (FAS No. 153), for exchanges of nonmonetary assets occurring after the implementation date. Prior to implementing FAS No. 153, the company generally did not recognize gains on nonmonetary exchanges involving proved oil and gas properties; however, for exchange transactions involving monetary consideration (if such consideration was less than 25% of the fair value of assets exchanged), a proportionate amount of the indicated gain was recognized based on the percentage of monetary consideration received. Exchanges of proved oil and gas properties involving receipt of monetary consideration of 25% or more were accounted for at fair value with full gain recognition. According to the provisions of FAS No. 153, all nonmonetary asset exchanges that have commercial substance, as defined, will be measured at fair value with gain or loss recognized in earnings.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Employee Stock-Based Compensation

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

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

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

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

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

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

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

(Millions of dollars, except per share amounts)	2005			2004			2003

Net income as reported	$	3,211		$	404		$	219
Add: Stock-based employee compensation expense included
in reported net income, net of taxes		31			11			7
Deduct: Stock-based compensation expense determined
using a fair-value method, net of taxes		(42	)		(24	)		(23	)
Pro forma net income	$	3,200		$	391		$	203

Net income per share -
Basic -
As reported	$	24.51		$	3.20		$	2.18
Pro forma		24.43			3.09			2.03

Diluted -
As reported	$	23.91		$	3.18		$	2.17
Pro forma		23.83			3.08			2.03

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

	2005			2004			2003
Inputs and assumptions -
Expected life (years)		6.0			5.8			5.8
Risk-free interest rate		3.9	%		3.5	%		3.6	%
Expected dividend yield		3.5			3.6			3.3
Expected volatility		27.4	%		22.6	%		32.7	%

Weighted-average exercise price of options granted	$	56.57		$	49.45		$	42.93
Weighted-average fair value of options granted		12.50			8.63			11.09

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

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

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

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

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

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

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

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

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

2. Discontinued Operations and Asset Divestitures and Exchanges

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

The following summarizes divestiture transactions completed or which the company expects to complete in 2006. In addition, as discussed in Note 3, the company completed the Tronox IPO in November 2005. The net proceeds from the divestitures and the separation of Tronox have been used for debt repayment and other corporate purposes. Debt repayments made in 2005 and early 2006 are discussed in Note 10.

				Pretax Gain on Sale, Net
	Gross			Continuing			Discontinued
(Millions of dollars)	Proceeds		(1)	Operations			Operations

Completed exchange transactions -
Exchange of interests in certain noncore oil and gas properties for a 37.5%
interest in the Blind Faith discovery in the deepwater Gulf of Mexico and cash	$	26		$	21		$	-
Exchange of interests in certain noncore oil and gas properties for overriding
royalty interests in the Greater Natural Buttes area and cash		27			24			-

Completed divestiture transactions -
Nonoperated North Sea fields		551			-			306
Remaining oil and gas operations in the North Sea		2,970			-			1,934
Nonoperating interest in gas processing facility		159			120	(2)		-
Several packages of U.S. onshore oil and gas properties		435			149			-
Other noncore oil and gas properties and other assets		56			17			(1	)
*Total completed exchange and divestiture transactions*	$	4,224		$	331		$	2,239

Expected 2006 divestiture transactions -
Interests in oil and gas properties on the Gulf of Mexico shelf		1,340	(3)
Noncore oil and gas assets onshore in the U.S.		15

⁽¹⁾

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

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

⁽²⁾

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

⁽³⁾	Represents expected cash proceeds as of October 1, 2005 effective date before considering working capital and other adjustments.

Discontinued Operations - Income from discontinued operations in the Consolidated Statement of Income relates primarily to the company’s North Sea oil and gas business, but also includes income (loss) from the former forest products operations, which the company exited in the fourth quarter of 2004.

The following summarizes the amounts included in income from discontinued operations for all periods presented:

	2005									2004									2003
	North Sea			Forest						North Sea			Forest						North Sea			Forest
	Oil and Gas			Products						Oil and Gas			Products						Oil and Gas			Products
(Millions of dollars)	Business			Business			Total			Business			Business			Total			Business			Business			Total

Revenues	$	994		$	-		$	994		$	759		$	22		$	781		$	791		$	105		$	896

Income from discontinued operations -
Income (loss) from operations	$	527		$	-		$	527		$	270		$	(17	)	$	253			319		$	(16	)	$	303
Gain (loss) on sale		2,240			(1	)		2,239			-			-			-			-			-			-
Adjustments for contingencies ⁽¹⁾		-			(25	)		(25	)		-			-			-			-			-			-
Pretax income (loss) from
discontinued operations		2,767			(26	)		2,741			270			(17	)		253			319			(16	)		303
Income tax (expense) benefit		(487	) (2)		9			(478	)		(119	)		6			(113	)		(210	)		6			(204	)
Minority interest, net of tax		-			2			2			-			-			-			-			-			-
Income (loss) from discontinued
operations, net of tax	$	2,280		$	(15	)	$	2,265		$	151		$	(11	)	$	140		$	109		$	(10	)	$	99

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

⁽²⁾

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

The company was required to use 100% of the net after-tax cash proceeds from sales of certain assets to repay debt. Because the North Sea oil and gas assets were subject to this requirement, $92 million of interest expense on debt that was required to be repaid upon their sale is classified as a component of income from discontinued operations. This amount represents interest expense on approximately $3.1 billion of the company’s obligations under the term loans described in Note 10, which was required to be repaid upon completing the North Sea divestiture transactions. Interest expense was allocated to discontinued operations beginning in May 2005, to coincide with initial borrowings under the term loans requiring mandatory prepayments.

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

	2005			2004			2003

U.S. statutory tax rate		35.0	%		35.0	%		35.0	%
Increases (decreases) resulting from -
Taxation of foreign operations		3.2			9.9			13.2
Effect of book and tax basis differences of investment
in subsidiary stock		8.7			-			-
Utilization of foreign tax credits		(25.8	)		-			-
Utilization of capital loss carryforwards		(4.0	)		-			-
Provision for U.S. income taxes on U.K. remittances⁽¹⁾		-			-			19.4
State income taxes		.2			-			-
Other - net		.1			(.2	)		(.3	)
Effective tax rate		17.4	%		44.7	%		67.3	%

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

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

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

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

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

Assets Held for Sale - Assets reported as held for sale at December 31, 2004 and associated liabilities in the Consolidated Balance Sheet consist primarily of assets and liabilities of the company's North Sea oil and gas business that was sold in 2005. At December 31, 2005, the company had assets held for sale of $5 million, associated with certain noncore assets in the U.S. expected to be sold in 2006. The company expects that selling prices of these assets less cost to sell will exceed their carrying value.

Subsequent to December 31, 2005, the company's interests in oil and gas properties on the Gulf of Mexico shelf met the criteria for reporting as held for sale. The company expects to complete the sale in the second quarter of 2006. The following presents the main classes of assets and liabilities associated with the Gulf of Mexico shelf properties as of December 31, 2005 (in millions of dollars):

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

3. Separation of Tronox

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

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

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

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

4. Westport Resources Merger

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

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

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

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

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

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

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

· Enhances the stability of high-margin production

· Expands low-risk exploitation opportunities

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

· Reduces leverage and enables greater financial flexibility

· Provides opportunities for synergies and related cost savings

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

(Millions of dollars)

Assets
Current assets	$	291
Property, plant and equipment		3,494
Other assets		39
Goodwill		804

Total Assets	$	4,628

Liabilities and Stockholders’ Equity
Current liabilities	$	360

Long-term debt		1,046
Deferred income taxes		656
Other liabilities		118
Total Noncurrent Liabilities		1,820

Stockholders’ Equity		2,448

Total Liabilities and Stockholders’ Equity	$	4,628

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

	Pro Forma Information
	(Unaudited)
	Year Ended
	December 31,
(Millions of dollars, except per-share amounts)	2004		2003

Revenues	$	4,848	$	4,017

Income from continuing operations		325		198
Net income		465		258

Net income per common share -
Basic	$	3.10	$	1.73
Diluted		3.08		1.71

5. Statement of Income Data

Asset Impairments - Impairment losses of $17 million in 2005 related primarily to a U.S. onshore property in Texas where unsuccessful drilling resulted in a reduction in proved undeveloped reserves ($10 million) and two U.S. Gulf of Mexico shelf properties that ceased producing in the first quarter. Impairment losses of $20 million in 2004 related primarily to a U.S. Gulf of Mexico field that ceased production sooner than expected. The 2003 impairments of $14 million related to mature oil and gas producing assets in the U.S. onshore and Gulf of Mexico shelf areas.

Additionally, in 2004 Tronox recognized an impairment loss of $8 million associated with the shutdown of sulfate-process titanium dioxide pigment production at its Savannah, Georgia facility. See Note 14 for information on other provisions related to the shutdown.

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

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

(Millions of dollars)	2005			2004			2003

Gain on sale of nonoperating interest in gas
processing facility ⁽¹⁾	$	120		$	-		$	-
Equity in net losses of equity method investees		(19	)		(26	)		(33	)
Net foreign currency transaction loss		(2	)		(13	)		(5	)
Gain on sale of Devon stock⁽²⁾		-			9			17
DECS and Devon stock revaluation		-			2			8
Interest income		10			4			2
Loss on accounts receivables sales and other		(5	)		(10	)		(14	)
Total	$	104		$	(34	)	$	(25	)

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

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

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

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

	2005						2004						2003
	Income						Income						Income
(Millions of dollars , except	from				Per-		from				Per-		from				Per-
per-share amounts, and	Continuing				share		Continuing				share		Continuing				share
thousands of shares)	Operations		Shares		Income		Operations		Shares		Income		Operations		Shares		Income

Basic earnings per share	$	946		131,012	$	7.22	$	264		126,313	$	2.09	$	155		100,145	$	1.55
Effect of dilutive securities:
5.25% convertible
debentures		4		1,585				-		-				-		-
Restricted stock and
stock options		-		1,889				-		782				-		714
Diluted earnings per share	$	950		134,486	$	7.07	$	264		127,095	$	2.08	$	155		100,859	$	1.54

The weighted average of diluted shares outstanding during 2004 and 2003 does not include the effect of employee stock options that were antidilutive because they were not “in the money” during the respective years. At December 31, 2004 and 2003 there were 3 million and 4.9 million of such options outstanding, with weighted average exercise prices of $63.63 and $60.26, respectively. All options outstanding at December 31, 2005 were “in the money.”

In March 2005, all of the 5.25% debentures were converted by the holders into 9.8 million shares of common stock. Accordingly, shares issued upon conversion of the debentures are included in basic earnings per share from the conversion date. The effect of these convertible debentures was excluded from the determination of diluted earnings per share for 2004 and 2003 because they were antidilutive.

In January 2006, the Board of Directors approved a $1 billion stock repurchase program. Assuming a per-share acquisition cost of $100, the company expects to repurchase 10 million shares in the open market in 2006. Additionally, as discussed in Note 19, subsequent to year-end 2005 the company issued additional stock options and restricted stock to its employees.

6. Balance Sheet Data

Inventories - Major categories of inventories at December 31, 2005 and 2004 are:

(Millions of dollars)	2005		2004

Chemicals and other products	$	250	$	236
Materials and supplies		97		71
Crude oil		5		7
Total	$	352	$	314

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

					Accumulated
					Depreciation and
	Gross Property				Depletion						Net Property
(Millions of dollars)	2005		2004		2005			2004			2005		2004

Exploration and production	$	13,490	$	12,553	$	(5,108	)	$	(4,443	)	$	8,382	$	8,110
Chemical		2,080		2,059		(1,244	)		(1,184	)		836		875
Other		148		195		(91	)		(107	)		57		88
Total	$	15,718	$	14,807	$	(6,443	)	$	(5,734	)	$	9,275	$	9,073

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

(Millions of dollars)	2005		2004

Prepaid pension cost	$	249	$	239
Investment in equity method investees		89		112
Nonqualified benefit plan deposits		48		48
Unamortized debt issue costs		38		24
Long-term derivative assets		35		15
Long-term accounts receivable and other assets		49		46
Total	$	508	$	484

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

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

	Segment
(Millions of dollars)	Exploration and Production			Chemical - Pigment			Total Carrying Amount

Balance at December 31, 2003 -	$	346		$	11		$	357
Goodwill associated with the Westport merger		839			-			839
Other changes (including foreign currency translation)		-			1			1
Balance at December 31, 2004 -		1,185			12			1,197
Tax-related adjustment to goodwill		(35	)		-			(35	)
Other changes (including foreign currency translation)		-			(1	)		(1	)
Balance at December 31, 2005 -	$	1,150		$	11		$	1,161

The changes in the carrying amount of indefinite-lived intangible assets for 2005 and 2004 are as follows. Additional information on the Savannah sulfate plant shutdown is provided in Note 14.

