Annual report 2005



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2005

Commission file number 1-16619

KERR-MCGEE CORPORATION
(Exact name of registrant as specified in its charter)

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

123 ROBERT S. KERR AVENUE, OKLAHOMA CITY, OKLAHOMA 73102
(Address of principal executive offices)

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

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

   
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS
 
WHICH REGISTERED
     
Common Stock $1 Par Value
 
New York Stock Exchange
Preferred Share Purchase Right
   

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
  Yes x No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
                                                                                                                          Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.  Yes x No o

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
        Yes x No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
       Yes o No x

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

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

 
DOCUMENTS INCORPORATED BY REFERENCE

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


KERR-McGEE CORPORATION
PART I

Items 1. and 2. Business and Properties
 
GENERAL DEVELOPMENT OF BUSINESS
 
Through predecessors of its affiliates, Kerr-McGee Corporation began operations in 1929 as a privately held company. In 1956, stock of the company’s affiliates began trading publicly on the New York Stock Exchange under the ticker symbol “KMG.” Kerr-McGee's worldwide businesses are consolidated for financial reporting and disclosure purposes. Accordingly, the terms "Kerr-McGee," "the company," “we,”“our” and similar terms are used interchangeably in this Form 10-K to refer to the consolidated group or to one or more of the companies that are part of the consolidated group. The term “Tronox” is used interchangeably in this Form 10-K to refer to Tronox Incorporated, one or more of its subsidiaries or the consolidated group of Tronox Incorporated and its subsidiaries. Tronox is a majority-owned subsidiary holding Kerr-McGee’s chemical business.

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

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

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

·  
Accelerated development of the company’s two major Rocky Mountain natural gas resource plays, the Greater Natural Buttes area in Utah and the Wattenberg field in Colorado
 
·  
Exploration focused on high-impact targets in proven hydrocarbon basins with a track record of delivering world-class discoveries, including the deepwater Gulf of Mexico, the North Slope of Alaska, Brazil and other international areas
 
·  
Creative business development by taking advantage of opportunities to maximize value in the long term through acquisitions, divestitures and strategic partnering

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

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

Asset Divestitures and Tronox Separation
 

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

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

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

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

For an expanded discussion of recent business developments, refer to Management’s Discussion and Analysis included in Item 7 of this Annual Report on Form 10-K.
 
Business Combinations
 
On June 25, 2004, we completed a merger with Westport Resources Corporation (Westport), an independent exploration and production company with operations onshore in the Rocky Mountain, Mid-Continent and Gulf Coast areas in the U.S. and in the Gulf of Mexico. The merger added 281 MMboe to our proved reserves, including natural gas reserves in the Greater Natural Buttes area in Utah. In exchange for Westport's common stock and options, Kerr-McGee issued stock valued at $2.4 billion, options valued at $34 million and assumed debt of $1 billion, for a total of $3.5 billion (net of $43 million of cash acquired). The fair value assigned to assets acquired and goodwill totaled $4.6 billion. We believe this merger improved the risk profile of our assets by adding low-risk exploitation opportunities and increasing the proportion of U.S. onshore natural gas reserves in our portfolio. For a more detailed description of the Westport merger, see Note 4 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.



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


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

(Millions of dollars)
 
2005
 
2004
 
2003
 
2002
 
2001
 
                       
Assets -
                     
Exploration and production
 
$
11,127
 
$
10,260
 
$
5,348
 
$
4,919
 
$
4,958
 
Chemical
   
1,750
   
1,543
   
1,734
   
1,655
   
1,631
 
Corporate and other
   
1,399
   
2,715
   
3,168
   
3,335
   
4,487
 
   Total
 
$
14,276
 
$
14,518
 
$
10,250
 
$
9,909
 
$
11,076
 
                                 
Revenues -
                               
Exploration and production
 
$
4,563
 
$
3,096
 
$
2,132
 
$
1,514
 
$
1,493
 
Chemical
   
1,364
   
1,302
   
1,157
   
1,065
   
1,023
 
   Total
 
$
5,927
 
$
4,398
 
$
3,289
 
$
2,579
 
$
2,516
 
                                 
Income (loss) from continuing operations
 
$
946
 
$
264
 
$
155
 
$
(97
)
$
279
 

For additional financial information with respect to our operating segments and geographic information, see Note 20 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
 
EXPLORATION AND PRODUCTION OPERATIONS
 
Our exploration and production business is focused on achieving value-added per-share growth through exploration, development and strategic acquisition of crude oil and natural gas properties. Our production efforts are concentrated in the U.S. Gulf of Mexico, the U.S. onshore and China. In addition, we explore for oil and gas in these core areas and in proven hydrocarbon trends worldwide, including the North Slope of Alaska and offshore West Africa, Brazil and Trinidad and Tobago.

Reserves

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

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



Oil and Gas Sales Revenues, Production and Prices

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

(Dollars in millions)
 
2005
 
2004
 
2003
 
               
Crude oil and condensate (million barrels) -
                   
U.S. Gulf of Mexico
   
20
   
22
   
21
 
U.S. onshore
   
13
   
10
   
7
 
China
   
7
   
3
   
1
 
     
40
   
35
   
29
 
                     
Crude oil and condensate sales revenues -
                   
U.S. Gulf of Mexico
 
$
878
 
$
645
 
$
541
 
U.S. onshore
   
522
   
293
   
188
 
China
   
311
   
92
   
23
 
   
$
1,711
 
$
1,030
 
$
752
 
                     
Natural gas (billion cubic feet) -
                   
U.S. Gulf of Mexico
   
138
   
133
   
101
 
U.S. onshore
   
213
   
173
   
129
 
     
351
   
306
   
230
 
                     
Natural gas sales revenues -
                   
U.S. Gulf of Mexico
 
$
988
 
$
724
 
$
493
 
U.S. onshore
   
1,350
   
878
   
554
 
   
$
2,338
 
$
1,602
 
$
1,047
 

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

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



Developed and Undeveloped Acreage

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

   
Developed Acreage
 
Undeveloped Acreage
 
Location
 
Gross
 
Net
 
Gross
 
Net
 
                   
United States -
                         
Onshore
   
2,798,911
   
1,626,298
   
2,314,096
   
1,190,151
 
Gulf of Mexico (1)
   
