**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.
                EmployerIncorporation
                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 ONTITLE
                OF EACH CLASS
            
            WHICH
                REGISTEREDCommon
                Stock $1 Par Value
            
            New
                York Stock ExchangePreferred
                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
            
            2001Assets
                -Exploration
                and production
            
            **$**
            **11,127**
            
            $
            10,260
            
            $
            5,348
            
            $
            4,919
            
            $
            4,958Chemical
            
            
            **1,750**
            
            
            1,543
            
            
            1,734
            
            
            1,655
            
            
            1,631Corporate
                and other
            
            
            **1,399**
            
            
            2,715
            
            
            3,168
            
            
            3,335
            
            
            4,487Total
            
            **$**
            **14,276**
            
            $
            14,518
            
            $
            10,250
            
            $
            9,909
            
            $
            11,076Revenues
                -Exploration
                and production
            
            **$**
            **4,563**
            
            $
            3,096
            
            $
            2,132
            
            $
            1,514
            
            $
            1,493Chemical
            
            
            **1,364**
            
            
            1,302
            
            
            1,157
            
            
            1,065
            
            
            1,023Total
            
            **$**
            **5,927**
            
            $
            4,398
            
            $
            3,289
            
            $
            2,579
            
            $
            2,516Income
                (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
            
            2003Crude
                oil and condensate (million barrels) -U.S.
                Gulf of Mexico
            
            
            **20**
            
            
            22
            
            
            21U.S.
                onshore
            
            
            **13**
            
            
            10
            
            
            7China
            
            
            **7**
            
            
            3
            
            
            1**40**
            
            
            35
            
            
            29Crude
                oil and condensate sales revenues -U.S.
                Gulf of Mexico
            
            **$**
            **878**
            
            $
            645
            
            $
            541U.S.
                onshore
            
            
            **522**
            
            
            293
            
            
            188China
            
            
            **311**
            
            
            92
            
            
            23**$**
            **1,711**
            
            $
            1,030
            
            $
            752Natural
                gas (billion cubic feet) -U.S.
                Gulf of Mexico
            
            
            **138**
            
            
            133
            
            
            101U.S.
                onshore
            
            
            **213**
            
            
            173
            
            
            129**351**
            
            
            306
            
            
            230Natural
                gas sales revenues -U.S.
                Gulf of Mexico
            
            **$**
            **988**
            
            $
            724
            
            $
            493U.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
            
            NetUnited
                States -Onshore
            
            
            2,798,911
            
            
            1,626,298
            
            
            2,314,096
            
            
            1,190,151Gulf
                of Mexico(1)
            
            
            973,640
            
            
            383,711
            
            
            3,438,890
            
            
            2,112,836Alaska
            
            
            -
            
            
            -
            
            
            46,418
            
            
            32,6873,772,551
            
            
            2,010,009
            
            
            5,799,404
            
            
            3,335,674China
            
            
            22,487
            
            
            9,015
            
            
            4,068,586
            
            
            3,873,216Other
                international -Morocco(2)
            
            
            -
            
            
            -
            
            
            27,280,425
            
            
            13,640,213Australia
            
            
            -
            
            
            -
            
            
            7,054,946
            
            
            4,640,959Bahamas
            
            
            -
            
            
            -
            
            
            5,190,945
            
            
            3,893,210Benin
            
            
            -
            
            
            -
            
            
            1,912,346
            
            
            764,938Brazil
            
            
            -
            
            
            -
            
            
            1,082,890
            
            
            408,853Angola
            
            
            -
            
            
            -
            
            
            1,181,162
            
            
            295,291Denmark
            
            
            -
            
            
            -
            
            
            359,904
            
            
            71,981Trinidad
                and Tobago
            
            
            -
            
            
            -
            
            
            159,324
            
            
            71,696-
            
            
            -
            
            
            44,221,942
            
            
            23,787,141Total
            
            
            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
            
            NetUnited
                States
            
            
            3,498
            
            
            2,303
            
            
            7,531
            
            
            4,593
            
            
            11,029
            
            
            6,896China
            
            
            53
            
            
            21
            
            
            -
            
            
            -
            
            
            53
            
            
            21Total
            
            
            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
            
            Total2005
                -(2)United
                States
            
            
            13.8
            
            
            12.7
            
            
            26.5
            
            
            448.7
            
            
            9.9
            
            
            458.6
            
            
            485.1China
            
            
            -
            
            
            2.8
            
            
            2.8
            
            
            8.8
            
            
            -
            
            
            8.8
            
            
            11.6Other
                international
            
            
            -
            
            
            .8
            
            
            .8
            
            
            -
            
            
            -
            
            
            -
            
            
            .8Total
            
            
            13.8
            
            
            16.3
            
            
            30.1
            
            
            457.5
            
            
            9.9
            
            
            467.4
            
            
            497.52004
                -United
                States
            
            
            13.6
            
            
            9.5
            
            
            23.1
            
            
            412.7
            
            
            7.5
            
            
            420.2
            
            
            443.3China
            
            
            -
            
            
            1.8
            
            
            1.8
            
            
            12.4
            
            
            -
            
            
            12.4
            
            
            14.2Other
                international
            
            
            -
            
            
            .9
            
            
            .9
            
            
            -
            
            
            -
            
            
            -
            
            
            .9Total
            
            
            13.6
            
            
            12.2
            
            
            25.8
            
            
            425.1
            
            
            7.5
            
            
            432.6
            
            
            458.42003
                -United
                States
            
            
            6.7
            
            
            11.0
            
            
            17.7
            
            
            241.6
            
            
            1.0
            
            
            242.6
            
            
            260.3Other
                international
            
            
            -
            
            
            5.0
            
            
            5.0
            
            
            .7
            
            
            -
            
            
            .7
            
            
            5.7Total
            
            
            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 orof
                Drilling
            
            Awaiting
                CompletionExploration
            
            Development
            
            Exploration
            
            DevelopmentUnited
                States -Gross
            
            
            4.0
            
            
            13.0
            
            
            38.0
            
            
            73.0Net
            
            
            1.7
            
            
            4.6
            
            
            14.5
            
            
            38.2China
                -Gross
            
            
            -
            
            
            4.0
            
            
            -
            
            
            1.0Net
            
            
            -
            
            
            1.5
            
            
            -
            
            
            .3Total
                -Gross
            
            
            4.0
            
            
            17.0
            
            
            38.0
            
            
            74.0Net
            
            
            1.7
            
            
            6.1
            
            
            14.5
            
            
            38.5








**Product
      S****ales 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 PriceReserves
                at 12/31/05
            
            2005
                Production
            
            Including
                HedgesOil
            
            GasMMboe
            
            Percentage
            
            Mboe/d
            
            Percentage
            
            $
                per Barrel
            
            $
                per McfU.S.
                onshore
            
            
            582
            
            
            60
            %
            
            133
            
            
            49
            %
            $
            40.62
            
            $
            6.32U.S.
                Gulf of Mexico
            
            
            346
            
            
            36
            
            
            118
            
            
            44
            
            
            43.79
            
            
            7.18U.S. Total
            
            
            928
            
            
            96
            
            
            251
            
            
            93
            
            
            42.55
            
            
            6.66China
            
            
            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 (TiO 2 ),
      a
      white pigment used in a wide range of products for its exceptional ability
      to
      impart whiteness, brightness and opacity. TiO 2 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 TiO 2 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.




**TiO** **2** **Capacity**


As
      of
      January 1, 2006


(Gross
      tonnes per year)


Facility
            Capacity
            
            ProcessHamilton,
                Mississippi
            225,000
            
            ChlorideSavannah,
                Georgia
            110,000
            
            ChlorideKwinana,
                Western Australia(1)
            110,000
            
            ChlorideBotlek,
                Netherlands
            72,000
            
            ChlorideUerdingen,
                Germany
            107,000
            
            SulfateTotal
            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
            
            2003Proven
                and probable reserves
            
            
            **5,145**
            
            
            5,570
            
            
            5,970Production
            
            
            **300**
            
            
            302
            
            
            294Average
                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 TiO 2 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 identifiedinthe 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
            
            OfficeLuke
                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**
            
            2004Quarter
                Ended -March
                31
            
            **$**
            **83.30**
            
            **$**
            **55.38**
            
            $
            53.39
            
            $
            46.92
            
            **$**
            **.45**
            
            $
            .45June
                30
            
            
            **82.09**
            
            
            **68.24**
            
            
            56.00
            
            
            47.05
            
            
            **.05**
            
            
            .45September
                30
            
            
            **98.83**
            
            
            **74.76**
            
            
            58.67
            
            
            50.49
            
            
            **.05**
            
            
            .45December
                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 ProgramsOctober
                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
                forEnvironmental
            
            Reimbursements(Millions
                of dollars)
            
            Remediation
            
            ReceivableTronox
            
            $
            224
            
            $
            57Other
                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
            
            $
            3,289Increase
                (decrease) in -Oil
                and gas sales revenues due to changes in realized prices
            
            
            
            
            $
            1,036
            
            
            
            
            $
            318Oil
                and gas sales revenues due to volume changes
            
            
            
            
            
            381
            
            
            
            
            
            515Hedge
                ineffectiveness, overhedge positions and nonhedgederivative
                losses
            
            
            
            
            
            (344
            )
            
            
            
            
            (18
            )Other
                exploration and production revenues(primarily
                marketing)
            
            
            
            
            
            394
            
            
            
            
            
            149Pigment
                sales revenues due to changes in realized prices
            
            
            
            
            
            136
            
            
            
            
            
            16Pigment
                sales revenues due to volume changes
            
            
            
            
            
            (78
            )
            
            
            
            
            114Other
                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
            
            $
            1,416Increase
                (decrease) in -Lease
                operating expense
            
            
            
            
            $
            143
            
            
            
            
            $
            106Gas
                purchase costs
            
            
            
            
            
            382
            
            
            
            
            
            127Pigment
                costs and operating expenses
            
            
            
            
            
            (6
            )
            
            
            
            
            120Costs
                associated with plant shutdowns
            
            
            
            
            
            (31
            )
            
            
            
            
            5Other
                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
            )
            $
            350Increase
                (decrease) in -Incentive compensation, including stock-based awards
            
            
            
            
            $
            52
            
            
            
            
            $
            32Employee 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
            
            $
            532Increase
                (decrease) in -Oil
                and gas depletion due to change in depletion rates
            
            
            
            
            $
            110
            
            
            
            
            $
            123Oil
                and gas depletion due to change in sales volumes
            
            
            
            
            
            92
            
            
            
            
            
            114Chemical
                segment accelerated depreciation
            
            
            
            
            
            (71
            )
            
            
            
            
            71Other
                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 (b efore
      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
            
            $
            -
            
            $
            -
            
            $
            38Consent
                solicitation costs (2)
            
            
            -
            
            
            -
            
            
            4
            
            
            4$
            38
            
            $
            -
            
            $
            4
            
            $
            42*Quarter
                ended March 31, 2006 -*Termination
                of the revolving credit facility (1)
            
            $
            12
            
            $
            -
            
            $
            -
            
            $
            12Early
                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
            
            2003Gain
                on sale of nonoperating interest in gasprocessing
                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
            
            
            17Interest
                income
            
            
            **10**
            
            
            4
            
            
            2Loss
                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
            
            2003Segment
                operating profit (loss) (1)
                -Exploration
                and production
            
            **$**
            **1,755**
            
            $
            973
            
            $
            649Chemical
                -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
            )
            
            15Minority
                interest, net of taxes
            
            
            **(1**
            **)**
            
            -
            
            
            -Total
                unallocated expenses
            
            
            **(903**
            **)**
            
            (627
            )
            
            (458
            )Income
                from continuing operations
            
            **$**
            **946**
            
            $
            264
            
            $
            155Income
                from continuing operations per common share -Basic
            
            **$**
            **7.22**
            
            $
            2.09
            
            $
            1.55Diluted
            
            
            **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
            )
            
            30Gain (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
            
            
            17Employee retention programs
            
            
            **(9**
            **)**
            
            -
            
            
            -Costs associated with work force reduction programs
            
            
            **(6**
            **)**
            
            -
            
            
            (18
            )Loss on early repayment and modification of debt
            
            
            **(42**
            **)**
            
            -
            
            
            -Cost of separating the Chemical business
            
            
            **(13**
            **)**
            
            -
            
            
            -Gain on sale of nonoperating interest in gas processing
                facility
            
            
            **120**
            
            
            -
            
            
            -Other
            
            
            **(14**
            **)**
            
            (4
            )
            
            (12
            )Items
                affecting comparability
            
            **$**
            **(70**
            **)**
            $
            (310
            )
            $
            (162
            )








**EXPLORATION
      AND PRODUCTION**





**Segment
      Operating Profit**





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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Revenues,
                excluding marketing revenues
            
            **$**
            **3,759**
            
            $
            2,677
            
            $
            1,834Operating
                costs and expenses -Lifting
                costs:Lease
                operating expense
            
            
            **437**
            
            
            294
            
            
            188Production
                and ad valorem taxes
            
            
            **156**
            
            
            104
            
            
            53Total
                lifting costs
            
            
            **593**
            
            
            398
            
            
            241Depreciation,
                depletion and amortization
            
            
            **838**
            
            
            636
            
            
            399Accretion
                expense (abandonment obligations)
            
            
            **22**
            
            
            18
            
            
            15Asset
                impairments
            
            
            **17**
            
            
            20
            
            
            14Loss
                (gain) on sale of assets
            
            
            **(211**
            **)**
            
            29
            
            
            (30
            )General
                and administrative expense
            
            
            **171**
            
            
            122
            
            
            113Transportation
                expense
            
            
            **92**
            
            
            74
            
            
            51Gas
                gathering, pipeline and other expenses
            
            
            **109**
            
            
            84
            
            
            62Exploration
                expense
            
            
            **377**
            
            
            324
            
            
            327Total
                operating costs and expenses
            
            
            **2,008**
            
            
            1,705
            
            
            1,192Operating
                profit, excluding net marketing margin
            
            
            **1,751**
            
            
            972
            
            
            642Marketing
                - gas sales revenues
            
            
            **804**
            
            
            419
            
            
            298Marketing
                - gas purchase cost (including transportation)
            
            
            **(800**
            **)**
            
            (418
            )
            
            (291
            )Net
                marketing margin
            
            
            **4**
            
            
            1
            
            
            7Total
                operating profit
            
            **$**
            **1,755**
            
            $
            973
            
            $
            649





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




(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Asset
                impairments
            
            **$**
            **(17**
            **)**
            $
            (20
            )
            $
            (14
            )Gain
                (loss) associated with assets held for sale
            
            
            **211**
            
            
            (29
            )
            
            30Gain
                (loss) on hedge ineffectiveness
            
            
            **(206**
            **)**
            
            4
            
            
            (1
            )Nonhedge
                derivative loss
            
            
            **(38**
            **)**
            
            (23
            )
            
            -Insurance
                premium adjustment
            
            
            **-**
            
            
            (12
            )
            
            -Employee
                retention programs
            
            
            **(15**
            **)**
            
            -
            
            
            -Costs
                associated with work force reduction programs
            
            
            **-**
            
            
            (1
            )
            
            (14
            )Environmental
                provisions
            
            
            **(4**
            **)**
            
            -
            
            
            -Other
            
            
            **-**
            
            
            (4
            )
            
            (14
            )Items
                affecting comparability
            
            **$**
            **(69**
            **)**
            $
            (85
            )
            $
            (13
            )





**Revenues**





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





(Millions
                of dollars, except per-unit amounts)
            
            **2005**
            
            2004
            
            2003Revenues
                -Crude
                oil and condensate sales
            
            **$**
            **1,711**
            
            $
            1,030
            
            $
            752Natural
                gas sales
            
            
            **2,338**
            
            
            1,602
            
            
            1,047Gain
                (loss) on hedge ineffectiveness
            
            
            **(206**
            **)**
            
            4
            
            
            (1
            )Loss
                on overhedge positions
            
            
            **(119**
            **)**
            
            -
            
            
            -Nonhedge
                derivative losses
            
            
            **(38**
            **)**
            
            (23
            )
            
            -Gas
                marketing activities
            
            
            **804**
            
            
            419
            
            
            298Processing,
                gathering and other revenues
            
            
            **73**
            
            
            64
            
            
            36Total
            
            **$**
            **4,563**
            
            $
            3,096
            
            $
            2,132Production
                -Crude
                oil and condensate (thousands of barrels per day):U.S.
                Gulf of Mexico
            
            
            **55**
            
            
            60
            
            
            57U.S.
                onshore
            
            
            **35**
            
            
            28
            
            
            20China
            
            
            **19**
            
            
            8
            
            
            2Total
            
            
            **109**
            
            
            96
            
            
            79Natural
                gas (MMcf per day):U.S.
                Gulf of Mexico
            
            
            **377**
            
            
            364
            
            
            277U.S.
                onshore
            
            
            **585**
            
            
            472
            
            
            352Total
            
            
            **962**
            
            
            836
            
            
            629Total
                equivalent barrels of oil (thousands of barrels per day)
            
            
            **270**
            
            
            236
            
            
            183Average
                sales prices (excluding hedges) -Crude
                oil and condensate (per barrel):U.S.
                Gulf of Mexico
            
            **$**
            **50.58**
            
            $
            37.97
            
            $
            29.14U.S.
                onshore
            
            
            **47.68**
            
            
            37.63
            
            
            27.42China
            
            
            **44.45**
            
            
            32.37
            
            
            29.66Average
            
            
            **48.57**
            
            
            37.41
            
            
            28.72Natural
                gas (per Mcf):U.S.
                Gulf of Mexico
            
            **$**
            **8.24**
            
            $
            6.25
            
            $
            5.60U.S.
                onshore
            
            
            **7.64**
            
            
            5.92
            
            
            4.87Average
            
            
            **7.87**
            
            
            6.06
            
            
            5.19Average
                realized sales prices (including hedges) -Crude
                oil and condensate (per barrel):U.S.
                Gulf of Mexico
            
            **$**
            **43.79**
            
            $
            29.43
            
            $
            26.12U.S.
                onshore
            
            
            **40.62**
            
            
            28.43
            
            
            26.23China
            
            
            **44.45**
            
            
            32.37
            
            
            29.66Average
            
            
            **42.89**
            
            
            29.38
            
            
            26.24Natural
                gas (per Mcf):U.S.
                Gulf of Mexico
            
            **$**
            **7.18**
            
            $
            5.44
            
            $
            4.88U.S.
                onshore
            
            
            **6.32**
            
            
            5.08
            
            
            4.31Average
            
            
            **6.66**
            
            
            5.24
            
            
            4.56








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





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





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





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





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





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





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





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





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








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





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





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





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





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





**Lease
      Operating Expense** ****





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





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








**Production
      and Ad Valorem Taxes**





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





Production
      and ad valorem taxes of $104 million in 2004 were $51 million higher than 2003
      primarily due to higher commodity prices and higher sales volumes. The addition
      of Westport’s properties in 2004 resulted in higher production taxes as a
      percentage of sales revenues compared to 2003 by increasing the proportion
      of
      U.S. onshore properties subject to production taxes in our portfolio.





**Depreciation,
      Depletion and Amortization (DD&A)**





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





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





**Asset
      Impairments and Gain (Loss) on Sale of Assets**





Kerr-McGee
      records impairment losses when performance analysis and other factors indicate
      that future net cash flows from production will not be sufficient to recover
      the
      carrying amounts of the related assets. In general, such write-downs most often
      occur on mature properties that are nearing the end of their productive lives
      or
      cease production sooner than anticipated. Impairment losses recorded in 2005,
      2004 and 2003 totaled $17 million, $20 million and $14 million, respectively.
      Impairment losses in 2005 related primarily to a U.S. onshore property in Texas
      where unsuccessful drilling resulted in a reduction in proved undeveloped
      reserves ($10 million) and two U.S. Gulf of Mexico shelf properties that ceased
      producing in the first quarter. Impairment losses in 2004 related primarily
      to a
      U.S. Gulf of Mexico field that experienced premature water breakthrough and
      ceased production sooner than expected. The 2003 impairments related to mature
      oil and gas producing assets in the U.S. onshore and Gulf of Mexico shelf areas.





