Edgar Filing: KERR MCGEE CORP /DE

2004 10K

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, 2004

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.)

KERR-MCGEE CENTER, OKLAHOMA CITY, OKLAHOMA 73125

(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 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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $8.1 billion computed by reference to the price at which the common equity was last sold as of June 30, 2004, 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, 2005, was 156,425,184. On March 2, 2005, an additional 6,798,333 shares were issued upon conversion of 5.25% debentures.

DOCUMENTS INCORPORATED BY REFERENCE

The definitive Proxy Statement for the 2005 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2004, 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 its predecessors, Kerr-McGee Corporation began operations in 1929 as a privately held company. In 1956 the company’s stock began trading publicly on the New York Stock Exchange under the ticker symbol “KMG.” Kerr-McGee's worldwide businesses and those of its subsidiaries 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.

Kerr-McGee is an energy and inorganic chemical holding company whose consolidated subsidiaries, joint ventures and other affiliates (together, "affiliates") have operations throughout the world. Our core businesses include:

Exploration and Production - Kerr-McGee is one of the largest independent oil and gas exploration and production companies in the world, with major areas of operation onshore in the United States, in the Gulf of Mexico, the United Kingdom sector of the North Sea and China. In addition, we have strategic exploration programs in Alaska, Brazil, Morocco, Bahamas, and Benin. The company actively acquires leases and concessions and explores for, develops, produces and markets crude oil and natural gas.

Chemical - Kerr-McGee affiliates engaged in chemical businesses produce and market inorganic industrial chemicals (primarily titanium dioxide pigment), lithium-metal-polymer batteries and heavy minerals. We are the world’s third-largest producer and marketer of titanium dioxide pigment in terms of volumes produced.

The following table provides an overview of our operating performance and the composition of our assets and revenues by segment:

(Millions of dollars)	2004		2003		2002			2001		2000

Assets -
Exploration and Production	$	12,246	$	7,385	$	7,030		$	8,076	$	4,849
Chemical		1,543		1,734		1,655			1,631		1,638
Corporate and other		729		1,131		1,224			1,369		1,179
Total	$	14,518	$	10,250	$	9,909		$	11,076	$	7,666

Revenues -
Exploration and Production	$	3,855	$	2,923	$	2,450		$	2,428	$	2,802
Chemical		1,302		1,157		1,065			1,023		1,153
Total	$	5,157	$	4,080	$	3,515		$	3,451	$	3,955

Income (Loss) from Continuing Operations	$	415	$	264	$	(590	)	$	480	$	812

Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in the company’s 2005 Proxy Statement are not deemed to be filed as part of this annual report on Form 10-K.

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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 million barrels of oil equivalent (boe) to our reserves, an increase of 27% from year-end 2003. 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 $4.7 billion. For a more detailed description of the Westport merger, see Note 2 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., an independent oil and gas exploration and production company with active projects in the Denver-Julesburg Basin, Gulf Coast, Mid-Continent and Northern Rocky Mountain regions of the U.S. Through this acquisition, we added approximately 217 million boe of proved reserves, primarily consisting of natural gas reserves in the Denver, Colorado, area, and expanded our low-risk exploitation drilling opportunities. The acquisition price totaled $1.8 billion in cash, company stock and assumption of debt. In connection with the HS Resources, Inc. acquisition, we completed a holding company reorganization in which Kerr-McGee Operating Corporation, formerly known as Kerr-McGee Corporation, changed its name and became a wholly owned subsidiary of the company. In this Form 10-K, filings and references to the company include business activity conducted by the current Kerr-McGee Corporation and the former Kerr-McGee Corporation before it reorganized as a subsidiary of the company and changed its name to Kerr-McGee Operating Corporation. At the end of 2002, another reorganization took place, whereby among other changes, Kerr-McGee Operating Corporation distributed its investment in certain subsidiaries (primarily the oil and gas operating subsidiaries) to a newly formed intermediate holding company, Kerr-McGee Worldwide Corporation. Kerr-McGee Operating Corporation formed a new subsidiary, Kerr-McGee Chemical Worldwide LLC, and merged into it.

In addition to a discussion of recent business developments provided below, reference is made to Management’s Discussion and Analysis included in Item 7 of this annual report on Form 10-K, and the Exploration and Production Operations and Chemical Operations discussions below.

RECENT DEVELOPMENTS

Company to Pursue the Separation of its Chemical Business

The company announced on March 8, 2005, that its Board of Directors (the Board) authorized management to proceed with its proposal to pursue alternatives for the separation of the chemical business, including a spinoff or sale.

Share Repurchase Program

On March 8, 2005, the Board authorized the company to proceed with a share repurchase program initially set at $1 billion. The Board expects to expand the share repurchase program as the chemical business separation proceeds. The initial $1 billion share repurchase program primarily will be financed through the use of free cash flow generated from operations after planned capital expenditures, which is projected to be approximately $850 million in 2005. To ensure a portion of the projected cash flow, the company has entered into commodity derivative instruments covering approximately 50% of its projected oil and gas production. The company also expects to utilize a portion of its existing bank credit facility and may issue new securities, which may be in the form of debt or perpetual preferred stock, to fund the remaining repurchase program. The company still intends to retire $450 million of debt maturities due in 2005 in addition to the conversion of subordinated debentures discussed below. The Board and management reiterated their commitment to maintain an investment-grade credit rating.

The timing and final number of shares to be repurchased under an expanded repurchase program will depend on the outcome of the chemical business separation, as well as business and market conditions, applicable securities law limitations and other factors. Shares may be purchased from time to time in the open market or through privately negotiated transactions at prevailing prices, and the program may be suspended or discontinued at any time without prior notice.

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Recommendation to Increase Authorized Stock

The company’s Board of Directors in the March 8, 2005 meeting recommended for the stockholders to approve an increase of the authorized number of shares of the company’s common stock, par value $1.00 share, from 300 million shares to 500 million shares.

Conversion of 5.25% Debentures

In February 2005, the company called for redemption all of the $600 million aggregate principal amount of its 5.25% convertible subordinated debentures due 2010 at a price of 102.625%. Prior to March 4, 2005, the redemption date, all of the debentures were converted by the holders into approximately 9.8 million shares of common stock. As a result of this conversion, the number of total common shares outstanding increased to approximately 162 million as of March 11, 2005. Pro forma for the conversion, the company’s year-end 2004 total debt to total capitalization ratio would have been 34%.

SEGMENT AND GEOGRAPHIC INFORMATION

For financial information by operating segment and geographic information, see Note 27 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 growth through exploration, exploitation and acquisitions. The company’s high-impact deepwater exploration efforts are balanced with lower risk exploration activities in proven world-class hydrocarbon basins in areas such as Brazil, Alaska, and China, as well as the U.S. onshore, Gulf of Mexico shelf and the North Sea. Through our strategic merger with Westport in 2004, we added complementary high-quality assets in core U.S. onshore and Gulf of Mexico regions. Combined with our existing U.S. assets, the Westport properties provide a stable foundation of high-margin production and low-risk growth opportunities, complementing our high-impact deepwater exploration program. The Westport acquisition added net proved reserves of 281 million boe, approximately two-thirds of which were natural gas reserves. Primarily as a result of this acquisition, natural gas reserves as a percentage of total proved reserves increased from 52% to 57% during 2004. Additionally, we increased proved developed reserves as a percentage of total proved reserves from 50% at December 31, 2003 to 65% by the end of 2004. This increase is attributable to both the Westport merger and to development investments made during the course of the year.

Strong crude oil and natural gas prices combined with record production during 2004 contributed to a 25% year-over-year increase in segment operating profit, which was $1.2 billion for 2004. The company’s 2004 average daily production was 312,200 boe, a 15% increase from 2003. Natural gas production volume averaged 921 million cubic feet per day, an increase of 27% from 2003, and crude oil production volumes increased 6% in 2004 to 158,800 barrels per day. We ended 2004 with record fourth quarter production levels of 372,000 boe per day. The increase in production volumes during 2004 was largely attributable to the Westport merger. For 2005, we expect annual production to average between 352,000 and 367,000 boe per day.

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Oil and Gas Sales Revenues, Volumes, Prices and Production Costs

The following table summarizes the company's crude oil and natural gas sales volumes and sales revenues from continuing operations for each of the three years in the period ended December 31, 2004. Sales revenues presented below include the impact of the company’s hedging program. For information on the average realized sales prices including and excluding the effect of hedging arrangements, refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations - Segment Operations in Item 7 of this annual report on Form 10-K. Note 30 to the Consolidated Financial Statements included in Item 8 of this report presents the average lifting costs per boe.

(Millions)	2004		2003		2002

Crude oil and condensate (barrels)
U.S. Gulf of Mexico		21.9		20.7		19.2
U.S. onshore		10.3		7.2		10.5
North Sea		23.2		26.1		37.2
China		2.8		0.8		1.2
Other international		-		-		1.4
		58.2		54.8		69.5

Crude oil and condensate sales revenues
U.S. Gulf of Mexico	$	644.6	$	540.3	$	414.8
U.S. onshore		293.1		188.1		224.8
North Sea		613.7		673.9		832.8
China		92.2		23.2		29.5
Other international		-		-		28.9
	$	1,643.6	$	1,425.5	$	1,530.8

Natural gas (thousands of cubic feet)
U.S. Gulf of Mexico		133.1		101.0		99.8
U.S. onshore		172.6		128.5		141.0
North Sea		31.2		35.4		36.7
		336.9		264.9		277.5

Natural gas sales revenues
U.S. Gulf of Mexico	$	724.0	$	493.1	$	322.2
U.S. onshore		877.5		553.8		410.5
North Sea		127.0		109.3		86.4
	$	1,728.5	$	1,156.2	$	819.1

Reserves

Kerr-McGee’s estimated crude oil, condensate, natural gas liquids and natural gas proved reserves at December 31, 2004, and the changes in net quantities of such reserves for the three years then ended are shown in Note 32 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 2004, 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 and, for certain acquired Westport properties, third-party reserve engineers. In 2004, we engaged the independent reserve engineering firm of Netherland, Sewell & Associates, Inc. (NSAI) to review methods and procedures used by our engineers to estimate December 31, 2004 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 32 to the Consolidated Financial Statements included in Item 8 of this annual report on Form 10-K.

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Developed and Undeveloped Acreage

The following table summarizes the company’s developed and undeveloped acreage held through leases, concessions, reconnaissance permits and other interests at December 31, 2004:

	Developed Acreage				Undeveloped Acreage
Location	Gross		Net		Gross		Net

United States -
Gulf of Mexico		933,499		381,632		3,604,879		2,097,040
Alaska		-		-		18,087		12,661
Onshore		2,903,532		1,752,601		2,337,695		1,256,934
		3,837,031		2,134,233		5,960,661		3,366,635

North Sea		363,403		121,378		792,495		392,286

China ⁽¹⁾		22,487		9,015		1,664,500		1,469,130

Other international -
Morocco		-		-		30,245,687		13,973,805
Australia		-		-		10,031,824		6,129,398
Canada		-		-		2,087,220		1,310,826
Benin		-		-		2,459,439		1,721,607
Bahamas		-		-		6,488,680		6,488,680
Brazil		-		-		2,218,369		830,424
		-		-		53,531,219		30,454,740

Total		4,222,921		2,264,626		61,948,875		35,682,791

(1)	Subsequent to December 31, 2004, Kerr-McGee signed a production sharing contract covering 2.4 million acres in the South China Sea with a 100% foreign contractor’s interest in the first phase of the exploration period.

Gross and Net Productive Wells

The number of productive oil and gas wells in which the company had an interest at December 31, 2004, is shown in the following table. These wells include 1,888 gross or 857 net wells associated with improved recovery projects, and 2,584 gross or 2,472 net wells that have multiple completions but are included as single wells.

Location	Crude Oil		Natural Gas		Total
United States
Gross		4,332		7,659		11,991
Net		2,880		4,495		7,375

North Sea
Gross		274		5		279
Net		51		-		51

China
Gross		31		-		31
Net		12		-		12

Total
Gross		4,637		7,664		12,301
Net		2,943		4,495		7,438

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Net Exploratory and Development Wells Drilled

Domestic and international exploratory and development wells that were completed as successful or dry holes during the three years ended December 31, 2004 are summarized in the following tables.