973,640
   
383,711
   
3,438,890
   
2,112,836
 
Alaska
   
-
   
-
   
46,418
   
32,687
 
     
3,772,551
   
2,010,009
   
5,799,404
   
3,335,674
 
                           
China
   
22,487
   
9,015
   
4,068,586
   
3,873,216
 
                           
Other international -
                         
Morocco (2)
   
-
   
-
   
27,280,425
   
13,640,213
 
Australia
   
-
   
-
   
7,054,946
   
4,640,959
 
Bahamas
   
-
   
-
   
5,190,945
   
3,893,210
 
Benin
   
-
   
-
   
1,912,346
   
764,938
 
Brazil
   
-
   
-
   
1,082,890
   
408,853
 
Angola
   
-
   
-
   
1,181,162
   
295,291
 
Denmark
   
-
   
-
   
359,904
   
71,981
 
Trinidad and Tobago
   
-
   
-
   
159,324
   
71,696
 
 
     -    
-
   
44,221,942
   
23,787,141
 
Total
   
3,795,038
   
2,019,024
   
54,089,932
   
30,996,031
 

(1)  
Includes acreage on the Gulf of Mexico shelf. As discussed under -Asset Divestitures and Tronox Separation above, we expect to sell our Gulf of Mexico shelf assets during 2006.
 
(2)  
Expires in April 2006.
 
Gross and Net Productive Wells

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

   
Crude Oil
 
Natural Gas
 
Total
 
Location 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
                           
United States
   
3,498
   
2,303
   
7,531
   
4,593
   
11,029
   
6,896
 
China
   
53
   
21
   
-
   
-
   
53
   
21
 
Total
   
3,551
   
2,324
   
7,531
   
4,593
   
11,082
   
6,917
 



Net Exploratory and Development Wells Drilled

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

   
Net Exploratory (1)
 
Net Development (1)
     
   
Productive
 
Dry Holes
 
Total
 
Productive
 
Dry Holes
 
Total
 
Total
 
2005 - (2)
                                           
United States
   
13.8
   
12.7
   
26.5
   
448.7
   
9.9
   
458.6
   
485.1
 
China
   
-
   
2.8
   
2.8
   
8.8
   
-
   
8.8
   
11.6
 
Other international
   
-
   
.8
   
.8
   
-
   
-
   
-
   
.8
 
Total
   
13.8
   
16.3
   
30.1
   
457.5
   
9.9
   
467.4
   
497.5
 
                                             
2004 -
                                           
United States
   
13.6
   
9.5
   
23.1
   
412.7
   
7.5
   
420.2
   
443.3
 
China
   
-
   
1.8
   
1.8
   
12.4
   
-
   
12.4
   
14.2
 
Other international
   
-
   
.9
   
.9
   
-
   
-
   
-
   
.9
 
Total
   
13.6
   
12.2
   
25.8
   
425.1
   
7.5
   
432.6
   
458.4
 
                                             
2003 -
                                           
United States
   
6.7
   
11.0
   
17.7
   
241.6
   
1.0
   
242.6
   
260.3
 
Other international
   
-
   
5.0
   
5.0
   
.7
   
-
   
.7
   
5.7
 
Total
   
6.7
   
16.0
   
22.7
   
242.3
   
1.0
   
243.3
   
266.0
 

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

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

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

   
Wells in Process
 
Wells Suspended or
 
   
of Drilling
 
Awaiting Completion
 
   
Exploration
 
Development
 
Exploration
 
Development
 
United States -
                         
Gross
   
4.0
   
13.0
   
38.0
   
73.0
 
Net
   
1.7
   
4.6
   
14.5
   
38.2
 
                           
China -
                         
Gross
   
-
   
4.0
   
-
   
1.0
 
Net
   
-
   
1.5
   
-
   
.3
 
                           
Total -
                         
Gross
   
4.0
   
17.0
   
38.0
   
74.0
 
Net
   
1.7
   
6.1
   
14.5
   
38.5
 


Product Sales and Marketing

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

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


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

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

Exploration and Development Activities

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

   
Estimated Proved
     
Realized Sales Price
 
   
Reserves at 12/31/05
 
2005 Production
 
Including Hedges
 
                   
Oil
 
Gas
 
   
MMboe
 
Percentage
 
Mboe/d
 
Percentage
 
$ per Barrel
 
$ per Mcf
 
                           
U.S. onshore
   
582
   
60
%
 
133
   
49
%
$
40.62
 
$
6.32
 
U.S. Gulf of Mexico
   
346
   
36
   
118
   
44
   
43.79
   
7.18
 
     U.S. Total
   
928
   
96
   
251
   
93
   
42.55
   
6.66
 
                                       
China
   
40
   
4
   
19
   
7
   
44.45
   
-
 
Total
   
968
   
100
%
 
270
   
100
%
 
42.89
   
6.66
 
                                       

U.S. Onshore

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


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

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

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

Rocky Mountain

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

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

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

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


Also in 2005, we continued the appraisal program, testing a third fracture on producing Codell wells and performing 38 additional tests. This program was successful economically and provided justification for prospective reserve additions.
 
In support of the ongoing DJ Basin exploitation program, the company continued to successfully integrate the Wattenberg gas gathering system into its operating activities. Approximately 71,000 horsepower is currently being utilized to maintain system pressures for over 1,700 miles of gathering pipeline. Operation and management of the gathering system continues to provide improved reliability and reduced wellhead pressures systemwide. Kerr-McGee now operates more than 3,700 wells in the DJ Basin. Company-operated production represents about 60% of the total system throughput of approximately 240 MMcf/d, 30 MMcf/d of which is processed at our Ft. Lupton plant.