The
      company recognized a net gain of $211 million on sales of oil and gas properties
      during 2005, related primarily to the divestiture of noncore U.S. onshore
      properties. A total of $435 million in cash was received in 2005 for the sale
      of
      our interests in certain oil and gas properties located in the Powder River
      basin, South Texas, Permian Basin/Mid-Continent and Barnett Shale areas,
      resulting in a net gain of $149 million. Also, as part of our business
      development activities, we acquired a 37.5% interest in the Blind Faith
      discovery in the deepwater Gulf of Mexico from BP Exploration & Production
      in exchange for our interests in various proved oil and gas properties in the
      Arkoma basin of southeast Oklahoma. In connection with this transaction, we
      received $26 million in cash and recognized a $21 million gain on the trade,
      based on the percentage of the Arkoma properties’ fair value that was received
      in cash. In addition, we sold our interest in certain oil and gas properties
      in
      the Table Mountain and Culp Draw fields of Wyoming to Anadarko Petroleum
      Corporation in exchange for Anadarko’s overriding interest in the Greater
      Natural Buttes area and $27 million in cash. We recognized a gain of $24 million
      in connection with this transaction.





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








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





**General
      and Administrative Expense**





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





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





**Transportation
      Expense** ****





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





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





**Exploration
                Expense**(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Exploration
                costs(1)
            
            **$**
            **48**
            
            $
            43
            
            $
            36Geological
                and geophysical costs
            
            
            **66**
            
            
            78
            
            
            54Dry
                hole expense
            
            
            **172**
            
            
            152
            
            
            173Amortization
                of undeveloped leases
            
            
            **92**
            
            
            59
            
            
            64Sales
                of unproved properties
            
            
            **(1**
            **)**
            
            (8
            )
            
            -Total
                exploration expense
            
            **$**
            **377**
            
            $
            324
            
            $
            327





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





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








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





Capitalized
      exploratory well costs associated with ongoing exploration and/or appraisal
      activities may be charged to earnings in a future period if management
      determines that commercial quantities of hydrocarbons have not been discovered
      or that future appraisal drilling or development activities are not likely
      to
      occur. At December 31, 2005, the company had capitalized costs of approximately
      $208 million associated with such ongoing exploration activities, primarily
      in
      the deepwater Gulf of Mexico, Alaska, Brazil and China. Additional information
      regarding deferred exploratory drilling costs is included in Note 23 to the
      Consolidated Financial Statements included in Item 8 of this Annual Report
      on
      Form 10-K.





**Gas
      Marketing Activities**





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





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











**CHEMICAL**





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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Revenues
                -Pigment
            
            **$**
            **1,267**
            
            $
            1,209
            
            $
            1,079Other
            
            
            **97**
            
            
            93
            
            
            78Total
            
            **$**
            **1,364**
            
            $
            1,302
            
            $
            1,157Operating
                profit (loss) -(1)Pigment
            
            **$**
            **100**
            
            $
            (80
            )
            $
            (13
            )Other
            
            
            **(6**
            **)**
            
            (2
            )
            
            (23
            )Total
            
            **$**
            **94**
            
            $
            (82
            )
            $
            (36
            )Titanium
                dioxide pigment production(thousands
                of tonnes)
            
            
            **537**
            
            
            549
            
            
            532





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





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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003*Included
                in chemical - pigment operating profit (loss) -*Plant
                shutdown costs and accelerated depreciation
            
            **$**
            **-**
            
            $
            (122
            )
            $
            (44
            )Asset
                impairments
            
            
            **-**
            
            
            (8
            )
            
            -Insurance
                premium adjustment
            
            
            **-**
            
            
            (4
            )
            
            -Environmental
                provisions
            
            
            **-**
            
            
            (1
            )
            
            (1
            )Employee
                retention programs
            
            
            **(1**
            **)**
            
            -
            
            
            -Cost
                associated with work force reduction programs
            
            
            **-**
            
            
            (1
            )
            
            (18
            )Other
            
            
            **-**
            
            
            4
            
            
            (4
            )*Included
                in chemical - other operating loss -*Plant
                shutdown costs and accelerated depreciation
            
            
            **-**
            
            
            -
            
            
            (1
            )Environmental
                provisions
            
            
            **(11**
            **)**
            
            (3
            )
            
            (12
            )Cost
                associated with work force reduction programs
            
            
            **-**
            
            
            -
            
            
            (3
            )Other
            
            
            **-**
            
            
            -
            
            
            (1
            )Items
                affecting comparability
            
            **$**
            **(12**
            **)**
            $
            (135
            )
            $
            (84
            )





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








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





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





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





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





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





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











**Financial
      Condition and Liquidity**





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





(Millions
                of dollars)
            
            **2005**
              **Pro
                forma**
            
            **2005**
            
            2004
            
            2003Current
                ratio(1)
            
            
            **0.6
                to 1**
            
            
            **0.8
                to 1**
            
            
            0.8
                to 1
            
            
            0.8
                to 1Cash
                and cash equivalents
            
            **$**
            **734**
            
            **$**
            **1,053**
            
            $
            76
            
            $
            142Debt
                repayment obligations due within one year
            
            
            **306**
            
            
            **308**
            
            
            463
            
            
            574Unused
                capacity under revolving lines of credit(2)
            
            
            **1,184**
            
            
            **1,400**
            
            
            1,550
            
            
            1,360Total
                debt
            
            
            **2,403**
            
            
            **3,133**
            
            
            3,699
            
            
            3,655Stockholders’
                equity and minority interest
            
            **$**
            **3,770**
            
            **$**
            **4,327**
            
            $
            5,318
            
            $
            2,636Debt
                to total capitalization(3)
            
            
            **39**
            **%**
            
            **42**
            **%**
            
            41
            %
            
            58
            %Variable-rate
              debt to total debt(4)
            
            
            19
            %
            
            20
            %
            
            25
            %
            
            14
            %





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




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




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




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




**Overview**





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





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








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




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





***Outlook*** - To
      meet our short- and long-term liquidity requirements, we expect to fund capital
      expenditures, debt payments, share repurchase programs and working-capital
      needs
      through a combination of cash on hand, cash generated from operating activities,
      proceeds from sale of assets, issuance of debt and/or borrowings under our
      $1.25
      billion revolving credit facility. Based on the company's forecast of cash
      flows
      and liquidity, the company believes that it has and will continue to have the
      financial resources and liquidity to meet future cash requirements. Included
      in
      that forecast are estimated proceeds from the sale of our Gulf of Mexico shelf
      oil and gas properties, which is expected to close in the second quarter of
      2006, pending certain regulatory approvals. We plan to use the net cash proceeds
      from this sale for debt reduction and other corporate purposes, including share
      repurchases.





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





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








***Credit
      Ratings*** - In
      rating the company’s debt, rating agencies consider our financial and operating
      risk profile by analyzing our debt levels, growth profile, cost structure,
      oil
      and gas reserve replacement ratios, capital expenditure requirements,
      contingencies, dividend policy and any other factors they deem relevant that
      could potentially impact our ability to service debt. In response to the
      company’s April 2005 announcement of our intention to commence the tender offer
      and increase leverage in the near term (which is discussed below), our credit
      ratings were downgraded. The following table provides a summary of our senior
      unsecured debt ratings by selected rating agencies as of March 31, 2005, and
      subsequent to the downgrades:





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





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





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





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





·
            Consolidated
                Leverage Ratio of no more than
                3.5:1


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


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





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





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





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





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


·
            Consolidated
                Interest Coverage Ratio of at least
                2:1


·
            Limitation
                on Capital Expenditures





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








**Cash
      Flows**





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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Net
                cash provided by operating activities
            
            **$**
            **3,103**
            
            $
            2,050
            
            $
            1,518Net
                cash provided by (used in) investing activities
            
            
            **2,081**
            
            
            (1,262
            )
            
            (951
            )Net
                cash used in financing activities
            
            
            **(4,210**
            **)**
            
            (851
            )
            
            (520
            )





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





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





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





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








(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Capital
                expenditures-Continuing
                exploration and production operations(1)
            
            **$**
            **(1,589**
            **)**
            $
            (1,096
            )
            $
            (949
            )Discontinued
                North Sea oil and gas business(1)
            
            
            **(228**
            **)**
            
            (134
            )
            
            (101
            )Tronox
                operations
            
            
            **(88**
            **)**
            
            (92
            )
            
            (97
            )Corporate and other
            
            
            **(15**
            **)**
            
            (18
            )
            
            (15
            )Total capital expenditures(1)
            
            
            **(1,920**
            **)**
            
            (1,340
            )
            
            (1,162
            )Acquisitions,
                net of cash acquired
            
            
            **-**
            
            
            43
            
            
            (110
            )Net
                proceeds from sale of North Sea oil and gas business
            
            
            **3,305**
            
            
            -
            
            
            -Proceeds
                from dispositions of other assets
            
            
            **704**
            
            
            23
            
            
            304Other
                investing activities
            
            
            **(8**
            **)**
            
            12
            
            
            17Total
                net cashprovided by (used in) investing activities
            
            **$**
            **2,081**
            
            $
            (1,262
            )
            $
            (951
            )





(1)
            Includes
                dry hole costs.





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





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





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





(Millions
                of dollars)
            
            **Est.
                2006**
            
            Percent
                of TotalBudgeted
                capital
                expenditures by region -Rocky Mountains
            
            **$**
            **580**
            
            
            44
            %Southern
            
            
            **170**
            
            
            13Deepwater
                Gulf of Mexico
            
            
            **400**
            
            
            30International / New venture areas
            
            
            **150**
            
            
            11Other
            
            
            **20**
            
            
            2Total budgeted capital expenditures
            
            **$**
            **1,320**
            
            
            100
            %





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





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








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





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





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





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





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





*Acquisitions* - In
      June 2004, we completed our merger with Westport, which was financed by issuing
      our common stock and assuming Westport’s debt obligations and, therefore did not
      affect investing cash flows, except for Westport cash balances of $43 million
      acquired in the merger. In 2003, we invested $110 million in selected oil and
      gas property acquisitions for an additional interest in the U.K. Gryphon and
      South Gryphon fields and an onshore property acquisition in South Texas.





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








(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Proceeds
                from Kerr-McGee term loan borrowings
            
            **$**
            **4,250**
            
            $
            686
            
            $
            31Proceeds
                from Tronox borrowings
            
            
            **550**
            
            
            -
            
            
            -Cash
                received upon exercises of employee stock options
            
            
            **225**
            
            
            55
            
            
            -Sale
                of Tronox stock
            
            
            **225**
            
            
            -
            
            
            -Repayment
                of term loan borrowings
            
            
            **(4,250**
            **)**
            
            -
            
            
            -Repayment
                of other Kerr-McGee debt
            
            
            **(501**
            **)**
            
            (1,278
            )
            
            (369
            )Repurchases
                of common stock under the tender offer
            
            
            **(3,975**
            **)**
            
            -
            
            
            -Purchases
                of treasury stock
            
            
            **(250**
            **)**
            
            -
            
            
            -Payment
                of dividends
            
            
            **(153**
            **)**
            
            (205
            )
            
            (181
            )Settlement
                of Westport derivatives
            
            
            **(238**
            **)**
            
            (101
            )
            
            -Debt
                issuance costs and other
            
            
            **(93**
            **)**
            
            (8
            )
            
            (1
            )Total cash used in financing activities
            
            **$**
            **(4,210**
            **)**
            $
            (851
            )
            $
            (520
            )*Noncash
                financing activities -*48.9
                million shares of common stock and 1.9 million stockoptions
                issued in connection with the Westport merger
            
            **$**
            **-**
            
            $
            2,448
            
            $
            -Increase
                (decrease) in debt associated with -Conversion
                of 5.25% debentures to common stock
            
            
            **(600**
            **)**
            
            -
            
            
            -Debt
                assumed in the Westport merger
            
            
            -
            
            
            1,046
            
            
            -Debt
                redemption with Devon stock
            
            
            -
            
            
            (330
            )
            
            -





*Repurchases
      of Common Stock* - In
      March 2005, the Board authorized a share repurchase program initially set at
      $1
      billion, with an expectation to expand the program as the chemical business
      separation proceeded. Before terminating this program in connection with the
      Board's approval of the tender offer discussed below, the company repurchased
      3.1 million shares of its common stock in the open market at an aggregate cost
      of $250 million. On April 18, 2005, the company commenced a self tender offer
      to
      repurchase 43.5 million shares of its common stock at a price not lower than
      $85
      or higher than $92 per share. We exercised our right to increase the number
      of
      shares purchased pursuant to the tender offer by 3.2 million shares, which
      resulted in repurchasing 46.7 million shares of common stock at $85 per share,
      for an aggregate cost of approximately $4 billion (including transaction costs
      of approximately $3 million). All of the shares repurchased under the
      tender offer were retired immediately. The cost of the repurchase was financed
      with a portion of the net proceeds of the borrowings under the $5.5 billion
      credit agreement discussed below and cash on hand. In January 2006, the Board
      authorized an additional $1 billion share repurchase program. As of March
      14, 2006, approximately 3.3 million shares had been repurchased under this
      program in the open market, for a total cost of $347 million.





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





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





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








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





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





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





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





**Off-Balance
      Sheet Arrangements**





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





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





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








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





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





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





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





**Obligations
      and Commitments**





In
      the
      normal course of business, the company enters into purchase obligations,
      contracts, leases and borrowing arrangements. The company has no debt guarantees
      for third parties. As part of our project-oriented exploration and production
      business, we routinely enter into contracts for certain aspects of a project,
      such as engineering, drilling, subsea work, etc. These contracts generally
      are
      not unconditional obligations; thus, the company accrues for the value of work done
      at any point in time, a portion of which is billed to partners. Commitments
      and
      obligations of Kerr-McGee and Tronox as of December 31, 2005, are summarized
      in
      the following table:








(Millions
                of dollars)
            
            Payments
                due by period2007
            
            2009
            
            AfterType
                of Obligation
            
            Total
            
            2006
            
            -2008
            
            -2010
            
            2010*Obligation
                and commitments of Kerr-McGee*-Long-term debt, including current portion(1) (2)
            
            $
            2,682
            
            $
            307
            
            $
            150
            
            $
            -
            
            $
            2,225Operating leases for Nansen, Boomvangand Gunnison
            
            
            559
            
            
            28
            
            
            54
            
            
            54
            
            
            423Other
                operating leases
            
            
            200
            
            
            49
            
            
            63
            
            
            32
            
            
            56Drilling
                rig commitments
            
            
            749
            
            
            226
            
            
            428
            
            
            52
            
            
            43Gas
                purchase and transportation contracts
            
            
            269
            
            
            120
            
            
            49
            
            
            37
            
            
            63Other
                purchase obligations
            
            
            213
            
            
            113
            
            
            100
            
            
            -
            
            
            -Leased
                equipment residual value guarantees
            
            
            72
            
            
            -
            
            
            35
            
            
            -
            
            
            37Subtotal
            
            
            4,744
            
            
            843
            
            
            879
            
            
            175
            
            
            2,847*Obligation
                and commitments of Tronox -*Long-term debt, including current
                portion(2)
            
            
            550
            
            
            2
            
            
            4
            
            
            4
            
            
            540Operating leases
            
            
            48
            
            
            8
            
            
            14
            
            
            10
            
            
            16Ore contracts
            
            
            642
            
            
            162
            
            
            303
            
            
            137
            
            
            40Other purchase obligations
            
            
            360
            
            
            86
            
            
            140
            
            
            96
            
            
            38Subtotal
            
            
            1,600
            
            
            258
            
            
            461
            
            
            247
            
            
            634Total
            
            $
            6,344
            
            $
            1,101
            
            $
            1,340
            
            $
            422
            
            $
            3,481


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




(2)
            Excludes
                future interest payments





**Market
      Risks**





The
      company is exposed to a variety of market risks, including credit risk, changes
      in oil and gas commodity prices, foreign currency exchange rates and interest
      rates. We address these risks through a controlled program of risk management
      that includes the use of insurance and derivative financial instruments. In
      addition to information included in this section, see Notes 1 and 9 to the
      Consolidated Financial Statements included in Item 8 of this Annual Report
      on
      Form 10-K for discussions of the company’s derivatives and hedging
      activities.





**Commodity
      Price Risk**





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








At
      December 31, 2005, outstanding commodity-related derivatives had a net liability
      fair value of $2 billion. The fair value of these derivative instruments was
      determined based on prices actively quoted, generally NYMEX prices. Realized
      and
      unrealized gains and losses arising from derivative instruments that have not
      been designated as hedges or that do not qualify for hedge accounting (“nonhedge
      derivatives”) are recognized in current earnings. Gains and losses on
      derivatives designated as cash flow hedges are deferred in accumulated other
      comprehensive income (loss) and reclassified into earnings when the hedged
      production is sold. Net after-tax losses on oil and gas derivatives in
      accumulated other comprehensive loss were $1.1 billion at December 31, 2005,
      and
      related to a portion of the company’s expected production through 2007. During
      the next 12 months, we expect to reclassify net after-tax losses of $617 million
      from accumulated other comprehensive loss into earnings, assuming no further
      changes in the fair value of the related contracts. Net realized oil and gas
      hedging losses associated with continuing operations totaled $655 million,
      $533
      million and $215 million in 2005, 2004 and 2003, respectively. The losses offset
      the higher oil and natural gas prices realized on the physical sale of crude
      oil
      and natural gas. Reference is made to the section *-Results of Operations by Segment - Exploration and Production,* which
      provides average realized oil and gas sales prices excluding and including
      the
      effect of our hedging program, as well as additional information on the effect
      of derivative instruments on our consolidated financial statements and our
      election to discontinue hedge accounting effective March 1, 2006.





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





**2006**
              
              **2007**Average
                Contract
                  Price
                ($/Barrel)
              
              Average
                  Daily Volume
                (Barrels)
              
              Average
                Contract
                  Price
                ($/Barrel)
              
              Average
                  Daily Volume
                (Barrels)**Crude
                  Oil (WTI) -****Hedge:**Fixed
                  price swaps
              
              $
              53.14
              
              
              18,781
              
              $
              51.44
              
              
              27,250Costless
                  collars
              
              $
              27.00
                  - $30.58
              
              
              19,000
              (a)
              
              -
              
              
              -$
              45.00
                  - $65.60
              
              
              18,288
              
              $
              45.00
                  - $61.42
              
              
              18,000**Nonhedge:**Three-way
                  collars(1)
              
              $
              25.00
                  - $28.65
              
              
              2,000
              (b)
              
              -
              
              
              -Three-way
                  average floor
              
              $
              20.8858,069
              
              
              
              
              
              45,250


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


(b)
            Acquired
                in the Westport merger.





(1)
            These
                derivatives function similar to a costless collar, with the exception
                that
                if the WTI price falls below the three-way floor, the company loses
                price
                protection. For example, the company only has $4.12/barrel of price
                protection if the WTI price falls below $20.88/barrel in the case
                of its
                2005 crude oil three-way collars ($25.00 -
                $20.88).