	Net Exploratory ⁽¹⁾						Net Development ⁽¹⁾
	Productive		Dry Holes		Total		Productive		Dry Holes		Total		Total
2004 ⁽²⁾
United States		13.6		9.5		23.1		412.7		7.5		420.2		443.3
North Sea		-		3.1		3.1		4.7		-		4.7		7.8
China		-		1.8		1.8		12.4		-		12.4		14.2
Other international		-		.9		.9		-		-		-		.9
Total		13.6		15.3		28.9		429.8		7.5		437.3		466.2

2003
United States		6.7		11.0		17.7		241.6		1.0		242.6		260.3
North Sea		-		1.0		1.0		2.1		.1		2.2		3.2
Other international		-		5.0		5.0		.7		-		.7		5.7
Total		6.7		17.0		23.7		244.4		1.1		245.5		269.2

2002
United States		4.8		11.1		15.9		186.9		1.4		188.3		204.2
North Sea		-		1.9		1.9		8.6		-		8.6		10.5
Other international		-		4.2		4.2		.8		-		.8		5.0
Total		4.8		17.2		22.0		196.3		1.4		197.7		219.7

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

(2)

The 2004 net exploratory well count does not include 8.5 successful net wells drilled in the United States that are currently suspended, nor does it include 1.0 successful net well drilled in China, 1.6 successful net wells drilled in the North Sea, .3 successful net wells drilled internationally or 1.4 successful net wells drilled in the United States that will not be used for production.

Wells in Process of Drilling

The following table shows the number of wells in the process of drilling and the number of wells suspended or awaiting completion as of December 31, 2004:

	Wells in Process of				Wells Suspended or
	Drilling				Awaiting Completion
	Exploration		Development		Exploration		Development
United States
Gross		4.0		19.0		33.0		33.0
Net		1.8		11.5		13.4		14.5

North Sea
Gross		1.0		1.0		1.0		2.0
Net		.3		.1		.4		.2

China
Gross		-		1.0		-		-
Net		-		.4		-		-

Total
Gross		5.0		21.0		34.0		35.0
Net		2.1		12.0		13.8		14.7

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Product Sales and Marketing

Our oil and natural gas production is sold at prevailing market prices, and the realized revenue on the physical sale is adjusted for net realized gains or losses on commodity derivative instruments designated to hedge sales of our oil and gas production. For further details on such derivative instruments, see the Market Risks section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this annual report on Form 10-K.

The company markets all of its crude oil, located primarily in the Gulf of Mexico, the U.K. North Sea and Bohai Bay, China, under a combination of term and spot contracts to refiners, marketers and end users under market-reflective prices. Our single-largest purchaser of crude oil during 2004 was BP PLC, accounting for 23% of total crude oil sales revenues and 9% of total natural gas sales revenues, or 17% of total crude oil and natural gas sales revenues. The creditworthiness of each successful bidder is reviewed prior to product delivery.

Our single-largest purchaser of domestic natural gas is Cinergy Marketing & Trading LLC, whose purchases are guaranteed by its parent company, Cinergy Corporation. Purchases by Cinergy represented approximately 48% of total gas sales revenues, or 23% of total crude oil and natural gas sales revenues in 2004. Kerr-McGee manages this significant single-customer exposure through a credit risk insurance policy.

The loss of any one customer is not expected to have a material effect on the company due to high demand for oil and natural gas.

Marketing of the company's domestic natural gas from the Wattenberg and Greater 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 share of 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. Natural gas production from the Wattenberg and Uinta fields, along with other Rocky Mountain fields acquired with the Westport merger, is sold at prevailing market prices.

North Sea natural gas is sold both under contract and through spot market sales in the geographic area of production.

Exploration and Development Activities

The following table shows a summary of key 2004 data for the company’s operating areas. Production volumes are presented in thousands of barrels of oil equivalent per day (Mboe/d). Reserve volumes are stated in thousands of barrels of oil equivalent (Mboe). Additional information regarding oil and condensate and natural gas production, along with average prices received in 2004, 2003, and 2002 for the company's core geographic areas can be found in Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this annual report on Form 10-K.

	Estimated Proved										Realized Sales Price
	Reserves at 12/31/04					2004 Production					Including Effect of Hedges
			Percentage					Percentage			Oil		Gas
	Mboe		of Total			Mboe/d		of Total			$ per Barrel		$ per Mcf

U.S. Gulf of Mexico		325,805		27	%		120		38	%	$	29.43	$	5.44
U.S. onshore		613,254		50			107		34			28.43		5.08
North Sea		242,355		20			77		25			26.50		4.06
China		36,686		3			8		3			32.37		-
Total		1,218,100		100	%		312		100	%	$	28.23	$	5.13

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U.S. Gulf of Mexico

Kerr-McGee has been one of the pioneering exploration and production companies in the Gulf of Mexico since 1947, when we drilled the first successful well out of the sight of land. This tradition has continued with the pursuit of oil and gas farther offshore and in deeper water, where the company has developed a competitive advantage through the use of innovative and cost-effective technologies. Kerr-McGee was the first company to utilize floating production spar technology in the Gulf of Mexico in 1997 for its Neptune development. We continued to advance this technology through utilization of improved truss spar designs for our developments at the Nansen, Boomvang and Gunnison discoveries, which were sanctioned for development in 2000 and 2001. During 2004, first production was achieved at the Red Hawk development, where we used new cell spar technology, which lowers the threshold for economic development of deepwater reservoirs. The innovative design of the cell spar reduces the cost of construction and simplifies installation compared to other spar designs. Also in 2004, Kerr-McGee sanctioned both the Constitution discovery, where the company’s fourth truss spar will be utilized, and the Independence Hub, a deep draft semi-submersible platform at a water depth of 8,000 feet. The nonoperated Independence Hub is being constructed by a consortium including Kerr-McGee and five other companies and is designed to process production from six fields including Kerr-McGee’s Merganser, San Jacinto and Vortex fields.

Our merger with Westport led to increased production volumes and reserves in the Gulf of Mexico. However, because reserves added with the merger were primarily located in the U.S. onshore region, the weight of Gulf of Mexico proved reserves in our portfolio declined from 35% at year-end 2003 to 27% at year-end 2004. In 2004, Gulf of Mexico production represented 38% of the company’s worldwide crude oil and condensate production and 39% of its natural gas production, largely unchanged from 2003. We expect that, in 2005, the Gulf of Mexico region will represent 27% of the company’s total oil production and 39% of its natural gas production.

Kerr-McGee is one of the largest independent exploration and production companies operating in the Gulf of Mexico, with leases covering over 4.5 million gross acres. In 2004, the company maintained its position as one of the largest independent leaseholders in the deepwater Gulf of Mexico with approximately 530 deepwater blocks (deepwater locations are those in depths of more than 1,000 feet). We believe this extensive acreage holding provides a significant competitive advantage in our effort to maintain and develop a high-quality exploration prospect inventory.

Exploration Efforts

The Gulf of Mexico was again a focus of our exploration efforts in 2004. A total of fourteen deepwater exploratory wells were drilled or were drilling at the close of 2004. These wells included new field wildcats, satellites to existing infrastructure and appraisal wells to discoveries. In addition to the deepwater program, twelve exploratory wells were spud on the shelf of the Gulf of Mexico. Discoveries during 2004 included Ticonderoga (Green Canyon 768), Dawson Deep (Garden Banks 625), San Jacinto (DeSoto Canyon 618) and Nile (Viosca Knoll 869). Nile has been completed and will commence production in early 2005. Ticonderoga and San Jacinto have been sanctioned and design and equipment procurement are under way. Dawson Deep is anticipated to be sanctioned in 2005. Our exploration efforts on the Gulf of Mexico shelf were more active in 2004 compared to the prior year, which is the result of a focus on deep gas potential in a mature area, as well as properties entering the inventory through the Westport acquisition. The Westport inventory exposes Kerr-McGee to new trends and complements the existing portfolio.

To further enhance the exploration program, we entered into a joint venture with Stone Energy Corp. in the third quarter of 2004. This joint venture covers five to seven deepwater prospects, as well as several prospects on the Gulf of Mexico shelf. Drilling at the first of two deepwater wells in the joint venture package was ongoing at the end of the year and reached target depth in early 2005. The wells were declared unsuccessful in February 2005. Two additional exploration wells are planned for 2005.

At the close of the year, Kerr-McGee had contracted four deepwater drilling rigs for all or part of 2005, to facilitate execution of this part of the exploration program. Securing rig availability should allow the exploration pace to quicken and be maintained throughout 2005.

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Development Activities

Our development activity in the deepwater Gulf of Mexico also continued at a high level during 2004 in terms of capital outlay, wells drilled and construction activity. Gunnison well completion activity continued throughout the year, gradually building the field’s production rates. Installation of a cell spar was completed at Red Hawk and production began in July 2004. The Boomvang subsea production loop was completed, resulting in first production from the East Breaks 598 and 599 wells in the Boomvang field area.

Kerr-McGee also sanctioned participation in a joint project to develop several gas fields in the ultra deep waters (defined as greater than 8,000 feet) in the eastern Gulf of Mexico. The Independence Hub development will consist of a host processing and export facility to be located in Mississippi Canyon Block 920. This facility will receive production from six fields in the area through subsea tieback systems. We own an interest 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%). The project is expected to be completed by year-end 2006, with first production anticipated in the second quarter of 2007. Kerr McGee’s anticipated net production is over 100 million cubic feet of gas per day.

At the company's Constitution development, significant progress was made in 2004 on the truss spar construction. Development well drilling commenced in December 2004 and is expected to be completed in the second quarter of 2005. This Green Canyon (GC) block 679/680 discovery, which was approved for development in January 2004, is operated by Kerr-McGee with a 100% working interest. In addition, Kerr-McGee finalized plans for subsea tieback development of the Ticonderoga discovery (GC 768, 50% working interest) to the Constitution truss spar. Production from Constitution and Ticonderoga is expected to commence in the second quarter of 2006.

Deepwater Gulf of Mexico

Nansen field, East Breaks (EB) blocks 602 and 646 (50%): The Nansen field was sanctioned for development in March 2000, and first production was achieved in January 2002. Average 2004 gross production was 29,400 barrels of oil per day and 147 million cubic feet of gas per day. The Nansen field is developed with a truss spar in 3,700 feet of water and has nine dry-tree producers and three subsea wells tied back to the spar from a subsea cluster. Planned activity for 2005 includes the sidetracking of one subsea well and recompletion of three dry tree wells.

Navajo field, East Breaks block 690 area (50%): The Navajo field cluster is located on EB 646, 689 and 690. The Navajo discovery well, located in block 690, was drilled in September 2001. Following discovery, the well was completed and tied back to the Nansen spar located approximately five miles to the north. First production from Navajo was achieved in June 2002. Two previously drilled exploratory wells were completed and began production through the Navajo subsea system in 2003. A recompletion of one Navajo well is planned for 2005. Gross production from Navajo, West Navajo and Northwest Navajo wells averaged 17 million cubic feet of gas per day and 4,300 barrels of oil per day in 2004.

Boomvang field, East Breaks blocks 642, 643, 688 (30%), block 598 (50%) 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 is developed with a truss spar in 3,450 feet of water and has five dry-tree producers and four subsea wells tied back to the spar from two subsea clusters. Two successful exploratory wells drilled on Kerr-McGee leases adjacent to the Boomvang field, EB 598 #1 and EB 599 #1, were tied back to the Boomvang spar during 2004. These two wells utilize a new subsea pipeline and cluster system. First production from both wells was achieved in October 2004. Average 2004 gross production from the Boomvang area was 30,500 barrels of oil per day and 127 million cubic feet of gas per day.

Gunnison field, Garden Banks block 668 area (50%): The Gunnison field, sanctioned for development in October 2001, incorporates a truss spar in 3,100 feet of water and has seven dry-tree wells and three subsea wells. First production from Gunnison started in 2003 from the three subsea wells, which produced approximately 3,600 barrels of oil per day and 125 million cubic feet of natural gas per day. During 2004, a completion rig was installed on the spar and completion operations began on the seven dry-tree wells. The final completion had to be sidetracked by the spar completion rig, but was placed on production in December 2004. Throughout 2004, oil rates were ramped up to a maximum of approximately 18,000 barrels of oil per day as wells were completed, and gas rates were maintained between 100 and 140 million cubic feet per day. Average gross production from Gunnison in 2004 was approximately 11,500 barrels of oil per day and 119 million cubic feet of gas per day.

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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 has been 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 first production began in July 2004. By the start of August, gross production had reached peak projected rates of 120 million cubic feet of gas per day. At year-end 2004, the field was producing approximately 128 million cubic feet of gas per day.