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

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

Southern

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

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

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

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

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




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

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

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

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

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

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


U.S. Gulf of Mexico

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

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

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



Development Activities

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

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

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

Exploration Efforts

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

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

Deepwater Gulf of Mexico

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


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

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

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

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

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

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

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



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

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

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

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

Gulf of Mexico Shelf

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

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

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


China

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


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

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

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

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

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

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


Core New Venture Areas

Brazil

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


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

Alaska

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

Angola

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

Trinidad and Tobago

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

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


Other International

Australia

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

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

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


Bahamas

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

Benin

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

Morocco

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

Nova Scotia, Canada

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


Other Information

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

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



CHEMICAL OPERATIONS

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

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

Titanium Dioxide Pigment
 
Tronox's primary chemical product is titanium dioxide pigment (TiO2), a white pigment used in a wide range of products for its exceptional ability to impart whiteness, brightness and opacity. TiO2 is a critical component of everyday applications, such as coatings, plastics and paper, as well as many specialty products such as inks, foods and cosmetics. Titanium dioxide is widely considered to be superior to alternative white pigments in large part due to its hiding power, which is the ability to cover or mask other materials effectively and efficiently. Titanium dioxide is designed, marketed and sold based on specific end-use applications.
 
Titanium dioxide pigment is produced using a combination of processes involving the manufacture of base pigment particles, followed by surface treatment, drying and milling (collectively known as finishing). There are two commercial production processes in use: the chloride process and the sulfate process. The chloride process is a newer technology and has several advantages over the sulfate process: it generates less waste, uses less energy, is less labor-intensive and permits the direct recycle of a major process chemical, chlorine, back into the production process. In addition, titanium dioxide produced using the chloride process is preferred for many of the largest end-use applications. As a result, the chloride process currently accounts for substantially all of the titanium dioxide production capacity in North America and approximately 60% of worldwide capacity. The vast majority of titanium dioxide production capacity built since the late 1980s uses the chloride process.

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



The following table summarizes the production capacity by location and process.
 
TiO2 Capacity
As of January 1, 2006
(Gross tonnes per year)
Facility
Capacity
 
Process
       
Hamilton, Mississippi
225,000
 
Chloride
Savannah, Georgia
110,000
 
Chloride
Kwinana, Western Australia (1)
110,000
 
Chloride
Botlek, Netherlands
72,000
 
Chloride
Uerdingen, Germany
107,000
 
Sulfate
Total
624,000
 
 
 
(1)  
Reflects 100% of the production capacity of the pigment plant, which is owned 50% by the company and 50% by our joint venture partner.
 
The company's subsidiary, Tronox Western Australia Pty. Ltd., has a 50% undivided interest in all the assets that comprise the operations conducted in Australia under the Tiwest joint venture arrangement and is severally liable for 50% of associated liabilities. The remaining 50% undivided interest is held by Tronox’s joint venture partner, Ticor Pty. Ltd. The joint venture partners operate a chloride process titanium dioxide plant located in Kwinana, Western Australia, as well as a mining venture in Cooljarloo, Western Australia, and a synthetic rutile processing facility in Chandala, Western Australia.

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

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

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

Heavy-Mineral Reserves, Production and Prices
 
(Thousands of tonnes)
 
2005
 
2004
 
2003
 
               
Proven and probable reserves
   
5,145
   
5,570
   
5,970
 
Production
   
300
   
302
   
294
 
Average market price (per tonne)
 
$
182
 
$
161
 
$
152
 

The primary raw materials used to produce titanium dioxide are various types of titanium-bearing ores, including ilmenite, natural rutile, synthetic rutile, titanium-bearing slag and leucoxene. The company generally purchases ores under multiyear agreements from a variety of suppliers in Australia, Canada, India, Norway, South Africa, Ukraine and the United States. Approximately 85% of the synthetic and natural rutile used by Tronox’s facilities is obtained from the operations under the Tiwest joint venture arrangement.
 
The global market in which the company's titanium dioxide business operates is highly competitive. The company actively markets its TiO2 utilizing primarily direct sales, but also through a network of agents and distributors. In general, products produced in a given market region will be sold there to minimize logistical costs. However, Tronox actively exports products, as required, from its facilities in the United States, Europe, and Australia to other market regions.


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


Other Chemical Products

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

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

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

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


Other Information

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

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

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

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




STORED POWER

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


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

Environmental Matters

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

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


The company and its affiliates are parties to a number of legal and administrative proceedings involving environmental matters and/or other matters pending in various courts or agencies. These include proceedings associated with businesses and facilities currently or previously owned, operated or used by the company's affiliates and/or their predecessors, and include claims for personal injuries, property damages, breach of contract, injury to the environment, including natural resource damages, and non-compliance with permits. The current and former operations of the company's affiliates also involve management of regulated materials and are subject to various environmental laws and regulations. These laws and regulations obligate the company's affiliates to clean up various sites at which petroleum and other hydrocarbons, chemicals, low-level radioactive substances and/or other materials have been contained, disposed of and/or released. Some of these sites have been designated Superfund sites by the U.S. Environmental Protection Agency (EPA) pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) and are listed on the National Priority List (NPL).

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

·  
Some sites are in the early stages of investigation, and other sites may be identified in the future.
 
·  
Remediation activities vary significantly in duration, scope and cost from site to site, depending on the mix of unique site characteristics, applicable technologies and regulatory agencies involved.
 
·  
Cleanup requirements are difficult to predict at sites where remedial investigations have not been completed or final decisions have not been made regarding cleanup requirements, technologies or other factors that bear on cleanup costs.
 
·  
Environmental laws frequently impose joint and several liability on all responsible parties, and it can be difficult to determine the number and financial condition of other responsible parties and their respective shares of responsibility for cleanup costs.
 
·  
Environmental laws and regulations, as well as enforcement policies, are continually changing, and the outcome of court proceedings and discussions with regulatory agencies are inherently uncertain.
 
·  
Unanticipated construction problems and weather conditions can hinder the completion of environmental remediation.
 
·  
Some legal matters are in the early stages of investigation or proceeding or their outcomes otherwise may be difficult to predict, and other legal matters may be identified in the future.
 
·  
The inability to implement a planned engineering design or use planned technologies and excavation methods may require revisions to the design of remediation measures, which can delay remediation and increase costs.
 