**2006**
              
              **2007**Average
                Contract
                  Price
                ($/MMBtu)
              
              Average
                  Daily Volume
                (MMBtu)
              
              Average
                Contract
                  Price
                ($/MMBtu)
              
              Average
                  Daily Volume
                (MMBtu)**Natural
                  Gas (NYMEX) -****Hedge:**Fixed
                  price swaps
              
              $
              7.57
              
              
              110,000
              
              $
              7.03
              
              
              20,000Costless
                  collars
              
              $
              4.75
                  - $ 5.50
              
              
              240,000
              (a)
              
              -
              
              
              -$
              6.00
                  - $10.78
              
              
              120,000
              
              $
              6.00
                  - $8.98
              
              
              155,000**Nonhedge:**Fixed
                  price swaps
              
              $
              7.50
              
              
              86,000
              
              $
              7.03
              
              
              245,000Costless
                  collars
              
              $
              4.75
                  - $ 5.50
              
              
              100,000
              (a)
              
              -
              
              
              -$
              6.00
                  - $10.83
              
              
              77,000
              
              $
              6.00
                  - $9.10
              
              
              110,000Three-way
                  collars(1)
              
              $
              4.00
                  - $ 6.00
              
              
              20,000
              (b)
              
              -
              
              
              -Three-way
                  average floor
              
              $
              3.04753,000
              
              
              
              
              
              530,000**Basis
                  Swaps vs. NYMEX -****Hedge:**CIG(2)
              
              $
              1.03
              
              
              39,890
              
              $
              0.39
              
              
              20,000NWPL(3)
              
              $
              1.04
              
              
              57,575
              
              
              -
              
              
              -**Nonhedge:**CIG
              
              $
              2.07
              
              
              45,123
              
              
              -
              
              
              -NWPL
              
              $
              1.75
              
              
              10,603
              
              $
              0.20
              
              
              15,000




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


(b)
            Acquired
                in the Westport merger.





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


(2)
            Colorado
                Interstate Gas pipeline index.


(3)
            Northwest
                Pipeline Rocky Mountain index.




**Foreign
      Currency Exchange Rate Risk**





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





**Interest
      Rate Risk**





*Debt
      Obligations* -
      The
      company is exposed to changes in interest rates, primarily as a result of its
      debt obligations. The fair value of our fixed-rate debt is affected by changes
      in market interest rates. To manage this risk, historically, we entered into
      interest rate swap agreements to effectively change the interest paid on a
      portion of our fixed-rate debt to a variable rate. Our variable-rate debt
      exposes us to the risk of higher interest cost if market interest rates
      increase. Based on the current mix of variable- and fixed-rate debt, we do
      not
      expect the impact of changes in interest rates to be material to our earnings
      or
      cash flows.








The
      table below presents principal amounts and related weighted-average interest
      rates by maturity date for the company’s debt obligations outstanding at
      December 31, 2005:


FairThere-
            
            
            
            Value(Millions
                of dollars)
            
            2006
            
            2007
            
            2008
            
            2009
            
            2010
            
            After(2)
            
            Total(3)
            
            12/31/05Fixed-rate
                debt -Principal
                amount
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            2,575
            
            $
            2,575
            
            $
            2,763Weighted-averageinterest
                rate
            
            
            -
            %
            
            -
            %
            
            -
            %
            
            -
            %
            
            -
            %
            
            7.47
            %
            
            7.47
            %Variable-rate
                debt(1)-Principal
                amount
            
            $
            309
            
            $
            152
            
            $
            2
            
            $
            2
            
            $
            2
            
            $
            190
            
            $
            657
            
            $
            657Weighted-averageinterest
                rate
            
            
            7.30
            %
            
            7.53
            %
            
            6.57
            %
            
            6.57
            %
            
            6.57
            %
            
            6.57
            %
            
            7.13
            %





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




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




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





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








**Critical
      Accounting Policies**





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





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





**Exploratory
      Drilling Costs**





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





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





**Proved
      Oil and Gas Reserves**





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





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








**Impairment
      of Assets**





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





**Business
      Combinations**





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





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





**Derivative
      Instruments**





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








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





**Environmental
      Remediation and Other Contingency Reserves**





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




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





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





**Tax
      Accruals**





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





**Benefit
      Plans**





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





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





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


·
            Discount
                rate


·
            Rate
                of compensation increases


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








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





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





Pension
                Benefits(1)
            
            Other
                Postretirement BenefitsNet
                Periodic
            
            Projected
            
            Net
                Periodic
            
            AccumulatedCost
            
            Benefit
            
            Cost
            
            Postretirement(Millions
                of dollars)
            
            (Benefit)
            
            Obligation
            
            (Benefit)
            
            Benefit
                ObligationIncrease
                of 0.5% in -Discount
                rates
            
            $
            (1
            )
            $
            (64
            )
            $
            (1
            )
            $
            (15
            )Expected
                return on plan assets
            
            
            (6
            )
            
            -
            
            
            -
            
            
            -Rate
                of compensation increase
            
            
            2
            
            
            14
            
            
            -
            
            
            1Decrease
                of 0.5% in -Discount
                rates
            
            $
            1
            
            $
            71
            
            $
            1
            
            $
            16Expected
                return on plan assets (2)
            
            
            6
            
            
            -
            
            
            -
            
            
            -Rate
                of compensation increase
            
            
            (2
            )
            
            (14
            )
            
            -
            
            
            (1
            )Change
                in health care cost trend rate of 1% -Increase
            
            $
            -
            
            $
            -
            
            $
            1
            
            $
            14Decrease
            
            
            -
            
            
            -
            
            
            (1
            )
            
            (12
            )





(1)
            The
                sensitivity analysis reflects only the impact of assumption changes
                on our
                U.S. qualified retirement plan. While Kerr-McGee sponsors other retirement
                plans for its U.S. employees, the year-end 2005 projected benefit
                obligation for the U.S. qualified retirement plan represented 93%
                of the
                total projected benefit obligation for all U.S. retirement
                plans.




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





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





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





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








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





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





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





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





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








**Environmental
      Matters**





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








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





**Current
      Businesses**





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





**Former
      Businesses**





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





**Environmental
      Costs**





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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003
            
            TotalExpenditures
                applied againstenvironmental
                reserves
            
            **$**
            **71**
            
            $
            99
            
            $
            104
            
            $
            274Recurring
                expenses
            
            
            **45**
            
            
            37
            
            
            39
            
            
            121Capital
                expenditures
            
            
            **12**
            
            
            9
            
            
            14
            
            
            35Total
            
            **$**
            **128**
            
            $
            145
            
            $
            157
            
            $
            430








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





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





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





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











RemainingTotal
                Expenditures Through 2005
            Reserve
                Balance at December 31, 2005
            TotalLocation
                of Site
            Stage
                of Investigation/Remediation
            (Millions
                of dollars)**EPA
                Superfund sites on**
              **National
                Priority List (NPL)**West
                Chicago, Ill.
              Vicinity
                areas
            Remediation
                of thorium tailings at Residential Areas and Reed-Keppler Park is
                substantially complete. Cleanup of thorium tailings at Kress Creek
                and
                Sewage Treatment Plant is ongoing.
            $
                141
            $75
            $
                216Milwaukee,
                Wis.
            Completed
                soil cleanup at former wood-treatment facility and began cleanup
                of
                offsite tributary creek. Groundwater remediation and cleanup of tributary
                creek is continuing.
            41
            4
            45Other
                sites
            Sites
                where the company has been named a PRP, including landfills, wood-treating
                sites, a mine site and an oil recycling refinery. These sites are
                in
                various stages of investigation/remediation.
            32
            12
            44214
            91
            305**Sites
                under consent order, license or agreement, not on EPA Superfund
                NPL**West
                Chicago, Ill.
              Former
                manufacturing
              facility
            Excavation,
                removal and disposal of contaminated soils at former thorium mill
                is
                substantially complete. The site will be used for moving material
                from the
                Kress Creek and Sewage Treatment Plant remediation sites. Surface
                restoration and groundwater monitoring and remediation are expected
                to
                continue for approximately 10 years.
            446
            12
            458Los
                Angeles County, Cal.
            Excavation,
                removal and disposal of soils contaminated with wastes from oil and
                gas
                production is ongoing.
            20
            23
            43Cushing,
                Okla.
            Excavation,
                removal and disposal of thorium and uranium residuals was substantially
                completed in 2004. Investigation of and remediation addressing hydrocarbon
                contamination is continuing.
            147
            12
            159Henderson,
                Nev.
            Groundwater
                treatment to address ammonium perchlorate contamination is being
                conducted
                under consent decree with Nevada Department of Environmental
                Protection.
            124
            37
            161Ambrosia
                Lake, New Mexico
            Uranium
                mill tailings and selected pond sediments consolidated and capped
                onsite.
                A request to end groundwater treatment and a decommissioning plan
                for
                impacted soils are under review by the Nuclear Regulatory
                Commission.
            28
            11
            39Other
                sites
            Sites
                related to wood-treatment, chemical production, landfills, mining,
                and oil
                and gas refining, distribution and marketing. These sites are in
                various
                stages of investigation/remediation.
            308
            82
            3901,073
            177
            1,250Total
            $1,287
            $268
            $1,555











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





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








**New/Revised
      Accounting Standards**





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





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





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





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





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




**Item
      7a.**  **Quantitative
      and Qualitative Disclosure about Market Risk**





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











**Item
      8.**  **Financial
      Statements and Supplementary Data**





Index
                to the Consolidated Financial Statements
            PAGEManagement’s
                Report on Internal Control over Financial Reporting
            74Report
                of Independent Registered Public Accounting Firmon
                Internal Control over Financial Reporting
            75Report
                of Independent Registered Public Accounting Firmon
                Consolidated Financial Statements
            76Consolidated
                Statement of Income for the years endedDecember
                31, 2005, 2004 and 2003
            77Consolidated
                Balance Sheet at December 31, 2005 and 2004
            78Consolidated
                Statement of Cash Flows for the years endedDecember
                31, 2005, 2004 and 2003
            79Consolidated
                Statement of Comprehensive Income and Stockholders’ Equityfor
                the years ended December 31, 2005, 2004 and 2003
            80Notes
                to Consolidated Financial Statements
            81Index
                to Supplementary DataFive-Year
                Financial Summary
            151Five-Year
                Operating Summary
            152Index
                to the Financial Statement SchedulesSchedule
                II - Valuation Accounts and Reserves
            162





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














**Management’s
      Report on Internal Control over Financial Reporting**





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





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





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











(Luke
                R. Corbett)
            (Robert
                M.
                Wohleber)Luke
                R. Corbett
            Robert
                M. WohleberChief
                Executive Officer
            Senior
                Vice President
                andChief
                Financial
                Officer











March
      14, 2006

















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





The
      Board of Directors and Stockholders


Kerr-McGee
      Corporation





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





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





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





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





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





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








/s/ ERNST & YOUNG LLP








Oklahoma
      City, Oklahoma


March
      14, 2006














**Report
      of Independent Registered Public Accounting Firm on Consolidated Financial
      Statements**








The
      Board of Directors and Stockholders


Kerr-McGee
      Corporation





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





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





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





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





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








/S/ ERNST & YOUNG LLP








Oklahoma
      City, Oklahoma


March
      14, 2006































**Consolidated
                Statement of Income**(Millions
                of dollars, except per-share amounts)
            
            **2005**
            
            2004
            
            2003**Revenues**
            
            **$**
            **5,927**
            
            $
            4,398
            
            $
            3,289**Costs
                and Expenses**Costs
                and operating expenses
            
            
            **2,304**
            
            
            1,794
            
            
            1,416Selling,
                general and administrative expenses
            
            
            **455**
            
            
            325
            
            
            350Shipping
                and handling expenses
            
            
            **145**
            
            
            128
            
            
            96Depreciation
                and depletion
            
            
            **952**
            
            
            842
            
            
            532Accretion
                expense
            
            
            **23**
            
            
            19
            
            
            15Asset
                impairments
            
            
            **17**
            
            
            28
            
            
            14(Gain)
                loss on sale of assets
            
            
            **(211**
            **)**
            
            29
            
            
            (30
            )Exploration,
                including exploratory dry holes andamortization
                of undeveloped leases
            
            
            **377**
            
            
            324
            
            
            327Taxes
                other than income taxes
            
            
            **202**
            
            
            144
            
            
            94Provision
                for environmental remediation and restoration,net
                of reimbursements
            
            
            **38**
            
            
            86
            
            
            60Interest
                and debt expense
            
            
            **253**
            
            
            244
            
            
            250Loss
                on early repayment and modification of debt
            
            
            **42**
            
            
            -
            
            
            -Total
                Costs and Expenses
            
            
            **4,597**
            
            
            3,963
            
            
            3,124**1,330**
            
            
            435
            
            
            165**Other
                Income (Expense)**
            
            
            **104**
            
            
            (34
            )
            
            (25
            )**Income
                from Continuing Operations before Income Taxes**
            
            
            **1,434**
            
            
            401
            
            
            140**Benefit
                (Provision) for Income Taxes**
            
            
            **(487**
            **)**
            
            (137
            )
            
            15**Minority
                Interest, net of taxes**
            
            
            **(1**
            **)**
            
            -
            
            
            -**Income
                from Continuing Operations**
            
            
            **946**
            
            
            264
            
            
            155**Income
                from Discontinued Operations, net of taxes (Note
                2)**
            
            
            **2,265**
            
            
            140
            
            
            99**Cumulative
                Effect of Change in Accounting Principle,****net
                of taxes**
            
            
            **-**
            
            
            -
            
            
            (35
            )**Net
                Income**
            
            **$**
            **3,211**
            
            $
            404
            
            $
            219**Income
                per Common Share**Basic
                -Continuing
                operations
            
            **$**
            **7.22**
            
            $
            2.09
            
            $
            1.55Discontinued
                operations
            
            
            **17.29**
            
            
            1.11
            
            
            .98Cumulative
                effect of change in accounting principle
            
            
            **-**
            
            
            -
            
            
            (.35
            )Net
                income
            
            **$**
            **24.51**
            
            $
            3.20
            
            $
            2.18Diluted
                -Continuing
                operations
            
            **$**
            **7.07**
            
            $
            2.08
            
            $
            1.54Discontinued
                operations
            
            
            **16.84**
            
            
            1.10
            
            
            .97Cumulative
                effect of change in accounting principle
            
            
            **-**
            
            
            -
            
            
            (.34
            )Net
                income
            
            **$**
            **23.91**
            
            $
            3.18
            
            $
            2.17




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








**Consolidated
                  Balance Sheet**(Millions
                  of dollars)
              
              **2005**
              
              2004**ASSETS****Current
                  Assets**Cash
                  and cash equivalents
              
              **$**
              **1,053**
              
              $
              76Accounts
                  receivable
              
              
              **1,069**
              
              
              825Inventories
              
              
              **352**
              
              
              314Derivatives
                  and other current assets
              
              
              **194**
              
              
              151Deferred
                  income taxes
              
              
              **581**
              
              
              327Assets
                  held for sale (Note 2)
              
              
              **-**
              
              
              194**Total
                  Current Assets**
              
              
              **3,249**
              
              
              1,887**Property,
                  Plant and Equipment - Net**
              
              
              **9,275**
              
              
              9,073**Deferred
                  Charges, Derivatives and Other Assets**
              
              
              **508**
              
              
              484**Intangible
                  Assets**
              
              
              **78**
              
              
              91**Assets
                  Held for Sale (Note 2)**
              
              
              **5**
              
              
              1,786**Goodwill**
              
              
              **1,161**
              
              
              1,197**Total
                  Assets**
              
              **$**
              **14,276**
              
              $
              14,518




**LIABILITIES
                  AND STOCKHOLDERS’ EQUITY****Current
                  Liabilities**Accounts
                  payable
              
              **$**
              **727**
              
              $
              607Long-term
                  debt due within one year
              
              
              **308**
              
              
              463Income
                  taxes payable
              
              
              **473**
              
              
              138Derivative
                  liabilities
              
              
              **1,508**
              
              
              350Accrued
                  liabilities
              
              
              **915**
              
              
              755Liabilities
                  associated with assets held for sale (Note 2)
              
              
              **-**
              
              
              192**Total
                  Current Liabilities**
              
              
              **3,931**
              
              
              2,505**Long-Term
                  Debt**
              
              
              **2,825**
              
              
              3,236**Noncurrent
                  Liabilities**Deferred
                  income taxes
              
              
              **1,524**
              
              
              1,727Asset
                  retirement obligations
              
              
              **345**
              
              
              336Derivative
                  liabilities
              
              
              **663**
              
              
              208Other
              
              
              **661**
              
              
              571Liabilities
                  associated with assets held for sale (Note 2)
              
              
              **-**
              
              
              617**Total
                  Noncurrent Liabilities**
              
              
              **3,193**
              
              
              3,459**Contingencies
                  and Commitments (Notes 16 and 17)****Minority
                  Interest in Tronox (Note 3)**
              
              
              **212**
              
              
              -**Stockholders’
                  Equity**Common
                  stock, par value $1.00 - 500,000,000 and 300,000,000shares
                  authorized, 119,668,552 and 152,049,127 sharesissued
                  at December 31, 2005 and 2004, respectively
              
              
              **120**
              
              
              152Capital
                  in excess of par value
              
              
              **3,702**
              
              
              4,205Preferred
                  stock purchase rights
              
              
              **1**
              
              
              2Retained
                  earnings
              
              
              **1,704**
              
              
              1,102Accumulated
                  other comprehensive loss
              
              
              **(1,079**
              **)**
              
              (79
              )Common
                  stock in treasury, at cost - 3,456,918 and 159,856 sharesat
                  December 31, 2005 and 2004, respectively
              
              
              **(266**
              **)**
              
              (8
              )Deferred
                  compensation
              
              
              **(67**
              **)**
              
              (56
              )**Total
                  Stockholders’ Equity**
              
              
              **4,115**
              
              
              5,318**Total
                  Liabilities and Stockholders’ Equity**
              
              **$**
              **14,276**
              
              $
              14,518
  The
          “successful efforts” method of accounting for oil and gas exploration and
          production activities has been followed in preparing this balance
          sheet.