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 11 dry-tree wells producing through the facility at a water depth of 1,950 feet. Four subsea wells also produced to the spar in 2004, and the Nile exploratory well was drilled and completed in late 2004, with first production expected in 2005. Average 2004 gross production from Neptune was 10,800 barrels of oil per day and 33 million cubic feet of gas per day. Additionally, platform upgrades are being completed to accommodate Neptune’s first third-party tieback, the Swordfish development, operated by Mariner. First production is planned for May 2005 and, along with Kerr-McGee’s recent subsea tiebacks, is expected to increase gross Neptune gas production to the expanded platform capacity of 100 million cubic feet per day.

Conger field, Garden Banks block 215 (25%): Average 2004 gross production from the Conger field was 28,000 barrels of oil per day and 87 million cubic feet of gas per day. 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 multi-well, 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 No. 6 well, was completed in December 2003. The Garden Banks 215 No. 8 well is anticipated to deplete its existing completion during 2005 and will be recompleted into a new zone, which is expected to increase production from this well.

Baldpate field, Garden Banks block 260 (50%): Average 2004 gross production from the Baldpate field, including the Penn State subsea satellite wells, was 14,100 barrels of oil per day and 36 million cubic feet of gas per day. 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.

Pompano field, Viosca Knoll block 989 area (25%): Average 2004 gross production from the Pompano field was 15,000 barrels of oil per day and 24 million cubic feet of gas per day. A platform rig was installed on Pompano during 2004 for a multi-well workover / recompletion program. Work on at least four wells is expected to be completed in the first half of 2005.

Gulf of Mexico Shelf

Production commenced in 2004 from several Gulf of Mexico shelf discoveries. Three wells were drilled at High Island 119 (42%), with initial gross production from two wells at 30 million cubic feet of gas. The third High Island 119 discovery began producing in January 2005. Three development wells and one exploratory well were drilled in the second half of 2004 at South Timbalier 41 (40%) with initial production of 15 million cubic feet of gas per day from the first well. First production from the remaining three wells, along with continued drilling in the field, is expected in 2005. In the fourth quarter of 2004, Garden Banks 208 (50%) began producing from a single subsea well at a gross rate of 15 million cubic feet of gas per day and Eugene Island 29 (45%) began producing at a gross rate of 5 million cubic feet of gas per day.

Development drilling took place in two fields in 2004. Two successful wells drilled at Main Pass 108 (75%) began producing at a gross rate of 15 million cubic feet of gas per day and two wells drilled in Ship Shoal 223 (32% to 45%) began producing at a gross rate of 5 million cubic feet of gas per day and 700 barrels of oil per day.

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U.S. Onshore

In the U.S. onshore exploration and production activities are segregated into two divisions, Rocky Mountain and Southern. Rocky Mountain operations are located in Colorado, North Dakota, Montana, Utah and Wyoming. Southern operations are primarily focused in Texas, Louisiana, Oklahoma, New Mexico and Kansas. In 2004, U.S. onshore production represented 51% of the company’s worldwide gas production, 18% of its oil production and 50% of total year-end proved reserves. The weight of U.S. onshore proved reserves in our worldwide portfolio increased from 34% at the beginning of the year, largely as a result of our merger with Westport. We expect that in 2005, this region will represent approximately 55% of the company’s total natural gas production and 20% of its oil production.

Rocky Mountain

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 Denver-Julesburg (DJ) basin in northeast Colorado. Our 2004 net production from this field was 11,300 barrels of oil per day and 171 million cubic feet of gas per day. During 2004, the company completed more than 300 development projects in the field, including deepenings, fracture stimulations, recompletions and an aggressive infill drilling program. The drilling activities in 2004 were focused on the Codell Niobrara formations, with approximately half of the wells including additional depth to allow for future completion in the J Sand. As part of the infill drilling program, 49 5^th spot wells (5^th well in 160 acres) were drilled in the field to recover reserves that are not being drained with the current field spacing. Results from this program were economic and additional locations have been scheduled for future drilling. Codell refracture programs, as well as the operations to add the third fracture stimulation to existing Codell producers, continue to supply significant low-risk development opportunities.

In support of the ongoing DJ basin exploitation program, the company continued to successfully integrate the Wattenberg gathering system into its operating activities. During 2004, one new compressor was purchased and installed. Approximately 69,000 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 system-wide. Kerr-McGee now operates more than 3,300 wells in the DJ basin, nearly 2,300 of which are connected to the Wattenberg gathering system. Company-operated production represents about 70% of the total system throughput of approximately 255 million cubic feet of natural gas per day, 30 million cubic feet of which is processed at the company’s Ft. Lupton plant.

During 2004, we participated in sixteen exploratory wells in the Rocky Mountain area. Evaluation continued in the northeastern Colorado Niobrara play with the drilling of three additional wells, all of which were successful. The Niobrara prospect acreage and the eight wells drilled during 2003 and 2004 were sold in August 2004. Production was established at the Iron Horse, Marquis and Ocla Draw prospects in the Wind River basin. Kerr-McGee is participating in a Coalbed Methane (CBM) pilot in the Green River basin. In 2004, we drilled a second test well in our Gold Coast block to evaluate CBM potential. We also are participating in the delineation of a Frontier discovery in the Big Horn basin. Exploration drilling and evaluation of our position in the NE Red Desert will continue in 2005.

Greater Natural Buttes field, Uinta County, Utah (82%): Kerr-McGee obtained an interest in the Greater Natural Buttes field area in 2004 as the result of the the Westport merger. Kerr-McGee operates approximately 850 wells in the greater Natural Buttes field area and has interests in an additional 430 nonoperated wells. The combined estimated net production rates from this area at year-end 2004 were 500 barrels of oil per day and 117 million cubic feet of gas per day. The 2004 drilling program was primarily focused on exploitation of the Wasatch and Mesa Verde formations. During 2004, Kerr-McGee participated in 128 wells in our ongoing, multi-year development program.

In support of the production operations in Natural Buttes, Kerr-McGee operates over 770 miles of gas gathering pipeline and 19 gas compressors, totaling 20,000 horsepower. The system grew by 6,000 horsepower in 2004. The system has the capacity to deliver 230 million cubic feet of gas per day 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 at least 10 additional compressor installations planned for 2005. Total gross production gathered at year-end 2004 was 195 million cubic feet of gas per day.

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Moxa Arch field, Southwest Wyoming (37%): Kerr-McGee obtained an interest in the Moxa Arch field area in 2004 as the result of the Westport merger. We now operate approximately 200 wells in the Moxa Arch field and have interests in 137 additional nonoperated wells. The combined estimated net production rates from this area at year-end 2004 were 300 barrels of oil per day and 27 million cubic feet of gas per day. The development program includes completions in both the Frontier and Dakota formations. During 2004, Kerr-McGee participated in 28 wells, including two wells that had initial production rates of 5 million cubic feet of gas per day in the Dakota formation. Development drilling is expected to continue in 2005.

Southern

The Southern division of our U.S. onshore operations had an active drilling program in 2004. We participated in 247 newly spud wells, of which 221 were development wells and 26 were exploratory wells. In 2004, we drilled 220 successful wells, and 13 wells were drilling at year-end, of which two are exploratory wells. The exploration program had a 77% success rate with twenty discoveries resulting in 2004, many of which have development follow-on potential.

Gulf Coast area: In the Gulf Coast area, a total of 41 wells were spud in 2004. The company plans to continue with an active drilling program in 2005, drilling over 50 wells in the Gulf Coast area. Kerr-McGee’s two primary Gulf Coast areas of development are Chambers County, Texas, and Liberty County, Texas.

Chambers County, Texas - In Chambers County, five of six development wells drilled in 2004 were successful. Our share of 2004 production averaged 2,400 barrels of oil equivalent per day from Chambers County. We plan to drill over 10 wells in this area during 2005.

Liberty County, Texas - In 2004, Kerr-McGee expanded its Liberty County property base by drilling five development wells, all of which were successful, and 13 exploratory wells, 12 of which were successful. The company’s net production rate at the end of 2004 was approximately 7,200 barrels of oil equivalent per day. We expect to drill over 10 wells in Liberty County in 2005.

South Texas area: In the South Texas area, a total of 56 wells were spud in 2004, including eight Wilcox, 21 Frio/Vicksburg, and 17 Lobo formation wells. Kerr-McGee plans to increase the drilling activity in 2005 by drilling in excess of 60 wells. Two areas of focus are:

Starr and Hidalgo counties, Texas - Kerr-McGee had an active drilling program in Starr County during 2004. Eighteen wells were spud, of which 17 resulted in new production. Average net production in 2004 from Starr and Hidalgo counties was 9,900 barrels of oil equivalent per day.

JC Martin field, Texas - The JC Martin field in Zapata County, Texas, produces from the Lobo formation at depths ranging from 8,500 to 10,000 feet. In 2004, we spud 11 development wells in the JC Martin field, 10 successful and one still drilling. This field produced an average of 2,300 net barrels of oil equivalent per day in 2004.

Mid-Continent/Permian area: In the Mid-Continent/Permian area, Kerr-McGee participated in 150 newly spud wells during 2004. At year-end, 122 of these new wells were producing, six were drilling and 19 were in the completion phase. This area covers production in 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 Indian Basin, New Mexico.

North Louisiana - The company owns an interest in the Elm Grove field and in the North Louisiana Field Complex, which is comprised of four adjacent fields. In 2004, Kerr-McGee maintained an aggressive development drilling program in the area, where 87 wells were drilled, 85 of which were successful, with two drilling at year-end. The company’s current net production for this area is approximately 5,000 barrels of oil equivalent per day. Kerr-McGee expects to drill over 70 wells in this area in 2005.

Indian Basin, New Mexico - This shallow decline area offers steady production to the Kerr-McGee portfolio. Four wells were drilled and brought online in 2004. Net production from Indian Basin averaged 2,300 barrels of oil equivalent per day in 2004.

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North Sea

Kerr-McGee has been active in the North Sea area since 1976. As of December 31, 2004, Kerr-McGee had interests in 20 producing fields in the United Kingdom sector. In 2004, North Sea production represented 39% of the company’s worldwide crude oil and condensate production and 9% of its gas production. The North Sea area represents about 20% of Kerr-McGee's total worldwide proved reserves. In 2004, the weight of the North Sea production and proved reserves in our worldwide portfolio declined due to our merger with Westport, which increased our reserve base in the U.S. We expect that in 2005 approximately 40% of the company’s total oil production and 6% of gas production will come from the North Sea area.

During 2004, the company launched a six-well North Sea exploration and appraisal program with the drilling of five operated wells and one nonoperated well. Of these six wells, four wells were dry and two wells were successful. One of these successful wells was the Dumbarton field appraisal well 15/20b-15, completed in November, which proved the southern area of the field. The Dumbarton field, Block 15/20, was acquired as part of the North Sea fallow block program. The field is currently under evaluation for development options either as a subsea tieback to existing nonoperated infrastructure or as a stand alone facility.

Business development initiatives during 2004 to strengthen the North Sea core area included acquiring 50% interest in license 29/20a and 11% in 30/2a shallow. In addition, a fallow block agreement was reached resulting in the acquisition of 66% interest and operatorship of block 22/25a, 50% interest and operatorship of blocks 23/26a (South), 30/1a and 30/1e, and 65% nonoperated interest in block 22/15. We also acquired 100% interest in block 16/21d and equalized our interest in blocks 9/15b and 9/15a (both are now at 86.32%). Certain of these acquired blocks contain known hydrocarbon discoveries, which the company believes may have future appraisal or development potential.

The following is a summary of the company’s five key developments in the North Sea area, with identification of Kerr-McGee’s working interest. These developments contributed approximately 77% of total net North Sea production during 2004.

Gryphon area, blocks 9/18a, 9/18b, 9/19 and 9/23a (Maclure field 33.3%, Gryphon field 86.5%, South Gryphon field 89.9% and Tullich field 100%): Average 2004 gross production from the Gryphon area was 29,200 barrels of oil per day and 10.7 million cubic feet of gas per day. The Maclure and Tullich subsea satellites began production in August 2002. In 2003, we acquired an additional 25% interest in the Gryphon area. This area is produced into a floating production, storage and offloading (FPSO) vessel, with oil exported via shuttle tanker. Gas is exported to the Leadon facility for fuel usage and/or sold on the spot market via the St. Fergus terminal.

Janice area, block 30/17a (75.3%): Average 2004 gross production from the Janice field was 11,400 barrels of oil per day and 1.2 million cubic feet of gas per day. During 2004, production began from the James field, part of the Janice area. Kerr-McGee operates James and Janice with a 75.3% interest. Oil from James is produced from a single well as a subsea tieback to the Janice 'A' floating production facility. First oil production from James occurred in November 2004 with sustained flow rates of approximately 8,000 barrels of oil equivalent per day.