·  
The identification of additional areas or volumes of contamination and changes in costs of labor, equipment and technology generate corresponding changes in environmental remediation costs.

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

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


AVAILABILITY OF REPORTS AND GOVERNANCE DOCUMENTS

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


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



Item 1a. Risk Factors

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

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

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

·  
Worldwide supply and consumer product demand
 
·  
Governmental regulations and taxes
 
·  
The price and availability of alternative fuels
 
·  
The level of imports and exports of oil and gas
 
·  
Actions of the Organization of Petroleum Exporting Countries
 
·  
The political and economic uncertainty of foreign governments
 
·  
International conflicts and civil disturbances
 
·  
The overall economic environment

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

·  
Curtailment or deferral of exploration and development projects
 
·  
Reduction in the level of economically viable proved reserves
 
·  
Reduction of the discounted future net cash flows relating to the company's proved oil and gas reserves
 
·  
Reduced ability of the company to maintain or grow its future production through future investment in exploration, exploitation and acquisition activities
 
·  
Reduced ability of the company to access capital



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

·  
Production is less than the volumes covered by the derivative instruments
 
·  
Basis differentials widen substantially from the prices established by these arrangements
 
·  
The counter-parties to commodity price and basis differential risk management contracts fail to perform as required by the contracts

The company's debt may limit its financial flexibility.

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

·  
A portion of the company's cash flow from operations may be applied to the payment of principal and interest and may not be available for other purposes.
 
·  
Ratings of the company's debt and other obligations vary from time to time and impact the cost, terms, conditions and availability of financing.
 
·  
Covenants associated with debt arrangements require the company to meet financial and other tests that may affect its flexibility in planning for and reacting to changes in its business, including possible acquisition, exploration and development opportunities.
 
·  
The company's ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited.
 
·  
The company may be at a competitive disadvantage to similar companies that have less debt.

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

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

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

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

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

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


·  
The risk of war, acts of terrorism, revolution, border disputes, expropriation, renegotiation or modification of existing contracts, import, export and transportation regulations and tariffs
 
·  
Taxation policies, including royalty and tax increases and retroactive tax claims
 
·  
Exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over the company's international operations
 
·  
Exposure to movements in foreign currency exchange rates, because the U.S. dollar is the functional currency for the company's international operations, except for the company's European chemical operations, for which the euro is the functional currency
 
·  
Laws and policies of the United States affecting foreign trade, taxation and investment
 
·  
The possibility of being subject to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States

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

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

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

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

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

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

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



Oil and gas reserve information is estimated.

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

·  
Historical production trends from a particular area are representative of future performance
 
·  
Data gathered for purposes of reserve estimation, such as well logs and cores, are representative of average reservoir properties
 
·  
Assumed effects of regulation by governmental agencies
 
·  
Assumptions concerning future oil and gas prices, future development, operating and abandonment costs and capital expenditures
 
·  
Estimates of future severance and excise taxes and workover and remedial costs

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

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

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

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

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

Costs of environmental liabilities and regulation could exceed estimates.

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


The company provides for costs related to environmental matters when a loss is probable and the amount is reasonably estimable. It is not possible for the company to reliably estimate the amount and timing of all future expenditures related to environmental matters for the reasons described above under -Government Regulations and Environmental Matters.
 
Although management currently believes that it has established appropriate reserves for cleanup costs, costs may be higher than anticipated and the company could be required to record additional reserves in the future.

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

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

The company is subject to lawsuits and claims.

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

Item 1b. Unresolved Staff Comments

The company has no outstanding or unresolved SEC staff comments.

Item 3. Legal Proceedings

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

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

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


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

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

None submitted during the fourth quarter of 2005.

Executive Officers of the Registrant

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

Name
 
Age
 
Office
         
Luke R. Corbett
 
59
 
Director since 1995, Chairman and Chief Executive Officer of the company since May 1999 and from 1997 to 1999; Chief Executive Officer from February to May 1999; President and Chief Operating Officer from 1995 to 1997. Currently, Director, OGE Energy Corp. and Noble Corporation.
         
Kenneth W. Crouch
 
62
 
Executive Vice President since March 2003; Senior Vice President (oil and gas exploration and production) from 1998 to 2003; previously Senior Vice President responsible for oil and gas exploration. Joined the company in 1974.
         
David A. Hager
 
49
 
Chief Operating Officer since 2005. Senior Vice President (oil and gas exploration and production) from 2003 to 2005; Vice President of Exploration and Production from 2002 to 2003; Vice President of Gulf of Mexico and Worldwide Deepwater Exploration and Production from 2001 to 2002; Vice President of Worldwide Deepwater Exploration and Production from 2000 to 2001; Vice President of International Operations, 2000; previously Vice President of Gulf of Mexico operations. Joined Sun Oil Co., predecessor of Oryx Energy Company, in 1981. Oryx and Kerr-McGee merged in 1999.
         
Gregory F. Pilcher
 
45
 
Senior Vice President, General Counsel and Corporate Secretary since 2000; Vice President, General Counsel and Corporate Secretary from 1999 to 2000; Deputy General Counsel for Business Transactions from 1998 to 1999; Associate/Assistant General Counsel for Litigation and Civil Proceedings from 1996 to 1998. Joined Kerr-McGee in 1992.
         
Robert M. Wohleber
 
55
 
Senior Vice President and Chief Financial Officer since 1999. Previously held various positions at the Freeport-McMoRan group of companies, including Senior Vice President and Chief Financial Officer of Freeport-McMoRan Inc. and President, Chief Executive Officer and Director of Freeport-McMoRan Sulphur. Currently, Director, Tronox Incorporated.
         
Richard C. Buterbaugh
 
51
 
Vice President of Corporate Planning since July 2005; Vice President of Investor Relations from 1998 to 2005; Director of Investor Relations from 1996 to 1998; Staff Director of Corporate Business Development from 1989 to 1996. Joined Kerr-McGee in 1989.