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







**Consolidated
                Statement of Cash Flows**(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003**Cash
                Flows from Operating Activities**Net
                income
            
            **$**
            **3,211**
            
            $
            404
            
            $
            219Adjustments
                to reconcile net income to net cashprovided
                by operating activities -Depreciation,
                depletion and amortization
            
            
            **1,177**
            
            
            1,124
            
            
            814Deferred
                income taxes
            
            
            **83**
            
            
            108
            
            
            156Unrealized
                losses on derivatives
            
            
            **200**
            
            
            12
            
            
            5Dry
                hole expense
            
            
            **185**
            
            
            161
            
            
            181Noncash
                stock-based compensation and ESOP expense
            
            
            **54**
            
            
            25
            
            
            42Asset
                impairments
            
            
            **17**
            
            
            36
            
            
            14Gain
                on sale of the North Sea oil and gas business
            
            
            **(2,240**
            **)**
            
            -
            
            
            -(Gain)
                loss on sale of assets
            
            
            **(327**
            **)**
            
            20
            
            
            (40
            )Loss
                on early repayment and modification of debt
            
            
            **42**
            
            
            -
            
            
            -Accretion
                expense
            
            
            **30**
            
            
            30
            
            
            25Cumulative
                effect of change in accounting principle
            
            
            **-**
            
            
            -
            
            
            35Provision
                for environmental remediationand
                restoration, net of reimbursements
            
            
            **49**
            
            
            92
            
            
            62Other
                noncash items affecting net income
            
            
            **116**
            
            
            147
            
            
            97Changes
                in assets and liabilities:(1)(Increase)
                decrease in accounts receivable
            
            
            **(232**
            **)**
            
            (236
            )
            
            45(Increase)
                decrease in inventories
            
            
            **(66**
            **)**
            
            83
            
            
            22Decrease
                in deposits, prepaids and other assets
            
            
            **7**
            
            
            48
            
            
            12Increase
                (decrease) in accounts payable,derivatives
                and accrued liabilities
            
            
            **390**
            
            
            136
            
            
            (57
            )Increase
                in income taxes payable
            
            
            **418**
            
            
            4
            
            
            16Other
            
            
            **(11**
            **)**
            
            (144
            )
            
            (130
            )**Net
                cash provided by operating activities**
            
            
            **3,103**
            
            
            2,050
            
            
            1,518**Cash
                Flows from Investing Activities**Capital
                expenditures
            
            
            **(1,751**
            **)**
            
            (1,262
            )
            
            (981
            )Dry
                hole costs
            
            
            **(169**
            **)**
            
            (78
            )
            
            (181
            )Acquisitions,
                net of cash acquired(2)
            
            
            **-**
            
            
            43
            
            
            (110
            )Net
                proceeds from sale of the North Sea oil and gas business
            
            
            **3,305**
            
            
            -
            
            
            -Proceeds
                from sale of assets
            
            
            **704**
            
            
            23
            
            
            304Other
                investing activities
            
            
            **(8**
            **)**
            
            12
            
            
            17**Net
                cash provided by (used in) investing activities**
            
            
            **2,081**
            
            
            (1,262
            )
            
            (951
            )**Cash
                Flows from Financing Activities****(2)**Issuance
                of common stock upon exercise of stock options
            
            
            **225**
            
            
            55
            
            
            -Sale
                of Tronox stock
            
            
            **225**
            
            
            -
            
            
            -Purchases
                of treasury stock
            
            
            **(250**
            **)**
            
            -
            
            
            -Repurchases
                of common stock under the tender offer
            
            
            **(3,975**
            **)**
            
            -
            
            
            -Dividends
                paid
            
            
            **(153**
            **)**
            
            (205
            )
            
            (181
            )Repayment
                of debt
            
            
            **(4,751**
            **)**
            
            (1,278
            )
            
            (369
            )Proceeds
                from borrowings
            
            
            **4,800**
            
            
            686
            
            
            31Debt
                issuance costs and other
            
            
            **(71**
            **)**
            
            (8
            )
            
            (1
            )Cash
                paid for modification of debt
            
            
            **(22**
            **)**
            
            -
            
            
            -Settlement
                of Westport derivatives
            
            
            **(238**
            **)**
            
            (101
            )
            
            -**Net
                cash used in financing activities**
            
            
            **(4,210**
            **)**
            
            (851
            )
            
            (520
            )**Effects
                of Exchange Rate Changes on Cash and Cash Equivalents**
            
            
            **3**
            
            
            (3
            )
            
            5**Net
                Increase (Decrease) in Cash and Cash Equivalents**
            
            
            **977**
            
            
            (66
            )
            
            52**Cash
                and Cash Equivalents at Beginning of Year**
            
            
            **76**
            
            
            142
            
            
            90**Cash
                and Cash Equivalents at End of Year**
            
            **$**
            **1,053**
            
            $
            76
            
            $
            142





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


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





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








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





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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Foreign
                currency translation adjustments
            
            **$**
            **(56**
            **)**
            $
            29
            
            $
            56Net
                losses on cash flow hedges
            
            
            **(939**
            **)**
            
            (69
            )
            
            (31
            )Available-for-sale
                securities
            
            
            **-**
            
            
            (5
            )
            
            (1
            )Minimum
                pension liability adjustments
            
            
            **(6**
            **)**
            
            11
            
            
            (7
            )Minority
                interest
            
            
            **1**
            
            
            -
            
            
            -Other
                comprehensive income (loss)
            
            **$**
            **(1,000**
            **)**
            $
            (34
            )
            $
            17




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








**Notes
      to Consolidated Financial
      Statements**





1. 
        **The Company and Significant Accounting Policies**


**The
      Company**





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





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





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





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





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





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








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





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





**Significant
      Accounting Policies**





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





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





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





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





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





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





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





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





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








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





***Property,
      Plant and Equipment***





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





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





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





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





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





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








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





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





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





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





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





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





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





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





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








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





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





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





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





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





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





***Employee
      Stock-Based Compensation***





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








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




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




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




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





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





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





(Millions
                of dollars, except per share amounts)
            
            **2005**
            
            2004
            
            2003Net
                income as reported
            
            **$**
            **3,211**
            
            $
            404
            
            $
            219Add:
                Stock-based employee compensation expense includedin
                reported net income, net of taxes
            
            
            **31**
            
            
            11
            
            
            7Deduct:
                Stock-based compensation expense determinedusing
                a fair-value method, net of taxes
            
            
            **(42**
            **)**
            
            (24
            )
            
            (23
            )Pro
                forma net income
            
            **$**
            **3,200**
            
            $
            391
            
            $
            203Net
                income per share -Basic
                -As
                reported
            
            **$**
            **24.51**
            
            $
            3.20
            
            $
            2.18Pro
                forma
            
            
            **24.43**
            
            
            3.09
            
            
            2.03Diluted
                -As
                reported
            
            **$**
            **23.91**
            
            $
            3.18
            
            $
            2.17Pro
                forma
            
            
            **23.83**
            
            
            3.08
            
            
            2.03





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





**2005**
            
            2004
            
            2003*Inputs
                and assumptions -*Expected
                life (years)
            
            
            
            
            
            **6.0**
            
            
            5.8
            
            
            5.8Risk-free
                interest rate
            
            
            
            
            
            **3.9**
            **%**
            
            3.5
            %
            
            3.6
            %Expected
                dividend yield
            
            
            
            
            
            **3.5**
            
            
            3.6
            
            
            3.3Expected
                volatility
            
            
            
            
            
            **27.4**
            **%**
            
            22.6
            %
            
            32.7
            %Weighted-average
                exercise price of options granted
            
            
            
            
            **$**
            **56.57**
            
            $
            49.45
            
            $
            42.93Weighted-average
                fair value of options granted
            
            
            
            
            
            **12.50**
            
            
            8.63
            
            
            11.09





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





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





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





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





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





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





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





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








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





**2. 
        Discontinued Operations and Asset Divestitures and
        Exchanges**





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





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








**Pretax
                Gain on Sale, Net****Gross**
            
            **Continuing**
            
            **Discontinued**(Millions
                of dollars)
            
            **Proceeds**
            (1)
            **Operations**
            
            **Operations***Completed
                exchange transactions -*Exchange
                of interests in certain noncore oil and gas properties for a 37.5%interest in the Blind Faith discovery in the deepwater Gulf of Mexico
                and
                cash
            
            $
            26
            
            $
            21
            
            $
            -Exchange
                of interests in certain noncore oil and gas properties for
                overridingroyalty interests in the Greater Natural Buttes area and
                cash
            
            
            27
            
            
            24
            
            
            -*Completed
                divestiture transactions -*Nonoperated
                North Sea fields
            
            
            551
            
            
            -
            
            
            306Remaining
                oil and gas operations in the North Sea
            
            
            2,970
            
            
            -
            
            
            1,934Nonoperating
                interest in gas processing facility
            
            
            159
            
            
            120
            (2)
            
            -Several
                packages of U.S. onshore oil and gas properties
            
            
            435
            
            
            149
            
            
            -Other
                noncore oil and gas properties and other assets
            
            
            56
            
            
            17
            
            
            (1
            )***Total completed exchange and divestiture
                transactions***
            
            $
            4,224
            
            $
            331
            
            $
            2,239*Expected
                2006 divestiture transactions -*Interests
                in oil and gas properties on the Gulf of Mexico shelf
            
            
            1,340
            (3)Noncore
                oil and gas assets onshore in the U.S.
            
            
            15





(1)
            For
                completed transactions, gross proceeds reflect working capital and
                other
                adjustments to the base cash purchase price. The following presents
                a
                reconciliation of the gross proceeds presented above to the net proceeds
                from asset divestitures presented in the company's Consolidated Statement
                of Cash Flows for the year ended December 31, 2005 (in millions of
                dollars):




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




(2)
            Gainon sale of the company's investment in the Javelina gas processing
                facility is reflected as a component of other income (expense)
                in the company's Consolidated Statement of Income. The company owned
                an
                interest in the facility through its 40% ownership of Javelina Company
                and
                Javelina Pipeline Company. This investment was accounted for using
                the
                equity method of accounting.




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








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





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




**2005**
            
            2004
            
            2003**North
                Sea**
            
            **Forest**
            
            
            
            North
                Sea
            
            Forest
            
            
            
            North
                Sea
            
            Forest**Oil
                and Gas**
            
            **Products**
            
            
            
            Oil
                and Gas
            
            Products
            
            
            
            Oil
                and Gas
            
            Products(Millions
                of dollars)
            
            **Business**
            
            **Business**
            
            **Total**
            
            Business
            
            Business
            
            Total
            
            Business
            
            Business
            
            TotalRevenues
            
            **$**
            **994**
            
            **$**
            **-**
            
            **$**
            **994**
            
            $
            759
            
            $
            22
            
            $
            781
            
            $
            791
            
            $
            105
            
            $
            896Income
                from discontinued operations -Income
                (loss) from operations
            
            **$**
            **527**
            
            **$**
            **-**
            
            **$**
            **527**
            
            $
            270
            
            $
            (17
            )
            $
            253
            
            
            319
            
            $
            (16
            )
            $
            303Gain
                (loss) on sale
            
            
            **2,240**
            
            
            **(1**
            **)**
            
            **2,239**
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Adjustments
                for contingencies(1)
            
            
            **-**
            
            
            **(25**
            **)**
            
            **(25**
            **)**
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Pretax
                income (loss) fromdiscontinued
                operations
            
            
            **2,767**
            
            
            **(26**
            **)**
            
            **2,741**
            
            
            270
            
            
            (17
            )
            
            253
            
            
            319
            
            
            (16
            )
            
            303Income
                tax (expense) benefit
            
            
            **(487**
            **)
                (2)**
            
            **9**
            
            
            **(478**
            **)**
            
            (119
            )
            
            6
            
            
            (113
            )
            
            (210
            )
            
            6
            
            
            (204
            )Minority
                interest, net of tax
            
            
            **-**
            
            
            **2**
            
            
            **2**
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Income
                (loss) from discontinuedoperations,
                net of tax
            
            **$**
            **2,280**
            
            **$**
            **(15**
            **)**
            **$**
            **2,265**
            
            $
            151
            
            $
            (11
            )
            $
            140
            
            $
            109
            
            $
            (10
            )
            $
            99





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


(2)
            Represents
                primarily U.S. taxes on the sale of North Sea oil and gas business.
                The
                net U.K. deferred tax liability was assumed by the acquirer as part
                of the
                divestiture transaction and, as such, was included in the carrying
                amount
                of the investment for purposes of calculating pretax gain on sale
                of the
                U.K. subsidiary.





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





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





**2005**
            
            2004
            
            2003U.S.
                statutory tax rate
            
            
            **35.0**
            **%**
            
            35.0
            %
            
            35.0
            %Increases
                (decreases) resulting from -Taxation of foreign operations
            
            
            **3.2**
            
            
            9.9
            
            
            13.2Effect of book and tax basis differences of investmentin subsidiary stock
            
            
            **8.7**
            
            
            -
            
            
            -Utilization of foreign tax credits
            
            
            **(25.8**
            **)**
            
            -
            
            
            -Utilization of capital loss carryforwards
            
            
            **(4.0**
            **)**
            
            -
            
            
            -Provision for U.S. income taxes on U.K. remittances(1)
            
            
            **-**
            
            
            -
            
            
            19.4State income taxes
            
            
            **.2**
            
            
            -
            
            
            -Other - net
            
            
            **.1**
            
            
            (.2
            )
            
            (.3
            )Effective
                tax rate
            
            
            **17.4**
            **%**
            
            44.7
            %
            
            67.3
            %





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





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








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





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





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





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





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





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





**3. 
        Separation of Tronox**





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





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








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





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





**4. 
        Westport Resources Merger**





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





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





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








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




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





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





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




·  Enhances
      the stability of high-margin production




·  Expands
      low-risk exploitation opportunities




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




·  Reduces
      leverage and enables greater financial flexibility




·  Provides
      opportunities for synergies and related cost savings




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





(Millions
                of dollars)AssetsCurrent
                assets
            
            $
            291Property,
                plant and equipment
            
            
            3,494Other
                assets
            
            
            39Goodwill
            
            
            804Total
                Assets
            
            $
            4,628Liabilities
                and Stockholders’ EquityCurrent
                liabilities
            
            $
            360Long-term
                debt
            
            
            1,046Deferred
                income taxes
            
            
            656Other
                liabilities
            
            
            118Total
                Noncurrent Liabilities
            
            
            1,820Stockholders’
                Equity
            
            
            2,448Total
                Liabilities and Stockholders’ Equity
            
            $
            4,628





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








Pro
                Forma Information(Unaudited)Year
                EndedDecember
                31,(Millions
                of dollars, except per-share amounts)
            
            2004
            
            2003Revenues
            
            $
            4,848
            
            $
            4,017Income
                from continuing operations
            
            
            325
            
            
            198Net
                income
            
            
            465
            
            
            258Net
                income per common share -Basic
            
            $
            3.10
            
            $
            1.73Diluted
            
            
            3.08
            
            
            1.71





**5. 
        Statement of Income Data**





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





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





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





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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Gain
                on sale of nonoperating interest in gasprocessing
                facility(1)
            
            **$**
            **120**
            
            $
            -
            
            $
            -Equity
                in net losses of equity method investees
            
            
            **(19**
            **)**
            
            (26
            )
            
            (33
            )Net
                foreign currency transaction loss
            
            
            **(2**
            **)**
            
            (13
            )
            
            (5
            )Gain
                on sale of Devon stock(2)
            
            
            **-**
            
            
            9
            
            
            17DECS
              and
              Devon stock revaluation
            
            
            -
            
            
            2
            
            
            8Interest
                income
            
            
            **10**
            
            
            4
            
            
            2Loss
                on accounts receivables sales and other
            
            
            **(5**
            **)**
            
            (10
            )
            
            (14
            )Total
            
            **$**
            **104**
            
            $
            (34
            )
            $
            (25
            )





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




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





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





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





**2005**
            
            2004
            
            2003Income
            
            
            
            
            
            Income
            
            
            
            
            
            Income(Millions
                of dollars , except
            
            from
            
            
            
            Per-
            
            from
            
            
            
            Per-
            
            from
            
            
            
            Per-per-share
                amounts, and
            
            Continuing
            
            
            
            share
            
            Continuing
            
            
            
            share
            
            Continuing
            
            
            
            sharethousands
                of shares)
            
            Operations
            
            Shares
            
            Income
            
            Operations
            
            Shares
            
            Income
            
            Operations
            
            Shares
            
            IncomeBasic
                earnings per share
            
            **$**
            **946**
            
            
            **131,012**
            
            **$**
            **7.22**
            
            $
            264
            
            
            126,313
            
            $
            2.09
            
            $
            155
            
            
            100,145
            
            $
            1.55Effect
                of dilutive securities:5.25%
                convertibledebentures
            
            
            **4**
            
            
            **1,585**
            
            
            
            
            
            -
            
            
            -
            
            
            
            
            
            -
            
            
            -Restricted stock andstock
                options
            
            
            **-**
            
            
            **1,889**
            
            
            
            
            
            -
            
            
            782
            
            
            
            
            
            -
            
            
            714Diluted
                earnings per share
            
            **$**
            **950**
            
            
            **134,486**
            
            **$**
            **7.07**
            
            $
            264
            
            
            127,095
            
            $
            2.08
            
            $
            155
            
            
            100,859
            
            $
            1.54





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





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





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





**6. 
        Balance Sheet Data**





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





(Millions
                of dollars)
            
            **2005**
            
            2004Chemicals
                and other products
            
            **$**
            **250**
            
            $
            236Materials
                and supplies
            
            
            **97**
            
            
            71Crude
                oil
            
            
            **5**
            
            
            7Total
            
            **$**
            **352**
            
            $
            314








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





AccumulatedDepreciation
                andGross
                Property
            
            Depletion
            
            Net
                Property(Millions
                of dollars)
            
            **2005**
            
            2004
            
            **2005**
            
            2004
            
            **2005**
            
            2004Exploration
                and production
            
            **$**
            **13,490**
            
            $
            12,553
            
            **$**
            **(5,108**
            **)**
            $
            (4,443
            )
            **$**
            **8,382**
            
            $
            8,110Chemical
            
            
            **2,080**
            
            
            2,059
            
            
            **(1,244**
            **)**
            
            (1,184
            )
            
            **836**
            
            
            875Other
            
            
            **148**
            
            
            195
            
            
            **(91**
            **)**
            
            (107
            )
            
            **57**
            
            
            88Total
            
            **$**
            **15,718**
            
            $
            14,807
            
            **$**
            **(6,443**
            **)**
            $
            (5,734
            )
            **$**
            **9,275**
            
            $
            9,073








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





(Millions
                of dollars)
            
            **2005**
            
            2004Prepaid
                pension cost
            
            **$**
            **249**
            
            $
            239Investment
                in equity method investees
            
            
            **89**
            
            
            112Nonqualified
                benefit plan deposits
            
            
            **48**
            
            
            48Unamortized
                debt issue costs
            
            
            **38**
            
            
            24Long-term
                derivative assets
            
            
            **35**
            
            
            15Long-term
                accounts receivable and other assets
            
            
            **49**
            
            
            46Total
            
            **$**
            **508**
            
            $
            484








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





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





Segment(Millions
                of dollars)
            
            Exploration
                and Production
            
            Chemical
                - Pigment
            
            Total
                Carrying AmountBalance
                at December 31, 2003 -
            
            $
            346
            
            $
            11
            
            $
            357Goodwill
                associated with the Westport merger
            
            
            839
            
            
            -
            
            
            839Other
                changes (including foreign currency translation)
            
            
            -
            
            
            1
            
            
            1Balance
                at December 31, 2004 -
            
            
            **1,185**
            
            
            **12**
            
            
            **1,197**Tax-related
                adjustment to goodwill
            
            
            **(35**
            **)**
            
            **-**
            
            
            **(35**
            **)**Other
                changes (including foreign currency translation)
            
            
            **-**
            
            
            **(1**
            **)**
            
            **(1**
            **)**Balance
                at December 31, 2005 -
            
            **$**
            **1,150**
            
            **$**
            **11**
            
            **$**
            **1,161**







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





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





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





(Millions
                of dollars)
            
            Gross
                Carrying Amount
            
            Accumulated
                Amortization
            
            Net
                Carrying AmountBalance
                at December 31, 2004 -Transportation
                contracts
            
            $
            49
            
            $
            (13
            )
            $
            36Other
            
            
            3
            
            
            (1
            )
            
            2Total
            
            $
            52
            
            $
            (14
            )
            $
            38Balance
                at December 31, 2005 -Transportation
                contracts
            
            **$**
            **49**
            
            **$**
            **(21**
            **)**
            **$**
            **28**Other
            
            
            **3**
            
            
            **(3**
            **)**
            
            **-**Total
            
            **$**
            **52**
            
            **$**
            **(24**
            **)**
            **$**
            **28**





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








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





(Millions
                of dollars)
            
            **2005**
            
            2004Accrued
                operating expenses and explorationand
                development costs
            
            **$**
            **406**
            
            $
            261Employee-related
                costs and benefits(1)
            
            
            **165**
            
            
            156Reserves
                for environmental remediation and restoration
            
            
            **90**
            
            
            97Interest
                payable
            
            
            **72**
            
            
            97Taxes
                other than income taxes
            
            
            **89**
            
            
            71Asset
                retirement obligations
            
            
            **24**
            
            
            17Other
            
            
            **69**
            
            
            56Total
            
            **$**
            **915**
            
            $
            755





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











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





(Millions
                of dollars)
            
            **2005**
            
            2004Postretirement
                benefit liability
            
            **$**
            **210**
            
            $
            209Reserves
                for environmental remediation and restoration
            