Leadon field, block 9/14a and 9/14b (100%): Average 2004 gross production from the Leadon field was 7,900 barrels of oil per day. The Leadon field is being produced into an FPSO vessel, and the oil is exported via shuttle tanker.

Harding field, block 9/23b (30%): Average 2004 gross production from the Harding field was 38,600 barrels of oil per day. The Harding field provides Kerr-McGee with additional infrastructure in the strategically important quadrant 9 area of the North Sea. Within the same quadrant, Kerr-McGee also has interests in Gryphon, Leadon, Buckland, Skene, Maclure, and Tullich.

Skene field, block 9/19 (33.3%): The Skene field began producing in December 2001. Average 2004 gross field production was 106 million cubic feet of gas per day and 5,100 barrels of oil per day. The Skene field is being produced through a subsea tieback to the Beryl Alpha platform. The oil is exported via shuttle tanker, while the gas is exported via pipeline to the St. Fergus terminal.

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China

During 2004, China’s Bohai Bay became a core operating area for Kerr-McGee, with a total of eight discoveries made since the company first became involved in the area. In 2004, production in China represented 3% of the company’s worldwide oil and gas production. We expect this area will contribute over 10% of the company’s total 2005 oil production. In early 2005, we entered into a production sharing contract with China National Offshore Oil Corp. (CNOOC) for block 43/11, which covers 2.4 million acres in the deepwater South China Sea. We hold a 100% foreign contractor’s interest in the first phase of the exploration period. CNOOC has the right to participate with up to a 51% interest if Kerr-McGee enters into the development phase.

Bohai Bay block 04/36 (81.8% working interest in exploration and 40.09% in development and production phases): Kerr-McGee commenced first production from the CFD 11-1 and 11-2 oil fields in July 2004. Two platform topsides were installed and the FPSO was built in China’s port city of Dalian and then mobilized to the field in May 2004. Development drilling continued throughout the year at the CFD 11-1 field, and the development drilling program was completed at the 11-2 field. Thirty-six wells were completed and placed on either production or injection by the end of 2004. Gross production for 2004 was 15,100 barrels of oil equivalent per day (annualized), with year-end rates at 41,000 barrels of oil equivalent per day.

Oil in Place (OIP) reports for the CFD 11-3/11-5 fields were approved by the Chinese government in June 2004. CNOOC approved the Overall Development Plan for these fields in March 2005. Government approval is expected in the second quarter of 2005. The development plan centers on a tieback to the CFD 11-1 and 11-2 facilities with full processing of the fluids at the FPSO. Export will be commingled with similar quality crude from the CFD 11-1 and 11-2 fields. The development plan is based on four wells initially being drilled. First production is anticipated in the fourth quarter of 2005.

The CFD 11-1N-1 exploration well was drilled in 2004 to the north of the CFD 11-1 development area, but was declared unsuccessful.

Bohai Bay block 05/36 (50% working interest in exploration phase): Two appraisal wells were successfully drilled in the CFD 12-1 and 12-1S fields during 2003. The OIP reports for the CFD 12-1 and 12-1S fields in block 05/36, along with CFD 11-6 field in block 04/36, were approved in December 2004. The development plan for these fields is in the final stages of the approval process with CNOOC and new prospects for block 05/36 are being evaluated for drilling in 2005. In addition, CNOOC has approved a one-year extension which would provide for a new permit expiration date of February 28, 2006, subject to government approval. There will be a one-well obligation resulting from this extension and Shahejie play leads are being developed in preparation for this extension.

Bohai Bay block 09/18 (100% working interest in exploration phase): Two exploration commitment wells were drilled in this area in 2004, the CFD 14-5-1 and CFD 23-3-1. CFD 14-5-1 was an oil discovery in Eocene Shahejie sands. An appraisal program for the area is planned for 2005. The CFD 23-3-1 was declared unsuccessful. CNOOC has approved a one-year extension for the exploration phase, subject to government approval, whereby all 550,000 acres will be retained until the next election point on November 1, 2005.

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. Since the 2004 CFD 14-5-1 discovery well was in the deep Shahejie formation, the appraisal will extend into block 09/06. Drilling will occur in 2005. The company purchased 3-D seismic data to help define prospectivity of the area.

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Alaska

Kerr-McGee signed a participation agreement with Armstrong Oil and Gas (Armstrong) on December 24, 2003, to jointly explore areas of the prolific Alaska North Slope. Kerr-McGee acquired a 70% working interest in and operates nine leases totaling approximately 18,000 acres off the Alaska coast, northwest of Prudhoe Bay. The agreement includes the right to acquire an interest in 14 additional leases in the area, totaling 52,000 acres. In the October 2004 State of Alaska lease sale, Kerr-McGee and Armstrong were high bidders on four adjacent tracks with 5,120 available acres. In 2004, the company drilled a successful exploration and appraisal well on the NW Milne Point prospect (Nikaitchuq). An appraisal and testing program of the Nikaitchuq discovery is currently under way and two additional exploration wells are drilling.

Other International

Australia

WA 34-R (Formerly WA 278P) (39%): In 2004, a retention lease was granted by the Australian government for the areas around Kerr-McGee's Prometheus and Rubicon wells. These wells, drilled in 2000, successfully encountered natural gas but were considered noncommercial. We sold our interest in October 2004 and have no further obligations.

WA 301, 302, 303, 304 and 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 phase two of exploration. Geologic studies are planned in 2005 for blocks 303, 304 and 305. We have withdrawn from blocks 301 and 302 and have no further interest in the area.

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 data was acquired in late 2003, and processing is now complete. The remaining obligation for these blocks includes geologic studies, which are planned for 2005.

EPP 33 (100%): In late 2003, Kerr-McGee was awarded an interest in 1.3 million acres in the deepwater Otway basin. A new 2-D seismic survey over the block was acquired in the fourth quarter of 2004. Processing of the seismic data is currently under way.

Bahamas

On June 25, 2003, Kerr-McGee signed an exploration contract (100%) on 6.5 million acres in northern Bahamian waters, 90 miles east of the Florida coast. Water depths range from 650 feet to 7,000 feet. Kerr-McGee completed a speculative seismic acquisition program in 2004. Activity planned for 2005 includes seismic processing and interpretation.

Benin

Block 4 (70%): Kerr-McGee owns a 70% working interest in 2.5 million acres offshore Benin. Water depths on this block range from 300 feet to 10,000 feet. A two-well drilling program was initiated in 2002, and both wells found noncommercial amounts of hydrocarbons. In late 2002, Kerr-McGee and Petronas Carigali Overseas Sdn Bhd. entered into a partnership on the block. The joint venture entered the next three-year phase of exploration in August 2003. Acquisition of additional 2-D seismic data was completed in 2003 to evaluate areas not covered by the existing 3-D seismic data. Kerr-McGee is renegotiating a farmout agreement to reduce its interest in the block to 40%, pending government approval. The company has an obligation to drill one well during the current phase of exploration.

Brazil

BM-ES-9 (50%): This offshore block was acquired in 2001 and extends over 535,000 acres in the Espirito Santo basin in water depths ranging from 4,400 feet to 9,600 feet. During 2002, 3-D seismic data was acquired. An exploratory well at the Tartaruga Verde prospect was drilled in 2004 and was unsuccessful. The company has elected to withdraw from this block and has no further obligations.

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BM-C-7 (33 1/3%): In December 2003, Kerr-McGee acquired an interest in 161,000 acres in the Campos basin. Water depth on this block ranges from 300 to 400 feet. In 2004, Kerr-McGee participated in an exploratory well at the Dragon prospect. The well encountered hydrocarbons and oil samples were taken. Kerr-McGee also drilled one vertical appraisal well in late 2004, which was unsuccessful. Additional appraisal drilling and a potential flow test are scheduled for 2005. EnCanBrasil operates the block with 66 2/3% interest.

BM-C-32 (33%), BM-C-30 (25%), BM-C-29 (100%), BM-ES-M-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 (water depths of 200 to 6,600 feet). In the Campos Basin, we operate C-M-101BM-C-30 and C-M-202BM-C29. In the Espirito Santo basin, Devon Energy Corporation operates block C-M-61BM-C-32 and Petrobras operates blocks BM-ES-M-24 and BM-ES-25. To comply with governmental requirements, we expect to increase our interest in C-M-101BM-C-30 to 30%. Work obligations for the contract area include the acquisition of 3-D seismic, as well as an eight-well drilling commitment over a four-year period.

Morocco

Cap Draa block (11.25%): Kerr-McGee and partners had an exploration contract covering approximately 3 million acres along the deepwater shelf edge offshore Morocco, in water depths ranging from 650 feet to 6,500 feet. A 3-D seismic acquisition was completed in 2002. In February 2004, the company executed a farm-out agreement with Shell Oil Company, reducing its interest in this block to 11.25%. In mid-2004, Kerr-McGee participated in the drilling of one exploratory well which was unsuccessful. We have withdrawn from this block and have no further obligations.

Boujdour block (50%): In October 2001, Kerr-McGee acquired a reconnaissance permit covering approximately 27 million acres offshore Morocco from the shoreline to a water depth of more than 10,000 feet. A reconnaissance permit allows Kerr-McGee to perform seismic and related activities for evaluation purposes. In early 2003, we acquired a large 2-D seismic grid. A new seismic and drop core survey was acquired in 2004 and evaluation of the data is currently under way. In 2004, Kerr-McGee, Kosmos Energy Morocco HC and Pioneer Natural Resources Morocco Limited entered into a partnership on the block. Kerr-McGee is involved in discussions with the Moroccan government on future actions.

Gabon

In the Olonga Marin block, Kerr-McGee and partners conducted seismic operations in 2003. The company relinquished its acreage at the end of the exploration period in the first quarter of 2004.

Nova Scotia, Canada

EL2383, EL2386, EL2393 and EL2396 (50%): Kerr-McGee was operator of four deepwater blocks covering approximately 1.5 million acres offshore Nova Scotia, Canada, in water depths ranging from 500 feet to 9,200 feet. The agreements expired in 2004.

EL2398 (66 2/3%), EL2399 (100%) and EL2404 (50%): These Kerr-McGee operated blocks, covering more than 1.5 million acres, are in water depths ranging from 350 feet to 10,000 feet. A regional 2-D seismic program was interpreted in 2001, and additional 2-D seismic data was acquired in 2003. Norsk Hydro has taken a working interest in EL2404 and EL2398 and is providing technical evaluation.

Yemen

Block 50 (47.5%): Kerr-McGee relinquished its interest in block 50 in April 2004.

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CHEMICAL OPERATIONS

Kerr-McGee chemical operations consist of two segments (pigment and other chemical products) that produce and market inorganic industrial chemicals and heavy minerals through its affiliates, Kerr-McGee Chemical LLC, KMCC Western Australia Pty. Ltd., Kerr-McGee Pigments GmbH, Kerr-McGee Pigments International GmbH, Kerr-McGee Pigments Ltd., Kerr-McGee Pigments (Holland) B.V. and Kerr-McGee 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. Additionally, Kerr-McGee owns a 50% interest in a joint venture that produces lithium-metal-polymer (LMP) batteries. As discussed under Recent Developments above, Kerr-McGee is pursuing alternatives for the separation of its chemical business.

Exit Activities

In 2004, the company shut down its titanium dioxide pigment sulfate production at its Savannah, Georgia, facility and recognized a pretax charge of $105 million for costs associated with the shutdown. Demand and prices for sulfate anatase pigments, particularly in the paper market, had declined in North America consistently during the past several years. The decreasing volumes, along with unanticipated environmental and infrastructure issues discovered after Kerr-McGee acquired the facility in 2000, created unacceptable financial returns for the facility and contributed to the decision. The company also ended production at its Savannah gypsum plant that used by-product from the sulfate process to manufacture gypsum. The Savannah facility’s work force of 410 was reduced by approximately 100 positions. The company expects this decision to result in an improvement in segment operating profit of approximately $15 million annually.

On December 16, 2002, the company announced plans to exit the forest products business due to the strategic focus on the growth of the core businesses, oil and gas exploration and production and the production and marketing of titanium dioxide pigment. Four of the company’s five wood-treatment facilities were closed during 2003. The fifth plant, which was a leased facility, ceased all significant operations by the end of 2004 and the assets were sold in early 2005. Results of operations for the forest products business are reflected in the Consolidated Statement of Operations in income (loss) from discontinued operations for all periods presented.