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

Alonzo J. Harris
 
47
 
Vice President and Chief Information Officer since July 2005; Vice President of Information Management and Technology from 2003 to 2005; Director of Information Management and Technology for the Oil & Gas unit from 2001 to 2003; Manager of Exploration and Production Information Management Technology from 1999 to 2001. Joined Sun Oil Co., predecessor of Oryx Energy Company, in 1982. Oryx and Kerr-McGee merged in 1999.
         
Fran G. Heartwell
 
59
 
Vice President of Human Resources since 2003; Vice President of Human Resources, Kerr-McGee Worldwide Corporation, from January to March 2003; Director of Human Resources, Kerr-McGee Oil & Gas, from 2002 to 2003; Vice President of Human Resources and Administration, Oryx Energy Company, from 1995 until the 1999 merger of Oryx and Kerr-McGee.
         
Charles A. Meloy
 
45
 
Vice President of Exploration and Production since July 2005; Vice President of Gulf of Mexico Exploration, Production and Development from 2004 to 2005; Vice President and Managing Director of Kerr-McGee North Sea (U.K.) Limited from 2002 to 2004; Vice President of Gulf of Mexico Deep Water from 2000 to 2002; Joined Sun Oil Co., predecessor of Oryx Energy Company, in 1982; Oryx and Kerr-McGee merged in 1999.

Christina M. Poos
 
36
 
Vice President and Treasurer since November 2004; Vice President and Treasurer for Kerr-McGee Worldwide Corporation from September to November 2004; Assistant Corporate Controller from February 2004 to September 2004; Manager of Financial Reporting from November 2002 to February 2004; Previously Director of Accounting, Foodbrands America Incorporated (a division of IBP, Inc., a food products company) from June 2000 to September 2002.
         
J. Michael Rauh
 
56
 
Vice President and Controller since 2002 and from 1987 to 1996; Vice President and Treasurer from 1996 to 2002. Joined the company in 1981. Currently, Director, Tronox Incorporated.
         
John F. Reichenberger
 
53
 
Vice President, Deputy General Counsel and Assistant Secretary since 2000; Assistant Secretary and Deputy General Counsel from 1999 to 2000; Deputy General Counsel from 1998 to 1999; previously Associate General Counsel for Remediation and Risk Management and Claims. Joined the company in 1985.

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


CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

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

PART II

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

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

   
Market Prices
 
Dividends
 
   
2005
 
2004
 
per Share
 
   
High
 
Low
 
High
 
Low
 
2005
 
2004
 
                           
Quarter Ended -
                                     
March 31
 
$
83.30
 
$
55.38
 
$
53.39
 
$
46.92
 
$
.45
 
$
.45
 
June 30
   
82.09
   
68.24
   
56.00
   
47.05
   
.05
   
.45
 
September 30
   
98.83
   
74.76
   
58.67
   
50.49
   
.05
   
.45
 
December 31
   
98.00
   
79.85
   
63.24
   
55.57
   
.05
   
.45
 

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

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



Issuer Purchases of Equity Securities
 
The following table summarizes the company’s repurchases of equity securities registered under Section 12 of the Securities Exchange Act of 1934 that occurred in the quarter ended December 31, 2005. In January 2006, the Board of Directors approved a $1 billion stock repurchase program. Assuming a per-share acquisition cost of $100, we expect to repurchase 10 million shares in the open market under this program. As of March 14, 2006, approximately 3.3 million shares of Kerr-McGee’s stock had been repurchased at an aggregate cost of $347 million.
Period
Total Number of Shares Purchased (1)
Average Price Paid per Share (1)
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
         
October 1-31, 2005
11,150
$83.07
-
$ -
November 1-30, 2005
92,386
52.94
-
-
December 1-31, 2005
6,100
89.10
-
-
Total
109,636
$58.02
-
$ -

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


Item 6. Selected Financial Data

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


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

Management’s Discussion and Analysis

 
Executive Overview

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

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

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

·  
Accelerated development of the company’s two major Rocky Mountain natural gas resource plays, the Greater Natural Buttes area in Utah and the Wattenberg field in Colorado
 
·  
Exploration focused on high-impact targets in proven hydrocarbon basins with a track record of delivering world-class discoveries, including the deepwater Gulf of Mexico, the North Slope of Alaska, Brazil and other international areas
 
·  
Creative business development by taking advantage of opportunities to maximize value in the long term through acquisitions, divestitures and strategic partnering
 
The Natural Buttes and the Wattenberg fields are our key U.S. onshore assets, with almost 400 MMboe of proved reserves, as well as additional identified resource potential. We believe accelerated development of our U.S. onshore properties will generate sustainable per-share growth of reserves, production and cash flow with greater predictability. With strong base performance generated by our accelerated development program, any success in the exploration program will yield meaningful incremental reserve and value growth for Kerr-McGee’s stockholders.
 
Operating Highlights - Significant operational highlights since year-end 2004 include the following:

·  
A 14% increase in average production rates, to 270 thousand barrels of oil equivalent per day (Mboe/d), despite disruptions caused by hurricanes
 
·  
Capital investment of $1.8 billion, the largest exploration and production capital program in company history
 
·  
Proved reserve additions of nearly 160 million boe from our exploration and development drilling programs
 
·  
Accelerated development drilling program in the Natural Buttes field, increasing the number of company-operated rigs from five to eight over the course of the year. As a result, net production from the field reached record rates in the second half of the year. Net production from this field was approximately 160 million cubic feet of natural gas equivalent per day at year-end 2005, a 30% increase over year-end 2004. We also have accelerated development activities in the Wattenberg field.
 
·  
Successful appraisal and pending development of the Chinook discovery on the BM-C-7 block in the Campos Basin offshore Brazil. Kerr-McGee holds a 50% working interest in the field and will take over operatorship during the development and production phases.
 
·  
Successful exploration and appraisal drilling results on the North Slope of Alaska at the Nikaitchuq discovery. Planning is under way for possible development sanctioning, with Kerr-McGee holding a 70% working interest as operator of the field.
 