(Millions of dollars)	Carrying Amount

Proprietary Technology
Balance at December 31, 2003 -	$	55
Impairment associated with the Savannah sulfate plant shutdown		(8	)
Other changes (including foreign currency translation)		6
Balance at December 31, 2004 -		53
Other changes (including foreign currency translation)		(3	)
Balance at December 31, 2005 -	$	50

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

(Millions of dollars)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount

Balance at December 31, 2004 -
Transportation contracts	$	49	$	(13	)	$	36
Other		3		(1	)		2
Total	$	52	$	(14	)	$	38

Balance at December 31, 2005 -
Transportation contracts	$	49	$	(21	)	$	28
Other		3		(3	)		-
Total	$	52	$	(24	)	$	28

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

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

(Millions of dollars)	2005		2004

Accrued operating expenses and exploration
and development costs	$	406	$	261
Employee-related costs and benefits⁽¹⁾		165		156
Reserves for environmental remediation and restoration		90		97
Interest payable		72		97
Taxes other than income taxes		89		71
Asset retirement obligations		24		17
Other		69		56
Total	$	915	$	755

⁽¹⁾	Includes current portion of liabilities for pension and other postretirement benefits of $25 million and $29 million, respectively.

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

(Millions of dollars)	2005		2004

Postretirement benefit liability	$	210	$	209
Reserves for environmental remediation and restoration		178		158
Pension benefit liability		75		47
Litigation reserves		26		24
Accrued rent for spar operating leases		54		46
Ad valorem taxes		39		33
Other		79		54
Total	$	661	$	571

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

(Millions of dollars)	2005			2004

Balance at January 1	$	524		$	421
Obligations incurred, including obligations acquired		42			30
Liability assumed in the Westport merger		-			79
Accretion expense		30			30
Changes in estimates, including timing		(32	)		(16	)
Abandonment expenditures		(19	)		(17	)
Obligations settled through divestitures		(195	)		(3	)
Adoption of FIN No. 47 ⁽¹⁾		19			-
Balance at December 31		369			524
Less: Asset retirement obligations associated with assets held for sale		-			(171	)
Less: Current asset retirement obligation		(24	)		(17	)
Noncurrent asset retirement obligation	$	345		$	336

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

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

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

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

7. Cash Flow Statement Data

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

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

(Millions of dollars)	2005			2004			2003

Income tax payments	$	481		$	154		$	115
Less: refunds received		(30	)		(19	)		(49	)
Net income tax payments	$	451		$	135		$	66

Interest payments	$	345		$	247		$	227

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

(Millions of dollars)	2005		2004			2003

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

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

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

(Millions of dollars)	2005			2004			2003

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

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

(Millions of dollars)	2005			2004			2003

Noncash investing activities -
Increase in property, plant and equipment associated with -
Westport merger	$	-		$	3,494		$	-
Asset retirement obligations incurred
(including changes in estimates)		7			7			30
Asset retirement costs recognized upon adopting a new
accounting standard		19			-			108
Gunnison Trust ⁽¹⁾		-			(83	)		83
Trading securities used for redemption of long-term debt ⁽²⁾		-			(586	)		-
Increase in fair value of securities available for sale ⁽²⁾		-			-			9

Noncash financing activities -
Common stock and stock options issued in connection with
the Westport merger	$	-		$	2,448		$	-
Increase (decrease) in debt associated with -
Conversion of 5.25% debentures to common stock		(600	)		-			-
Westport merger		-			1,046			-
Gunnison Trust ⁽¹⁾		-			(75	)		75
Debt redemption with trading securities ⁽²⁾		-			(330	)		-
Settlement of DECS derivative ⁽²⁾		-			(256	)		-
Increase in valuation of the DECS ⁽²⁾		-			-			8

⁽¹⁾

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

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

8. Other Comprehensive Income (Loss)

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

(Millions of dollars)	2005			2004			2003

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

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

(Millions of dollars)	2005			2004

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

9. Derivative Instruments

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

The following tables summarize the balance sheet presentation of the company’s derivatives as of December 31, 2005 and 2004. Derivative assets and liabilities associated with the company’s North Sea oil and gas business, which was sold in 2005, are included in assets and liabilities held for sale in the Consolidated Balance Sheet at December 31, 2004.

	December 31, 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	$	101	$	34	$	(1,422	)	$	(658	)	$	(1,095	)
Acquired Westport positions		-		-		(70	)		-			-
Gas marketing-related derivatives ⁽²⁾		13		1		(14	)		-			-
Foreign currency derivatives		1		-		-			-			1
Interest rate swaps		-		-		-			(5	)		-
Other		-		-		(2	)		-			(1	)
Total derivative contracts	$	115	$	35	$	(1,508	)	$	(663	)	$	(1,095	)

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

Oil and gas commodity derivatives -
Kerr-McGee positions	$	41		$	12	$	(213	)	$	(188	)	$	(174	)
Acquired Westport positions		1			1		(123	)		(16	)		(7	)
Gas marketing-related derivatives ⁽²⁾		6			2		(6	)		(2	)		-
Foreign currency derivatives		(2	)		-		(6	)		-			(2	)
Interest rate swaps		4			-		(1	)		(2	)		-
Other derivatives		3			-		(1	)		-			1
Total - continuing operations		53			15		(350	)		(208	)		(182	)
North Sea oil and gas business		35			-		(22	)		-			25
Total derivative contracts	$	88		$	15	$	(372	)	$	(208	)	$	(157	)

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

⁽²⁾

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

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

	2005								2004								2003
							Other							Other								Other
				Costs and			Income					Costs and		Income						Costs and		Income
(Millions of dollars)	Revenues			Expenses			(Expense)		Revenues			Expenses		(Expense)			Revenues			Expenses		(Expense)

Hedge Activity -
Oil and gas commodity derivatives	$	(655	)	$	-		$	-	$	(533	)	$	-	$	-		$	(215	)	$	-	$	-
Foreign currency derivatives		1			(3	)		-		(1	)		10		-			-			10		-
Interest rate swaps		-			(4	)		-		-			15		-			-			11		-
Other derivatives		-			8			-		-			1		-			-			-		-
Gain (loss) on hedge ineffectiveness		(206	)		-			-		4			-		-			(1	)		-		-
Total hedging contracts		(860	)		1			-		(530	)		26		-			(216	)		21		-

Nonhedge Activity -
Oil and gas commodity derivatives -
Kerr-McGee positions		75			-			-		(10	)		-		1			-			-		2
Acquired Westport positions		(113	)		-			-		(13	)		-		-			-			-		-
Overhedge derivative loss		(119	)		-			-		-			-		-			-			-		-
Gas marketing-related derivatives		6			-			-		7			-		(1	)		(7	)		-		(5	)
DECS call option (1)		-			-			-		-			-		(101	)		-			-		(88	)
Foreign currency derivatives		-			-			3		-			-		(8	)		-			-		(7	)
Total nonhedge contracts		(151	)		-			3		(16	)		-		(109	)		(7	)		-		(98	)

Total derivative contracts	$	(1,011	)	$	1		$	3	$	(546	)	$	26	$	(109	)	$	(223	)	$	21	$	(98	)

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

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

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

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

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

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

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

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

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

10. Debt

As discussed in Note 3, in November 2005, the company completed the IPO of Tronox Class A common stock. In March 2006, the Board of Directors approved the Distribution of Kerr-McGee’s remaining ownership interest in Tronox, which is expected to be completed before the end of the first quarter of 2006. Concurrent with the IPO, Tronox, through its wholly-owned subsidiaries, borrowed $550 million and entered into a senior secured credit agreement.

Lines of Credit

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

	Term	Period	Period	Available Capacity
Revolving Credit Facility	(years)	Effective	Terminated	at December 31, 2005

Kerr-McGee Corporation -
$1.5 billion unsecured facility	5	November 2004	May 2005	-
$1.25 billion senior secured facility⁽¹⁾	5	May 2005	January 2006	$1.18 billion
$1.25 billion unsecured facility ⁽²⁾	5	January 2006	Facility currently in effect	-

Tronox Incorporated -
$250 million senior secured facility ⁽³⁾	5	November 2005	Facility currently in effect	$216 million

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

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

_⁽³⁾

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

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

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

·	Consolidated Leverage Ratio of no more than 3.5:1

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

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

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

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

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

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

·	Consolidated Interest Coverage Ratio of at least 2:1

·	Limitation on Capital Expenditures

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

Long-Term Debt

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

	December 31,
(Millions of dollars)	2005			2004

Kerr-McGee Corporation -
Debentures
5.25% Convertible subordinated debentures due February 15, 2010
(convertible at $61.08 per share)	$	-		$	600
7% Debentures due November 1, 2011, net of unamortized
discount of $70 and $77 (14.25% effective rate) ⁽¹⁾		180			173
7.125% Debentures due October 15, 2027		150			150
Notes payable
5.375% Notes due April 15, 2005, including a premium of $4 in 2004
for fair value hedge adjustment		-			354
8.125% Notes due October 15, 2005, net of a discount of $1 in 2004
for fair value hedge adjustment		-			108
5.875% Notes due September 15, 2006, net of unamortized discount
of $1 in 2005 (6.23% effective rate)		306			307
6.625% Notes due October 15, 2007, net of discount of $5 and $2
for fair value hedge adjustment		145			148
6.875% Notes due September 15, 2011, net of unamortized discount
of $4 and $1 (6.99% effective rate)		671			674
6.95% Notes due July 1, 2024, net of unamortized discount of $12
in 2005 and $5 in 2004 (7.05% effective rate)		638			645
7.875% Notes due September 15, 2031, net of unamortized
discount of $7 and $2 (7.93% effective rate)		493			498
Commercial paper and other		-			42

Tronox Incorporated -
9.5% Notes due December 1, 2012		350			-
Variable-rate term loan due in installments through November 28, 2011		200			-
		3,133			3,699
Long-term debt due within one year		(308	)		(463	)

Total	$	2,825		$	3,236

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

											There-
(Millions of dollars)	2006		2007		2008		2009		2010		after ⁽¹⁾		Total ⁽²⁾

Kerr-McGee debt	$	306	$	145	$	-	$	-	$	-	$	2,132	$	2,583
Tronox debt		2		2		2		2		2		540		550
Total long-term debt	$	308	$	147	$	2	$	2	$	2	$	2,672	$	3,133

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

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

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

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

(Million of dollars)	Mandatory Prepayment		Optional Prepayment		Total		Debt Issue Costs Written Off

Transactions Resulting in Prepayments -
Sale of the North Sea oil and gas business	$	3,072	$	102	$	3,174	$	28
Sale of nonoperating interest in gas processing facility		111		39		150		1
Tronox initial public offering		800		120		920		9
	$	3,983	$	261	$	4,244	$	38
Scheduled principal payment						6
Total term loan repayments					$	4,250

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

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

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

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

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

12. Financial Instruments

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

DECS and Investment in Devon Stock

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

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

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

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

Financial Instruments for Other than Trading Purposes

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

2005

2004

Carrying

Fair

Carrying

Fair

(Millions of dollars)

Amount

Value

Amount

Value

Cash and cash equivalents

1,053

Long-term debt

3,133

3,414

3,699

4,039

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

13. Income Taxes

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

(Millions of dollars)	2005		2004		2003

U.S. Federal -
Current	$	364	$	26	$	(35	)
Deferred		45		83		11
		409		109		(24	)
International -
Current		46		12		-
Deferred		21		13		6
		67		25		6
State		11		3		3
Total	$	487	$	137	$	(15	)

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

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

	2005			2004			2003

U.S. statutory tax rate		35.0	%		35.0	%		35.0	%
Increases (decreases) resulting from -
Charitable contribution		-			-			(3.7	)
U.S. federal tax audit settlement		-			-			(41.9	)
Adjustment of deferred tax balances due
to tax rate changes		(.2	)		(1.0	)		-
Taxation of foreign operations		(1.2	)		1.4			(2.0	)
State income taxes		.5			.5			1.6
Other - net		(.1	)		(1.7	)		.3
Effective tax rate		34.0	%		34.2	%		(10.7	)%

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

(Millions of dollars)	2005		2004		2003

United States	$	1,209	$	339	$	162
International		225		62		(22	)
Total	$	1,434	$	401	$	140

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

(Millions of dollars)	2005			2004

Deferred tax liabilities -
Property, plant and equipment	$	1,914		$	1,932
Undistributed earnings of certain foreign subsidiaries		28			28
Deferred state, local and other taxes		38			16
Intangible assets		16			31
Other		29			53
Deferred tax liabilities of discontinued operations		-			518
Total deferred tax liabilities		2,025			2,578

Deferred tax assets -
Net operating loss and other carryforwards		(33	)		(201	)
Derivative instruments		(694	)		(123	)
Asset retirement and environmental obligations		(201	)		(149	)
Foreign exploration expenses		(59	)		(83	)
Obligations for pension and other benefits		(47	)		(28	)
Financial accruals and deferrals		(50	)		(59	)
Other		(4	)		(23	)
Deferred tax assets of discontinued operations		-			(67	)
		(1,088	)		(733	)
Valuation allowance associated with loss carryforwards -
- Continuing operations		6			6
- Discontinued operations		-			2
Net deferred tax assets		(1,082	)		(725	)