Titanium Dioxide Pigment

The company’s primary chemical product is titanium dioxide pigment (TiO₂), a white pigment used in a wide range of products, including paint, coatings, plastics, paper and specialty applications. TiO₂ is used in these products for its unique ability to impart whiteness, brightness and opacity.

Titanium dioxide pigment is produced in two crystalline forms - rutile and anatase. The rutile form has a higher refractive index than anatase titanium dioxide, providing better opacity and tinting strength. Rutile titanium dioxide products also provide a higher level of durability (resistance to weathering). In general, the rutile form of titanium dioxide is preferred for use in paint, coatings, plastics and inks. Anatase titanium dioxide is less abrasive than rutile and is preferred for use in fibers, rubber, ceramics and some paper applications.

Titanium dioxide is produced using one of two different technologies, the chloride process and the sulfate process, both of which are used by Kerr-McGee. Because of market considerations, chloride-process capacity has increased to a substantially higher level than sulfate-process capacity during the past 20 years. The chloride process currently makes up about 60% of total industry capacity and accounts for approximately 83% of the company’s gross production capacity.

The company produces TiO₂ pigment at five production facilities. Two are located in the United States, the others are in Australia, Germany and the Netherlands. The following table outlines the company’s production capacity by location and process.

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TiO₂ Capacity

As of January 1, 2005

(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⁾ The Kwinana facility is part of the Tiwest Joint Venture, in which the company owns a 50% undivided interest.

The company owns a 50% undivided interest in a joint venture that operates an integrated TiO₂ project in Western Australia (the Tiwest Joint Venture). The venture consists of a heavy-minerals mine, a minerals separation facility, a synthetic rutile plant and a titanium dioxide plant.

Heavy minerals are mined from 8,513 hectares (21,027 acres) leased by the Tiwest Joint Venture. The company’s 50% interest in the properties’ remaining in-place proven and probable reserves is 6 million tonnes of heavy minerals contained in 214 million tonnes of sand averaging 2.8% heavy minerals. The valuable heavy minerals are composed of 61% ilmenite, 4.5% natural rutile, 3.4% leucoxene and 10% zircon, with the remaining 21.1% of heavy minerals having no significant value.

Heavy-mineral concentrate from the mine is processed at a 750,000 tonne-per-year dry separation plant. 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. The Tiwest Joint Venture provides synthetic rutile feedstock to its 110,000 tonne-per-year titanium dioxide plant located at Kwinana, Western Australia. Production of ilmenite, synthetic rutile, natural rutile and leucoxene in excess of the Tiwest Joint Venture’s requirements is sold to third parties, as well as to Kerr-McGee as part of its feedstock requirement for TiO₂ manufacturing under a long-term agreement executed in September 2000.

Information regarding the company’s 50% interest in heavy-mineral reserves, production and average prices for the three years ended December 31, 2004, 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)	2004		2003		2002
Proven and probable reserves		5,570		5,970		5,700
Production		302		294		289
Average market price (per tonne)	$	161	$	152	$	150

Titanium-bearing ores used for the production of TiO₂ include ilmenite, natural rutile, synthetic rutile, titanium-bearing slag and leucoxene. These products are mined and processed in many parts of the world. In addition to ores purchased from the Tiwest Joint Venture, the company obtains ores for its TiO₂business from a variety of suppliers in the United States, Australia, Canada, South Africa, Norway, India and Ukraine. Ores are generally purchased under multi-year agreements.

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, the company actively exports products, as required, from its facilities in the United States, Europe and Australia to other market regions.

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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 company’s products 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 consisted of the company's electrolytic operations and forest products business. As discussed above, the company sold its remaining assets of the forest products business in January 2005.

Electrolytic Products: Plants at the company’s Hamilton, Mississippi, complex include a 135,000 tonne-per-year sodium chlorate facility. Sodium chlorate is used in the environmentally preferred chlorine dioxide process for bleaching pulp. The conversion by the pulp and paper industry to chlorine dioxide technology from chlorine is essentially complete. Over 95% of sodium chlorate is consumed by the pulp and paper industry. Sodium chlorate demand in the United States is expected to increase approximately 2% to 3% per year in the near term as the pulp and paper industry recovers.

The company operates facilities at Henderson, Nevada, producing electrolytic manganese dioxide (EMD) and boron trichloride. Annual production capacity is 29,500 tonnes for EMD and 340,000 kilograms 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. The company’s share of the North American EMD market is approximately one-third. Demand is being driven by the need for alkaline batteries for portable electronic devices.

In July 2003, the company filed an anti-dumping action against low-priced EMD illegally imported into the U.S. and temporarily idled the Henderson, Nevada, EMD manufacturing facility due to the impact of these imports on market conditions. Partly as a result of the anti-dumping petition, demand for U.S. EMD products increased and the plant resumed operations in December 2003. While the company withdrew the anti-dumping petition in February 2004, we are continuing to monitor market conditions.

As part of the company’s strategic decision to focus on the titanium dioxide pigment business, the company continues to investigate divestiture options for the electrolytic business.

Forest Products: The principal product of the forest products business was treated railroad crossties. Other products included railroad crossing materials, bridge timbers and utility poles. As previously discussed, the company ceased significant operations at its remaining wood-treatment plant in December 2004.

Stored Power

The company owns a 50% interest in Avestor, a joint venture formed in 2001 to produce and commercialize a solid-state LMP 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. The Avestor joint venture began battery sales in late 2003 from its plant near Montreal, Canada, and started increasing production and sales rates in 2004. Initial battery sales and customer feedback indicate strong demand in the North American telecommunications industry, the initial target market. The European telecommunications market will be the most likely target in 2006. Battery quality and performance are being carefully monitored and evaluated as production rates increase. Development of AVESTOR batteries for industrial and electric utility markets is currently under way, with field trials planned in 2006. With market demand growing, Avestor expects to achieve a breakeven operating cash position in 2006 and anticipates sales matching plant capacity in 2009.

OTHER

Research and Development

The company’s Technical Center in Oklahoma City performs research and development in support of existing businesses and for the development of new and improved products and processes. The primary focus of the company’s research and development efforts is on the titanium dioxide business. A separate dedicated group at the Technical Center performs research and development in support of the company’s battery materials business.

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Employees

On December 31, 2004, the company and its affiliates had 4,084 employees. Approximately 888, or 22%, of these employees were represented by chemical industry collective bargaining agreements in the United States and Europe.

Competitive Conditions

The oil and gas exploration and production industry is highly competitive, and competition exists from the initial process of bidding for leases to the sale of crude oil and natural gas. Competitive factors include the ability to find, develop and produce crude oil and natural gas efficiently, as well as the development of successful marketing strategies. Many of the company's competitors, including integrated multinational oil and gas companies, have access to substantially greater financial resources, facilities and staffs than Kerr-McGee.

The titanium dioxide pigment business is highly competitive and some of our competitors have greater financial resources, staffs and facilities. The number of competitors in the industry has declined due to recent consolidations, and this trend is expected to continue. Our competitors' resources may give them various advantages when responding to market conditions. Significant consolidation among the consumers of titanium dioxide has also taken place during the past five years and is expected to continue. Worldwide, Kerr-McGee is one of only five producers that own proprietary chloride-process technology to produce titanium dioxide pigment. Cost efficiency and product quality as well as technical and customer service are key competitive factors in the titanium dioxide business.

It is not possible to predict the effect of future competition on Kerr-McGee's operating and financial results.

GOVERNMENT REGULATIONS AND ENVIRONMENTAL MATTERS

General

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 2004, direct capital and operating expenditures related to environmental protection and cleanup of operating sites totaled $32 million. Additional expenditures totaling $99 million were charged against reserves for environmental remediation and restoration. While it is difficult to estimate the total direct and indirect costs to the company of government environmental regulations, the company presently estimates that in 2005 it will incur $11 million in direct capital expenditures, $11 million in operating expenditures and $96 million in expenditures charged to reserves. Additionally, the company estimates that in 2006 it will incur $6 million in direct capital expenditures, $11 million in operating expenditures and $64 million in expenditures charged to reserves.

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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 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 potentially responsible parties, and it can be difficult to determine the number and financial condition of other potentially responsible parties and their respective shares of responsibility for cleanup costs;

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

·	unanticipated construction problems and weather conditions can hinder the completion of environmental remediation;

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

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

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, Environmental Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Item 7, and Note 19 to the Consolidated Financial Statements in Item 8 of this annual report on Form 10-K.

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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; and

·	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; and

·	reduced ability of the company to borrow funds.

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 tighten substantially from the prices established by these arrangements; or

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

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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 will be applied to the payment of principal and interest and will not be available for other purposes;

·	ratings of the company’s debt and other obligations vary from time to time and impact the costs, terms, conditions and availability of financing;

·	covenants associated with debt arrangements require the company to meet financial and other tests that can affect its flexibility in planning for and reacting to changes in its business, including possible acquisition opportunities;

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

·	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 significant 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;

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·	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; and

·	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 have occasionally 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 and the titanium dioxide pigment business are each 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 and chemical 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 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, as well as in producing chemicals, 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; failure of chemical plant equipment; and environmental hazards such as gas leaks, chemical leaks, oil spills and discharges of toxic gases.

Any of these risks can cause substantial losses in connection with the: 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:

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·	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; and

·	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, which includes review by independent reserve engineers, Netherland, Sewell & Associates, Inc. (NSAI), of the company’s procedures and methods for estimating reserves, internal peer review and third-party assessment of significant reserve additions and annual internal review of about 80% of the company’s total proved reserves. At December 31, 2004, approximately 43% of the company's proved reserves had been subjected to third-party procedures and methods reviews.

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. 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, such as: 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.

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 clean-up 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.

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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 non-compliance 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.

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 estimate reliably the amount and timing of all future expenditures related to environmental matters for the reasons described above in Items 1 and 2 under Government Regulations and Environmental Matters.

Although management 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 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 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 a material adverse effect on the company's results of operations for the accounting period or periods in which one or more of them might be resolved adversely.

AVAILABILITY OF REPORTS AND GOVERNANCE DOCUMENTS

Kerr-McGee makes available at no cost on its Internet website, 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 website. 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 website 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 website under the Corporate Governance link.

On June 1, 2004, 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, 2003, the certifications required under section 302 of the Sarbanes-Oxley Act of 2002.

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Item 3. Legal Proceedings

A. In 2001, the company’s chemical affiliate (Chemical) received a Notice of Violation (NOV) from EPA, Region 9. The NOV claims that Chemical has been in continuous violation of the Clean Air Act new source review requirements applicable to the construction in 1994 and continued operation of an open-hearth furnace at its Henderson, Nevada, facility. Chemical operated the open-hearth furnace in compliance with state-issued permits and believes that the NOV is without substantial merit. During the fourth quarter of 2004, the parties reached an agreement in principle on a settlement that is expected to resolve the NOV. Under the settlement, the government would waive its claim, and Chemical would pay penalties totaling approximately $50,000.

B. In 2002, Tiwest Pty Ltd, an Australian joint venture that produces titanium dioxide and in which Chemical indirectly has a 50% interest, received a complaint and notice of violation from the Department of Environmental Waters and Catchment Protection in Western Australia (the Department) alleging violations of the Environmental Protection Act (1986). This matter concerned an alleged chlorine release at the facility. Tiwest defended the proceeding in the Court of Petty Sessions, Perth, Western Australia, and on March 26, 2004, the Court found in favor of Tiwest. The Department has appealed the Court’s decision. Tiwest is vigorously defending against the appeal, and the company believes that, should the Court’s ruling be overturned, any fines or penalties related to the matter will not have a material adverse effect on the company.

C. On January 7, 2004, the United States filed a civil lawsuit in the U.S. District Court for the District of Oregon against Kerr-McGee Chemical Worldwide LLC and two other private parties in connection with the remediation of contaminated materials at the White King/Lucky Lass uranium mines in Lakeview, Oregon. The mines were owned and operated by a predecessor of Kerr-McGee Chemical Worldwide LLC and are currently designated as a Superfund site. The lawsuit seeks reimbursement of Forest Service response costs, an injunction requiring compliance with an Administrative Order issued to the private parties regarding cleanup of the site, and civil penalties for alleged noncompliance with the Administrative Order. All legal proceedings have been stayed pending discussions to resolve outstanding issues. The company believes that the litigation will not have a material adverse effect on the company.