·  
Installation of the company’s sixth spar in the deepwater Gulf of Mexico at the Constitution and Ticonderoga discoveries. Production from Ticonderoga began in February 2006 at gross daily rates of 20 thousand barrels of oil (Mbbl) and 15 million cubic feet (MMcf) of natural gas. We expect to ramp up production from the field during 2006, ultimately reaching gross peak daily rates of about 65 Mbbl of oil and 100 MMcf of natural gas in early 2007. Kerr-McGee holds a 100% working interest in Constitution and a 50% working interest in Ticonderoga.
 
·  
First production from the CFD 11-3 and 11-5 fields in China’s Bohai Bay in July 2005, operated by Kerr-McGee with a 40.1% working interest
 
·  
Development sanctioning for the Blind Faith field in the deepwater Gulf of Mexico. First production is expected in mid-2008, with initial daily production estimated at gross rates of 30 Mbbls of oil and 30 MMcf of gas. Kerr-McGee holds a 37.5% working interest in the project.
 
·  
Successful recovery from one of the worst hurricane seasons in U.S. history. Production from the Gulf of Mexico has resumed to approximately 90% of capacity by early 2006. Our facilities currently are capable of full production capacity and we expect to resume full rates by the end of first quarter 2006, as third-party-operated pipelines and infrastructure damage is repaired.
 
Divestitures - As part of the divestiture program initiated in 2005, we sold our North Sea oil and gas business and selected oil and gas assets onshore in the U.S., realizing net proceeds of $4 billion (before cash income taxes). We expect to complete the divestiture program by the end of the second quarter 2006 with the sale of our Gulf of Mexico shelf oil and gas properties for approximately $1.34 billion in cash, subject to certain adjustments. The transaction has an effective date of October 1, 2005 and is subject to customary closing conditions and regulatory approvals. Had we completed this transaction at the end of 2005, our proved reserves would have been approximately 900 MMboe.


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

·  
Record revenues generated by the oil and gas business (excluding revenues associated with gas marketing activities and discontinued operations) of $3.8 billion, 40% higher than 2004
 
·  
Income from continuing operations of $946 million (or $7.22 per common share), more than a three-fold increase over 2004
 
·  
Cash flows provided by operating activities of $3.1 billion, $1.1 billion higher than 2004
 
·  
Share repurchases totaling $4.2 billion in 2005, including a $4 billion tender offer that reduced shares outstanding at year-end 2004 by 28%. An additional $1 billion share repurchase program was approved by the Board of Directors (the Board) in January 2006 and is being executed through open market purchases.
 
·  
Completion of the Tronox IPO, reducing our equity interest in Tronox to 56.7%
 
·  
Net reduction in the principal amount of outstanding debt of $801 million from January 1, 2005 through March 10, 2006 (or approximately $1.4 billion excluding $550 million borrowed by Tronox in connection with the IPO that will be derecognized with the distribution of our remaining equity interest in Tronox, as discussed below)
 

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

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

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



Separation of Tronox

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

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

The following discussion outlines certain effects of the expected Distribution.

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

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



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

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

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


 
Operating Environment
 
Commodity Markets - Prices for oil and natural gas were sustained at record or near-record levels throughout 2005. Supply and geopolitical uncertainties, coupled with one of the most active U.S. tropical storm seasons in recent history, resulted in significant price volatility and historically high commodity prices. Prices for West Texas Intermediate (WTI) crude oil averaged approximately $57 per barrel for the year, compared to an average price of about $41 per barrel in 2004. At the beginning of 2005, the price of crude oil was below $50 per barrel and steadily increased through the first half of the year, peaking at levels of nearly $70 per barrel during the third quarter, following weather-related supply disruptions in the Gulf of Mexico and U.S. Gulf Coast due to two Category 5 hurricanes. In 2005, crude oil prices were driven by industry supply concerns resulting from both short-term weather-related disruption and infrastructure damage, as well as longer-term concerns regarding the industry’s ability to meet growing world demand. In addition, continued geopolitical instabilities in major producing areas, including the Middle East, Nigeria and Venezuela, contributed to market volatility and higher oil prices. The year ended with the WTI crude oil price at just over $61 per barrel.
 
U.S. natural gas pricing also was strong throughout the year, with New York Mercantile Exchange (NYMEX) futures trading at or above $5.75 per million British thermal units (MMBtu). During 2005 the North American gas market was driven by fundamental uncertainties regarding the industry’s ability to maintain supply in line with increasing demand. This uncertainty, combined with weather-related supply disruptions in Gulf of Mexico and Gulf Coast producing regions, resulted in historically high prices and extreme volatility. Despite historically high inventories, natural gas pricing remained strong going into the winter season, reaching a peak of about $15.40 per MMBtu in December, before moderating to end the year at about $11.25 per MMBtu. NYMEX natural gas prices averaged approximately $9 per MMBtu in 2005, 46% higher than in 2004. In early March 2006, natural gas prices decreased to under $7 per MMBtu. The outlook for the commodity markets in 2006 indicates continued volatility. Many experts expect prices for both oil and gas to moderate somewhat, but remain at high levels relative to recent history.

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


Industry Environment and Competition - The oil and gas industry is highly competitive. We compete with a large number of other oil and gas companies for attractive acquisition, exploration, exploitation and development opportunities. We add to our proved reserves through successful exploration and development, application of new technologies to improve recovery from existing fields and acquisitions. We believe we have a well-balanced portfolio of high-quality oil and gas assets that provides a large inventory of repeatable, low-risk exploitation projects and high-potential exploration opportunities. Additionally, we make significant investment in skilled personnel and technology to successfully execute our exploration, development and exploitation activities and identify tactical acquisition and trade opportunities.
 
Our oil and gas asset portfolio includes major positions in two large resource plays, the Greater Natural Buttes area in Utah and the Wattenberg field in Colorado, which provide an ongoing source of predictable proved reserve addition opportunities and organic production growth, complementing our exploration program. We focus our exploration efforts in basins where working commercial hydrocarbon systems are known to exist, such as the deepwater Gulf of Mexico. We believe facilities we operate in the deepwater Gulf of Mexico provide Kerr-McGee with a significant competitive advantage by enabling us to efficiently employ a hub-and-spoke concept of satellite exploration and exploitation of nearby opportunities. Another competitive strength for the company is our ability to profitably develop smaller offshore oil and gas discoveries that might have previously been considered uneconomic.
 