Net deferred tax liability		943			1,853
Less: net deferred tax liability of discontinued operations⁽¹⁾		-			453
Net deferred tax liability - continuing operations	$	943		$	1,400

⁽¹⁾

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

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

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

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

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

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

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

14. Exit, Disposal and Restructuring Activities

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

	Reserve Activity									Other Activity
	Dismantlement			Personnel						Asset		Benefit		Total
(Millions of dollars)	and Closure			Costs			Total			Write-downs		Plan Charges		Charges

Balance at December 31, 2002	$	23		$	4		$	27
Provisions / Accruals		12			37			49		$	20	$	48	$	117
Payments		(18	)		(16	)		(34	)
Adjustments⁽¹⁾		(5	)		2			(3	)						(1	)
Balance at December 31, 2003		12			27			39						$	116

Provisions / Accruals		17			23			40		$	114	$	6	$	160
Payments		(16	)		(40	)		(56	)
Adjustments⁽¹⁾		1			(2	)		(1	)						(1	)
Balance at December 31, 2004		14			8			22						$	159

Provisions / Accruals		-			29			29		$	-	$	3	$	32
Payments		(6	)		(15	)		(21	)
Adjustments⁽¹⁾		(2	)		(1	)		(3	)						(3	)
Balance at December 31, 2005	$	6		$	21		$	27						$	29

Costs expected to be incurred in
excess of established reserves (2)	$	-		$	12		$	12

Expected payments -
2006	$	4		$	31		$	35
2007 and thereafter		2			2			4

⁽¹⁾	Includes effects of foreign currency translation

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

The following summarizes costs associated with exit, disposal and restructuring activities incurred in the last three years by each of the company's reportable segments and their classification in the company's financial statements (accruals for severance associated with the Westport merger were reflected in the purchase price allocation as an assumed liability):

(Millions of dollars)	2005			2004		2003
Costs and charges by reportable segment -
Exploration and production	$	15		$	1	$	14
Chemical - pigment		(1	)		129		64
Chemical - other		(2	)		-		2
Corporate costs not allocated to segments		15			1		19
Subtotal - income from continuing operations		27			131		99
Costs reflected in income from discontinued operations (pretax)		2			10		17
Severance costs associated with the Westport merger		-			18		-
Total	$	29		$	159	$	116

Classification of costs and charges in income from continuing operations -
Costs and operating expenses	$	-		$	32	$	33
Selling, general and administrative expenses		27			3		48
Depreciation and depletion		-			87		15
Asset impairments		-			7		-
Taxes other than income		-			1		2
Provision for environmental remediation and
restoration, net of reimbursements		-			1		1
Total	$	27		$	131	$	99

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

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

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

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

15. Employee Benefit Plans

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

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

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

							Postretirement
	Retirement Plans						Health and Life Plans
(Millions of dollars)	2005			2004			2005			2004

Change in benefit obligations -
Benefit obligation, beginning of year	$	1,172		$	1,175		$	276		$	314
Service cost		32			26			3			3
Interest cost		66			68			16			18
Plan amendments/law changes ⁽¹⁾		-			1			-			(72	)
Net actuarial loss		84			91			24			38
Foreign currency rate changes		(11	)		6			-			-
Contributions by plan participants		-			-			9			9
Special termination benefits, settlement
and curtailment (gains) losses		3			(1	)		-			-
Benefits paid		(91	)		(194	)		(31	)		(34	)
Benefit obligation, end of year		1,255			1,172			297			276
Change in plan assets -
Fair value of plan assets, beginning of year		1,168			1,239			-			-
Actual return on plan assets		54			102			-			-
Employer contributions ⁽²⁾		9			16			22			25
Participant contributions		-			-			9			9
Foreign currency rate changes		(8	)		5			-			-
Benefits paid		(91	)		(194	)		(31	)		(34	)
Fair value of plan assets, end of year ⁽³⁾		1,132			1,168			-			-

Funded status of plans - under funded		(123	)		(4	)		(297	)		(276	)
Amounts not recognized in the Consolidated
Balance Sheet -
Prior service costs		42			49			(14	)		(16	)
Net actuarial loss		282			159			80			59
Net prepaid expense (accrued liability) recognized	$	201		$	204		$	(231	)	$	(233	)
Classification of amounts recognized in the
Consolidated Balance Sheet -
Prepaid pension cost	$	249		$	239		$	-		$	-
Accrued benefit liability		(79	)		(55	)		(231	)		(233	)
Accumulated other comprehensive loss (pretax)		31			20			-			-
Total	$	201		$	204		$	(231	)	$	(233	)

⁽¹⁾

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

⁽²⁾

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

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

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

At December 31, 2005

At December 31, 2004

U.S.

Germany

U.S.

Germany

Nonqualified

Postretirement

Retirement

Nonqualified

Postretirement

Retirement

(Millions of dollars)

Plans ⁽¹⁾

Plan

Plans ⁽¹⁾

Plan

Accumulated benefit obligation

297

276

Projected benefit obligation

297

276

⁽¹⁾

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

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

	At December 31, 2005						At December 31, 2004
	U.S.			The Netherlands			U.S.		The Netherlands
	Qualified			Retirement			Qualified		Retirement
(Millions of dollars)	Plan			Plan			Plan		Plan

Accumulated benefit obligation	$	990		$	59		$	941	$	61

Projected benefit obligation	$	1,093		$	68		$	1,034	$	70
Market value of plan assets		1,070			62			1,109		59
Funded status - (under)/over funded	$	(23	)	$	(6	)	$	75	$	(11	)

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

											2011-
(Millions of dollars)	2006		2007		2008		2009		2010		2015

Retirement Plans	$	92	$	102	$	90	$	94	$	97	$	478
Postretirement Health and Life Plans		21		21		21		21		21		106

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

Net Periodic Cost - Income from continuing operations for 2005, 2004 and 2003 includes the following components of net periodic cost:

										Postretirement
	Retirement Plans									Health and Life Plans
(Millions of dollars)	2005			2004			2003			2005			2004		2003

Net periodic cost -
Service cost	$	32		$	26		$	22		$	3		$	3	$	3
Interest cost		66			68			70			16			18		16
Expected return on plan assets		(99	)		(113	)		(119	)		-			-		-
Special termination benefits, settlement
and curtailment losses		3			14			30			-			-		10
Net amortization -
Prior service cost		8			8			9			(2	)		1		-
Net actuarial (gain) loss		5			1			(10	)		3			2		-
Total	$	15		$	4		$	2		$	20		$	24	$	29

Net periodic pension cost for the year ended December 31, 2005 includes special termination benefits resulting from an involuntary termination program initiated by the company in October 2005. The 2004 net periodic cost includes special termination benefit and curtailment costs associated with the shutdown of sulfate production at the Savannah, Georgia, facility and plan settlement losses related to normal retirements and retirements resulting from the work force reduction program initiated in 2003. The 2003 net periodic cost includes special termination benefit and curtailment costs associated with the shutdown of Tronox’s Mobile, Alabama facility and curtailment costs associated with the 2003 work force reduction program.

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

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

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

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

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

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

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

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

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

							The Netherlands
	U.S. Plan Assets						Plan Assets
	at December 31,						at December 31,
	2005			2004			2005			2004

Equity securities		55	%		57	%		28	%		24	%
Debt securities		42			41			63			76
Cash and cash equivalents		3			2			9			-
Total		100	%		100	%		100	%		100	%

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

Substantially all of the plan’s assets are invested with eight equity fund managers and six fixed-income fund managers. At year-end 2005 and 2004, equity securities held by the plan included $5 million and $3 million of Kerr-McGee stock, respectively, or 50,737 shares. Dividends paid on these shares were less than $100,000 in 2005 and 2004. To control risk, equity fund managers are prohibited from entering into the following transactions, (i) investing in commodities, including all futures contracts, (ii) purchasing letter stock, (iii) short selling and (iv) option trading. In addition, equity fund managers are prohibited from purchasing on margin and are prohibited from purchasing Kerr-McGee securities. Equity managers are monitored to ensure investments are in line with their style and are generally permitted to invest in U.S. common stock, U.S. preferred stock, U.S. securities convertible into common stock, common stock of foreign companies listed on major U.S. exchanges, common stock of foreign companies listed on foreign exchanges, covered call writing, and cash and cash equivalents.

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

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

16. Contingencies

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

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

Because Tronox is a consolidated subsidiary of Kerr-McGee as of December 31, 2005, the Consolidated Balance Sheet reflects Tronox’s liabilities for environmental remediation and restoration costs that are probable and estimable. The accompanying financial statements do not include any effects of the reimbursement obligation discussed above between the parties within the consolidated group. It is expected that upon completion of the Distribution, Tronox will no longer be a consolidated subsidiary of Kerr-McGee, at which time Kerr-McGee will recognize a liability associated with its reimbursement obligation. The liability will initially be measured at its estimated fair value.

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

			Reserves for
	Legal		Environmental		Reimbursements
(Millions of dollars)	Reserves		Remediation		Receivable

Tronox	$	9	$	224	$	57
Other Kerr-McGee		21		44		-
Balance at December 31, 2005	$	30	$	268	$	57

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

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

Balance at December 31, 2002	$	73		$	258		$	113
Provisions / Accruals		8			94			32
Payments / Settlements		(44	)		(104	)		(15	)
Balance at December 31, 2003		37			248			130
Provisions / Accruals ⁽²⁾		15			106			14
Payments / Settlements		(13	)		(99	)		(50	)
Balance at December 31, 2004		39			255			94
Provisions / Accruals		9			84			35
Payments / Settlements		(18	)		(71	)		(72	)
Balance at December 31, 2005	$	30		$	268		$	57

⁽¹⁾

Provisions for environmental remediation and restoration in 2005, 2004 and 2003 include $11 million, $6 million and $2 million, respectively, related to Tronox’s former forest products operations. These charges are reflected in the Consolidated Statement of Income as a component of income from discontinued operations (net of tax).

⁽²⁾	The 2004 accruals for litigation include a $7 million increase in the reserve upon Kerr-McGee’s assumption of contingent obligations in connection with the Westport merger.

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

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

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

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

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

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

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

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

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

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

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

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

Contingencies of Tronox

Environmental

Henderson, Nevada

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

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

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

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

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

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

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

West Chicago, Illinois

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

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

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

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

Government Reimbursement - Pursuant to Title X, the U.S. Department of Energy (DOE) is obligated to reimburse Tronox LLC for certain decommissioning and cleanup costs incurred in connection with the West Chicago sites in recognition of the fact that about 55% of the facility's production was dedicated to U.S. government contracts. The amount authorized for reimbursement under Title X is $365 million plus inflation adjustments. That amount is expected to cover the government's full share of West Chicago cleanup costs. Through December 31, 2005, Tronox LLC had been reimbursed approximately $281 million under Title X.

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

Ambrosia Lake, New Mexico

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

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

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

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

Milwaukee, Wisconsin

In 1976, Tronox LLC closed a wood-treatment facility it had operated in Milwaukee, Wisconsin. Operations at the facility prior to its closure had resulted in the contamination of soil and groundwater at and around the site with creosote and other substances used in wood treating. In 1984, EPA designated the Milwaukee wood-treatment facility as a Superfund site under CERCLA, listed the site on the NPL and named Tronox LLC as a PRP. Tronox LLC executed a consent decree in 1991 that required it to perform soil and groundwater remediation at and below the former wood-treatment area and to address a tributary creek of the Menominee River that had become contaminated as a result of the wood-treatment operations. Actual remedial activities were deferred until after the decree was finally entered in 1996 by a federal court in Milwaukee.

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

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

New Jersey Wood-Treatment Site

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

Cushing, Oklahoma

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

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

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

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

Litigation and Claims

Forest Products Litigation

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

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

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

Kemira

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

Other Sites and Matters

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

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

Other Contingencies of Kerr-McGee

Los Angeles County, California

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

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

Other Sites and Matters

Deepwater Royalty Relief Act

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

Other

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

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

17. Commitments

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

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

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

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

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

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

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

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

18. Capital Stock

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

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

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

In January 2006, the Board of Directors approved a $1 billion stock repurchase program. Assuming a per-share acquisition cost of $100, the company expects to repurchase 10 million shares in the open market in 2006. As of March 14, 2006, approximately 3.3 million shares of Kerr-McGee’s stock had been repurchased at an aggregate cost of $347 million.

Changes in common stock issued and treasury stock held for 2005, 2004 and 2003 are as follows:

	Common			Treasury
(Thousands of shares)	Stock			Stock

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

There are 1,107,692 shares of the company’s common stock registered in the name of a wholly-owned subsidiary of the company. These shares are not included in the number of shares shown in the preceding table or in the Consolidated Balance Sheet. These shares are not entitled to be voted.