D. On September 8, 2003, the Environmental Protection Division of the Georgia Department of Natural Resources (EPD) issued a unilateral Administrative Order to Kerr-McGee Pigments (Savannah) Inc., claiming that the Savannah plant exceeded emission allowances provided for in the facility's Title V air permit. The EPD is seeking monetary penalties of approximately $173,000. The company is vigorously defending against the claims made in the order and, in that connection, the order was appealed, and its effectiveness stayed, on October 8, 2003. The company believes that any penalties related to the Order will not have a material adverse effect on the company.

E. On September 15, 2004, the Missouri Attorney General issued to Kerr-McGee Chemical LLC (Chemical) a Notice of Violations (NOV) of the Missouri Clean Water Act. The NOV alleges the discharge of untreated contaminants from Chemical’s plant in Springfield, Missouri to the City of Springfield sanitation system and the Little Sac River. The Attorney General is requesting a civil penalty of $375,000, the performance of an environmental assessment and natural resource damages, which the Missouri Department of Natural Resources currently estimates to be $500,000. The contractor performing the decommissioning work at the plant at the time of the alleged discharge has acknowledged its contractual obligation to indemnify Chemical for costs, damages or fines resulting from its actions. The company believes that the claims made in the NOV are without substantial merit and that any penalties and damages related to the NOV will not have a material adverse effect on the company.

F. For a discussion of other legal proceedings and contingencies, reference is made to the Environmental Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Item 7 and Note 19 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.

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

None submitted during the fourth quarter of 2004.

Executive Officers of the Registrant

The following is a list of executive officers, their ages, and their positions and offices as of March 1, 2005:

Name	Age	Office

Luke R. Corbett	58	Chief Executive Officer since 1997. Chairman of the Board since May 1999 and from 1997 to February 1999. President and Chief Operating Officer from 1995 until 1997.

Kenneth W. Crouch	61	Executive Vice President since March 2003. Senior Vice President from 1996 to 2003. Senior Vice President, Exploration and Production Operations, from 1998 to 2003. Senior Vice President, Exploration, from 1996 to 1998.

David A. Hager	48	Senior Vice President (oil and gas exploration and production), since March 2003. Vice President of Exploration and Production, 2002 to 2003. Vice President of Gulf of Mexico and Worldwide Deepwater Exploration and Production, 2001 to 2002; Vice President of Worldwide Deepwater Exploration and Production, 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	44	Senior Vice President, General Counsel and Corporate Secretary since July 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.

Robert M. Wohleber	54	Senior Vice President and Chief Financial Officer since December 1999. Prior to joining the company in 1999, served as Executive Vice President and Chief Financial Officer of Freeport-McMoRan Exploration Company, President and Chief Executive Officer of Freeport-McMoRan Sulfur and Senior Vice President of Freeport-McMoRan Gold and Copper Corporation, each of which is a natural resources company.

Thomas W. Adams	44	Vice President of Chemical since September 2004. Vice President and General Manager of the Pigment Division from May to September 2004. Vice President of Strategic Planning and Business Development from 2003 to 2004. Vice President of Acquisitions from March 2003 to September 2003. Vice President of Information Management and Technology from 2002 to 2003. Joined Sun Oil Co., predecessor of Oryx Energy Company, in 1982. Oryx and Kerr-McGee merged in 1999.

George D. Christiansen	60	Vice President, Safety and Environmental Affairs, since 1998. Vice President, Environmental Assessment and Remediation, from 1996 to 1998.

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Fran G. Heartwell	58	Vice President of Human Resources since March 2003; Director of Human Resources, Kerr-McGee Oil & Gas, from September 2002 to January 2003; Vice President of Human Resources and Administration, Oryx Energy Company, from 1995 until the 1999 merger of Oryx and Kerr-McGee.

Christina M. Poos	35	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	55	Vice President since 1987. Controller from 1987 to 1996 and from January 2002 to present. Treasurer from 1996 to 2002.

John F. Reichenberger	52	Vice President, Deputy General Counsel and Assistant Secretary since July 2000. Assistant Secretary and Deputy General Counsel from 1999 to 2000. Deputy General Counsel from 1998 to 1999. Associate General Counsel from 1996 to 1999.

There is no family relationship 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, demand for consumer products for which Kerr-McGee’s businesses supply raw materials, the financial resources of competitors, changes in laws and regulations, the ability to respond to challenges in international markets, including changes in currency exchange rates, political or economic conditions 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.

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PART II

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

Information relating to the market in which the company's common stock is traded, the high and low sales prices of the common stock by quarters for the past two years, and the approximate number of holders of common stock is furnished in Note 34 to the Consolidated Financial Statements included in Item 8 of this annual report on Form 10-K.

Quarterly dividends declared totaled $1.80 per share for each of the years 2004, 2003 and 2002. Cash dividends have been paid continuously since 1941 and totaled $205 million in 2004, $181 million in 2003 and $181 million in 2002.

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.

Item 6. Selected Financial Data

Information regarding selected financial data required in this item is presented in the schedule captioned "Ten-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

Overview

Kerr-McGee Corporation is one of the largest U.S.-based independent oil and gas exploration and production companies and the world's third-largest producer and marketer of titanium dioxide pigment in terms of volumes produced. Kerr-McGee has three reportable business segments, oil and gas exploration and production, production and marketing of titanium dioxide pigment (chemical - pigment), and production and marketing of other chemical products (chemical - other). Discussion of business developments and results of operations for each of our reportable segments is provided below. The company announced on March 8, 2005, that its Board of Directors authorized management to proceed with its proposal to pursue alternatives for the separation of the chemical business, including a spinoff or sale.

In 2004, we merged with Westport Resources Corporation (Westport), an independent exploration and production company with operations onshore in the United States and in the Gulf of Mexico. The merger, which was completed on June 25, 2004, increased our year-end 2003 proved oil and gas reserves by approximately 30% on a pro forma basis, with year-end 2004 reserves reaching 1.2 billion barrels of oil equivalent. 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 $4.7 billion. The Westport merger added properties to our oil and gas business that are complementary to existing operations. We believe this merger improves the risk profile of our assets by adding low-risk exploitation opportunities and increasing the weight of U.S. onshore natural gas reserves in our portfolio. U.S. onshore reserves increased from 34% of total proved reserves at the beginning of the year to 50% at year-end, largely as a result of our merger with Westport. Additionally, the merger contributed to an increase in proved developed reserves from 50% of total proved reserves at December 31, 2003, to 65% by the end of 2004. Because the percentage of our reserves located onshore in the U.S. increased, we expect that this area will represent a higher proportion of our worldwide production volumes and a larger share of our total capital spending in the future. Based on our current budget, we expect that U.S. onshore production will represent approximately 40% of our total production in 2005 on a barrel of oil equivalent basis, an increase from 34% during 2004, and our capital expenditures in this region are anticipated to increase from 17% of total capital expenditures in 2004 to 32% in 2005.

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Strategically, Kerr-McGee focuses on growing its exploration and production operations and improving profitability of its titanium dioxide pigment business through technological advancements and optimization of assets. Additionally, we continue to concentrate on reducing the company’s total debt burden to remain competitive and to increase financial flexibility. As a result of certain investing and financing activities, including the Westport merger, the ratio of total debt to total capitalization improved from 58% at year-end 2003 to 41% by the end of 2004 (capitalization is determined as total debt plus stockholders’ equity). In February 2005, the company called for redemption all of the $600 million aggregate principal amount of its 5.25% convertible subordinated debentures due 2010 at a price of 102.625%. Prior to March 4, 2005, the redemption date, all of the debentures were converted by the holders into approximately 9.8 million shares of common stock. Pro forma for the conversion, the company’s year-end 2004 total debt to total capitalization ratio would have been 34%. On March 8, 2005, the Board of Directors authorized the company to proceed with a share repurchase program initially set at $1 billion. Expanded discussion of the company’s cash flows, liquidity and capital resources is included in the Financial Condition section below.

We continue to manage risks associated with our environmental remediation responsibilities. Because of the nature of Kerr-McGee’s current and historical operations, the company has significant environmental remediation responsibilities and provides reserves for these remediation projects. During 2004, the company provided $92 million (net of reimbursements) for environmental remediation and restoration costs, of which $6 million related to discontinued operations, and funded $49 million of expenditures associated with its environmental projects, net of $50 million in reimbursements received from other parties. A discussion of the status and circumstances surrounding these projects is included in the Environmental Matters section below.

The following table summarizes segment operating profit (loss), with a reconciliation to consolidated net income (loss) for each of the last three years:

(Millions of dollars)	2004			2003			2002

Segment operating profit (loss) (1) -
Exploration and production	$	1,249		$	1,002		$	(140	)

Chemical -
Pigment		(80	)		(13	)		24
Other		(1	)		(23	)		(13	)
Total Chemical		(81	)		(36	)		11

Total segment operating profit (loss)		1,168			966			(129	)

Unallocated expenses -
Interest and debt expense		(245	)		(251	)		(275	)
Corporate expenses		(130	)		(152	)		(158	)
Environmental provisions, net of reimbursements		(82	)		(47	)		(32	)
Other income (expense)		(40	)		(57	)		(31	)
Benefit (provision) for income taxes		(256	)		(195	)		35
Total unallocated expenses		(753	)		(702	)		(461	)

Income (Loss) from continuing operations		415			264			(590	)
Discontinued operations, net of taxes		(11	)		(10	)		105
Cumulative effect of change in accounting principle, net of taxes		-			(35	)		-
Net Income (Loss)	$	404		$	219		$	(485	)

Net Income (loss) per Common Share:
Basic	$	3.20		$	2.18		$	(4.84	)
Diluted		3.11			2.17			(4.84	)

⁽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.

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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 (loss) 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 in the Results of Operations - Consolidated and Results of Operations by Segment sections below.

(Millions of dollars)	2004			2003			2002
Included in Total Segment Operating Profit:
Plant shutdown costs and accelerated depreciation	$	(122	)	$	(45	)	$	(12	)
Environmental provisions		(4	)		(13	)		(21	)
Asset impairments		(36	)		(14	)		(646	)
Gain (loss) associated with assets held for sale		(29	)		45			(176	)
Nonhedge derivative loss		(23	)		-			-
Insurance premium adjustment		(16	)		-			-
Costs associated with the 2003 work force reduction program		(2	)		(35	)		-
Compensation expense for allocated ESOP shares		-			(15	)		-
Other		-			(4	)		(4	)

Included in Unallocated Expenses:
Environmental provisions, net of reimbursements		(82	)		(47	)		(32	)
Foreign currency losses		(21	)		(41	)		(38	)
Litigation costs		(6	)		(9	)		(72	)
Gain on sale of Devon stock		9			17			-
Costs associated with the 2003 work force reduction program		-			(18	)		-
Compensation expense for allocated ESOP shares		-			(6	)		-
Other		(4	)		(6	)		6

Total items affecting comparability	$	(336	)	$	(191	)	$	(995	)

An overview of each segment is included below to provide background information for the various discussions that follow in Management’s Discussion and Analysis of Financial Condition and Results of Operations. A detailed discussion of each segment’s business and properties is included in Items 1 and 2 of this annual report on Form 10-K.

Exploration and Production - The company's oil and gas business is principally focused on exploration, development and production of crude oil and natural gas. Our core areas of operation are in the Gulf of Mexico, onshore in the United States, the United Kingdom sector of the North Sea and China. In addition, we are actively engaged in exploration efforts within the core areas listed above, as well as in Alaska, Brazil, Morocco, Bahamas, Benin and other areas.

Our exploration and production business is focused on creating shareholder value and profitable growth through exploration, core area exploitation and tactical acquisitions. The first component of our strategy is deepwater-focused exploration in both the Gulf of Mexico and key international basins, complemented by lower risk exploration activities onshore in the U.S., Gulf of Mexico shelf, the North Sea and China. Over the past year, Kerr-McGee has refined its international/new ventures exploration strategy to focus primarily on opportunities in areas with proven world-class hydrocarbon basins such as Brazil and Alaska. We believe this refined strategy will yield more predictable results from exploration and better year-over-year growth performance from the drill-bit.

Cost-efficient core area exploitation is a second key component of the company’s strategy. Exploitation and development opportunities within our core areas of operation provide the base cash generation capability of our business and ultimately fund exploration growth opportunities. The company supplements its exploration and exploitation programs with tactical acquisitions in its core producing areas. We only pursue acquisition opportunities where we can add incremental value through unique geological knowledge, utilization of existing infrastructure in the areas acquired or our ability to lower costs.

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Commodity prices were relatively high throughout 2004. This price strength, coupled with a 15% increase in average daily production volume, enabled us to fund a $1.2 billion capital expenditure program and still generate significant excess free cash flow. Significant financial and operating milestones achieved by the exploration and production business in 2004 included:

·	Successful completion of the Westport merger.