            
            **178**
            
            
            158Pension
                benefit liability
            
            
            **75**
            
            
            47Litigation
                reserves
            
            
            **26**
            
            
            24Accrued
                rent for spar operating leases
            
            
            **54**
            
            
            46Ad
                valorem taxes
            
            
            **39**
            
            
            33Other
            
            
            **79**
            
            
            54Total
            
            **$**
            **661**
            
            $
            571








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





(Millions
                of dollars)
            
            **2005**
            
            2004Balance
                at January 1
            
            **$**
            **524**
            
            $
            421Obligations
                incurred, including obligations acquired
            
            
            **42**
            
            
            30Liability
                assumed in the Westport merger
            
            
            **-**
            
            
            79Accretion
                expense
            
            
            **30**
            
            
            30Changes
                in estimates, including timing
            
            
            **(32**
            **)**
            
            (16
            )Abandonment
                expenditures
            
            
            **(19**
            **)**
            
            (17
            )Obligations
                settled through divestitures
            
            
            **(195**
            **)**
            
            (3
            )Adoption
                of FIN No. 47(1)
            
            
            **19**
            
            
            -Balance
                at December 31
            
            
            **369**
            
            
            524Less:
                Asset retirement obligations associated with assets held for
                sale
            
            
            **-**
            
            
            (171
            )Less:
                Current asset retirement obligation
            
            
            **(24**
            **)**
            
            (17
            )Noncurrent
                asset retirement obligation
            
            **$**
            **345**
            
            $
            336





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





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




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







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





**7. 
        Cash Flow Statement Data**





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





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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Income
                tax payments
            
            **$**
            **481**
            
            $
            154
            
            $
            115Less:
                refunds received
            
            
            **(30**
            **)**
            
            (19
            )
            
            (49
            )Net
                income tax payments
            
            **$**
            **451**
            
            $
            135
            
            $
            66Interest
                payments
            
            **$**
            **345**
            
            $
            247
            
            $
            227





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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Pension
                and postretirement expense
            
            **$**
            **39**
            
            $
            36
            
            $
            44Litigation
                reserves
            
            
            **9**
            
            
            8
            
            
            8Equity
                in net losses of equity method investees
            
            
            **19**
            
            
            26
            
            
            33Noncash
                interest expense
            
            
            **22**
            
            
            17
            
            
            20Noncash
                spar rental expense
            
            
            **7**
            
            
            14
            
            
            8Increase
                in fair value of embedded options in the DECS(1)
            
            
            **-**
            
            
            101
            
            
            88Increase
                in fair value of trading securities(1)
            
            
            **-**
            
            
            (103
            )
            
            (96
            )All
                other
            
            
            **20**
            
            
            48
            
            
            (8
            )Total
            
            **$**
            **116**
            
            $
            147
            
            $
            97





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





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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Environmental
                expenditures
            
            **$**
            **(71**
            **)**
            $
            (99
            )
            $
            (104
            )Reimbursements
                of environmental expenditures
            
            
            **72**
            
            
            50
            
            
            15Cash
                abandonment expenditures
            
            
            **(19**
            **)**
            
            (17
            )
            
            (17
            )Contributions
                to pension and postretirement plans
            
            
            **(33**
            **)**
            
            (67
            )
            
            (29
            )All
                other
            
            
            **40**
            
            
            (11
            )
            
            5Total
            
            **$**
            **(11**
            **)**
            $
            (144
            )
            $
            (130
            )








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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003*Noncash
                investing activities -*Increase
                in property, plant and equipment associated with -Westport merger
            
            **$**
            **-**
            
            $
            3,494
            
            $
            -Asset retirement obligations incurred(including changes in estimates)
            
            
            **7**
            
            
            7
            
            
            30Asset retirement costs recognized upon adopting a newaccounting standard
            
            
            **19**
            
            
            -
            
            
            108Gunnison Trust(1)
            
            
            **-**
            
            
            (83
            )
            
            83Trading securities used for redemption of long-term debt(2)
            
            
            **-**
            
            
            (586
            )
            
            -Increase
                in fair value of securities available for sale(2)
            
            
            **-**
            
            
            -
            
            
            9*Noncash
                financing activities -*Common
                stock and stock options issued in connection withthe Westport merger
            
            **$**
            **-**
            
            $
            2,448
            
            $
            -Increase
                (decrease) in debt associated with -Conversion of 5.25% debentures to common stock
            
            
            **(600**
            **)**
            
            -
            
            
            -Westport merger
            
            
            **-**
            
            
            1,046
            
            
            -Gunnison Trust(1)
            
            
            **-**
            
            
            (75
            )
            
            75Debt redemption with trading securities(2)
            
            
            **-**
            
            
            (330
            )
            
            -Settlement of DECS derivative(2)
            
            
            **-**
            
            
            (256
            )
            
            -Increase
                in valuation of the DECS(2)
            
            
            **-**
            
            
            -
            
            
            8





(1)
            During
                2001, the company entered into a leasing arrangement with Kerr-McGee
                Gunnison Trust (Gunnison Trust) for the construction of the company's
                share of a platform to be used in the development of the Gunnison
                field,
                in which the company has a 50% working interest. Adoption of the
                FASB
                Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN
                No. 46) resulted in the company consolidating the Gunnison Trust
                as of
                December 31, 2003. In January 2004, the $83 million of the synthetic
                lease facility was converted to a leveraged lease structure, whereby
                the
                company leases an interest in the platform under an operating lease
                agreement from a separate business trust. Because the company is
                not the
                primary beneficiary of the operating lease trust, property, plant
                and
                equipment, debt and other assets and liabilities of the Gunnison
                Trust
                were de-consolidated in 2004.





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








**8. 
        Other Comprehensive Income (Loss)**





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





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Foreign
                currency translation -Translation
                adjustments
            
            **$**
            **(41**
            **)**
            $
            22
            
            $
            56Reclassification
                to net income
            
            
            **-**
            
            
            7
            
            
            -Reclassification
                to gain on sale of Tronox stock
            
            
            **(16**
            **)**
            
            -
            
            
            -Total
                foreign currency translation adjustments
            
            
            **(57**
            **)**
            
            29
            
            
            56Net
                losses on cash flow hedges -Unrealized
                losses, net of taxes of $838, $296 and $124
            
            
            **(1,512**
            **)**
            
            (531
            )
            
            (203
            )Reclassification
                of realized losses to net income,net
                of taxes of $(329), $(267) and $(94)
            
            
            **575**
            
            
            462
            
            
            172Reclassification
                of unrealized gains to gain on sale of Tronox stock
            
            
            **(1**
            **)**
            
            -
            
            
            -Total
                losses on cash flow hedges, net
            
            
            **(938**
            **)**
            
            (69
            )
            
            (31
            )Available-for-sale
                securities -Unrealized
                gain, net of taxes of $(3)
            
            
            **-**
            
            
            -
            
            
            6Reclassification
                of realized gain, net of taxes of $3 and $3
            
            
            **-**
            
            
            (5
            )
            
            (7
            )Total
                available-for-sale securities
            
            
            **-**
            
            
            (5
            )
            
            (1
            )Minimum
                pension liability -Minimum
                pension liability adjustments, net of taxes of $4, $(7) and
                $5
            
            
            **(7**
            **)**
            
            11
            
            
            (7
            )Reclassification
                to gain on sale of Tronox stock
            
            
            **1**
            
            
            -
            
            
            -Total
                minimum pension liability adjustments
            
            
            **(6**
            **)**
            
            11
            
            
            (7
            )Minority
                interest, net of tax
            
            
            **1**
            
            
            -
            
            
            -Other
                comprehensive income (loss)
            
            **$**
            **(1,000**
            **)**
            $
            (34
            )
            $
            17








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





(Millions
                of dollars)
            
            **2005**
            
            2004Foreign
                currency translation adjustments
            
            **$**
            **35**
            
            $
            91Unrealized
                loss on cash flow hedges
            
            
            **(1,095**
            **)**
            
            (157
            )Minimum
                pension liability adjustments
            
            
            **(19**
            **)**
            
            (13
            )**$**
            **(1,079**
            **)**
            $
            (79
            )





**9. 
        Derivative Instruments**





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







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





December
                31, 2005Derivative
                Fair ValueCurrent
            
            Long-Term
            
            Current
            
            Long-Term
            
            Deferred
                Gain(Millions
                of dollars)
            
            Asset
            
            Asset
            
            Liability
            
            Liability
            
            (Loss)
                in AOCI(1)Oil
                and gas commodity derivatives -Kerr-McGee
                positions
            
            $
            101
            
            $
            34
            
            $
            (1,422
            )
            $
            (658
            )
            $
            (1,095
            )Acquired
                Westport positions
            
            
            -
            
            
            -
            
            
            (70
            )
            
            -
            
            
            -Gas
                marketing-related derivatives(2)
            
            
            13
            
            
            1
            
            
            (14
            )
            
            -
            
            
            -Foreign
                currency derivatives
            
            
            1
            
            
            -
            
            
            -
            
            
            -
            
            
            1Interest
                rate swaps
            
            
            -
            
            
            -
            
            
            -
            
            
            (5
            )
            
            -Other
            
            
            -
            
            
            -
            
            
            (2
            )
            
            -
            
            
            (1
            )Total
                derivative contracts
            
            $
            115
            
            $
            35
            
            $
            (1,508
            )
            $
            (663
            )
            $
            (1,095
            )





December
                31, 2004Derivative
                Fair ValueCurrent
            
            Long-Term
            
            Current
            
            Long-Term
            
            Deferred
                Gain(Millions
                of dollars)
            
            Asset
            
            Asset
            
            Liability
            
            Liability
            
            (Loss)
                in AOCI(1)Oil
                and gas commodity derivatives -Kerr-McGee
                positions
            
            $
            41
            
            $
            12
            
            $
            (213
            )
            $
            (188
            )
            $
            (174
            )Acquired
                Westport positions
            
            
            1
            
            
            1
            
            
            (123
            )
            
            (16
            )
            
            (7
            )Gas
                marketing-related derivatives(2)
            
            
            6
            
            
            2
            
            
            (6
            )
            
            (2
            )
            
            -Foreign
                currencyderivatives
            
            
            (2
            )
            
            -
            
            
            (6
            )
            
            -
            
            
            (2
            )Interest
                rate swaps
            
            
            4
            
            
            -
            
            
            (1
            )
            
            (2
            )
            
            -Other
                derivatives
            
            
            3
            
            
            -
            
            
            (1
            )
            
            -
            
            
            1Total
                - continuing operations
            
            
            53
            
            
            15
            
            
            (350
            )
            
            (208
            )
            
            (182
            )North
                Sea oil and gas business
            
            
            35
            
            
            -
            
            
            (22
            )
            
            -
            
            
            25Total
                derivative contracts
            
            $
            88
            
            $
            15
            
            $
            (372
            )
            $
            (208
            )
            $
            (157
            )




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




(2)
            The
                company’s marketing subsidiary, Kerr-McGee Energy Services (KMES)
                purchases third-party natural gas for aggregation and sale with the
                company’s own production in the Rocky Mountain area. Under some of its
                marketing arrangements, KMES receives fixed prices for the sale of
                natural
                gas. Existing contracts for the physical delivery of gas at fixed
                prices
                have not been designated as hedges and are marked-to-market through
                earnings in accordance with FAS No. 133. KMES has entered into natural
                gas
                swaps and basis swaps that largely offset its fixed-price risk on
                physical
                contracts and lock in margins associated with the physical sales.
                The
                gains and losses on the swaps, which also are marked-to-market through
                earnings, substantially offset the gains and losses from the fixed-price
                physical delivery contracts.







The
      following tables summarize the gain (loss) on the company’s derivative
      instruments and its classification in the Consolidated Statement of Income
      for
      each of the last three years:





**2005**
            
            2004
            
            2003**Other**
            
            
            
            
            
            Other
            
            
            
            
            
            Other**Costs
                and**
            
            **Income**
            
            
            
            Costs
                and
            
            Income
            
            
            
            Costs
                and
            
            Income(Millions
                of dollars)
            
            **Revenues**
            
            **Expenses**
            
            **(Expense)**
            
            Revenues
            
            Expenses
            
            (Expense)
            
            Revenues
            
            Expenses
            
            (Expense)Hedge
                Activity -Oil
                and gas commodity derivatives
            
            **$**
            **(655**
            **)**
            **$**
            **-**
            
            **$**
            **-**
            
            $
            (533
            )
            $
            -
            
            $
            -
            
            $
            (215
            )
            $
            -
            
            $
            -Foreign
                currency derivatives
            
            
            **1**
            
            
            **(3**
            **)**
            
            **-**
            
            
            (1
            )
            
            10
            
            
            -
            
            
            -
            
            
            10
            
            
            -Interest
                rate swaps
            
            
            **-**
            
            
            **(4**
            **)**
            
            **-**
            
            
            -
            
            
            15
            
            
            -
            
            
            -
            
            
            11
            
            
            -Other
                derivatives
            
            
            **-**
            
            
            **8**
            
            
            **-**
            
            
            -
            
            
            1
            
            
            -
            
            
            -
            
            
            -
            
            
            -Gain
                (loss) on hedge ineffectiveness
            
            
            **(206**
            **)**
            
            **-**
            
            
            **-**
            
            
            4
            
            
            -
            
            
            -
            
            
            (1
            )
            
            -
            
            
            -Total
                hedging contracts
            
            
            **(860**
            **)**
            
            **1**
            
            
            **-**
            
            
            (530
            )
            
            26
            
            
            -
            
            
            (216
            )
            
            21
            
            
            -Nonhedge
                Activity -Oil
                and gas commodity derivatives -Kerr-McGee
                positions
            
            
            **75**
            
            
            **-**
            
            
            **-**
            
            
            (10
            )
            
            -
            
            
            1
            
            
            -
            
            
            -
            
            
            2Acquired
                Westport positions
            
            
            **(113**
            **)**
            
            **-**
            
            
            **-**
            
            
            (13
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Overhedge
                derivative loss
            
            
            **(119**
            **)**
            
            **-**
            
            
            **-**
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Gas
                marketing-related derivatives
            
            
            **6**
            
            
            **-**
            
            
            **-**
            
            
            7
            
            
            -
            
            
            (1
            )
            
            (7
            )
            
            -
            
            
            (5
            )DECS
                call option (1)
            
            
            **-**
            
            
            **-**
            
            
            **-**
            
            
            -
            
            
            -
            
            
            (101
            )
            
            -
            
            
            -
            
            
            (88
            )Foreign
                currency derivatives
            
            
            **-**
            
            
            **-**
            
            
            **3**
            
            
            -
            
            
            -
            
            
            (8
            )
            
            -
            
            
            -
            
            
            (7
            )Total
                nonhedge contracts
            
            
            **(151**
            **)**
            
            **-**
            
            
            **3**
            
            
            (16
            )
            
            -
            
            
            (109
            )
            
            (7
            )
            
            -
            
            
            (98
            )Total
                derivative contracts
            
            **$**
            **(1,011**
            **)**
            **$**
            **1**
            
            **$**
            **3**
            
            $
            (546
            )
            $
            26
            
            $
            (109
            )
            $
            (223
            )
            $
            21
            
            $
            (98
            )





(1)
            As
                discussed in Note 5, other income (expense) in 2004 and 2003 also
                includes
                unrealized gains on Devon stock classified as
                trading.





***Oil
      and Gas Commodity Derivatives*** - The
      company periodically enters into financial derivative instruments that generally
      fix the commodity prices to be received for a portion of its future sales of
      oil
      and natural gas produced. The fair value of the company’s oil and gas commodity
      derivative instruments was determined based on prices actively quoted, generally
      NYMEX prices.





*Hedge
      Ineffectiveness* - For
      the year ended December 31, 2005, as a result of significantly increased
      commodity prices and widening differentials between NYMEX forward prices and
      expected future oil and gas sales prices, the company recognized losses on
      hedge
      ineffectiveness of $206 million, associated with its commodity derivative
      instruments designated as hedges of future oil and gas sales. These losses
      represent the excess of mark-to-market losses on the company’s commodity
      derivatives over the higher cash flows expected to be realized upon sales of
      hedged production.





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





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








*Overhedge
      Derivative Loss* - As a
      result of two major hurricanes in the Gulf of Mexico late in the third quarter
      of 2005, the company’s physical deliveries to certain Gulf of Mexico sales
      indices in the third and fourth quarters of 2005 were insufficient to cover
      the
      associated derivative contracts in place. Consequently, the company recognized
      realized losses of $119 million in 2005 associated with certain derivative
      contracts in excess of hedged physical deliveries for 2005. Such losses are
      reported as overhedge derivative losses in revenues.





*Hedge
      Gains (Losses) in Equity* - At
      December 31, 2005, the net after-tax loss on oil and gas derivatives in
      accumulated other comprehensive loss relates to a portion of the company’s
      expected oil and gas sales through 2007. The company expects to reclassify
      $617
      million of the total net after-tax derivative loss from accumulated other
      comprehensive loss to earnings during the next 12 months, assuming no further
      changes in the fair value of the related contracts.





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





***Foreign
      Currency Derivatives*** - From
      time to time, the company enters into forward contracts to buy and sell foreign
      currencies. Certain of these contracts (purchases of Australian dollars and
      sales of euro) have been designated and have qualified as cash flow hedges
      of
      the company’s anticipated future cash flows related to pigment sales, raw
      material purchases and operating costs.





***Interest
      Rate Derivatives*** - From
      time to time, the company enters into interest rate swaps to hedge against
      changes in fair value of the related debt as a result of interest rate changes.
      The swaps are carried in the Consolidated Balance Sheet at their estimated
      fair
      value. Any unrealized gain or loss on the swaps is offset by a comparable gain
      or loss resulting from recording changes in the fair value of the related debt.
      Gains and losses on interest rate swaps, along with the changes in the fair
      value of the related debt, are reflected in interest and debt expense in the
      Consolidated Statement of Income. The critical terms of the swaps match the
      terms of the debt; therefore, the swaps are considered highly effective and
      no
      hedge ineffectiveness has been recognized.





**10. 
        Debt**





As
      discussed in Note 3, in November 2005, the company completed the IPO of Tronox
      Class A common stock. In March 2006, the Board of Directors approved the
      Distribution of Kerr-McGee’s remaining ownership interest in Tronox, which is
      expected to be completed before the end of the first quarter of 2006. Concurrent
      with the IPO, Tronox, through its wholly-owned subsidiaries, borrowed
      $550 million and entered into a senior secured credit agreement.





**Lines
      of Credit**





The
      following presents a summary of revolving credit facilities that served as
      a
      source of liquidity in 2005 and those that are currently in effect. No
      borrowings were outstanding under the revolving credit agreements at December
      31, 2005. Available capacity under the credit agreements presented below
      reflects capacity utilization in support of outstanding letters of
      credit.










Term
            Period
            Period
            Available
                CapacityRevolving
                Credit Facility
            (years)
            Effective
            Terminated
            at
                December 31, 2005*Kerr-McGee
                Corporation -*$1.5
                billion unsecured facility
            5
            November
                2004
            May
                2005
            -$1.25
                billion senior secured facility(1)
            5
            May
                2005
            January
                2006
            $1.18
                billion$1.25
                billion unsecured facility(2)
            5
            January
                2006
            Facility
                currently in effect
            -*Tronox
                Incorporated -*$250
                million senior secured facility(3)
            5
            November
                2005
            Facility
                currently in effect
            $216
                million





(1)
            The
                $1.25 billion secured credit facility was available to the company
                under
                the $5.5 billion credit agreement, which also included $4.25 billion
                in term loan facilities. As discussed below, the term loans were
                repaid in
                2005.




(2)
            Available
                capacity under this facility was $1.18 billion as of February 28,
                2006,
                reflecting capacity utilization in support of outstanding letters
                of
                credit.