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

19. Employee Stock-Based Compensation Plans

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

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

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

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

	Contractual	Vesting			Cash- or
	Life	Period	Vesting		Stock-	Vesting and Other
	(years)	(years)	Term		Settled	Conditions

Stock options	10	3	Graded	⁽¹⁾	Stock	Employee service
Restricted stock	not applicable	3	Cliff	⁽²⁾	Stock	Employee service
Performance units ⁽³⁾	3	3	Cliff	⁽²⁾	Cash	Employee service and
						achievement of specified
						stockholder return targets

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

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

⁽³⁾

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

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

(Millions of dollars)	2005		2004		2003

Stock options	$	9	$	1	$	-
Restricted stock		22		15		10
Performance units		19		2		-
Total	$	50	$	18	$	10

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

Restricted Stock - The following summarizes information about shares of restricted stock granted during the last three years:

	2005		2004		2003

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

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

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

	2005		2004		2003

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

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

Stock Options - The following table summarizes the stock option transactions during 2005, 2004 and 2003 under Kerr-McGee’s compensation plans and in connection with the Westport merger. As discussed in Note 4, on June 25, 2004, the company completed its merger with Westport. In connection with the merger, the company exchanged Westport options outstanding as of the merger date for Kerr-McGee options based on the exchange factor set forth in the merger agreement.

	2005					2004					2003
	Options			Price ⁽¹⁾		Options			Price ⁽¹⁾		Options			Price ⁽¹⁾

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

⁽¹⁾	Represents weighted average exercise price.

The following table summarizes information about stock options issued under the plans described above that are outstanding and exercisable at December 31, 2005. Approximately 160,000 Kerr-McGee options held by Tronox employees are expected to be forfeited, as discussed above under Effect of Tronox Separation.

	Options Outstanding						Options Exercisable
Range of			Contractual
Exercise Prices	Options		Life (years) (1)		Price (1)		Options		Price (1)

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

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

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

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

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

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

(Thousands of shares)	2005		2004

Participants’ accounts		1,119		1,432
Loan suspense account		187		246

The shares in the loan suspense account at December 31, 2005, included approximately 11,000 released shares that were allocated to participants’ accounts in January 2006. At December 31, 2004, the shares in the loan suspense account included approximately 17,000 released shares that were allocated to participants’ accounts in January 2005.

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

20. Reporting by Business Segments and Geographic Locations

The company has three operating segments: oil and gas exploration and production, production and marketing of titanium dioxide pigment, and production and marketing of other chemical products. These segments are managed separately because of their distinctly different products, operating environments and capital expenditure requirements. We routinely review the operating results of these segments individually to make decisions about resources to be allocated to the segment and to assess their individual performance. 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 and China. Exploration efforts also extend to the North Slope of Alaska and offshore West Africa, Brazil and Trinidad and Tobago. The chemical business is conducted by Tronox and its subsidiaries. Tronox primarily produces and markets titanium dioxide pigment and has production facilities in the United States, Australia, Germany and the Netherlands. Other chemical products segment represents Tronox’s U.S. electrolytic manufacturing and marketing operations. Segment performance is evaluated based on operating profit (loss), which represents results of operations before considering general corporate expenses, interest and debt expense, environmental provisions related to businesses in which the company’s affiliates are no longer engaged, other income (expense) and income taxes.

For the years ended December 31, 2005, 2004 and 2003, natural gas sales to Cinergy Marketing & Trading totaled $1.4 billion, $1 billion and $0.8 billion, respectively. Sales to subsidiary companies are eliminated as described in Note 1.

(Millions of dollars)	2005			2004			2003

Revenues -
Exploration and production	$	4,563		$	3,096		$	2,132
Chemical -
Pigment		1,267			1,209			1,079
Other		97			93			78
Total chemical		1,364			1,302			1,157
Total	$	5,927		$	4,398		$	3,289

Operating profit (loss) -
Exploration and production	$	1,755		$	973		$	649
Chemical -
Pigment		100			(80	)		(13	)
Other		(6	)		(2	)		(23	)
Total chemical		94			(82	)		(36	)
Total		1,849			891			613

Interest and debt expense		(253	)		(244	)		(250	)
Loss on early repayment and modification of debt		(42	)		-			-
Corporate expenses		(201	)		(130	)		(151	)
Provision for environmental remediation and restoration,
net of reimbursements ⁽¹⁾		(23	)		(82	)		(47	)
Other income (expense) ⁽²⁾		104			(34	)		(25	)
Benefit (provision) for income taxes		(487	)		(137	)		15
Minority interest, net of taxes		(1	)		-			-
Income from continuing operations	$	946		$	264		$	155

Depreciation, depletion and amortization -
Exploration and production ⁽³⁾	$	930		$	695		$	463
Chemical -
Pigment		91			182			110
Other		12			14			15
Total chemical		103			196			125
Other		11			9			8
Discontinued operations		133			224			218
Total	$	1,177		$	1,124		$	814

⁽¹⁾	Includes provisions, net of reimbursements, related to 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 16.

⁽²⁾

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

⁽³⁾	Includes amortization of nonproducing leasehold costs that is reported in exploration expense in the Consolidated Statement of Income.

(Millions of dollars)	2005			2004			2003

Capital expenditures -
Exploration and production	$	1,432		$	1,027		$	776
Chemical -
Pigment		79			83			90
Other		9			9			7
Total chemical		88			92			97
Other		15			18			15
Discontinued operations		216			125			93
Total	$	1,751		$	1,262		$	981

Total assets -
Exploration and production	$	11,127		$	10,260		$	5,348
Chemical -
Pigment		1,507			1,359			1,521
Other		243			184			213
Total chemical		1,750			1,543			1,734
Corporate and other assets		1,399			726			1,127
Discontinued operations		-			1,989			2,041
Total	$	14,276		$	14,518		$	10,250

Revenues -
U.S. operations	$	5,007		$	3,720		$	2,755
International operations -
China - exploration and production		312			92			23
Europe - pigment		369			361			313
Australia - pigment		239			225			198
		920			678			534
Total	$	5,927		$	4,398		$	3,289

Operating profit (loss) -
U.S. operations	$	1,696		$	880		$	634
International operations -
China - exploration and production		198			41			1
Other - exploration and production		(61	)		(52	)		(66	)
Europe - pigment		(12	)		(16	)		14
Australia - pigment		28			38			30
		153			11			(21	)
Total	$	1,849		$	891		$	613

Net property, plant and equipment -
U.S. operations	$	8,612		$	8,425		$	4,973
International operations -
China - exploration and production		252			226			165
Other - exploration and production		48			26			4
Europe - pigment		274			303			281
Australia - pigment		89			93			102
		663			648			552
Total	$	9,275		$	9,073		$	5,525

21. Costs Incurred in Crude Oil and Natural Gas Activities

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

(Millions of dollars)	Property Acquisition Costs			Exploration Costs⁽²⁾		Development Costs⁽³⁾		Total

2005 -
Continuing operations -
United States	$	56		$	373	$	1,212	$	1,641
China		-			21		81		102
Other international		14			64		-		78
Total - continuing operations		70	⁽¹⁾		458		1,293		1,821	⁽⁴⁾
Discontinued operations		21			57		141		219
Total costs incurred	$	91		$	515	$	1,434	$	2,040

2004 -
Continuing operations -
United States	$	3,477		$	231	$	757	$	4,465
China		1			19		75		95
Other international		25			51		-		76
Total - continuing operations		3,503	⁽¹⁾		301		832		4,636	⁽⁴⁾
Discontinued operations		4			36		110		150
Total costs incurred	$	3,507		$	337	$	942	$	4,786

2003 -
Continuing operations -
United States	$	122		$	357	$	475	$	954
China		1			31		45		77
Other international		1			49		-		50
Total - continuing operations		124	⁽¹⁾		437		520		1,081	⁽⁴⁾
Discontinued operations		54			43		55		152
Total costs incurred	$	178		$	480	$	575	$	1,233

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

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

⁽³⁾

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

⁽⁴⁾

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

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

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

												Loss (Gain) on			Income			Results of
			Production							Depreciation,		Asset Sales			Tax			Operations,
			(Lifting)		Other			Exploration		Depletion and		and			Expense			Producing
(Millions of dollars)	Revenues		Costs		Costs			Expenses		Accretion		Impairments			(Benefit)			Activities
2005 -
United States	$	3,374	$	560	$	256		$	298	$	789	$	(194	)	$	583		$	1,082
China		312		33		2			23		56		-			65			133
Other international		-		-		15			56		-		-			(29	)		(42	)
Total crude oil and
natural gas activities		3,686		593		273	⁽¹⁾		377		845		(194	)		619			1,173
Other (2)		877		-		899			-		15		-			(13	)		(24	)
Total - continuing
operations		4,563		593		1,172			377		860		(194	)		606			1,149
Discontinued operations		994		171		50			30		137		(2,240	)		1,026			1,820
Total	$	5,557	$	764	$	1,222		$	407	$	997	$	(2,434	)	$	1,632		$	2,969

2004 -
United States	$	2,520	$	385	$	189		$	265	$	620	$	50		$	355		$	656
China		92		13		5			11		22		(1	)		14			28
Other international		-		-		6			48		1		-			(19	)		(36	)
Total crude oil and
natural gas activities		2,612		398		200	⁽¹⁾		324		643		49			350			648
Other (2)		484		-		498			-		11		-			(7	)		(18	)
Total - continuing
operations		3,096		398		698			324		654		49			343			630
Discontinued operations		759		158		55			32		230		8			120			156
Total	$	3,855	$	556	$	753		$	356	$	884	$	57		$	463		$	786

2003 -
United States	$	1,775	$	236	$	149		$	249	$	400	$	(4	)	$	255		$	490
China		23		5		8			19		2		(12	)		1			-
Other international		-		-		6			59		1		-			(22	)		(44	)
Total crude oil and
natural gas activities		1,798		241		163	⁽¹⁾		327		403		(16	)		234			446
Other (2)		334		-		354			-		11		-			(11	)		(20	)
Total - continuing
operations		2,132		241		517			327		414		(16	)		223			426
Discontinued operations		797		146		63			27		220		(9	)		150			200
Total	$	2,929	$	387	$	580		$	354	$	634	$	(25	)	$	373		$	626

⁽¹⁾	^{_{Includes transportation, general and administrative expense, and taxes other than income taxes associated with oil and natural gas producing activities.}}

⁽²⁾	Includes gas marketing activities, gas processing plants, pipelines and other items that do not fit the definition of crude oil and natural gas producing activities but have been included above to reconcile to the segment presentations.

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

	2005		2004		2003

Average realized price of crude oil (per barrel) ⁽¹⁾ -
United States	$	42.55	$	29.11	$	26.14
China		44.45		32.37		29.66
Average - continuing operations		42.89		29.38		26.24

Average realized price of natural gas (per Mcf) ⁽¹⁾ -
United States	$	6.66	$	5.24	$	4.56

Lifting costs (per barrel of oil equivalent) -
United States	$	6.12	$	4.63	$	3.57
China		4.79		4.37		6.02
Average - continuing operations		6.03		4.63		3.61

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

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

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

(Millions of dollars)	2005		2004

Capitalized costs -
Proved properties	$	11,615	$	10,467
Unproved properties		1,427		1,674
Other		448		412
		13,490		12,553
Assets held for sale		8		4,183
Total		13,498		16,736

Accumulated depreciation, depletion and amortization -
Proved properties		4,744		4,154
Unproved properties		248		190
Other		116		99
		5,108		4,443
Assets held for sale		3		2,424
Total		5,111		6,867

Net capitalized costs	$	8,387	$	9,869

Exploratory Drilling Costs

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

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

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

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

(Millions of dollars)	2005			2004			2003

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

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

			Costs Incurred
(Millions of dollars)	Total		2005			2004		2003

Gulf of Mexico ⁽¹⁾	$	98	$	68		$	5	$	25
Alaska		68		48			20		-
Brazil		30		20			10		-
China		8		(1	)		9		-
Other		4		4			-		-
Total capitalized exploratory drilling costs	$	208	$	139		$	44	$	25

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

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

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

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

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

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

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

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

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

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

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

·	Independent third-party procedures and methods assessment

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

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

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

	Continuing Operations
Crude Oil, Condensate and Natural Gas Liquids	United									Discontinued
(Millions of barrels)	States			China			Total			Operations			Total