·	Operating profit increased 25% over 2003, reaching a record $1.2 billion.

·	Average daily production volumes were 312,200 barrels of oil equivalent in 2004, an increase of 15% over 2003, largely due to the Westport merger. We anticipate that 2005 average daily production will range between 352,000 and 367,000 barrels of oil equivalent.

·	Replaced 280% of 2004 production largely as a result of the Westport merger.

·	Achieved first production from the Red Hawk development in the deepwater Gulf of Mexico. The project was completed on time and within budget.

·	Achieved first production from the CFD 11-1 and CFD 11-2 development in Bohai Bay, China. First production was achieved nearly five months ahead of schedule and within budget.

Although the company achieved a number of significant exploration successes in 2004, most were not well enough defined to recognize proved reserves, but may offer potential for future proved reserves additions. 2004 discoveries included:

·	Ticonderoga (50% working interest) in the deepwater Gulf of Mexico, which will be developed as a subsea tieback to our Constitution development.

·	Nikaitchuq (70%) in Alaska where we drilled two successful wells in 2004. An appraisal and testing program designed to delineate the discovery is currently under way.

·	BMC-7 (33%) in the Campos Basin of Brazil. Appraisal of this discovery is ongoing.

·	CFD-14-5-1 (100%) in the 09/18 block in Bohai Bay, China. Appraisal planning for this discovery is under way, and we expect to spud the first appraisal well in the first quarter of 2005.

Despite these successes and other successful exploratory wells onshore in the U.S. and in the Gulf of Mexico, the exploration program was unable to deliver an acceptable level of proved reserve additions in 2004, with an exploration-based production replacement of only 34%. To improve the consistency of its exploration performance, the company has refocused its core exploration program in areas with proven world-class hydrocarbon basins. Concentrating our exploration in areas where working hydrocarbon systems are known to exist reduces the geologic risk profile for the company, increasing our chances of discovering economically recoverable accumulations of oil and gas. We believe this shift in focus moves us to a more appropriate overall risk profile. The merger with Westport also is anticipated to provide an important source of future low-risk proved reserve additions. The company believes its refined exploration strategy, supplemented by low- to moderate-risk offshore satellite opportunities and an active U.S. onshore program focused on contributing to our proved reserves, will improve the consistency of results from exploration and deliver better year-over-year performance.

The merger with Westport added substantial depth, breadth and balance to the company’s oil and gas operations. Specifically, the merger expanded the company’s base of low-risk exploitation projects in the Rocky Mountains, U.S. Gulf Coast and the Mid-Continent/Permian Basin areas. In addition, the merger changed the composition of the company’s reserve base, increasing U.S. reserves from 69% at year-end 2003 to 77% at year-end 2004. A significant portion of the acquired U.S. reserves are long-lived natural gas reservoirs. The Westport merger accelerated the company’s growth profile, contributing to a 15% increase in production over 2003. Since the completion of the merger, we have moved rapidly to capitalize on new exploitation opportunities, with much of our effort focused in two key fields, the Greater Natural Buttes in Utah and Moxa Arch in Wyoming. This exploitation focus is already generating strong results, with production from Westport’s Rocky Mountain properties up by over 15% since the merger.

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Our refined exploration strategy has been designed to put the company on track to deliver improved exploration performance in 2005 and beyond. The company has a large portfolio of low-risk exploitation projects, and we intend to capitalize on those opportunities in 2005. For 2005, we have planned the largest exploration and development program in the company’s history, including some 900 exploration and development wells, $1.7 billion in capital expenditures and $380 million in exploration costs. We are committing the resources necessary to effectively execute this program with a goal of delivering growth in both reserves and production.

Chemical - Our chemical business has focused its strategy on its titanium dioxide pigment operations. As part of this strategic decision, we continue to investigate divestiture options for the electrolytic business and finalized our exit of the forest products business in early 2005. Results of operations for the forest products business are reflected in the Consolidated Statement of Operations in income (loss) from discontinued operations for all periods presented.

Titanium dioxide pigment is produced using one of two different technologies, the chloride process and the sulfate process. The chloride process produces a pigment with superior brightness and durability preferred by many manufactures of paint, coatings and plastics. In early 2005, chloride-process capacity accounted for 83% of our gross pigment production capacity. The remaining capacity is sulfate-process production, which produces pigment used in paper and specialty products. In the global titanium dioxide pigment industry, Kerr-McGee is the third-largest producer and marketer and one of five companies that own chloride technology.

The profitability and cash flows of the company’s pigment operations is directly tied to the global demand, consumption and pricing of titanium dioxide pigment, which tends to follow global economic trends (discussed in the Operating Environment and Outlook section below). While the general business environment and pigment pricing play a major role in profitability, execution of asset optimization plans, operations excellence, supply chain management principles, technological innovation and market segmentation further affect performance.

To optimize our assets and improve profitability, the company shut down its Savannah, Georgia, titanium dioxide pigment sulfate facility in 2004. This facility contributed approximately 4% of our total worldwide pigment production in the first half of 2004. Demand and prices for sulfate anatase pigments, particularly in the paper market, had consistently declined in North America during the past several years. The decreasing volumes, along with unanticipated environmental and infrastructure issues discovered after Kerr-McGee acquired the facility in 2000, created unacceptable financial returns for the facility and contributed to the decision. In conjunction with this decision, the company also ended production at its Savannah gypsum plant that used by-product from the sulfate process to manufacture gypsum. In connection with the shutdown, the company recognized a pretax charge of $105 million during 2004.

As part of the company's efforts in the area of technological innovation, low-cost capacity expansions were added to take advantage of future market growth. As a result of these efforts, production began through a new high-productivity oxidation line at the Savannah, Georgia, chloride process pigment plant in early 2004. This new technology is expected to result in low-cost, incremental capacity increases through modification of existing chloride oxidation lines and should allow for improved operating efficiencies through simplification of hardware configurations and reduced maintenance requirements.

The company continues to evaluate the performance of this new oxidation line and expects to have a better understanding of how the Savannah site might be reconfigured to exploit its capabilities in 2005. The possible reconfiguration of the Savannah site, if any, could include redeployment of certain assets, idling of certain assets and reduction of the future useful life of certain assets, resulting in the acceleration of depreciation expense and the recognition of other charges.

The Avestor joint venture was created by Kerr-McGee and Hydro-Quebec, one of North America’s largest utilities, to commercialize and produce a lithium-metal-polymer battery. Commercial battery production and sales commenced in late 2003 to the North American telecommunications industry. Production and sales rates increased during 2004 and are expected to continue increasing during 2005. Avestor’s unique technical and product offering capability is expected to create additional high-market-value opportunities in the electric utility and industrial battery back-up energy markets. With market demand growing, Avestor expects to achieve a breakeven operating cash position in 2006 and anticipates sales matching plant capacity in 2009.

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Operating Environment and Outlook

Oil and Gas Exploration and Production

Commodity Markets - The oil and gas industry enjoyed strong commodity prices throughout 2004. Supply and geopolitical uncertainties, combined with strong demand, resulted in historically high prices for the industry. Prices for West Texas Intermediate (WTI) crude oil averaged $41.40 per barrel for the year, with a low price of about $32.50 per barrel occurring in the first quarter and a high price point in excess of $55.00 per barrel in late October. Crude oil prices were driven largely by geopolitical instabilities in various producing regions, including the Middle East, Nigeria and Venezuela, as well as concerns that world oil production may be challenged to meet overall market demand. These concerns, coupled with rapidly growing demand, particularly in Asian markets, contributed to strong pricing and market volatility. The year ended with WTI crude oil prices at about $43.50 per barrel. U.S. natural gas pricing was also strong throughout the year, with New York Mercantile Exchange (NYMEX) futures prices never falling below $5.00 per million British thermal units (MMBtu). The gas market continues to be driven by fundamental uncertainties regarding the industry’s ability to maintain supply in line with increasing demand. In spite of high gas storage inventories, pricing peaked during the fourth quarter of 2004 at around $8.00 per MMBtu. Late in the fourth quarter, prices moderated in response to continued high inventory levels and mild winter conditions for much of the country. For the year, NYMEX natural gas prices averaged about $6.15 per MMBtu and ended the year at about $6.40 per MMBtu. The outlook for the commodity markets in 2005 calls for continued volatility. Most experts see prices for both oil and gas moderating, but remaining above historical levels.

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

Industry Environment - Competition in the oil and gas industry for attractive exploration, exploitation and development opportunities is intense. To meet this competition, Kerr-McGee employs a balanced portfolio of attractive exploration opportunities, supplemented by lower-risk satellite and onshore exploration prospects and a strong exploitation project inventory. In addition, the company pursues tactical acquisitions, property exchanges and other business development activity to augment its exploration, exploitation and development programs.

The company’s exploration portfolio is anchored by a large acreage and prospect inventory. The company makes extensive use of technology and highly trained geoscientists to effectively evaluate prospects, reducing pre-drill risk to an acceptable level. The company maintains a dedicated exploration technology group which focuses on 3-D visualization technology, seismic data processing and interpretation, and application of new and emerging technologies to more effectively evaluate exploration prospects. Over the past year, our exploration efforts have been refocused on proven world-class hydrocarbon basins to lower the overall risk profile. The company maintains a core group of highly experienced development personnel to quickly and efficiently exploit attractive new offshore oil and gas discoveries using new technologies. We currently operate five facilities in the deepwater Gulf of Mexico. This infrastructure provides Kerr-McGee with a competitive advantage, enabling the company to efficiently employ a hub-and-spoke concept of satellite exploration and exploitation of nearby opportunities. One of the company’s key strengths is its ability to profitably develop smaller offshore oil and gas discoveries that previously might have been considered uneconomical.

The company’s acquisition of HS Resources in 2001 and Westport in mid-2004 greatly enhanced its inventory of low-risk natural gas exploitation opportunities in the Rocky Mountain region. These gas resources are long life reservoirs, which work to stabilize the company’s production base. The relatively low risk nature of these opportunities provides balance to the company’s exploration program. In the U.K. the company also employs a hub and spoke development philosophy utilizing Kerr-McGee’s operated infrastructure as a base for satellite exploration and exploitation of nearby opportunities.

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The company utilizes regional business development teams to evaluate tactical acquisition and trade opportunities to supplement its exploration and exploitation efforts. A good example is the recently announced trade of our U.S. onshore Arkoma Basin properties for British Petroleum’s interest in the Blind Faith discovery in the Gulf of Mexico. The transaction provided the company with a 37.5% interest in a new offshore discovery which Kerr-McGee plans to quickly develop into new proved reserves and production.

In 2005, with higher commodity prices, the company expects competition for high-quality exploration and exploitation opportunities to remain strong. The company will continue to refine the exploration, exploitation and business development approach described above to gain competitive advantage among its peers.

Chemical

Titanium dioxide is a quality-of-life product, and its consumption follows general economic trends. Coming off a challenging year in 2003, business conditions for the company's chemical operations improved in 2004 due to general strengthening of the global economy. These economic forces created increases in demand, pushing capacity utilization higher and reduced overall inventory levels, thereby creating an environment favorable for product price gains. Partially offsetting the general economic robustness, were the impacts of higher energy prices on our operations and the weakening of the U.S. dollar, which weakened local pricing dynamics in various global markets. While overall global economic growth was strong throughout 2004, the last quarter of 2004 did begin to show signs of a leveling off in the leading U.S. economic indicators and Euro-zone gross domestic product. Moving into 2005, general economic conditions are expected to resemble more normal growth patterns, particularly in North America and Europe, while Asian markets are expected to lead the way, as they did in 2004.

The strategy for Kerr-McGee's chemical unit focuses on continued improvement in asset productivity, process and product capability, cost reductions and providing superior products for market-segment growth. Multiple initiatives are being pursued to capture new market growth through segmentation strategies that align products with customer needs, low-cost plant modifications to increase production capacity, continuous improvement programs to increase efficiency and lower operating costs, and technology-based programs to improve product quality and lower costs.

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Results of Operations - Consolidated

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

Revenues - The increase in 2004 revenues was primarily due to higher average realized sales prices and higher sales volumes for crude oil, natural gas and titanium dioxide pigment. Approximately 87% of the 2004 growth in consolidated revenues was generated by our oil and gas exploration and production segment. Oil and gas sales volumes on a barrel of oil equivalent basis increased 15% over 2003 volumes as a result of the Westport merger completed in June 2004. Oil and gas sales volumes declined in 2003 compared to 2002 primarily due to property divestitures. Average prices realized from sales of oil and gas, including the effect of realized losses on our hedging contracts, increased by 13% in 2004 and 29% in 2003 as a result of stronger commodity prices. Gas marketing sales revenues increased by $121 million in 2004 and $228 million in 2003 largely as a result of higher natural gas marketing volumes and prices. These increases were offset by higher gas purchase costs. Improvement in the general economic conditions favorably affected pigment sales volumes in 2004 and 2003, contributing to growth in our consolidated revenues. A summary of components of changes in consolidated revenues over the three-year period ended December 31, 2004, is presented below. Additional analysis of factors contributing to these changes is included in Results of Operations by Segment.