Due to higher recent commodity prices, the industry is facing significant challenges in the cost and availability of key goods and services. Costs for drilling rigs and well services have increased markedly during 2005, and continue to increase in 2006. In many instances, there are not enough drilling rigs or materials to meet demand, regardless of price. To address this challenge, Kerr-McGee has employed its supply chain management expertise both to control costs and to ensure the execution of its exploration and development programs. For example, we have executed multiyear contracts to secure deepwater drilling rigs to carry out our exploration and development programs for 2006 and much of 2007.
 
The availability of personnel with critical skills also is a major industry concern. The combination of industry demographics, with many experienced personnel now nearing retirement, and strong demand for petro-technical personnel, has resulted in a tight, highly competitive labor market. The company utilizes a combination of competitive compensation and benefits, along with challenging and rewarding work assignments, to remain an attractive employer for critical petro-technical personnel.
 


Results of Operations - Consolidated

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

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

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


(Millions of dollars)
 
2005
 
2005 vs. 2004
 
2004
 
2004 vs. 2003
 
2003
 
                       
Revenues
 
$
5,927
 
$
1,529
 
$
4,398
 
$
1,109
 
$
3,289
 
Increase (decrease) in -
                               
Oil and gas sales revenues due to changes in realized prices
       
$
1,036
       
$
318
       
Oil and gas sales revenues due to volume changes
         
381
         
515
       
Hedge ineffectiveness, overhedge positions and nonhedge
                               
derivative losses
         
(344
)
       
(18
)
     
Other exploration and production revenues
                               
(primarily marketing)
         
394
         
149
       
Pigment sales revenues due to changes in realized prices
         
136
         
16
       
Pigment sales revenues due to volume changes
         
(78
)
       
114
       
Other chemical segment revenues
         
4
         
15
       
Total change in revenues
       
$
1,529
       
$
1,109
       

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

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

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


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

(Millions of dollars)
 
2005
 
2005 vs.
2004
 
2004
 
2004 vs.
2003
 
2003
 
                       
Costs and operating expenses
 
$
2,304
 
$
510
 
$
1,794
 
$
378
 
$
1,416
 
Increase (decrease) in -
                               
Lease operating expense
       
$
143
       
$
106
       
Gas purchase costs
         
382
         
127
       
Pigment costs and operating expenses
         
(6
)
       
120
       
Costs associated with plant shutdowns
         
(31
)
       
5
       
Other costs and operating expenses
         
22
         
20
       
Total change in costs and operating expenses
       
$
510
       
$
378
       

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

(Millions of dollars)
 
2005
 
2005 vs.
2004
 
2004
 
2004 vs.
2003
 
2003
 
                       
Selling, general and administrative expenses
 
$
455
 
$
130
 
$
325
 
$
(25
)
$
350
 
Increase (decrease) in -
                               
   Incentive compensation, including stock-based awards
       
$
52
       
$
32
       
   Employee retention programs
         
23
         
-
       
   Advisory, legal and other costs associated with strategic realignment
 
28
         
-
       
   Cost of work force reduction programs
         
5
         
(47
)
     
   Insurance coverage and adjustments for self-insured risks
         
12
         
(7
)
     
   Other selling, general and administrative expenses
         
10
         
(3
)
     
  Total change in selling, general and administrative
                               
  expenses
       
$
130
       
$
(25
)
     

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

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

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

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


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

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

(Millions of dollars)
 
2005
 
2005 vs.
2004
 
2004
 
2004 vs.
2003
 
2003
 
                       
Depreciation and depletion
 
$
952
 
$
110
 
$
842
 
$
310
 
$
532
 
Increase (decrease) in -
                               
Oil and gas depletion due to change in depletion rates
       
$
110
       
$
123
       
Oil and gas depletion due to change in sales volumes
         
92
         
114
       
Chemical segment accelerated depreciation
         
(71
)
       
71
       
Other depreciation
         
(21
)
       
2
       
Total change in depreciation and depletion
       
$
110
       
$
310
       
                                 

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

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

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

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

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

In the first quarter of 2006, Tronox recognized a receivable of $21 million as a result of a settlement of its claims against the United States, which was documented in a consent decree approved by the court on January 13, 2006. This reimbursement was received by Tronox in February 2006.
 
Interest and Debt Expense - Interest and debt expense for 2005, 2004 and 2003 was $253 million, $244 million and $250 million, respectively. As discussed below, a portion of 2005 interest and debt expense is reported in income from discontinued operations (net of tax) in connection with the divestiture of the company’s North Sea oil and gas business. Including amounts reported in income from discontinued operations, our total 2005 interest and debt expense was $345 million, $101 million higher than in 2004. This increase is primarily the result of $1.1 billion higher average outstanding debt in 2005, in addition to $19 million higher expense associated with interest rate swaps designated to hedge the fair value of our debt. These increases in interest and debt expense were partially offset by $15 million higher capitalized interest driven by increased qualifying capital expenditures.

In May 2005, in connection with the tender offer to repurchase Kerr-McGee’s stock, the company entered into a credit agreement for three credit facilities with an aggregate commitment of $5.5 billion, as more fully discussed under -Financial Condition and Liquidity. Provisions of the credit agreement required the company to use 100% of the net after-tax cash proceeds from sales of certain assets for debt repayment. Because our North Sea assets were subject to this requirement, $92 million of interest expense on debt that was required to be repaid upon their sale is classified as a component of income from discontinued operations. The amount of interest and debt expense allocated to discontinued operations is based on approximately $3.1 billion of the company’s obligations under the term loans that were repaid during 2005 with the net after-tax cash proceeds from the sale of the North Sea oil and gas business. Interest expense was allocated to discontinued operations beginning in May 2005, to coincide with initial borrowings under the term loans that required mandatory prepayments.