Proved developed and undeveloped reserves -
Balance at December 31, 2002		241			35			276			211			487
Revisions of previous estimates		7			2			9			(7	)		2
Purchases of reserves in place		3			-			3			12			15
Sales of reserves in place		(16	)		(3	)		(19	)		(9	)		(28	)
Extensions, discoveries and other additions		55			6			61			14			75
Production		(28	)		(1	)		(29	)		(26	)		(55	)
Balance at December 31, 2003		262			39			301			195			496
Revisions of previous estimates		9			1			10			6			16
Purchases of reserves in place		67			-			67			-			67
Sales of reserves in place		(10	)		-			(10	)		-			(10	)
Extensions, discoveries and other additions		14			-			14			1			15
Production		(32	)		(3	)		(35	)		(23	)		(58	)
Balance at December 31, 2004		310			37			347			179			526
Revisions of previous estimates		31			2			33			1			34
Purchases of reserves in place		1			-			1			4			5
Sales of reserves in place		(27	)		-			(27	)		(168	)		(195	)
Extensions, discoveries and other additions		40			8			48			3			51
Production		(33	)		(7	)		(40	)		(19	)		(59	)
Balance at December 31, 2005		322			40			362			-			362


Natural Gas (Billions of cubic feet)

Proved developed and undeveloped reserves -
Balance at December 31, 2002		2,779			-			2,779			496			3,275
Revisions of previous estimates		(10	)		-			(10	)		11			1
Purchases of reserves in place		57			-			57			30			87
Sales of reserves in place		(77	)		-			(77	)		-			(77	)
Extensions, discoveries and other additions		152			-			152			8			160
Production		(230	)		-			(230	)		(35	)		(265	)
Balance at December 31, 2003		2,671			-			2,671			510			3,181
Revisions of previous estimates		86			-			86			(98	)		(12	)
Purchases of reserves in place		1,289			-			1,289			-			1,289
Sales of reserves in place		(27	)		-			(27	)		-			(27	)
Extensions, discoveries and other additions		59			-			59			-			59
Production		(306	)		-			(306	)		(31	)		(337	)
Balance at December 31, 2004		3,772			-			3,772			381			4,153
Revisions of previous estimates		128			-			128			26			154
Purchases of reserves in place		19			-			19			9			28
Sales of reserves in place		(208	)		-			(208	)		(396	)		(604	)
Extensions, discoveries and other additions		273			-			273			3			276
Production		(351	)		-			(351	)		(23	)		(374	)
Balance at December 31, 2005		3,633			-			3,633			-			3,633

	Continuing Operations
Crude Oil, Condensate and Natural Gas Liquids (Millions of barrels)	United States		China		Total		Discontinued Operations		Total

Proved developed reserves -
December 31, 2003		122		-		122		125		247
December 31, 2004		197		16		213		120		333
December 31, 2005		234		19		253		-		253

Natural Gas (Billions of cubic feet)

Proved developed reserves -
December 31, 2003		1,502		-		1,502		113		1,615
December 31, 2004		2,620		-		2,620		135		2,755
December 31, 2005		2,560		-		2,560		-		2,560

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

	Continuing Operations
Barrels of Oil Equivalent (Millions of barrels)	United States			China			Total			Discontinued Operations			Total

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

	Continuing Operations
(Millions of equivalent barrels)	United States		China		Total		Discontinued Operations		Total

Proved developed reserves -
December 31, 2003		372		-		372		144		516
December 31, 2004		634		16		650		142		792
December 31, 2005		661		19		680		-		680

Proved undeveloped reserves -
December 31, 2003		335		39		374		136		510
December 31, 2004		305		21		326		100		426
December 31, 2005		267		21		288		-		288

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

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

													Standardized
									Future				Measure of
	Future		Future		Future		Future		Net		10%		Discounted
	Cash		Production		Development		Income		Cash		Annual		Future Net
(Millions of dollars)	Inflows (1)		Costs		Costs		Taxes		Flows		Discount		Cash Flows

2005 -
United States	$	48,739	$	10,722	$	3,232	$	11,661	$	23,124	$	9,402	$	13,722
China		1,821		415		98		363		945		319		626
Total	$	50,560	$	11,137	$	3,330	$	12,024	$	24,069	$	9,721	$	14,348	⁽²⁾

2004 -
United States	$	33,512	$	7,976	$	2,752	$	7,158	$	15,626	$	6,549	$	9,077
China		986		306		83		113		484		148		336
Total - continuing operations		34,498		8,282		2,835		7,271		16,110		6,697		9,413
Discontinued operations		8,927		2,988		999		1,863		3,077		934		2,143
Total	$	43,425	$	11,270	$	3,834	$	9,134	$	19,187	$	7,631	$	11,556

2003 -
United States	$	23,850	$	5,002	$	2,067	$	5,467	$	11,314	$	4,721	$	6,593
China		1,114		306		130		178		500		208		292
Total - continuing operations		24,964		5,308		2,197		5,645		11,814		4,929		6,885
Discontinued operations		7,770		2,437		790		1,552		2,991		970		2,021
Total	$	32,734	$	7,745	$	2,987	$	7,197	$	14,805	$	5,899	$	8,906

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

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

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

(Millions of dollars)	2005			2004			2003

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

26. Condensed Consolidating Financial Information

The company’s Notes (as defined in Note 10, under Modification to Guarantee Provisions) with an aggregate principal amount of $2.1 billion have been fully and unconditionally guaranteed by Kerr-McGee Rocky Mountain Corporation, a wholly-owed subsidiary of Kerr-McGee Corporation. 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 subsidiary and (c) the nonguarantor subsidiaries. Other income (expense) in the Condensed Consolidating Statement of Income for all periods presented includes equity interest in income (loss) of subsidiaries.

As discussed in Note 10, Tronox Worldwide LLC was released from its guarantee of the Notes in November 2005 upon the IPO of its parent, Tronox Incorporated.

Condensed Consolidating Statement of Income for the Year Ended December 31, 2005
(Millions of dollars)	Kerr-McGee Corporation			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated

Revenues	$	-		$	1,504		$	4,423		$	-		$	5,927
Costs and Expenses
Costs and operating expenses		-			920			1,384			-			2,304
Selling, general and administrative expenses		-			(2	)		457			-			455
Shipping and handling expenses		-			12			133			-			145
Depreciation and depletion		-			118			834			-			952
Accretion expense		-			3			20			-			23
Asset impairments		-			2			15			-			17
Gain on sale of assets		-			-			(211	)		-			(211	)
Exploration, including exploratory dry holes
and amortization of undeveloped leases		-			11			366			-			377
Taxes, other than income taxes		-			39			163			-			202
Provision for environmental remediation and
restoration, net of reimbursements		-			4			34			-			38
Interest and debt expense		211			8			501			(467	)		253
Loss on early repayment and modification of debt		42			-			-			-			42
Total Costs and Expenses		253			1,115			3,696			(467	)		4,597
		(253	)		389			727			467			1,330
Other Income (Expense)		3,463			5			485			(3,849	)		104
Income from Continuing Operations
before Income Taxes		3,210			394			1,212			(3,382	)		1,434
Benefit (Provision) for Income Taxes		61			(138	)		(410	)		-			(487	)
Minority Interest, net of taxes		-			-			(1	)		-			(1	)
Income from Continuing Operations		3,271			256			801			(3,382	)		946
Income (Loss) from Discontinued
Operations, net of taxes		(60	)		-			2,325			-			2,265
Net Income	$	3,211		$	256		$	3,126		$	(3,382	)	$	3,211

Condensed Consolidating Statement of Income for the Year Ended December 31, 2004
(Millions of dollars)	Kerr-McGee Corporation			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated

Revenues	$	-		$	864		$	3,534		$	-		$	4,398
Costs and Expenses
Costs and operating expenses		-			519			1,278			(3	)		1,794
Selling, general and administrative expenses		1			2			322			-			325
Shipping and handling expenses		-			8			120			-			128
Depreciation and depletion		-			120			722			-			842
Accretion expense		-			3			16			-			19
Asset impairments		-			3			25			-			28
Loss on sale of assets		-			-			29			-			29
Exploration, including exploratory dry holes and
amortization of undeveloped leases		-			14			310			-			324
Taxes other than income taxes		-			37			107			-			144
Provision for environmental remediation and
restoration, net of reimbursements		-			-			86			-			86
Interest and debt expense		138			35			304			(233	)		244
Total Costs and Expenses		139			741			3,319			(236	)		3,963
		(139	)		123			215			236			435
Other Income (Expense)		793			-			116			(943	)		(34	)
Income from Continuing Operations
before Income Taxes		654			123			331			(707	)		401
Provision for Income Taxes		(250	)		(43	)		(114	)		270			(137	)
Income from Continuing Operations		404			80			217			(437	)		264
Income from Discontinued Operations,
net of taxes		-			-			140			-			140
Net Income	$	404		$	80		$	357		$	(437	)	$	404

Condensed Consolidating Statement of Income for the Year Ended December 31, 2003
(Millions of dollars)	Kerr-McGee Corporation			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated

Revenues	$	-		$	694		$	2,595		$	-		$	3,289
Costs and Expenses
Costs and operating expenses		-			351			1,065			-			1,416
Selling, general and administrative expenses		-			3			347			-			350
Shipping and handling expenses		-			9			87			-			96
Depreciation and depletion		-			122			410			-			532
Accretion expense		-			2			13			-			15
Asset impairments		-			-			14			-			14
Loss (gain) on sale of assets		-			1			(31	)		-			(30	)
Exploration, including exploratory dry holes and
amortization of undeveloped leases		-			15			312			-			327
Taxes other than income taxes		-			25			69			-			94
Provision for environmental remediation and
restoration, net of reimbursements		-			-			60			-			60
Interest and debt expense		116			35			277			(178	)		250
Total Costs and Expenses		116			563			2,623			(178	)		3,124
		(116	)		131			(28	)		178			165
Other Income (Expense)		506			(3	)		82			(610	)		(25	)
Income from Continuing Operations
before Income Taxes		390			128			54			(432	)		140
Benefit (Provision) for Income Taxes		(171	)		(46	)		45			187			15
Income from Continuing Operations		219			82			99			(245	)		155
Income from Discontinued Operations,
net of taxes		-			-			99			-			99
Cumulative Effect of Change in Accounting
Principle, net of taxes		-			(1	)		(34	)		-			(35	)
Net Income	$	219		$	81		$	164		$	(245	)	$	219

Condensed Consolidating Balance Sheet as of December 31, 2005
(Millions of dollars)	Kerr-McGee Corporation		Guarantor Subsidiary		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1	$	-	$	1,052	$	-		$	1,053
Accounts receivable		1		245		823		-			1,069
Inventories		-		3		349		-			352
Derivatives and other current assets		-		14		180		-			194
Deferred income taxes		-		2		579		-			581
Total Current Assets		2		264		2,983		-			3,249
Property, Plant and Equipment - Net		-		1,915		7,360		-			9,275
Investments in Subsidiaries		8,688		-		-		(8,688	)		-
Deferred Charges, Derivatives and Other Assets		25		1		562		(80	)		508
Goodwill and Other Intangible Assets		-		346		893		-			1,239
Assets Held for Sale		-		-		5		-			5
Total Assets	$	8,715	$	2,526	$	11,803	$	(8,768	)	$	14,276

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Intercompany borrowings	$	2,459		$	183	$	3,037	$	(5,679	)	$	-
Accounts payable		6			69		652		-			727
Long-term debt due within one year		306			-		2		-			308
Derivative liabilities		-			14		1,494		-			1,508
Accrued liabilities		(72	)		239		1,221		-			1,388
Total Current Liabilities		2,699			505		6,406		(5,679	)		3,931
Long-Term Debt		1,801			-		1,024		-			2,825
Noncurrent Liabilities
Deferred income taxes		(9	)		517		1,016		-			1,524
Derivative liabilities		-			-		663		-			663
Other noncurrent liabilities		-			78		928		-			1,006
Total Noncurrent Liabilities		(9	)		595		2,607		-			3,193
Minority Interest in Tronox		-			-		212		-			212
Stockholders’ Equity		4,224			1,426		1,554		(3,089	)		4,115
Total Liabilities and Stockholders’ Equity	$	8,715		$	2,526	$	11,803	$	(8,768	)	$	14,276

Condensed Consolidating Balance Sheet as of December 31, 2004
(Millions of dollars)	Kerr-McGee Corporation		Guarantor Subsidiary		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	2	$	-	$	74	$	-		$	76
Intercompany receivables		-		-		58		(58	)		-
Accounts receivable		-		140		685		-			825
Inventories		-		5		309		-			314
Derivatives and other current assets		4		24		123		-			151
Deferred income taxes		2		13		312		-			327
Assets held for sale		-		-		194		-			194
Total Current Assets		8		182		1,755		(58	)		1,887
Property, Plant and Equipment - Net		-		1,947		7,126		-			9,073
Investments in Subsidiaries		6,306		-		599		(6,905	)		-
Deferred Charges, Derivatives and Other Assets		17		5		542		(80	)		484
Goodwill and Other Intangible Assets		-		352		936		-			1,288
Assets Held for Sale		-		-		1,786		-			1,786
Total Assets	$	6,331	$	2,486	$	12,744	$	(7,043	)	$	14,518