(Millions of dollars)	2004		2004 vs. 2003		2003		2003 vs. 2002			2002

*Revenues*	$	5,157	$	1,077	$	4,080	$	565		$	3,515
Increase (decrease) in:
Oil and gas sales revenues due to volume changes			$	405			$	(362	)
Oil and gas sales revenues due to changes in realized prices				385				594
Gas marketing sales revenues				121				228
Other exploration and production segment revenues				21				13
Pigment sales revenues due to volume changes				114				(10	)
Pigment sales revenues due to changes in realized prices				16				94
Other chemical segment revenues				15				8
Total change in revenues			$	1,077			$	565

Costs and Operating Expenses - Costs and operating expenses during 2004 increased by $390 million, or 25%, over 2003, largely due to higher lease operating expenses, gas purchase costs and pigment production costs. The increase in lease operating expenses is primarily attributable to the Westport merger. Cost of natural gas marketed and associated transportation expenses increased by $127 million, more than offsetting the increase in gas marketing sales revenues discussed above. Additionally, higher pigment sales volume and average cost contributed to the 2004 increase. Costs and operating expenses for 2003 increased $220 million over 2002, primarily due to higher gas marketing costs of $233 million (which offset higher gas marketing sales revenues), higher pigment production costs of $35 million and 2003 plant shutdown provisions associated with the closure of the synthetic rutile facility in Mobile, Alabama. These increases were partially offset by lower lease operating expense of $114 million, mainly due to oil and gas property divestitures.

(Millions of dollars)	2004		2004 vs. 2003		2003		2003 vs. 2002			2002

*Costs and Operating Expenses*	$	1,953	$	390	$	1,563	$	220		$	1,343
Increase (decrease) in:
Lease operating expense			$	118			$	(114	)
Gas purchase costs				127				233
Costs associated with plant shutdowns				16				28
Pigment production costs				108				35
Other costs and operating expenses				21				38
Total change in costs and operating expenses			$	390			$	220

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Selling, General and Administrative Expenses - The decrease of $28 million from 2003 to 2004 was mainly due to certain 2003 expenses that did not reoccur, partially offset by higher 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. An additional $1 million of costs associated with the 2003 work force reduction program was incurred in 2004. Recurring employee-related costs, primarily incentive compensation, increased by $32 million in 2004. During 2003, selling, general and administrative expenses increased 19% over 2002, primarily due to provisions associated with the 2003 work force reduction program and additional compensation expense resulting from loan prepayments required to release shares from the company’s employee stock ownership plan. Additionally, higher expense associated with incentive compensation awards and pension and postretirement benefits contributed to the 2003 increase. These increases were partially offset by a decrease in litigation provisions. In 2002, we recognized a charge of $72 million mainly related to certain forest products litigation in Mississippi, Louisiana and Pennsylvania. This litigation is discussed in Note 19 to the Consolidated Financial Statements included in Item 8 of this annual report on Form 10-K.

(Millions of dollars)	2004		2004 vs. 2003			2003		2003 vs. 2002			2002

*Selling, general and administrative expenses*	$	337	$	(28	)	$	365	$	57		$	308
Increase (decrease) in:
Cost of the 2003 work force reduction program			$	(47	)			$	48
Compensation expense for allocated ESOP shares				(16	)				16
Other compensation, including incentive compensation				32					21
Litigation provisions				3					(63	)
Other selling, general and administrative expenses				-					35
Total change in selling, general and administrative
expenses			$	(28	)			$	57

Depreciation and Depletion - The 2004 increase reflects the impact of the Westport merger, changes in reserve estimates for certain oil and gas properties and accelerated depreciation associated with chemical plants. The decrease in 2003 is due to divested or held-for-sale oil and gas properties and lower depletion on the Leadon field, the value of which was written down in 2002, partially offset by higher depletion expense in the Gulf of Mexico region, mainly due to increased oil and gas production volumes.

(Millions of dollars)	2004		2004 vs. 2003		2003		2003 vs. 2002			2002

*Depreciation and depletion*	$	1,060	$	318	$	742	$	(67	)	$	809
Increase (decrease) in:
Oil and gas depletion due to change in depletion rates			$	150			$	19
Oil and gas depletion due to change in sales volumes				95				(100	)
Chemical segment accelerated depreciation				71				3
Other depreciation				2				11
Total change in depreciation and depletion			$	318			$	(67	)

Exploration Expense - Total exploration expense of $356 million in 2004 remained substantially unchanged from 2003. Exploration expense in 2003 was higher than in 2002 by $81 million. Components of exploration expense are further analyzed in Results of Operations by Segment - Exploration and Production.

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Interest and Debt Expense - Interest and debt expense for 2004, 2003 and 2002 was $245 million, $251 million and $275 million, respectively. The 2004 decrease 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 these instruments, refer to the Market Risks section below. The decrease from 2002 to 2003 was attributable to lower average borrowings under revolving credit facilities and commercial paper of approximately $570 million and slightly lower average interest rates on the company’s long-term debt.

Shipping and Handling Expenses - Shipping and handling expenses for 2004, 2003 and 2002 were $166 million, $139 million and $124 million, respectively. An analysis of transportation and shipping and handling expenses is provided in Results of Operations by Segment below.

Accretion Expense - Accretion expense for 2004 and 2003 was $30 million and $25 million, respectively. The increase during 2004 resulted primarily from an increase in our asset retirement obligations associated with Westport properties.

Asset Impairments - Asset impairment charges totaled $36 million in 2004, $14 million in 2003 and $646 million in 2002. Our chemical - pigment segment incurred an asset impairment 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 were related to our exploration and production segment and are discussed in more detail in Results of Operations by Segment - Exploration and Production.

Gains (Losses) Associated with Assets Held for Sale - Net gains (losses) associated with assets held for sale in 2004, 2003 and 2002 were $(29) million, $45 million and $(176) million, respectively, all of which related to our oil and gas exploration and production segment. Additional discussion of these gains and losses is provided in Results of Operations by Segment - Exploration and Production.

Taxes, Other than Income Taxes - Taxes, other than income taxes totaled $148 million, $96 million and $102 million in 2004, 2003 and 2002, respectively, and includes $104 million, $52 million and $67 million, respectively, of 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 2004 compared to 2003 due to higher sales volumes primarily as a result of the Westport merger and higher realized prices. The decrease from 2002 to 2003 was caused by elimination of royalty payments in the U.K. North Sea and lower sales volumes due to property divestitures. Taxes, other than income taxes also includes payroll and ad valorem taxes, which did not change significantly over the three-year period ended December 31, 2004.

Provision for Environmental Remediation and Restoration - Provision for environmental remediation and restoration, net of reimbursements, totaled $86 million, $60 million and $53 million in 2004, 2003 and 2002, respectively. Our environmental obligations are discussed in detail under Environmental Matters below.

Other Income (Expense) - Other income (expense) totaled $(40) million, $(57) million and $(31) million, which included $(21) million, $(41) million and $(38) million in 2004, 2003 and 2002, respectively, of net foreign currency losses. The majority of the foreign currency losses resulted from the company's U.K. operations due to unfavorable changes in the U.S. dollar/British pound sterling exchange rates. Additionally, equity in net losses of equity method investees, net of gains, totaled $26 million, $33 million and $25 million in 2004, 2003 and 2002, respectively, and were primarily the result of the investment in the Avestor joint venture formed in 2001 to develop lithium-metal-polymer batteries. These losses were partially offset in 2004 and 2003 by gains on sales of Devon common stock. 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. Through August 2, 2004, we also held 8.4 million shares of Devon common stock classified as trading. On August 2, 2004, these shares were distributed to the holders of our debt exchangeable for common stock to repay the debt at maturity. During 2002, 2003 and through August 2, 2004, other income (expense) included net gains of $27 million, $8 million and $2 million representing changes in the fair value of Devon common stock classified as trading and changes in the estimated fair value of options embedded in the debt exchangeable for common stock.

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Provision (Benefit) for Income Taxes - The effective tax rate for 2004 was 38.2%, compared with 42.5% in 2003 and (5.6)% in 2002. The effective tax rate declined in 2004 because of decreased proportion of income from continuing operations attributable to foreign operations. The 2002 tax benefit was reduced from the U.S. statutory rate due to deferred tax expense of $132 million associated with a 33% increase in the U.K. corporate tax rate for oil and gas companies, together with the impact of taxation on foreign operations.

Income (Loss) from Discontinued Operations - The company recognized a loss from discontinued operations as a result of its decision to dispose of the forest products business of $11 million, $10 million and $21 million, net of tax benefit, for the years 2004, 2003 and 2002, respectively. Prior to its disposition, the forest product business reqresented a componet of our chemical - other segment. The 2002 income from discontinued operations also includes income of $126 million (including tax benefit of $22 million) resulting from the company’s decision in early 2002 to dispose of its exploration and production interests in Indonesia and Kazakhstan and its interest in the Bayu-Undan project in the East Timor Sea offshore Australia. The $126 million income included a net pretax gain on sale of $72 million associated with the divestitures. These divestiture decisions were made as part of the company’s strategic plan to rationalize noncore chemical and oil and gas assets.

Cumulative Effect of Change in Accounting Principle - We recognized a loss of $35 million (net of income tax benefit of $18 million) in 2003 upon adoption, as of January 1, 2003, of Financial Accounting Standards Board Statement No. 143 (FAS No. 143), “Accounting for Asset Retirement Obligations.” Adoption of this standard also resulted in an increase in net property of $108 million, an increase in abandonment liabilities of $161 million and a decrease in deferred income tax liabilities of $18 million.

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Results of Operations by Segment

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.

(Millions of dollars)	2004			2003			2002

Revenues, excluding marketing revenues	$	3,436		$	2,625		$	2,380
Operating costs and expenses:
Lifting costs:
Lease operating expense		452			334			448
Production and ad valorem taxes		104			52			67
Total lifting costs		556			386			515

Depreciation, depletion and amortization		854			609			690
Accretion expense (abandonment obligations)		30			25			-
Asset impairments		28			14			646
Loss (gain) associated with assets held for sale		29			(45	)		176
General and administrative expense		135			127			87
Transportation expense		111			94			84
Gas gathering, pipeline and other expenses		89			66			61
Exploration expense		356			354			273
Total operating cost and expenses		2,188			1,630			2,532

Operating profit (loss), excluding net marketing margin		1,248			995			(152	)

Marketing - Gas sales revenues		419			298			70
Marketing - Gas purchase cost (including transportation)		(418	)		(291	)		(58	)
Net marketing margin		1			7			12

Total Operating Profit (Loss)	$	1,249		$	1,002		$	(140	)

Operating profit (loss) 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 operating profit (loss) 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)	2004			2003			2002

Asset impairments	$	(28	)	$	(14	)	$	(646	)
Gain (loss) associated with assets held for sale		(29	)		45			(176	)
Nonhedge derivative loss		(23	)		-			-
Insurance premium adjustment		(12	)		-			-
Costs associated with the 2003 work force reduction program		(1	)		(14	)		-
Environmental provisions		-			-			(11	)
Compensation expense for allocated ESOP shares		-			(9	)		-
Other		(4	)		(5	)		(2	)
Total items affecting comparability	$	(97	)	$	3		$	(835	)

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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)	2004			2003		2002

Revenues -
Crude oil and condensate sales	$	1,644		$	1,426	$	1,531
Natural gas sales		1,728			1,156		819
Gas marketing activities		419			298		70
Other revenues		87			43		30
Nonhedge derivative losses		(23	)		-		-
Total	$	3,855		$	2,923	$	2,450

Production -
Crude oil and condensate (thousands of barrels per day):
U.S. Gulf of Mexico		59.9			56.8		52.7
U.S. onshore		28.2			19.7		28.6
North Sea		62.3			71.6		102.8
China		8.4			2.1		3.3
Other International		-			-		3.9
Total		158.8			150.2		191.3

Natural gas (MMcf per day):
U.S. Gulf of Mexico		364			277		273
U.S. onshore		472			352		386
North Sea		85			97		101