(3)
            In
                November 2005, Tronox Incorporated and certain of its wholly-owned
                subsidiaries entered into a $450 million senior secured credit agreement
                which provides for a six-year term loan facility of $200 million
                (which
                was fully drawn at the time of the IPO) and a $250 million five-year
                multicurrency revolving credit
                facility.





The
      company has arrangements to maintain compensating balances with certain banks
      that provide credit. At year-end 2005, the aggregate amount of such compensating
      balances was not material, and the company was not legally restricted from
      withdrawing all or a portion of such balances at any time during the
      year.





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





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





·
            Consolidated
                Leverage Ratio of no more than 3.5:1


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


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





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





***Tronox’s
      $450 million Senior Secured Credit Agreement*** - In
      November 2005, Tronox entered into a senior secured credit facility consisting
      of a $200 million six-year term loan facility and a five-year multicurrency
      revolving credit facility of $250 million. Interest on amounts borrowed under
      the Tronox credit agreement is payable, at Tronox’s election, at a base rate or
      a LIBOR rate, in each case as defined in the Tronox credit agreement. The
      initial margin applicable to LIBOR borrowings is 175 basis points and may vary
      from 100 to 200 basis points depending on Tronox’s credit rating.





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





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


·
            Consolidated
                Interest Coverage Ratio of at least
                2:1


·
            Limitation
                on Capital Expenditures








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





**Long-Term
      Debt**





As
      more
      fully discussed below, in 2005, the company borrowed and repaid an aggregate
      of
      $4.25 billion under term loans. In February 2005, the company called for
      redemption all of the $600 million aggregate principal amount of its 5.25%
      convertible subordinated debentures due 2010 at a price of 102.625%. Prior
      to
      March 4, 2005, the redemption date, all of the debentures were converted by
      the
      holders into approximately 9.8 million shares of Kerr-McGee common stock. In
      February 2006, the company redeemed the 7% debentures due 2011 at face value
      of
      $250 million using cash on hand. In connection with the early redemption, a
      pretax loss of $69 million, representing a write-off of unamortized discount
      on
      the debentures, will be recognized in the first quarter of 2006. The following
      table presents the composition of long-term debt at December 31, 2005 and
      2004.





December
                31,(Millions
                of dollars)
            
            **2005**
            
            2004*Kerr-McGee
                Corporation -*Debentures5.25%
                Convertible subordinated debentures due February 15, 2010(convertible
                at $61.08 per share)
            
            **$**
            **-**
            
            $
            6007%
                Debentures due November 1, 2011, net of unamortizeddiscount
                of $70 and $77 (14.25% effective rate)(1)
            
            
            **180**
            
            
            1737.125%
                Debentures due October 15, 2027
            
            
            **150**
            
            
            150Notes
                payable5.375%
                Notes due April 15, 2005, including a premium of $4 in
                2004for
                fair value hedge adjustment
            
            
            **-**
            
            
            3548.125%
                Notes due October 15, 2005, net of a discount of $1 in
                2004for
                fair value hedge adjustment
            
            
            **-**
            
            
            1085.875%
                Notes due September 15, 2006, net of unamortized discountof
                $1 in 2005 (6.23% effective rate)
            
            
            **306**
            
            
            3076.625%
                Notes due October 15, 2007, net of discount of $5 and $2for
                fair value hedge adjustment
            
            
            **145**
            
            
            1486.875%
                Notes due September 15, 2011, net of unamortized discountof
                $4 and $1 (6.99% effective rate)
            
            
            **671**
            
            
            6746.95%
                Notes due July 1, 2024, net of unamortized discount of $12in
                2005 and $5 in 2004 (7.05% effective rate)
            
            
            **638**
            
            
            6457.875%
                Notes due September 15, 2031, net of unamortizeddiscount
                of $7 and $2 (7.93% effective rate)
            
            
            **493**
            
            
            498Commercial
                paper and other
            
            
            **-**
            
            
            42*Tronox
                Incorporated -*9.5%
                Notes due December 1, 2012
            
            
            **350**
            
            
            -Variable-rate
                term loan due in installments through November 28, 2011
            
            
            **200**
            
            
            -**3,133**
            
            
            3,699Long-term
              debt
              due within one year
            
            
            (308
            )
            
            (463
            )Total
            
            **$**
            **2,825**
            
            $
            3,236







The
      following summarizes the scheduled debt maturities as of December 31,
      2005:


There-(Millions
                  of dollars)
              
              2006
              
              2007
              
              2008
              
              2009
              
              2010
              
              after(1)
              
              Total
                  (2)Kerr-McGee
                  debt
              
              $
              306
              
              $
              145
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              2,132
              
              $
              2,583Tronox
                  debt
              
              
              2
              
              
              2
              
              
              2
              
              
              2
              
              
              2
              
              
              540
              
              
              550Total
                  long-term debt
              
              $
              308
              
              $
              147
              
              $
              2
              
              $
              2
              
              $
              2
              
              $
              2,672
              
              $
              3,133







(1)
            As
                discussed above, the 7% debentures due in 2011 were redeemed in February
                2006.




(2)
            These
                amounts include unamortized discount on issuance of $94 million and
                net
                fair value hedge adjustments of $5
                million.





***$5.5
      Billion Secured Credit Agreement*** - In
      May 2005, the company completed a self tender offer for its common stock for
      an
      aggregate cost of $4 billion. In connection with the tender offer, the company
      entered into a $5.5 billion secured credit agreement (Credit Agreement)
      consisting of a $2 billion two-year term loan (Tranche X), a $2.25 billion
      six-year term loan (Tranche B) and a $1.25 billion five-year revolving credit
      facility. The term loans were fully funded at closing, with proceeds used
      primarily to finance the tender offer and to pay fees and expenses associated
      with the Credit Agreement. While the Tranche X and Tranche B term loans were
      outstanding, the weighted average interest rates on the loans were 5.9% and
      6.2%, respectively. All borrowings under the Credit Agreement were repaid by
      the
      end of 2005 and the Credit Agreement was terminated on January 9, 2006.





Under
      the Credit Agreement, the company was subject to mandatory prepayment
      provisions, including required prepayments with 100% of the net cash proceeds,
      as defined, from asset disposals. The following provides information on
      repayments of the Tranche X and Tranche B term loans during 2005. As discussed
      in Note 2, as a result of this requirement, a portion of interest and debt
      expense associated with term loan borrowings was reflected in income from
      discontinued operations.





(Million
                of dollars)
            
            Mandatory
              Prepayment
            
            Optional
              Prepayment
            
            Total
            
            Debt
                Issue Costs Written Off*Transactions
                Resulting in Prepayments*-Sale
                of the North Sea oil and gas business
            
            $
            3,072
            
            $
            102
            
            $
            3,174
            
            $
            28Sale
                of nonoperating interest in gas processing facility
            
            
            111
            
            
            39
            
            
            150
            
            
            1Tronox
                initial public offering
            
            
            800
            
            
            120
            
            
            920
            
            
            9$
            3,983
            
            $
            261
            
            $
            4,244
            
            $
            38Scheduled
                principal payment
            
            
            
            
            
            
            
            
            6Total
                term loan repayments
            
            
            
            
            
            
            
            $
            4,250





In
      connection with the Credit Agreement, the company incurred financing costs
      of
      $58 million, which were initially capitalized and amortized as interest expense
      over the terms of the related facilities. Repayment of term loan borrowings
      earlier than scheduled resulted in writing off $38 million of debt issue costs
      during 2005. This charge is included in loss on early repayment and modification
      of debt in the Consolidated Statement of Income. The company will recognize
      an
      additional charge of $12 million in the first quarter of 2006 in connection
      with
      the termination of the Credit Agreement. This charge represents unamortized
      financing costs associated with the $1.25 billion revolving credit facility
      under the Credit Agreement.





***Modification
      to Guarantee Provisions*** -
      Prior
      to completing Tronox’s IPO, the company’s chemical business subsidiary, Tronox
      Worldwide LLC (formerly Kerr-McGee Chemical Worldwide LLC), was one of the
      guarantor subsidiaries of the company’s 5.875% Notes due 2006, 6.875% Notes due
      2011, 6.95% Notes due 2024 and 7.875% Notes due 2031 (collectively referred
      to
      herein as the Notes). In September 2005, the company received consent from
      a
      majority of the noteholders to amend the indenture governing the Notes. The
      supplemental indenture, which became effective as of September 21, 2005,
      provided for the release of Tronox Worldwide LLC as a guarantor of the Notes
      upon an IPO by Tronox Worldwide LLC, or upon a spinoff or splitoff of Tronox
      Worldwide LLC, or its parent, Tronox Incorporated. Upon completing the IPO,
      Tronox Worldwide LLC was released from its guaranty of the Notes. As a result
      of
      this modification to the indenture governing the Notes, the company paid
      aggregate consent and release fees to noteholders of $18 million, which were
      recorded as a reduction in the carrying value of the associated Notes and will
      increase interest expense over the remaining terms of the Notes. In connection
      with the consent solicitation, the company incurred transaction costs of $4
      million, which is included in loss on early repayment and modification of debt
      in the accompanying Consolidated Statement of Income.








**11. 
        Accounts Receivable Sales**





Through
      April 2005, the company had an accounts receivable monetization program with
      a
      maximum availability of $165 million. Under the terms of the program, selected
      qualifying customer accounts receivable arising from sales of titanium dioxide
      pigment by Tronox were sold monthly to a special-purpose entity (SPE), which
      in
      turn sold an undivided ownership interest in the receivables to a third-party
      multi-seller commercial paper conduit sponsored by an independent financial
      institution. Tronox sold, and retained an interest in, excess receivables to
      the
      SPE as over-collateralization for the program. The retained interest in sold
      receivables was subordinate to, and provided credit enhancement for, the
      conduit’s ownership interest in the SPE’s receivables, and was available to the
      conduit to pay certain fees or expenses due to the conduit, and to absorb credit
      losses incurred on any of the SPE’s receivables in the event of program
      termination. No recourse obligations were recorded since the company had no
      obligations for any recourse actions on the sold receivables. At December 31,
      2004, the outstanding balance of receivables sold (and excluded from the
      company’s Consolidated Balance Sheet as of that date) was $165 million, which
      was net of the company’s retained interest in receivables serving as
      over-collateralization of $39 million.





The
      accounts receivable monetization program included ratings downgrade triggers
      that provided for certain program modifications, including a program termination
      event upon which the program would effectively liquidate over time and the
      third-party multi-seller commercial paper conduit would be repaid with the
      collections on accounts receivable sold by the SPE. In April 2005, following
      the
      announcement of the self tender offer and the related increase in the company’s
      leverage discussed in Note 1, the company’s senior unsecured debt was
      downgraded, triggering program termination. As opposed to liquidating the
      program over time in accordance with its terms, the company entered into an
      agreement to terminate the program by repurchasing the then outstanding balance
      of receivables sold of $165 million. Repurchased accounts receivable were
      collected by the company later in 2005.





While
      the program was in effect in 2005 and during 2004 and 2003, the company sold
      $384 million, $1.1 billion and $836 million, respectively. The resulting
      losses are reflected as a component of other income (expense). The losses are
      equal to the difference in the book value of the receivables sold and the total
      of cash and the fair value of the deposit retained by the SPE.





**12. 
        Financial Instruments**





The
      company holds or issues financial instruments for other than trading purposes.
      Prior to 2005, the company invested in certain available for sale and trading
      securities, substantially all of which were disposed of by the end of 2004.
      Investments in marketable securities are classified as either “trading” or
“available for sale” depending on management’s intent and are carried in the
      Consolidated Balance Sheet at their estimated fair values based on quoted market
      prices. Unrealized gains or losses on trading securities are recognized in
      earnings, while unrealized gains or losses on available-for-sale securities
      are
      recorded as a component of other comprehensive income (loss) within
      stockholders’ equity. Realized gains and losses are determined using the average
      cost method and are reflected as a component of other income (expense) in the
      Consolidated Statement of Income. Discussion that follows provides information
      about debt exchangeable for common stock (DECS) which was redeemed using shares
      of Devon Energy Corporation common stock (Devon stock).







**DECS
      and Investment in Devon Stock**





The
      company issued 5.5% notes exchangeable for common stock (DECS) in August 1999,
      which allowed each holder to receive between .85 and 1.0 share of Devon common
      stock or, at the company’s option, an equivalent amount of cash at maturity in
      August 2004. Embedded options in the DECS provided the company a floor price
      on
      Devon’s common stock of $33.19 per share (the put option). The company also had
      the right to retain up to 15% of the shares if Devon’s stock price was greater
      than $39.16 per share (the DECS holders had an embedded call option on 85%
      of
      the shares). Using the Black-Scholes valuation model, the company estimated
      the
      fair value of the put and call options and recognized gains or losses resulting
      from changes in their fair value in other income (expense) in the Consolidated
      Statement of Income, along with the changes in the market value of Devon stock
      classified as trading. The company classified a portion of its Devon stock
      holdings necessary to repay the DECS as trading (8.4 million shares), with
      the remaining shares designated as available for sale.





***Available-for-Sale
      Securities*** - ****** Through
      January 2004, the company held shares of Devon stock considered to be available
      for sale. A portion of this investment was sold in December 2003, resulting
      in a
      gain of $17 million. The remaining shares were sold in January 2004 for a gain
      of $9 million. Proceeds from the December 2003 sales totaled $59 million
      ($47 million received in 2003 and $12 million received in 2004) and
      proceeds from the January 2004 sales totaled $27 million.





***Trading
      Securities and DECS Redemption*** - ****** Unrealized
      gains related to the company’s investment in Devon stock classified as trading
      amounted to $103 million in 2004 through the date of disposition and
      $96 million in 2003. These gains were partially offset by unrealized losses
      on the embedded options associated with the DECS of $101 million in 2004
      through the date of the DECS redemption, and $88 million in 2003.





On
      August 2, 2004, the company’s DECS matured and were settled with the
      distribution of shares of Devon stock, at which time the fair values of the
      embedded put and call options in the DECS were nil and $256 million,
      respectively, and the fair value of the 8.4 million shares of Devon stock was
      $586 million. The fair value of Devon stock less the call option liability
      resulted in a net asset carrying value of $330 million, which was offset
      exactly by the fair value of the DECS resulting in no gain or loss on redemption
      of the debt. The company recognized, as a component of other income (expense),
      a
      charge against earnings of $7 million related to a cumulative translation
      adjustment recorded prior to 1999 when the company accounted for its investment
      in Devon using the equity method. The proportionate share of Devon’s cumulative
      translation adjustment was removed from equity and reported in earnings in
      2004,
      when the liquidation of the associated investment occurred.





**Financial
      Instruments for Other than Trading Purposes**





At
      December 31, 2005 and 2004, the carrying amount and estimated fair value of
      financial instruments held or issued for other than trading purposes are as
      follows:





**2005**
            
            2004**Carrying**
            
            **Fair**
            
            Carrying
            
            Fair(Millions
                of dollars)
            
            **Amount**
            
            **Value**
            
            Amount
            
            ValueCash
                and cash equivalents
            
            **$**
            **1,053**
            
            **$**
            **1,053**
            
            $
            76
            
            $
            76Long-term
                debt
            
            
            **3,133**
            
            
            **3,414**
            
            
            3,699
            
            
            4,039





The
      carrying amount of cash and cash equivalents approximates fair value of those
      instruments due to their short maturity. The fair value of the company’s
      long-term debt is based on the quoted market prices for the same or similar
      debt
      issues or on the current rates offered to the company for debt with the same
      remaining maturity. Carrying values of derivative instruments, which reflect
      their estimated fair values, are presented in Note 9.







13. 
      **Income Taxes**


The
      2005, 2004 and 2003 income tax provision (benefit) from continuing operations
      are summarized below:





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003U.S.
                Federal -Current
            
            **$**
            **364**
            
            $
            26
            
            $
            (35
            )Deferred
            
            
            **45**
            
            
            83
            
            
            11**409**
            
            
            109
            
            
            (24
            )International
                -Current
            
            
            **46**
            
            
            12
            
            
            -Deferred
            
            
            **21**
            
            
            13
            
            
            6**67**
            
            
            25
            
            
            6State
            
            
            **11**
            
            
            3
            
            
            3Total
            
            **$**
            **487**
            
            $
            137
            
            $
            (15
            )





On
      October 22, 2004, the President of the United States signed the American Jobs
      Creation Act of 2004 (the “Act”) into law. A provision of the Act includes a one
      time dividends received deduction of 85% of certain foreign earnings that are
      repatriated, as defined in the Act. In 2005, management completed its analysis
      of the impact of the Act on the company’s plans for repatriation. Based upon
      this analysis, the company repatriated $231 million of qualifying foreign
      earnings in 2005 and recognized income tax expense of $9 million (net of foreign
      tax credits of $5 million).





In
      the
      following table, the U.S. federal income tax rate is reconciled to the company’s
      effective tax rates for income or loss from continuing operations as reflected
      in the Consolidated Statement of Income.





**2005**
            
            2004
            
            2003U.S.
                statutory tax rate
            
            
            **35.0**
            **%**
            
            35.0
            %
            
            35.0
            %Increases
                (decreases) resulting from -Charitable
                contribution
            
            
            **-**
            
            
            -
            
            
            (3.7
            )U.S.
                federal tax audit settlement
            
            
            **-**
            
            
            -
            
            
            (41.9
            )Adjustment
                of deferred tax balances dueto
                tax rate changes
            
            
            **(.2**
            **)**
            
            (1.0
            )
            
            -Taxation
                of foreign operations
            
            
            **(1.2**
            **)**
            
            1.4
            
            
            (2.0
            )State
                income taxes
            
            
            **.5**
            
            
            .5
            
            
            1.6Other
                - net
            
            
            **(.1**
            **)**
            
            (1.7
            )
            
            .3Effective
                tax rate
            
            
            **34.0**
            **%**
            
            34.2
            %
            
            (10.7
            )%








Taxation
      for a company with operations in several foreign countries involves many complex
      variables, such as tax structures that differ from country to country and the
      effect on U.S. taxation of international earnings. These complexities do not
      permit meaningful comparisons between the U.S. and international components
      of
      income before income taxes and the provision for income taxes, and disclosures
      of these components do not necessarily provide reliable indicators of
      relationships in future periods. Income from continuing operations before income
      taxes is comprised of the following:





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003United
                States
            
            **$**
            **1,209**
            
            $
            339
            
            $
            162International
            
            
            **225**
            
            
            62
            
            
            (22
            )Total
            
            **$**
            **1,434**
            
            $
            401
            
            $
            140








Net
      deferred tax liabilities at December 31, 2005 and 2004 are comprised of the
      following:





(Millions
                of dollars)
            
            **2005**
            
            2004Deferred
                tax liabilities -Property,
                plant and equipment
            
            **$**
            **1,914**
            
            $
            1,932Undistributed
                earnings of certain foreign subsidiaries
            
            
            **28**
            
            
            28Deferred
                state, local and other taxes
            
            
            **38**
            
            
            16Intangible
                assets
            
            
            **16**
            
            
            31Other
            
            
            **29**
            
            
            53Deferred
                tax liabilities of discontinued operations
            
            
            **-**
            
            
            518Total
                deferred tax liabilities
            
            
            **2,025**
            
            
            2,578Deferred
                tax assets -Net
                operating loss and other carryforwards
            
            
            **(33**
            **)**
            
            (201
            )Derivative
                instruments
            
            
            **(694**
            **)**
            
            (123
            )Asset
                retirement and environmental obligations
            
            
            **(201**
            **)**
            
            (149
            )Foreign
                exploration expenses
            
            
            **(59**
            **)**
            
            (83
            )Obligations
                for pension and other benefits
            
            
            **(47**
            **)**
            
            (28
            )Financial
                accruals and deferrals
            
            
            **(50**
            **)**
            
            (59
            )Other
            
            
            **(4**
            **)**
            
            (23
            )Deferred
                tax assets of discontinued operations
            
            
            **-**
            
            
            (67
            )**(1,088**
            **)**
            
            (733
            )Valuation
                allowance associated with loss carryforwards -- Continuing operations
            
            
            **6**
            
            
            6- Discontinued operations
            
            
            **-**
            
            
            2Net
                deferred tax assets
            
            
            **(1,082**
            **)**
            
            (725
            )Net
                deferred tax liability
            
            
            **943**
            
            
            1,853Less:
                net deferred tax liability of discontinued operations(1)
            
            
            **-**
            
            
            453Net
                deferred tax liability - continuing operations
            
            **$**
            **943**
            
            $
            1,400







(1)
            The
                net U.K. deferred tax liability associated with discontinued operations
                was assumed by the acquirer as part of the divestiture transaction
                discussed in Note 2 and, as such, was included in the carrying amount
                of
                the investment for purposes of calculating pretax gain on sale of
                the U.K.
                subsidiary.