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Intercompany borrowings	$	68		$	598	$	1,233	$	(1,899	)	$	-
Accounts payable		68			55		484		-			607
Long-term debt due within one year		354			-		109		-			463
Derivative liabilities		6			71		273		-			350
Accrued liabilities		10			123		760		-			893
Liabilities associated with assets held for sale		-			-		192		-			192
Total Current Liabilities		506			847		3,051		(1,899	)		2,505
Long-Term Debt		2,125			-		1,111		-			3,236
Noncurrent Liabilities
Deferred income taxes		(2	)		592		1,137		-			1,727
Derivative liabilities		-			59		149		-			208
Other noncurrent liabilities		-			85		825		(3	)		907
Liabilities associated with assets held for sale		-			-		617		-			617
Total Noncurrent Liabilities		(2	)		736		2,728		(3	)		3,459
Stockholders’ Equity		3,702			903		5,854		(5,141	)		5,318
Total Liabilities and Stockholders’ Equity	$	6,331		$	2,486	$	12,744	$	(7,043	)	$	14,518

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2005
(Millions of dollars)	Kerr-McGee Corporation			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash Flow from Operating Activities
Net income	$	3,211		$	256		$	3,126		$	(3,382	)	$	3,211
Adjustments to reconcile net income to net cash
provided by operating activities -
Depreciation, depletion and amortization		-			120			1,057			-			1,177
Deferred income taxes		(6	)		(1	)		90			-			83
Unrealized loss on derivatives		-			-			200			-			200
Dry hole expense		-			1			184			-			185
Noncash stock-based compensation and ESOP
expense		-			-			54			-			54
Asset impairments		-			2			15			-			17
Gain on sale of the North Sea oil and gas business		-			-			(2,240	)		-			(2,240	)
Gain on sale of assets		-			-			(327	)		-			(327	)
Loss on early repayment and modification of debt		42			-			-			-			42
Accretion expense		-			3			27			-			30
Equity in earnings of subsidiaries		(3,382	)		-			-			3,382			-
Provision for environmental remediation and
restoration, net of reimbursements		-			4			45			-			49
Other noncash items affecting net income		(9	)		46			79			-			116
Changes in assets and liabilities		(70	)		40			536			-			506
Net cash provided by (used in) operating
activities		(214	)		471			2,846			-			3,103

Cash Flow from Investing Activities
Capital expenditures		-			(124	)		(1,627	)		-			(1,751	)
Dry hole costs		-			-			(169	)		-			(169	)
Net proceeds from sale of the North Sea oil and gas business		-			-			3,305			-			3,305
Proceeds from sale of assets		-			13			691			-			704
Accounts receivable purchase and collection		(165	)		-			165			-			-
Other investing activities		-			-			(8	)		-			(8	)
Net cash provided by (used) in investing
activities		(165	)		(111	)		2,357			-			2,081

Cash Flow from Financing Activities
Issuance of common stock upon exercise of stock options		225			-			-			-			225
Sale of Tronox stock		-			-			225			-			225
Purchases of treasury stock		(250	)		-			-			-			(250	)
Repurchases of common stock under the tender offer		(3,975	)		-			-			-			(3,975	)
Dividends paid		(153	)		-			-			-			(153	)
Increase (decrease) in intercompany notes payable		4,962			(360	)		(4,602	)		-			-
Repayment of debt		(4,600	)		-			(151	)		-			(4,751	)
Proceeds from borrowings		4,250			-			550			-			4,800
Debt issuance costs and other		(59	)		-			(12	)		-			(71	)
Cash paid for modification of debt		(22	)		-			-			-			(22	)
Settlement of Westport derivatives		-			-			(238	)		-			(238	)
Net cash provided by (used in) financing
activities		378			(360	)		(4,228	)		-			(4,210	)

Effects of Exchange Rate Changes on Cash and Cash
Equivalents		-			-			3			-			3
Net Increase (Decrease) in Cash and Cash Equivalents		(1	)		-			978			-			977
Cash and Cash Equivalents at Beginning of Year		2			-			74			-			76
Cash and Cash Equivalents at End of Year	$	1		$	-		$	1,052		$	-		$	1,053

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2004
(Millions of dollars)	Kerr-McGee Corporation			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash Flow from Operating Activities
Net income	$	404		$	80		$	357		$	(437	)	$	404
Adjustments to reconcile net income to net cash
provided by operating activities -
Depreciation, depletion and amortization		-			125			999			-			1,124
Deferred income taxes		2			13			93			-			108
Unrealized loss on derivatives		-			(1	)		13			-			12
Dry hole expense		-			2			159			-			161
Noncash stock-based compensation and ESOP
expense		-			-			25			-			25
Asset impairments		-			3			33			-			36
(Gain) loss on sale of assets		-			(1	)		21			-			20
Accretion expense		-			3			27			-			30
Provision for environmental remediation and
restoration, net of reimbursements		-			-			92			-			92
Equity in earnings of subsidiaries		(439	)		-			-			439			-
Other noncash items affecting net income		2			109			36			-			147
Changes in assets and liabilities		(19	)		30			(118	)		(2	)		(109	)
Net cash provided by (used in) operating
activities		(50	)		363			1,737			-			2,050
Cash Flow from Investing Activities
Capital expenditures		-			(108	)		(1,154	)		-			(1,262	)
Dry hole costs		-			(2	)		(76	)		-			(78	)
Acquisitions, net of cash acquired		-			-			43			-			43
Proceeds from sale of assets		-			7			16			-			23
Other investing activities		-			-			12			-			12
Net cash used in investing activities		-			(103	)		(1,159	)		-			(1,262	)
Cash Flow from Financing Activities
Issuance of common stock upon exercise of stock options		55			-			-			-			55
Dividends paid		(205	)		-			-			-			(205	)
Increase (decrease) in intercompany notes payable		(436	)		(260	)		696			-			-
Repayment of debt		-			-			(1,278	)		-			(1,278	)
Proceeds from borrowings		645			-			41			-			686
Debt issuance costs and other		(9	)		-			1			-			(8	)
Settlement of Westport derivatives		-			-			(101	)		-			(101	)
Net cash provided by (used in) financing
activities		50			(260	)		(641	)		-			(851	)
Effects of Exchange Rate Changes on Cash and Cash
Equivalents		-			-			(3	)		-			(3	)
Net Decrease in Cash and Cash Equivalents		-			-			(66	)		-			(66	)
Cash and Cash Equivalents at Beginning of Year		2			-			140			-			142
Cash and Cash Equivalents at End of Year	$	2		$	-		$	74		$	-		$	76

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2003
(Millions of dollars)	Kerr-McGee Corporation			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash Flow from Operating Activities
Net income	$	219		$	81		$	164		$	(245	)	$	219
Adjustments to reconcile net income to net cash
provided by operating activities -
Depreciation, depletion and amortization		-			127			687			-			814
Deferred income taxes		(6	)		23			139			-			156
Unrealized loss on derivatives		-			4			1			-			5
Dry hole expense		-			-			181			-			181
Noncash stock-based compensation and ESOP
expense		-			-			42			-			42
Asset impairments		-			-			14			-			14
Gain on sale of assets		-			-			(40	)		-			(40	)
Accretion expense		-			2			23			-			25
Cumulative effect of change in accounting principle		-			1			34			-			35
Provision for environmental remediation and
restoration, net of reimbursements		-			-			62			-			62
Equity in earnings of subsidiaries		(245	)		-			-			245			-
Other noncash items affecting net income		1			1			95			-			97
Changes in assets and liabilities		3			(13	)		(82	)		-			(92	)
Net cash provided by (used in) operating
activities		(28	)		226			1,320			-			1,518
Cash Flow from Investing Activities
Capital expenditures		-			(129	)		(852	)		-			(981	)
Dry hole costs		-			-			(181	)		-			(181	)
Acquisitions, net of cash acquired		-			-			(110	)		-			(110	)
Proceeds from sale of assets		-			8			296			-			304
Other investing activities		-			-			17			-			17
Net cash used in investing activities		-			(121	)		(830	)		-			(951	)
Cash Flow from Financing Activities
Dividends paid		(181	)		-			-			-			(181	)
Increase (decrease) in intercompany notes payable		226			(105	)		(121	)		-			-
Repayment of debt		(18	)		-			(351	)		-			(369	)
Proceeds from borrowings		-			-			31			-			31
Other financing activities		-			-			(1	)		-			(1	)
Net cash provided by (used in) financing
activities		27			(105	)		(442	)		-			(520	)
Effects of Exchange Rate Changes on Cash and Cash
Equivalents		-			-			5			-			5
Net Increase (Decrease) in Cash and Cash Equivalents		(1	)		-			53			-			52
Cash and Cash Equivalents at Beginning of Year		3			-			87			-			90
Cash and Cash Equivalents at End of Year	$	2		$	-		$	140		$	-		$	142

27. Quarterly Financial Information (Unaudited)

A summary of quarterly consolidated results for 2005 and 2004 is presented below. Net income for the third and fourth quarters of 2005 includes after-tax gains on sale of the company’s North Sea oil and gas business of $283 million and $1.8 billion, respectively. Refer to Note 2 for additional information regarding the effects of disposals of discontinued businesses. The quarterly per-share amounts do not add to the annual amounts due to the effects of the weighted average of stock issued and the anti-dilutive effect of convertible debentures in certain quarters.

										Income from
					Income from					Continuing Operations
(Millions of dollars,			Operating		Continuing			Net		per Common Share
except per-share amounts)	Revenues ⁽¹⁾		Profit ⁽¹⁾		Operations ⁽¹⁾			Income		Basic ⁽¹⁾			Diluted ⁽¹⁾

2005 Quarter Ended -
March 31	$	1,405	$	497	$	250		$	355	$	1.61		$	1.56
June 30		1,539		541		267			371		1.90			1.87
September 30		1,208		202		53			359		.46			.46
December 31		1,775		609		376			2,126		3.28			3.22
Total	$	5,927	$	1,849	$	946		$	3,211		7.22			7.07

2004 Quarter Ended -
March 31	$	891	$	254	$	110		$	152	$	1.10		$	1.03
June 30		912		204		72			111		.70			.67
September 30		1,203		157		(24	)		7		(.16	)		(.16	)
December 31		1,392		276		106			134		.71			.69
Total	$	4,398	$	891	$	264		$	404		2.09			2.08

⁽¹⁾

As discussed in Note 2, in the third quarter of 2005, criteria for presenting results of operations of the company’s North Sea oil and gas business as a discontinued operation were met. Therefore, revenues, income from continuing operations and per-share data in the above table differ from the quarterly amounts disclosed in the respective Forms 10-Q.

Five-Year Financial Summary
(Millions of dollars, except per-share amounts)	2005			2004 (1)			2003			2002			2001 (2)
Statement of income summary
Revenues	$	5,927		$	4,398		$	3,289		$	2,579		$	2,516
Costs and operating expenses		4,302			3,719			2,874			2,486			2,113
Interest and debt expense (3)		295			244			250			267			186
Total costs and expenses		4,597			3,963			3,124			2,753			2,299
		1,330			435			165			(174	)		217
Other income (expense)		104			(34	)		(25	)		15			219
Benefit (provision) for income taxes		(487	)		(137	)		15			62			(157	)
Minority interest, net of taxes		(1	)		-			-			-			-
Income (loss) from continuing operations	$	946		$	264		$	155		$	(97	)	$	279
Effective income tax rate		34.0	%		34.2	%		(10.7	)%		(39.0	)%		36.0	%
Income (loss) from continuing operations per common share
Basic	$	7.22		$	2.09		$	1.55		$	(0.97	)	$	2.87
Diluted	$	7.07		$	2.08		$	1.54		$	(0.97	)	$	2.80

Shares outstanding at year-end (thousands)		116,212			151,889			100,860			100,384			100,185
Per share information -
Dividends declared	$	.60		$	1.80		$	1.80		$	1.80		$	1.80
Stockholders’ equity ⁽⁴⁾		35.17			32.86			23.79			23.01			28.83
Market prices -
High		98.83			63.24			48.59			63.58			74.10
Low		55.38			46.92			37.82			38.02			46.94
Year-end		90.86			57.79			46.49			44.30			54.80
Balance sheet information -
Property, plant and equipment - net	$	9,275		$	9,073		$	5,525		$	5,066		$	4,492
Total assets		14,276			14,518			10,250			9,909			11,076
Long-term debt		2,825			3,236			3,081			3,798			4,540
Total debt		3,133			3,699			3,655			3,904			4,574
Stockholders’ equity		4,115			5,318			2,636			2,536			3,174
Cash flow information -
Net cash provided by operating activities	$	3,103		$	2,050		$	1,518		$	1,448		$	1,143
Capital expenditures (5)		1,920			1,340			1,162			1,272			1,864
Dividends paid		153			205			181			181			173
Repurchases of Kerr-McGee stock		4,225			-			-			-			-
Ratios -
Current ratio		.8			.8			.8			.8			1.2
Average price/earnings ratio		3.2			17.3			19.9			NM			12.8
Debt to total capitalization (6)		42	%		41	%		58	%		61	%		59	%

⁽¹⁾	As described in Note 4 to the Consolidated Financial Statements, on June 25, 2004, the company completed a merger with Westport Resources Corporation.