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

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

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

   
Debt Issue
 
Unamortized
 
Transaction
     
(Millions of dollars)
 
Costs
 
Discount
 
Costs
 
Total
 
                   
Year ended December 31, 2005 -
                         
Prepayment of term loans (1)
 
$
38
 
$
-
 
$
-
 
$
38
 
Consent solicitation costs (2)
   
-
   
-
   
4
   
4
 
   
$
38
 
$
-
 
$
4
 
$
42
 
                           
Quarter ended March 31, 2006 -
                         
Termination of the revolving credit facility (1)
 
$
12
 
$
-
 
$
-
 
$
12
 
Early redemption of 7% debentures (3)
   
-
   
69
   
-
   
69
 
   
$
12
 
$
69
 
$
-
 
$
81
 

(1)  
As discussed under -Financial Condition and Liquidity, by the end of 2005, we fully repaid $4.25 billion of term loan borrowings under the $5.5 billion credit agreement, which resulted in the write-off of unamortized debt issuance costs associated with the facilities. The credit agreement, which was terminated in January 2006, also included a $1.25 billion five-year revolving credit facility. Unamortized debt issuance costs associated with the revolving credit facility ($12 million) were written off in connection with the termination of the credit agreement.
 
(2)  
The modification to the indenture terms for certain notes payable provided for the release of the company’s chemical business subsidiary, Tronox Worldwide LLC, as a guarantor of the notes in connection with the Tronox IPO. Additional information about this modification to the indenture terms is provided in Note 10 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
 

(3)  
In February 2006, we used cash on hand to redeem the 7% debentures due 2011 at face value of $250 million.
 
Other Income (Expense) - The components of other income (expense) are presented in the table below.

(Millions of dollars)
 
2005
 
2004
 
2003
 
               
Gain on sale of nonoperating interest in gas
                   
processing facility (1)
 
$
120
 
$
-
 
$
-
 
Equity in net losses of equity method investees (2)
   
(19
)
 
(26
)
 
(33
)
Net foreign currency transaction loss
   
(2
)
 
(13
)
 
(5
)
Gain on sale of Devon stock (3)
   
-
   
9
   
17
 
Interest income
   
10
   
4
   
2
 
Loss on accounts receivables sales and other
   
(5
)
 
(8
)
 
(6
)
Total
 
$
104
 
$
(34
)
$
(25
)

(1)  
We owned an interest in the Javelina gas processing facility through our 40% ownership of Javelina Company and Javelina Pipeline Company. This investment was accounted for using the equity method of accounting. We sold our investment in Javelina in November 2005 for cash proceeds of $159 million.
 
(2)  
Equity in net losses of equity method investees relate primarily to our investment in the Avestor joint venture formed in 2001 to develop lithium-metal-polymer batteries, partially offset by equity in net earnings of Javelina in 2005 and 2004. Additional information about Avestor operations is provided in Items 1 and 2, Business and Properties - Segment and Geographic Information - Stored Power.
 
(3)  
In December 2003, we sold a portion of our investment in Devon shares classified as available for sale, resulting in a pretax gain of $17 million. The remaining shares classified as available for sale were sold in January 2004 for a pretax gain of $9 million.

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

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

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





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

(Millions of dollars)
 
2005
 
2004
 
2003
 
               
Segment operating profit (loss) (1) -
                   
Exploration and production
 
$
1,755
 
$
973
 
$
649
 
Chemical -
                   
Pigment
   
100
   
(80
)
 
(13
)
Other
   
(6
)
 
(2
)
 
(23
)
Total chemical
   
94
   
(82
)
 
(36
)
                     
Unallocated expenses -
                   
Interest and debt expense
   
(253
)
 
(244
)
 
(250
)
Loss on early repayment and modification of debt
   
(42
)
 
-
   
-
 
Corporate expenses
   
(201
)
 
(130
)
 
(151
)
Environmental provisions, net of reimbursements
   
(23
)
 
(82
)
 
(47
)
Other income (expense)
   
104
   
(34
)
 
(25
)
Benefit (provision) for income taxes
   
(487
)
 
(137
)
 
15
 
Minority interest, net of taxes
   
(1
)
 
-
   
-
 
Total unallocated expenses
   
(903
)
 
(627
)
 
(458
)
Income from continuing operations
 
$
946
 
$
264
 
$
155
 
                     
Income from continuing operations per common share -
                   
Basic
 
$
7.22
 
$
2.09
 
$
1.55
 
Diluted
   
7.07
   
2.08
   
1.54
 

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



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

(Millions of dollars)
 
2005
 
2004
 
2003
 
               
Included in total segment operating profit -
                   
   Plant shutdown costs and accelerated depreciation
 
$
-
 
$
(122
)
$
(45
)
   Environmental provisions
   
(15
)
 
(4
)
 
(13
)
   Asset impairments
   
(17
)
 
(28
)
 
(14
)
   Gain (loss) associated with assets held for sale
   
211
   
(29
)
 
30
 
   Gain (loss) on hedge ineffectiveness
   
(206
)
 
4
   
(1
)
   Nonhedge derivative loss
   
(38
)
 
(23
)
 
-
 
   Insurance premium adjustment
   
-
   
(16
)
 
-
 
   Employee retention programs
   
(16
)
 
-
   
-
 
   Costs associated with work force reduction programs
   
-
   
(2
)
 
(35
)
   Other
   
-
   
-
   
(19
)
        Subtotal       (81 )     (220    (97
                     
Included in unallocated expenses -
                   
   Environmental provisions, net of reimbursements
   
(23
)
 
(82
)
 
(47
)
   Foreign currency losses
   
(2
)
 
(13
)
 
(5
)
   Gain on sale of Devon stock
   
-
   
9
   
17
 
   Employee retention programs
   
(9
)
 
-
   
-
 
   Costs associated with work force reduction programs
   
(6
)
 
-
   
(18
)
   Loss on early repayment and modification of debt
   
(42
)
 
-
   
-
 
   Cost of separating the Chemical business
   
(13
)
 
-
   
-
 
   Gain on sale of nonoperating interest in gas processing facility
   
120
   
-