At
      December 31, 2005, Tronox had a $7.5 million United States federal net operating
      loss carryforward. Such loss could not be utilized by Kerr-McGee due to Tronox’s
      status as a non-consolidated corporation for U.S. federal tax reporting
      following the November 2005 IPO. No valuation allowance has been provided for
      the net operating loss carryforward, as Tronox management expects to use the
      full amount of the loss carryforward in the 2006 Tronox federal income tax
      return.





At
      December 31, 2005, Tronox and its consolidated subsidiaries had foreign
      operating loss carryforwards totaling $158 million. Of this amount, $10 million
      expires in 2009, $21 million in 2011, $1 million in 2012 and $126 million has
      no
      expiration date. Realization of these operating loss carryforwards depends
      on
      generating sufficient taxable income in future periods. A valuation allowance
      of
      $6 million has been recorded to reduce deferred tax assets associated with
      loss
      carryforwards that the company does not expect to fully realize prior to
      expiration.





Undistributed
      earnings of certain consolidated foreign subsidiaries totaled $185 million
      and
      $115 million for Kerr-McGee and Tronox, respectively. No provision for deferred
      U.S. income taxes has been made for these earnings because they are considered
      to be indefinitely invested outside the United States. The distribution of
      these
      earnings in the form of dividends or otherwise, may subject the company to
      U.S.
      income taxes and, possibly, foreign withholding taxes. However, because of
      the
      complexities of U.S. taxation of foreign earnings, it is not practicable to
      estimate the amount of additional tax that might be payable on the eventual
      remittance of these earnings.








The
      Internal Revenue Service has completed its examination of the Kerr-McGee
      Corporation and subsidiaries' federal income tax returns for all years through
      2002 and is conducting an examination of the years 2003 and 2004. The years
      through 1996 have been closed with the exception of issues for which a refund
      claim has been filed. The Oryx Energy Company income tax returns have been
      examined through 1997, and the years through 1978 have been closed, as have
      the
      years 1988 through 1998. Oryx and Kerr-McGee merged in 1999. The company
      believes that it has made adequate provision for income taxes that may be
      payable with respect to open years.





***Tax
      Sharing Agreement and Tax Allocations*** -
      Kerr-McGee entered into a tax sharing agreement with Tronox that governs each
      party's respective rights, responsibilities and obligations subsequent to the
      IPO with respect to taxes for tax periods ending in 2005 and prior. Generally,
      taxes incurred or accrued prior to the IPO that are attributable to the business
      of one party will be borne solely by that party.





Kerr-McGee
      may incur certain restructuring taxes as a result of the Tronox separation.
      Under the tax sharing agreement, restructuring tax is any tax incurred as a
      result of any restructuring transaction undertaken to effectuate the Tronox
      separation, which in the judgment of the parties is currently required to be
      taken into account in determining the tax liability of Kerr-McGee or Tronox
      (or
      their respective subsidiaries) for any pre-IPO period. The tax sharing agreement
      provides that Kerr-McGee will be responsible for 100% of the restructuring
      taxes
      up to, but not to exceed, $17 million. In addition, Tronox is required to
      indemnify Kerr-McGee for any tax liability incurred by reason of the IPO and
      subsequent Distribution being considered a taxable transaction to Kerr-McGee
      as
      a result of a breach of any of Tronox’s representations, warranties, or
      covenants contained in the tax sharing agreement.





**14. 
        Exit, Disposal and Restructuring Activities**





The
      following table presents a reconciliation of the beginning and ending balances
      of reserves for exit and restructuring activities for the last three years,
      as
      well as charges not affecting reserve balances, such as accelerated depreciation
      of assets, asset impairments and benefit plan curtailment charges. Discussion
      of
      significant exit, disposal and restructuring activities is provided
      below.





Reserve
                Activity
            
            Other
                ActivityDismantlement
            
            Personnel
            
            
            
            Asset
            
            Benefit
            
            Total(Millions
                of dollars)
            
            and
                Closure
            
            Costs
            
            Total
            
            Write-downs
            
            Plan
                Charges
            
            ChargesBalance
                at December 31, 2002
            
            $
            23
            
            $
            4
            
            $
            27Provisions
                / Accruals
            
            
            12
            
            
            37
            
            
            49
            
            $
            20
            
            $
            48
            
            $
            117Payments
            
            
            (18
            )
            
            (16
            )
            
            (34
            )Adjustments(1)
            
            
            (5
            )
            
            2
            
            
            (3
            )
            
            
            
            
            
            
            
            (1
            )Balance
                at December 31, 2003
            
            
            12
            
            
            27
            
            
            39
            
            
            
            
            
            
            
            $
            116Provisions
                / Accruals
            
            
            17
            
            
            23
            
            
            40
            
            $
            114
            
            $
            6
            
            $
            160Payments
            
            
            (16
            )
            
            (40
            )
            
            (56
            )Adjustments(1)
            
            
            1
            
            
            (2
            )
            
            (1
            )
            
            
            
            
            
            
            
            (1
            )**Balance
                at December 31, 2004**
            
            
            **14**
            
            
            **8**
            
            
            **22**
            
            
            
            
            
            
            
            $
            159**Provisions
                / Accruals**
            
            
            **-**
            
            
            **29**
            
            
            **29**
            
            **$**
            **-**
            
            **$**
            **3**
            
            **$**
            **32****Payments**
            
            
            **(6**
            **)**
            
            **(15**
            **)**
            
            **(21**
            **)****Adjustments****(1)**
            
            
            **(2**
            **)**
            
            **(1**
            **)**
            
            **(3**
            **)**
            
            
            
            
            
            
            
            **(3**
            **)****Balance
                at December 31, 2005**
            
            **$**
            **6**
            
            **$**
            **21**
            
            **$**
            **27**
            
            
            
            
            
            
            
            **$**
            **29**Costs
                expected to be incurred inexcess of established reserves (2)
            
            $
            -
            
            $
            12
            
            $
            12Expected
                payments -2006
            
            $
            4
            
            $
            31
            
            $
            352007 and thereafter
            
            
            2
            
            
            2
            
            
            4





(1)
            Includes
                effects of foreign currency
                translation




(2)
            For
                certain employee severance and retention programs, the company recognizes
                provisions and associated reserves over the period when employee
                services
                necessary to earn the benefits are
                provided.







The
        following summarizes costs associated with exit, disposal and restructuring
        activities incurred in the last three years by each of the company's reportable
        segments and their classification in the company's financial statements
        (accruals for severance associated with the Westport merger were reflected
        in
        the purchase price allocation as an assumed liability):





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003*Costs
                and charges by reportable segment -*Exploration
                and production
            
            **$**
            **15**
            
            $
            1
            
            $
            14Chemical
                - pigment
            
            
            **(1**
            )
            
            129
            
            
            64Chemical
                - other
            
            
            **(2**
            **)**
            
            -
            
            
            2Corporate
                costs not allocated to segments
            
            
            **15**
            
            
            1
            
            
            19Subtotal
                - income from continuing operations
            
            
            **27**
            
            
            131
            
            
            99Costs
                reflected in income from discontinued operations (pretax)
            
            
            **2**
            
            
            10
            
            
            17Severance
                costs associated with the Westport merger
            
            
            **-**
            
            
            18
            
            
            -Total
            
            **$**
            **29**
            
            $
            159
            
            $
            116*Classification
                of costs and charges in income from continuing operations -*Costs
                and operating expenses
            
            **$**
            **-**
            
            $
            32
            
            $
            33Selling,
                general and administrative expenses
            
            
            **27**
            
            
            3
            
            
            48Depreciation
                and depletion
            
            
            **-**
            
            
            87
            
            
            15Asset
                impairments
            
            
            **-**
            
            
            7
            
            
            -Taxes
                other than income
            
            
            **-**
            
            
            1
            
            
            2Provision
                for environmental remediation andrestoration,
                net of reimbursements
            
            
            **-**
            
            
            1
            
            
            1Total
            
            **$**
            **27**
            
            $
            131
            
            $
            99





***Activities
      Initiated in 2005*** - **** As
      discussed in Note 1, in 2005, the company made a number of strategic decisions,
      including divestitures of its North Sea oil and gas business and selected oil
      and gas properties in the U.S. and the separation of Tronox. In April 2005,
      in
      connection with the planned exit activities, the company initiated employee
      retention programs with an aggregate cost of $34 million, designed to provide
      an
      incentive to certain employees to remain with the company over a
      stated period ranging from six to 18 months. Later in 2005, in connection
      with the Tronox separation, the company identified approximately 80 employees
      for involuntary termination by the end of 2006. The majority of these employees
      will receive severance payments and other benefits upon completion of a
      specified service period of up to 14 months, for an aggregate cost of $5
      million. Qualifying employees terminated under this program also will be
      eligible for enhanced benefits under the company's pension and postretirement
      plans.





***Activities
      Initiated in 2004*** - **** In
      2004, Tronox shut down its titanium dioxide pigment sulfate and gypsum
      production at its Savannah, Georgia, facility as a result of unacceptable
      financial returns for the facility due to declining demand and prices for
      sulfate anatase pigments, along with unanticipated environmental and
      infrastructure issues discovered after the facility was acquired in 2000. The
      Savannah facility’s work force of 410 was reduced by approximately 100
      positions. Tronox incurred an aggregate charge of $123 million in 2004
      associated with the shutdown.





***Activities
      Initiated in 2003*** - In
      September 2003, the company announced a program to reduce its U.S. nonbargaining
      work force through both voluntary retirements and involuntary terminations.
      As a
      result of the program, the company’s eligible U.S. nonbargaining work force was
      reduced by approximately 9%, or 271 employees. Qualifying employees terminated
      under this program were eligible for enhanced benefits under the company’s
      pension and postretirement plans, along with severance payments. The program
      was
      substantially complete by the end of 2003 and resulted in a charge of
      $56 million in 2003, of which $34 million was for curtailment and special
      termination benefits associated with the company’s retirement
      plans.





In
      June
      2003, Tronox closed its synthetic rutile plant in Mobile, Alabama. The plant
      processed and supplied a portion of the feedstock for Tronox’s titanium dioxide
      pigment plants in the United States. The plant was closed when the company
      identified opportunities to purchase the feedstock more economically than it
      could be manufactured at the Mobile plant. Tronox provided $61 million and
      $7
      million in 2003 and 2004, respectively, for costs associated with the plant
      closure. The Mobile plant closure will ultimately result in 127 employees being
      terminated, of which 112 were terminated by year-end 2005.








**15. 
        Employee Benefit Plans**





***Overview*** -
      Kerr-McGee is a sponsor of noncontributory defined-benefit retirement plans
      and
      contributory postretirement plans for health care and life insurance, in each
      case for the benefit of the company’s current and former employees in the U.S.
      Most U.S. employees are covered under the company’s retirement plans, and
      substantially all U.S. employees may become eligible for the postretirement
      benefits if they reach retirement age while working for the company.
      Additionally, certain foreign subsidiaries of Tronox sponsor contributory
      retirement plans in Germany and the Netherlands. As discussed in Note 3, under
      the provisions of the Employee Benefits Agreement between Kerr-McGee and Tronox,
      qualifying current and former U.S. employees of Tronox also participate in
      Kerr-McGee’s benefit plans through the date of the Distribution. Effects of the
      Distribution on defined-benefit plans sponsored by Kerr-McGee are discussed
      in
      more detail below. The measurement date used for all plans is December
      31.





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





***Benefit
      Obligations and Funded Status*** - ****** The
      following provides a reconciliation of benefit obligations, plan assets and
      funded status of the company’s pension and other postretirement plans as of and
      for the years ended December 31, 2005 and 2004. The following table excludes
      information associated with the U.K. retirement plan sponsored by the company’s
      North Sea oil and gas business that was sold in 2005, as discussed in Note
      2. At
      December 31, 2004, the projected benefit obligation and the fair value of plan
      assets for the U.K. retirement plan were $88 million and $79 million,
      respectively. Assets held for sale in the company’s Consolidated Balance Sheet
      as of December 31, 2004 include prepaid pension cost of $23 million associated
      with this plan.







PostretirementRetirement
                Plans
            
            Health
                and Life Plans(Millions
                of dollars)
            
            **2005**
            
            2004
            
            **2005**
            
            2004*Change
                in benefit obligations -*Benefit
                obligation, beginning of year
            
            **$**
            **1,172**
            
            $
            1,175
            
            **$**
            **276**
            
            $
            314Service
                cost
            
            
            **32**
            
            
            26
            
            
            **3**
            
            
            3Interest
                cost
            
            
            **66**
            
            
            68
            
            
            **16**
            
            
            18Plan
                amendments/law changes(1)
            
            
            **-**
            
            
            1
            
            
            **-**
            
            
            (72
            )Net
                actuarial loss
            
            
            **84**
            
            
            91
            
            
            **24**
            
            
            38Foreign
                currency rate changes
            
            
            **(11**
            **)**
            
            6
            
            
            **-**
            
            
            -Contributions
                by plan participants
            
            
            **-**
            
            
            -
            
            
            **9**
            
            
            9Special
                termination benefits, settlementand
                curtailment (gains) losses
            
            
            **3**
            
            
            (1
            )
            
            **-**
            
            
            -Benefits
                paid
            
            
            **(91**
            **)**
            
            (194
            )
            
            **(31**
            **)**
            
            (34
            )Benefit
                obligation, end of year
            
            
            **1,255**
            
            
            1,172
            
            
            **297**
            
            
            276*Change
                in plan assets -*Fair
                value of plan assets, beginning of year
            
            
            **1,168**
            
            
            1,239
            
            
            **-**
            
            
            -Actual
                return on plan assets
            
            
            **54**
            
            
            102
            
            
            **-**
            
            
            -Employer
                contributions(2)
            
            
            **9**
            
            
            16
            
            
            **22**
            
            
            25Participant
                contributions
            
            
            **-**
            
            
            -
            
            
            **9**
            
            
            9Foreign
                currency rate changes
            
            
            **(8**
            **)**
            
            5
            
            
            **-**
            
            
            -Benefits
                paid
            
            
            **(91**
            **)**
            
            (194
            )
            
            **(31**
            **)**
            
            (34
            )Fair
                value of plan assets, end of year(3)
            
            
            **1,132**
            
            
            1,168
            
            
            **-**
            
            
            -Funded
                status of plans - under funded
            
            
            **(123**
            **)**
            
            (4
            )
            
            **(297**
            **)**
            
            (276
            )*Amounts
                not recognized in the Consolidated**Balance
                Sheet -*Prior
                service costs
            
            
            **42**
            
            
            49
            
            
            **(14**
            **)**
            
            (16
            )Net
                actuarial loss
            
            
            **282**
            
            
            159
            
            
            **80**
            
            
            59Net
                prepaid expense (accrued liability) recognized
            
            **$**
            **201**
            
            $
            204
            
            **$**
            **(231**
            **)**
            $
            (233
            )*Classification
                of amounts recognized in the**Consolidated Balance Sheet -*Prepaid
                pension cost
            
            **$**
            **249**
            
            $
            239
            
            **$**
            **-**
            
            $
            -Accrued
                benefit liability
            
            
            **(79**
            **)**
            
            (55
            )
            
            **(231**
            **)**
            
            (233
            )Accumulated
              other comprehensive loss (pretax)
            
            
            31
            
            
            20
            
            
            -
            
            
            -Total
            
            **$**
            **201**
            
            $
            204
            
            **$**
            **(231**
            **)**
            $
            (233
            )








(1)
            The
                2004 reduction in the postretirement benefit obligation related to
                plan
                amendments/law changes of $72 million is primarily the result of the
                company’s adoption of FASB Staff Position (FSP) FAS 106-2, “Accounting and
                Disclosure Requirements Related to the Medicare Prescription Drug,
                Improvement and Modernization Act of 2003” and a November 1, 2004 plan
                change causing prescription drug coverage provided by the company’s U.S.
                postretirement health and life plan to become secondary to Medicare
                Part D
                coverage.




(2)
            During
                2005, the company made a discretionary contribution of approximately
                $7
                million to the Netherlands trust fund to increase plan assets above
                the
                accumulated benefit obligation level. The company expects 2006
                contributions to be $5 million for the U.S. nonqualified plans, $21
                million for the U.S. postretirement plans and approximately $2 million
                for
                the foreign retirement plans. No contributions are expected in 2006
                for
                the U.S. qualified retirement plan.




(3)
            Excludes
                the grantor trust assets of $50 million at year-end 2005 and 2004
                associated with the company’s supplemental nonqualified U.S. plans. In
                January 2006, the company made an additional $22 million discretionary
                contribution to the grantor
                trust.





The
      following table summarizes the accumulated benefit obligations and the projected
      benefit obligations associated with the company’s unfunded benefit
      plans.





**At
                December 31, 2005**
            
            At
                December 31, 2004U.S.
            
            U.S.
            
            Germany
            
            U.S.
            
            U.S.
            
            GermanyNonqualified
            
            Postretirement
            
            Retirement
            
            Nonqualified
            
            Postretirement
            
            Retirement(Millions
                of dollars)
            
            Plans(1)
            
            Plan
            
            Plan
            
            Plans(1)
            
            Plan
            
            PlanAccumulated
                benefit obligation
            
            **$**
            **65**
            
            **$**
            **297**
            
            **$**
            **13**
            
            $
            37
            
            $
            276
            
            $
            12Projected
                benefit obligation
            
            
            **80**
            
            
            **297**
            
            
            **14**
            
            
            55
            
            
            276
            
            
            13





(1)
            Although
                not considered plan assets, a grantor trust was established from
                which
                payments for certain U.S. supplemental benefits are made. The trust
                assets
                had a balance of $50 million at year-end 2005 and 2004. In January
                2006,
                the company made and additional $22 million discretionary contribution
                to
                the grantor trust.





Summarized
      below are the accumulated benefit obligation, the projected benefit obligation,
      the market value of plan assets and the funded status of the company’s funded
      retirement plans.





**At
                December 31, 2005**
            
            At
                December 31, 2004U.S.
            
            The
                Netherlands
            
            U.S.
            