⁽²⁾

On August 1, 2001, the company completed an acquisition of HS Resources for a total cost of $1.8 billion, consisting of cash of $955 million, assumption of debt of $506 million and issuance of 5.1 million common shares. Additionally, effective January 1, 2001, the company implemented FAS 133, “Accounting for Derivatives and Hedging Activities” (FAS 133), as amended. In conjunction with implementation, the company recorded the fair value of its derivative instruments on the balance sheet, including options embedded in the company’s debt exchangeable for stock (DECS) of Devon Energy Corporation owned by the company. Further, the company chose to reclassify a portion of Devon shares owned from available-for-sale to trading category. As a result, the company recognized, as a component of other income (expense), an unrealized gain on securities of $181 million.

⁽³⁾	Includes losses on early repayment and modification of debt.

⁽⁴⁾	Stockholder’s equity per share for all periods presented reflects the effect of potential dilution, assuming potentially issuable shares are issued at the end of the reporting period.

⁽⁵⁾	Inclusive of dry hole costs and exclusive of acquisition cost (net of cash acquired).

⁽⁶⁾	Determined as total debt plus total stockholders’ equity and, in 2005, minority stockholders’ interest in net assets of Tronox.

Five-Year Operating Summary
	2005		2004		2003		2002		2001
Crude oil and condensate production
(thousands of barrels per day) -
United States		90		88		77		81		78
China		19		8		2		3		4
Other international		-		-		-		4		5
Total - continuing operations		109		96		79		88		87
Average price of crude oil (per barrel) -
United States	$	42.55	$	29.11	$	26.14	$	21.56	$	22.05
China		44.45		32.37		29.66		24.84		21.94
Other international		-		-		-		20.28		19.14
Average - continuing operations	$	42.89	$	29.38	$	26.24	$	21.62	$	21.91
U.S. natural gas production (MMcf per day)		962		836		629		660		534
U.S. average price of natural gas (per Mcf)	$	6.66	$	5.24	$	4.56	$	3.04	$	4.00

Net exploratory wells drilled ⁽¹⁾-
Productive		13.8		13.6		6.7		4.8		2.4
Dry		16.3		15.3		17.0		17.2		11.4
Total		30.1		28.9		23.7		22.0		13.8
Net development wells drilled ⁽¹⁾-
Productive		457.5		429.8		244.4		196.3		128.6
Dry		9.9		7.5		1.1		1.4		6.6
Total		467.4		437.3		245.5		197.7		135.2
Undeveloped net acreage (thousands) ⁽¹⁾-
United States		3,336		3,367		2,884		2,399		2,382
North Sea		-		392		369		871		932
China		3,873		1,469		1,488		1,046		917
Other international		23,787		30,455		47,178		41,514		50,450
Total		30,996		35,683		51,919		45,830		54,681
Developed net acreage (thousands) ⁽¹⁾ -
United States		2,010		2,134		1,352		1,266		1,192
North Sea		-		122		136		109		149
China		9		9		-		17		17
Other international		-		-		-		1		639
Total		2,019		2,265		1,488		1,393		1,997
Estimated proved reserves ⁽¹⁾ -
(millions of equivalent barrels)		968		1,218		1,026		1,033		1,509

⁽¹⁾	Includes discontinued operations.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. 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 fourth quarter of 2005 that has materially affected or is reasonably likely to materially affect the company’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

This report is included in Item 8 on page 74 of this report and is incorporated by reference.

PART III

Item 10. Directors and Executive Officers of the Registrant

(a) Identification of directors -

For information required under this section, reference is made to the "Director Information" section of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 9, 2006.

(b) Identification of executive officers -

The information required under this section is set forth in the caption "Executive Officers of the Registrant" on pages 27 and 28 of this Annual Report on Form 10-K pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to Form 10-K.

For information required under this section, reference is made to the "Section 16(a) Beneficial Ownership Reporting Compliance" section of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 9, 2006.

(d) Code of Ethics for the Chief Executive Officer and Principal Financial Officers -

Information regarding the Code of Ethics for the Chief Executive Officer and Principal Financial Officers can be found in Items 1 and 2 of this Annual Report on Form 10-K under "Availability of Reports and Governance Documents."

Item 11. Executive Compensation

For information required under this section, reference is made to the executive compensation sections of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 9, 2006.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information regarding Kerr-McGee common stock that may be issued under the company’s equity compensation plans as of December 31, 2005, is included in the following table:

	Number of shares of common stock to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of shares remaining available for future issuance under equity compensation plans (1)
Equity compensation plans approved
by security holders	4,344,311	$56.15	9,998,180
Equity compensation plans not
approved by security holders	454,813	46.15	-
Total	4,799,124	53.21	9,998,180

⁽¹⁾	Excludes shares to be issued upon exercise of outstanding options, warrants and rights.

The Kerr-McGee Corporation Performance Share Plan was approved by the Board of Directors in January 1998 but was not approved by the company's stockholders. The plan was terminated in September 2005. This plan was a broad-based stock option plan that provided for the granting of options to purchase the company's common stock to full-time, nonbargaining-unit employees, except officers. A total of 1,500,000 shares of common stock were authorized to be issued under this plan. A copy of the plan document was attached as exhibit 10.19 to the company's December 31, 2002 Form 10-K and is incorporated by reference in exhibit 10.18 to the company’s December 31, 2005 Form 10-K.

Awards under certain equity compensation plans of Oryx Energy Company and Westport Resources Corporation were assumed by the company in connection with its acquisitions of Oryx and Westport. The terms of those awards are governed by the Oryx and Westport plans, respectively. The plans, which provided for the granting of stock options to officers and employees of Oryx and Westport, did not require approval of Kerr-McGee stockholders. No further grants may be made under the Oryx or Westport plans.

For information required under Item 403 of Regulation S-K, reference is made to the "Ownership of Stock of the Company" section of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 9, 2006.

Item 13. Certain Relationships and Related Transactions

For information required under this section, reference is made to the “Transactions with Management and Others” section of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 9, 2006.

Item 14. Principal Accountant Fees and Services

For information required under this section, reference is made to the “Fees Paid to the Independent Auditors” section of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 9, 2006.

PART IV

Item 15.		Exhibits, Financial Statement Schedules, and Reports on Form 8-K

(a)	1.	Financial Statements - See the Index to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

(a)	2.	Financial Statement Schedules - See the Index to the Financial Statement Schedules included in Item 8 of this Annual Report on Form 10-K.

(a)	3.	Exhibits - The following documents are filed under Security and Exchange Commission file numbers 1-16619 and 1-3939 as part of this report.

	Exhibit No.

	3.1	Amended and restated Certificate of Incorporation of Kerr-McGee Corporation, filed as Exhibit 4.1 to the Registration Statement on Form S-4 dated June 28, 2001, and incorporated herein by reference.

	3.2	Certificate of Amendment of Amended and Restated Certificate of Incorporation of Kerr-McGee Corporation, filed as Exhibit 3.1 to the 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 Current Report on Form 8-K dated April 14, 2005, and incorporated herein by reference.

	4.1	Rights Agreement dated as of July 26, 2001, by and between the company and UMB Bank, N.A., filed as Exhibit 4.1 to the Registration Statement on Form 8-A filed on July 27, 2001, and incorporated herein by reference.

	4.2	First Amendment to Rights Agreement, dated as of July 30, 2001, by and between the company and UMB Bank, N.A., filed as Exhibit 4.1 to the Registration Statement on Form 8-A/A filed on August 1, 2001, and incorporated herein by reference.

	4.3	Indenture dated as of August 1, 1982, filed as Exhibit 4 to the Registration Statement on Form S-3, effective August 27, 1982, Registration Statement No. 2-78952, and incorporated herein by reference, and the first supplement thereto dated May 7, 1996, between the company and Citibank, N.A., as trustee, relating to the company’s 6.625% notes due October 15, 2007, and 7.125% debentures due October 15, 2027, filed as Exhibit 4.1 to the Current Report on Form 8-K filed July 27, 1999, and incorporated herein by reference.

	4.4	Indenture dated as of August 1, 2001, between the company and Citibank, N.A., as trustee, relating to the company's $325 million, 5-7/8% notes due September 15, 2006; $675 million, 6-7/8% notes due September 15, 2011; $500 million 7-7/8% notes due September 15, 2031; and $650 million, 6.95% notes due July 1, 2024, filed as Exhibit 4.1 to the Pre-effective Amendment No. 1 to the Registration Statement on Form S-3 filed August 30, 2001, and incorporated herein by reference.

	4.5	Supplemental Indenture, dated September 21, 2005, amending the Indenture dated as of August 1, 2001, between the company and Citibank, N.A., as Trustee, filed as Exhibit 99.1 to the Current Report on Form 8-K dated September 27, 2005, and incorporated herein by reference.

	Exhibit No.

	4.6	The company agrees to furnish to the Securities and Exchange Commission, upon request, copies of each of the following instruments defining the rights of the holders of certain long-term debt of the Registrant: the Note Agreement dated as of November 29, 1989, among the Kerr-McGee Corporation Employee Stock Ownership Plan Trust, referred to as the Trust, and several lenders, providing for a loan guaranteed by the company of $125 million to the Trust; and the Credit Agreement dated as of January 9, 2006, among the company and various banks providing for revolving credit up to $1.25 billion through January 9, 2011. The total amount of securities authorized under each of such instruments does not exceed 10% of the total assets of the Registrant and its subsidiaries on a consolidated basis.

	4.7	Kerr-McGee Corporation Direct Purchase and Dividend Reinvestment Plan filed on September 9, 2001, pursuant to Rule 424(b)(2) of the Securities Act of 1933 as the Prospectus Supplement to the Prospectus dated August 31, 2001, and incorporated herein by reference.

	10.1*	Kerr-McGee Corporation Deferred Compensation Plan for Non-Employee Directors as amended and restated effective January 1, 2003, filed as Exhibit 10.1 to the Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.

	10.2*	Amendment No. 1 to the Kerr-McGee Corporation Deferred Compensation Plan for Non-Employee Directors as amended and restated effective January 1, 2003, dated December 14, 2005.

	10.3*	Kerr-McGee Corporation Executive Deferred Compensation Plan as amended and restated effective January 1, 2003, filed as Exhibit 10.4 to the Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.

	10.4*	Amendment No. 1 to the Kerr-McGee Corporation Executive Deferred Compensation Plan as amended and restated effective January 1, 2003, dated December 14, 2005.

	10.5*	Benefits Restoration Plan as amended and restated effective May 1, 1999, filed as Exhibit 10.3 to the Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated herein by reference.

	10.6*	First Supplement to Benefits Restoration Plan as amended and restated effective January 1, 2000, filed as Exhibit 10.4 to the Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated herein by reference.

	10.7*	Second Supplement to Benefits Restoration Plan as amended and restated effective January 1, 2001, filed as Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated herein by reference.

	10.8*	Kerr-McGee Corporation Supplemental Executive Retirement Plan as amended and restated effective February 26, 1999, filed as Exhibit 10.6 to the Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.

	10.9*	First Supplement to the Kerr-McGee Corporation Supplemental Executive Retirement Plan as amended and restated effective February 26, 1999, filed as Exhibit 10.7 to the Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.

	Exhibit No.

	10.10*	Amended and Restated Second Supplement to the Kerr-McGee Corporation Supplemental Executive Retirement Plan as amended and restated effective February 26, 1999, filed as Exhibit 10.8 to the Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated herein by reference.

	10.11*	Amendment No. 1 to the Kerr-McGee Corporation Supplemental Executive Retirement Plan Amended and Restated effective as of February 26, 1999, dated October 19, 2005, filed as Exhibit 10.9 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, and incorporated herein by reference.

	10.12*	The Long Term Incentive Program as amended and restated effective May 9, 1995, filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 1995, and incorporated herein by reference.

	10.13*	The Kerr-McGee Corporation 1998 Long Term Incentive Plan effective January 1, 1998, filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, and incorporated herein by reference.

	10.14*	The Kerr-McGee Corporation 2000 Long Term Incentive Plan effective May 1, 2000, filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, and incorporated herein by reference.

	10.15*	The 2002 Long Term Incentive Plan effective May 14, 2002, filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, and incorporated herein by reference.

	10.16*	The 2005 Long Term Incentive Plan effective May 10, 2005, filed as Exhibit 10.1 to the Current Report on Form 8-K dated May 12, 2005, and incorporated herein by reference.

	10.17*	The 2002 Annual Incentive Compensation Plan effective May 14, 2002, filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, and incorporated herein by reference.

	10.18*	Kerr-McGee Corporation Performance Share Plan effective January 1, 1998, filed as Exhibit 10.19 to the Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.

	10.19*	Oryx Energy Company 1992 Long-Term Incentive Plan, as amended and restated May 1, 1997, filed as Exhibit 10.15 to the Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated herein by reference.

	10.20*	Oryx Energy Company 1997 Long-Term Incentive Plan, as amended and restated May 1, 1997, filed as Exhibit 10.16 to the Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated herein by reference.

	10.21*	Amended and Restated Agreement, restated as of January 11, 2000, between the company and Luke R. Corbett filed as Exhibit 10.10 to the Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.

	10.22*	Amended and Restated Agreement, restated as of January 11, 2000, between the company and Kenneth W. Crouch filed as Exhibit 10.11 to the Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.

	Exhibit No.

	10.23*	Amended and Restated Agreement, restated as of January 11, 2000, between the company and Robert M. Wohleber filed as Exhibit 10.12 to the Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.

	10.24*	Amended and Restated Agreement, restated as of January 11, 2000, between the company and Gregory F. Pilcher filed as Exhibit 10.14 to the Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.

	10.25*	Agreement, dated as of September 3, 2002, between the company and David A. Hager filed as Exhibit 10.21 to the Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated herein by reference.

	10.26*	Registration Rights Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation, Westport Energy LLC, Medicor Foundation and EQT Investments, LLC, filed as Exhibit 99.7 to the Current Report on Form 8-K dated April 8, 2004, and incorporated herein by reference.

	10.27*	Compensation Arrangements with Non-Employee Directors, filed as Exhibit 10.1 to the Current Report on Form 8-K dated January 17, 2006, and incorporated herein by reference.

	10.28*	Compensation Arrangements with Named Executive Officers, filed as Exhibit 10.2 to the Current Report on Form 8-K dated January 17, 2006, and incorporated herein by reference.

	10.29	Voting Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation, Belfer Corp., Renee Holdings Partnership, L.P., Vantz Limited Partnership, LDB Two Corp., Belfer Two Corp., Liz Partners, L.P., filed as Exhibit 99.2 to the Current Report on Form 8-K dated April 8, 2004, and incorporated herein by reference.

	10.30	Voting Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation and EQT Investments, LLC, filed as Exhibit 99.3 to the Current Report on Form 8-K dated April 8, 2004, and incorporated herein by reference.

	10.31	Voting Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation and Medicor Foundation, filed as Exhibit 99.4 to the Current Report on Form 8-K dated April 8, 2004, and incorporated herein by reference.

	10.32	Voting Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation and Westport Energy LLC., filed as Exhibit 99.5 to the Current Report on Form 8-K dated April 8, 2004, and incorporated herein by reference.

	10.33	Voting Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation and Donald D. Wolf, filed as Exhibit 99.6 to the Current Report on Form 8-K dated April 8, 2004, and incorporated herein by reference.

	10.34	Amended and Restated Gas Purchase Agreement, dated July 1, 1998, among Oryx Gas Marketing Limited Partnership, Sun Operating Limited Partnership and Producers Energy Marketing, LLC, filed as Exhibit 10.23 to the Amendment to Annual Report on Form 10-K/A for the year ended December 31, 2003, and incorporated herein by reference.

	Exhibit No

	10.35	Amendment to Amended and Restated Gas Purchase Agreement, dated May 1, 2000, among Oryx Gas Marketing Limited Partnership, Kerr-McGee Oil & Gas Corporation, Kerr-McGee Oil and Gas Onshore LP, and Cinergy Marketing & Trading, LLC, filed as Exhibit 10.24 to the Amendment to Annual Report on Form 10-K/A for the year ended December 31, 2003, and incorporated herein by reference.

	10.36	Amendment No. 2 to Amended and Restated Gas Purchase Agreement, dated July 1, 2002, among Oryx Gas Marketing Limited Partnership, Kerr-McGee Oil & Gas Corporation, Kerr-McGee Oil and Gas Onshore LP, and Cinergy Marketing & Trading, LLC, filed as Exhibit 10.25 to the Amendment to Annual Report on Form 10-K/A for the year ended December 31, 2003, and incorporated herein by reference.

	10.37	Letter Agreement, dated May 23, 2003, amending Amended and Restated Gas Purchase Agreement, dated July 1, 1998, among Kerr-McGee Oil & Gas Corporation, Kerr-McGee Oil and Gas Onshore LP, and Cinergy Marketing & Trading, LLC, filed as Exhibit 10.26 to the Amendment to Annual Report on Form 10-K/A for the year ended December 31, 2003, and incorporated herein by reference.

	10.38*	Oryx Energy Company Executive Retirement Plan, as amended and restated January 1, 1995, filed as Exhibit 10.34A to the Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated herein by reference.

	10.39	Agreement, dated April 14, 2005, between the Company, Carl C. Icahn, Barberry Corporation, Hopper Investments, LLC, High River Limited Partnership, Icahn Partners Master Fund LP, Icahn Offshore LP, CCI Offshore LLC, Icahn Partners LP, Icahn Onshore LP and CCI Onshore LLC and Barry Rosenstein, Gary Claar and JANA Partners LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K dated April 14, 2005, and incorporated herein by reference.

	10.40	Retirement Benefit Preservation Agreement, dated July 18, 2005 between Kerr-McGee Corporation and Luke R. Corbett, filed as Exhibit 99.2 to the Current Report on Form 8-K dated July 18, 2005, and incorporated herein by reference.

	10.41	Retirement Benefit Preservation Agreement, dated July 18, 2005 between Kerr-McGee Corporation and Kenneth W. Crouch, filed as Exhibit 99.3 to the Current Report on Form 8-K dated July 18, 2005, and incorporated herein by reference.

	10.42	Agreement and Plan of Merger, dated January 23, 2006, among Kerr-McGee Oil & Gas Corporation, Kerr-McGee Oil & Gas (Shelf) LLC, W&T Offshore, Inc., and W&T Energy V, LLC.

	10.43	Sale and Purchase Agreement between Kerr-McGee North Sea (U.K.) Limited (“KM North Sea”) and Centrica Resources Limited (“Centrica”), dated August 6, 2005, pursuant to which KM North Sea agreed to sell its nonoperating interest in the Skene field assets to Centrica, filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, and incorporated herein by reference.

	10.44	Sale and Purchase Agreement between KM North Sea and Centrica, dated August 6, 2005, pursuant to which KM North Sea agreed to sell its nonoperating interest in the Buckland field assets to Centrica, filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, and incorporated herein by reference.

	Exhibit No.

	10.45	Letter Agreement between KM North Sea and Centrica dated August 30, 2005, amending (i) the Sale and Purchase Agreement between KM North Sea and Centrica, dated August 6, 2005, pursuant to which KM North Sea agreed to sell its nonoperating interest in the Skene field assets to Centrica and (ii) the Sale and Purchase Agreement between KM North Sea and Centrica, dated August 6, 2005, pursuant to which KM North Sea agreed to sell its nonoperating interest in the Buckland field assets to Centrica, filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, and incorporated herein by reference.

	10.46	Sale and Purchase Agreement between KM North Sea and Talisman North Sea Limited (“Talisman”), dated September 30, 2005, pursuant to which KM North Sea agreed to sell its nonoperating interest in the Andrew field assets to Talisman, filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, and incorporated herein by reference.

	10.47	Sale and Purchase Agreement between Kerr-McGee Oil (U.K.) Limited (“KM Oil”) and Centrica, dated August 6, 2005, pursuant to which KM Oil agreed to sell its nonoperating interest in the Brae field assets to Centrica, filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, and incorporated herein by reference.

	10.48	Sale and Purchase Agreement between KM Denmark Overseas ApS (“KM Denmark”) and Centrica Canada Limited (“Centrica Canada”), dated August 6, 2005, pursuant to which KM Denmark agreed to sell 100% of the stock of Kerr-McGee Canada Limited (“KM Canada”) to Centrica Canada, filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, and incorporated herein by reference.

	10.49	Sale and Purchase Agreement between KM Denmark, Alnery No. 2524 Limited (“Maersk”), the Company and A.P. Moller-Maersk A/S, dated August 7, 2005, pursuant to which KM Denmark agreed to sell all of the company’s remaining North Sea assets through the sale of 100% of the stock of Kerr-McGee (G.B.) Limited and Kerr-McGee Norway AS to Maersk, filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, and incorporated herein by reference.

	10.50	Sale and Purchase Agreement between KM North Sea and Amerada Hess Limited (“Hess”), dated September 30, 2005, pursuant to which KM North Sea agreed to sell its nonoperating interest in the UKCS License 103 Area W to Hess, filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, and incorporated herein by reference.

	10.51	Master Separation Agreement, dated as of November 28, 2005, among Kerr-McGee Corporation, Kerr-McGee Worldwide Corporation, and Tronox Incorporated.

	10.52	Employee Benefits Agreement, dated as of November 28, 2005, by and between Kerr-McGee Corporation and Tronox Incorporated.

	10.53	Tax Sharing Agreement dated as of November 28, 2005, between Kerr-McGee Corporation and Tronox Incorporated.

	10.54	Transition Services Agreement, dated as of November 28, 2005, among Kerr-McGee Corporation, Kerr-McGee Worldwide Corporation and Tronox Incorporated.

	Exhibit No.

	10.55	2005 Annual Incentive Compensation Plan Awards, filed as Exhibit 10.1 to the Current Report on Form 8-K dated February 27, 2006, and incorporated herein by reference.

	12	Computation of ratio of earnings to fixed charges.

	21	Subsidiaries of the Registrant.

	23.1	Consent of Ernst & Young LLP.

	23.2	Consent of Netherland, Sewell & Associates, Inc.

	24	Powers of Attorney.

	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.

	99	Report of Netherland, Sewell & Associates, Inc.

*These exhibits relate to the compensation plans and arrangements of the company.

SCHEDULE II

KERR-McGEE CORPORATION AND SUBSIDIARY COMPANIES

VALUATION ACCOUNTS AND RESERVES

			Additions
	Balance at		Charged to		Charged to			Deductions		Balance at
	Beginning		Profit and		Other			from		End of
(Millions of dollars)	of Year		Loss		Accounts			Reserves		Year

Year Ended December 31, 2005
Deducted from asset accounts
Allowance for doubtful notes
and accounts receivable	$	23	$	2	$	(1	)	$	-	$	24
Valuation allowance for
deferred tax assets		8		-		-			2		6
Warehouse inventory
obsolescence		12		2		-			4		10
Total	$	43	$	4	$	(1	)	$	6	$	40

Year Ended December 31, 2004
Deducted from asset accounts
Allowance for doubtful notes
and accounts receivable	$	19	$	4	$	2		$	2	$	23
Valuation allowance for
deferred tax assets		9		1		-			2		8
Warehouse inventory
obsolescence		8		5		-			1		12
Total	$	36	$	10	$	2		$	5	$	43

Year Ended December 31, 2003
Deducted from asset accounts
Allowance for doubtful notes
and accounts receivable	$	19	$	1	$	-		$	1	$	19
Valuation allowance for
deferred tax assets		-		9		-			-		9
Warehouse inventory
obsolescence		4		6		-			2		8
Total	$	23	$	16	$	-		$	3	$	36

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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



	By:	Luke R. Corbett*
		Luke R. Corbett, Director
		Chief Executive Officer



March 15, 2006	By:	(Robert M. Wohleber)
Date		Robert M. Wohleber
		Senior Vice President and
		Chief Financial Officer


	By:	(John M. Rauh)
		John M. Rauh
		Vice President and Controller
		and Chief Accounting Officer

* By his signature set forth below, John M. Rauh has signed this Annual Report on Form 10-K as attorney-in-fact for the officer noted above, pursuant to power of attorney filed with the Securities and Exchange Commission.

	By:	(John M. Rauh)
		John M. Rauh

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the date indicated.

	By:	Luke R. Corbett*
		Luke R. Corbett, Director

	By:	William E. Bradford*
		William E. Bradford, Director

	By:	Sylvia A. Earle*
		Sylvia A. Earle, Director

	By:	David C. Genever-Watling*
		David C. Genever-Watling, Director

March 15, 2006	By:	Martin C. Jischke*
Date		Martin C. Jischke, Director

	By:	Robert O. Lorenz*
		Robert O. Lorenz, Director

	By:	Michael Portillo*
		Michael Portillo, Director

	By:	Leroy C. Richie*
		Leroy C. Richie, Director

	By:	William F. Wallace*
		William F. Wallace, Director

	By:	Farah M. Walters*
		Farah M. Walters, Director

	By:	Ian L. White-Thomson*
		Ian L. White-Thomson, Director

* By his signature set forth below, John M. Rauh has signed this Annual Report on Form 10-K as attorney-in-fact for the directors noted above, pursuant to the powers of attorney filed with the Securities and Exchange Commission.

	By:	(John M. Rauh)
		John M. Rauh