            The
                NetherlandsQualified
            
            Retirement
            
            Qualified
            
            Retirement(Millions
                of dollars)
            
            Plan
            
            Plan
            
            Plan
            
            PlanAccumulated
                benefit obligation
            
            **$**
            **990**
            
            **$**
            **59**
            
            $
            941
            
            $
            61Projected
                benefit obligation
            
            **$**
            **1,093**
            
            **$**
            **68**
            
            $
            1,034
            
            $
            70Market
                value of plan assets
            
            
            **1,070**
            
            
            **62**
            
            
            1,109
            
            
            59Funded
                status - (under)/over funded
            
            **$**
            **(23**
            **)**
            **$**
            **(6**
            **)**
            $
            75
            
            $
            (11
            )





***Expected
      Benefit Payments*** -
      Following are the expected benefit payments for the next five years and in
      the
      aggregate for the years 2011 through 2015:





2011-(Millions
                of dollars)
            
            2006
            
            2007
            
            2008
            
            2009
            
            2010
            
            2015Retirement
                Plans
            
            $
            92
            
            $
            102
            
            $
            90
            
            $
            94
            
            $
            97
            
            $
            478Postretirement
                Health and Life Plans
            
            
            21
            
            
            21
            
            
            21
            
            
            21
            
            
            21
            
            
            106





For
      the
      retirement plans that qualify under the Employee Retirement Income Security
      Act
      of 1974 (ERISA), the benefit amount that can be provided to employees by the
      plans is limited by both ERISA and the Internal Revenue Code. Therefore, the
      company has unfunded supplemental nonqualified plans designed to maintain
      benefits for all employees at the plan formula level and to provide senior
      executives with benefits equal to a specified percentage of their final average
      compensation.





***Net
      Periodic Cost*** -
      Income from continuing operations for 2005, 2004 and 2003 includes the following
      components of net periodic cost:





PostretirementRetirement
                Plans
            
            Health
                and Life Plans(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003
            
            **2005**
            
            2004
            
            2003Net
                periodic cost -Service
                cost
            
            **$**
            **32**
            
            $
            26
            
            $
            22
            
            **$**
            **3**
            
            $
            3
            
            $
            3Interest
                cost
            
            
            **66**
            
            
            68
            
            
            70
            
            
            **16**
            
            
            18
            
            
            16Expected
                return on plan assets
            
            
            **(99**
            **)**
            
            (113
            )
            
            (119
            )
            
            **-**
            
            
            -
            
            
            -Special
                termination benefits, settlementand
                curtailment losses
            
            
            **3**
            
            
            14
            
            
            30
            
            
            **-**
            
            
            -
            
            
            10Net
                amortization -Prior
                service cost
            
            
            **8**
            
            
            8
            
            
            9
            
            
            **(2**
            **)**
            
            1
            
            
            -Net
                actuarial (gain) loss
            
            
            **5**
            
            
            1
            
            
            (10
            )
            
            **3**
            
            
            2
            
            
            -Total
            
            **$**
            **15**
            
            $
            4
            
            $
            2
            
            **$**
            **20**
            
            $
            24
            
            $
            29







Net
      periodic pension cost for the year ended December 31, 2005 includes special
      termination benefits resulting from an involuntary termination program initiated
      by the company in October 2005. The 2004 net periodic cost includes special
      termination benefit and curtailment costs associated with the shutdown of
      sulfate production at the Savannah, Georgia, facility and plan settlement losses
      related to normal retirements and retirements resulting from the work force
      reduction program initiated in 2003. The 2003 net periodic cost includes special
      termination benefit and curtailment costs associated with the shutdown of
      Tronox’s Mobile, Alabama facility and curtailment costs associated with the 2003
      work force reduction program.





***Assumptions*** -
      The
      following weighted average assumptions were used to determine the net periodic
      cost:





**2005**
            
            2004
            
            2003**United**
            
            
            
            United
            
            
            
            United**States**
            
            **International**
            
            States
            
            International
            
            States
            
            InternationalDiscount
                rate
            
            
            **5.75**
            **%**
            
            **4.75**
            **%**
            
            6.25
            %(1)
            
            5.29
            %
            
            6.75
            %
            
            5.55
            %Expected
                return onplan
                assets
            
            
            **8.25**
            
            
            **5.50**
            
            
            8.50
            
            
            5.75
            
            
            8.50
            
            
            5.75Rate
                of compensationincreases
            
            
            **4.50**
            
            
            **3.42**
            
            
            4.50
            
            
            2.81
            
            
            4.50
            
            
            2.55





(1)
            Following
                remeasurement at July 1, 2004 to recognize a settlement for the qualified
                plan, the discount rate for the qualified plan was 6.5% for the remainder
                of the year.





The
      following assumptions were used in estimating the actuarial present value of
      the
      plans’ benefit obligations:





**2005**
            
            2004
            
            2003**United**
            
            
            
            United
            
            
            
            United**States**
            
            **International**
            
            States
            
            International
            
            States
            
            InternationalDiscount
                rate
            
            
            **5.50**
            **%**
            
            **4.25**
            **%**
            
            5.75
            %
            
            4.75
            %
            
            6.25
            %
            
            5.29
            %Rate
                of compensationincreases
            
            
            **4.50**
            
            
            **3.42**
            
            
            4.50
            
            
            3.42
            
            
            4.50
            
            
            2.81





In
      forming the assumption of the U.S. long-term rate of return, the company takes
      into account the expected earnings on funds already invested, earnings on
      contributions expected to be received in the current year, and earnings on
      reinvested returns. The long-term rate of return estimation methodology for
      U.S.
      plans is based on a capital asset pricing model using historical data. An
      expected return analysis is performed which incorporates the current portfolio
      allocation, historical asset-class returns and an assessment of expected future
      performance using asset-class risk factors. Our assumption of the long-term
      rate
      of return for the Netherlands plan is developed considering the portfolio mix
      and country-specific economic data that includes the rates of return on local
      government and corporate bonds.





The
      company selects a discount rate for its U.S. qualified plan and its
      postretirement plan using the results of a cash flow matching analysis based
      on
      projected cash flows for the plans. For foreign plans, the company bases the
      discount rate assumption on local corporate bond index rates.





The
      health care cost trend rates used to determine the year-end 2005 postretirement
      benefit obligation were 10% in 2006, gradually declining to 5% in 2012 and
      thereafter. A 1% increase in the assumed health care cost trend rate for each
      future year would increase the postretirement benefit obligation at December
      31,
      2005 by $14 million, while the aggregate of the service and interest cost
      components of the 2005 net periodic postretirement cost would increase by $1
      million. A 1% decrease in the trend rate for each future year would reduce
      the
      benefit obligation at year-end 2005 by $12 million and decrease the aggregate
      of
      the service and interest cost components of the net periodic postretirement
      cost
      for 2005 by $1 million.







***Plan
      Assets*** -
      Asset categories for the company’s funded retirement plans and the associated
      asset allocations by category at December 31, 2005 and 2004 are as
      follows:





The
                NetherlandsU.S.
                Plan Assets
            
            Plan
                Assetsat
                December 31,
            
            at
                December 31,**2005**
            
            2004
            
            **2005**
            
            2004Equity
                securities
            
            
            **55**
            **%**
            
            57
            %
            
            **28**
            **%**
            
            24
            %Debt
                securities
            
            
            **42**
            
            
            41
            
            
            **63**
            
            
            76Cash
                and cash equivalents
            
            
            **3**
            
            
            2
            
            
            **9**
            
            
            -Total
            
            
            **100**
            **%**
            
            100
            %
            
            **100**
            **%**
            
            100
            %





The
      U.S. plan is administered by a board-appointed committee that has fiduciary
      responsibility for the plan’s management. The committee maintains an investment
      policy stating the guidelines for the performance and allocation of plan assets,
      performance review procedures and updating of the policy. At least annually,
      the
      U.S. plan’s asset allocation guidelines are reviewed in light of evolving risk
      and return expectations. Current guidelines permit the committee to manage
      the
      allocation of funds between equity and debt securities within the range of
      40-60% equity securities and 40-60% debt securities.





Substantially
      all of the plan’s assets are invested with eight equity fund managers and six
      fixed-income fund managers. At year-end 2005 and 2004, equity securities held
      by
      the plan included $5 million and $3 million of Kerr-McGee stock,
      respectively, or 50,737 shares. Dividends paid on these shares were less than
      $100,000 in 2005 and 2004. To control risk, equity fund managers are prohibited
      from entering into the following transactions, (i) investing in commodities,
      including all futures contracts, (ii) purchasing letter stock, (iii) short
      selling and (iv) option trading. In addition, equity fund managers are
      prohibited from purchasing on margin and are prohibited from purchasing
      Kerr-McGee securities. Equity managers are monitored to ensure investments
      are
      in line with their style and are generally permitted to invest in U.S. common
      stock, U.S. preferred stock, U.S. securities convertible into common stock,
      common stock of foreign companies listed on major U.S. exchanges, common stock
      of foreign companies listed on foreign exchanges, covered call writing, and
      cash
      and cash equivalents.





Fixed-income
      fund managers are prohibited from investing in (i) direct real estate mortgages
      or commingled real estate funds, (ii) private placements above certain portfolio
      thresholds, (iii) tax exempt debt of state and local governments above certain
      portfolio thresholds, (iv) fixed income derivatives that would cause leverage,
      (v) guaranteed investment contracts, and (vi) Kerr-McGee securities. They are
      permitted to invest in debt securities issued by the U.S. government, its
      agencies or instrumentalities, commercial paper rated A3/P3, FDIC insured
      certificates of deposit or bankers acceptances, and corporate debt obligations.
      Each fund manager’s portfolio should have an average credit rating of A or
      better.





The
      Netherlands plan is administered by a pension committee representing the
      employer, the employees and the pensioners, each with one equal vote. The
      pension committee members are approved by the state’s lead pension agency based
      upon experience and character. The pension committee meets at least quarterly
      to
      discuss regulatory changes, asset performance and asset allocation. The plan
      assets are managed by one Dutch fund manager against a mandate set at least
      annually by the pension committee. The plan assets are evaluated annually by
      a
      multinational benefits consultant against state defined actuarial tests to
      determine funding requirements.





**16. 
        Contingencies**


***Effect
      of Tronox Separation*** - As
      discussed in Note 3, in 2005, Kerr-McGee transferred to Tronox the subsidiaries
      holding and operating Kerr-McGee’s chemical business and completed the IPO of
      Tronox Class A common stock. The company expects to distribute its remaining
      56.7% ownership interest in Tronox to Kerr-McGee’s stockholders in March 2006.








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





Because
      Tronox is a consolidated subsidiary of Kerr-McGee as of December 31, 2005,
      the
      Consolidated Balance Sheet reflects Tronox’s liabilities for environmental
      remediation and restoration costs that are probable and estimable. The
      accompanying financial statements do not include any effects of the
      reimbursement obligation discussed above between the parties within the
      consolidated group. It is expected that upon completion of the Distribution,
      Tronox will no longer be a consolidated subsidiary of Kerr-McGee, at which
      time
      Kerr-McGee will recognize a liability associated with its reimbursement
      obligation. The liability will initially be measured at its estimated fair
      value.





The
      following table presents December 31, 2005 balances of reserves for
      environmental and legal contingencies and the related reimbursements receivable
      from the U.S. government and insurers.





Reserves
                forLegal
            
            Environmental
            
            Reimbursements(Millions
                of dollars)
            
            Reserves
            
            Remediation
            
            ReceivableTronox
            
            $
            9
            
            $
            224
            
            $
            57Other
                Kerr-McGee
            
            
            21
            
            
            44
            
            
            -Balance
                at December 31, 2005
            
            $
            30
            
            $
            268
            
            $
            57





***Overview*** - The
      following table summarizes the reserve balances, provisions, payments and
      settlements for 2003, 2004 and 2005 associated with environmental and legal
      contingencies, as well as balances, accruals and receipts of reimbursements
      of
      environmental costs from other parties.








Reserves
                forLegal
            
            Environmental
            
            Reimbursements(Millions
                of dollars)
            
            Reserves
            
            Remediation(1)
            
            ReceivableBalance
                at December 31, 2002
            
            $
            73
            
            $
            258
            
            $
            113Provisions
                / Accruals
            
            
            8
            
            
            94
            
            
            32Payments
                / Settlements
            
            
            (44
            )
            
            (104
            )
            
            (15
            )Balance
                at December 31, 2003
            
            
            37
            
            
            248
            
            
            130Provisions
                / Accruals(2)
            
            
            15
            
            
            106
            
            
            14Payments
                / Settlements
            
            
            (13
            )
            
            (99
            )
            
            (50
            )**Balance****at
                December 31, 2004**
            
            
            **39**
            
            
            **255**
            
            
            **94****Provisions
                / Accruals**
            
            
            **9**
            
            
            **84**
            
            
            **35****Payments
                / Settlements**
            
            
            **(18**
            **)**
            
            **(71**
            **)**
            
            **(72**
            **)****Balance
                at December 31, 2005**
            
            **$**
            **30**
            
            **$**
            **268**
            
            **$**
            **57**





(1)
            Provisions
                for environmental remediation and restoration in 2005, 2004 and 2003
                include $11 million, $6 million and $2 million, respectively, related
                to
                Tronox’s former forest products operations. These charges are reflected
                in
                the Consolidated Statement of Income as a component of income from
                discontinued operations (net of tax).




(2)
            The
                2004 accruals for litigation include a $7 million increase in the
                reserve
                upon Kerr-McGee’s assumption of contingent obligations in connection with
                the Westport merger.







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





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





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




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




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




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




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




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




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




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




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





Current
      and former operations of the company and its affiliates require the management
      of regulated materials and are subject to various environmental laws and
      regulations. These laws and regulations will obligate the company to clean
      up
      various sites at which petroleum and other hydrocarbons, chemicals, low-level
      radioactive substances and/or other materials have been contained, disposed
      of
      or released. Some of these sites have been designated Superfund sites by the
      U.S. Environmental Protection Agency (EPA) pursuant to the Comprehensive
      Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) or
      state equivalents. Similar environmental laws and regulations and other
      requirements exist in foreign countries in which the company operates. Following
      are discussions regarding certain environmental sites and litigation of Tronox
      and its subsidiaries, as well as discussions of other Kerr-McGee sites and
      matters.








**Contingencies
      of Tronox**





*Environmental*





**Henderson,
      Nevada**





In
      1998, Tronox LLC (formerly Kerr-McGee Chemical LLC) decided to exit the ammonium
      perchlorate business. At that time, Tronox LLC curtailed operations and began
      preparation for the shutdown of the associated production facilities in
      Henderson, Nevada, that produced ammonium perchlorate and other related
      products. Manufacture of perchlorate compounds began at Henderson in 1945 in
      facilities owned by the U.S. government. The U.S. Navy expanded production
      significantly in 1953 when it completed construction of a plant for the
      manufacture of ammonium perchlorate. The Navy continued to own the ammonium
      perchlorate plant as well as other associated production equipment at Henderson
      until 1962, when the plant was purchased by a predecessor of the company. The
      ammonium perchlorate produced at the Henderson facility was used primarily
      in
      federal government defense and space programs. Perchlorate that may have
      originated, at least in part, from the Henderson facility has been detected
      in
      nearby Lake Mead and the Colorado River, which contribute to municipal water
      supplies in Arizona, Southern California and Southern Nevada.




Tronox
      LLC began decommissioning the facility and remediating associated perchlorate
      contamination, including surface impoundments and groundwater, when it decided
      to exit the business in 1998. In 1999 and 2001, Tronox LLC entered into consent
      orders with the Nevada Division of Environmental Protection (NDEP) that require
      it to implement both interim and long-term remedial measures to capture and
      remove perchlorate from groundwater. In April 2005, Tronox LLC entered into
      an amended consent order with NDEP that requires, in addition to the capture
      and
      treatment of groundwater, the closure of a certain impoundment related to the
      past production of ammonium perchlorate, including treatment and disposal of
      solution and sediment contained in the impoundment.  An agreement with NDEP
      requires Tronox LLC to test for various potential contaminants at the site,
      which is ongoing.




In
      1999, Tronox LLC initiated the interim measures required by the consent orders.
      A long-term remediation system is operating in compliance with the consent
      orders. Initially, the remediation system was
      projected to operate through 2007. However, studies of the decline of
      perchlorate levels in the groundwater now indicate that Tronox LLC may need
      to
      operate the system through 2011. The scope, duration and cost of groundwater
      remediation likely will be driven in the long term by drinking water standards
      regarding perchlorate, which to date have not been formally established by
      applicable state or federal regulatory authorities. EPA and other federal and
      state agencies continue to evaluate the health and environmental risks
      associated with perchlorate as part of the process for ultimately setting
      drinking water standards. One state agency, the California Environmental
      Protection Agency (CalEPA), has set a public health goal for perchlorate, and
      the federal EPA has established a reference dose for perchlorate, which are
      preliminary steps to setting drinking water standards. The establishment of
      drinking water standards could materially affect the scope, duration and cost
      of
      the long-term groundwater remediation that Tronox LLC is required to perform.




***Financial
      Reserves*** - ****** As
      of
      December 31, 2005, reserves for environmental remediation at Henderson
      totaled $37  million.
      This includes $32  million
      added to the reserve in 2005 because of increased costs for removing and
      treating ammonium perchlorate solids contained in a lined pond, purchasing
      additional equipment to perform cleanup and extending the projected operating
      period of the groundwater remediating system through 2011. As noted above,
      the
      long-term scope, duration and cost of groundwater remediation and impoundment
      closure are uncertain and, therefore, additional costs beyond those accrued
      may
      be incurred in the future. However, the amount of any additional costs cannot
      be
      reasonably estimated at this time.




***Litigation*** - In
      2000, Tronox LLC initiated litigation against the United States seeking
      contribution for its Henderson response costs. The suit was based on the fact
      that the government owned the plant in the early years of its operation,
      exercised significant control over production at the plant and the sale of
      products produced at the plant, even while not the owner, and was the largest
      consumer of products produced at the plant. Before trial, the parties agreed
      to
      a settlement of the claims against the United States. The settlement was
      memorialized in a consent decree approved by the court on January 13, 2006.
      Under the consent decree, the United States will pay Tronox LLC approximately
      $21 million in contribution for past costs and, commencing January 1, 2011,
      the
      United States will be obligated to pay 21% of Tronox LLC’s remaining response
      costs at Henderson, if any, related to perchlorate. In the first quarter of
      2006, Tronox LLC recognized a receivable for environmental cost reimbursement
      of
      $21 million pursuant to the consent decree provisions. The receivable was
      collected in February 2006.







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




At
      December 31, 2005, Tronox LLC had received $6  million
      of cost reimbursement under the insurance policy, and expects additional
      estimated aggregate cleanup costs of $92 million less the $61  million
      self-insured retention to be covered by the policy (for a net amount of
      $31  million
      in additional reimbursement, including $22  million
      accrued in 2005).
      The company believes that additional reimbursement of $31million
      is probable, and, accordingly, the company has recorded a receivable in the
      financial statements for that amount.







**West
      Chicago, Illinois**




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




***Closed
      Facility*** -
      Pursuant to agreements reached in 1994 and 1997 among Tronox LLC, the City
      of
      West Chicago (the City) and the State regarding the decommissioning of the
      closed West Chicago facility, Tronox LLC has substantially completed the
      excavation of contaminated soils and has shipped those soils to a licensed
      disposal facility. Surface restoration was completed in 2004, except for areas
      designated for use in connection with the Kress Creek and Sewage Treatment
      Plant
      remediation discussed below. Groundwater monitoring and remediation is expected
      to continue for approximately ten years.




***Vicinity
      Areas*** - EPA
      has listed four areas in the vicinity of the closed West Chicago facility on
      the
      NPL and has designated Tronox LLC as a Potentially Responsible Party (PRP)
      in
      these four areas. Tronox LLC has substantially completed remedial work for
      two
      of the areas (known as the Residential Areas and Reed-Keppler Park). The other
      two NPL sites, known as Kress Creek and the Sewage Treatment Plant, are
      contiguous and involve low levels of insoluble thorium residues, principally
      in
      streambanks and streambed sediments, virtually all within a floodway. Tronox
      LLC
      has reached an agreement with the appropriate federal and state agencies and
      local communities regarding the characterization and cleanup of the sites,
      past
      and future government response costs, and the waiver of natural resource damages
      claims. The agreement is incorporated in consent decrees, which were approved
      and entered by the federal court in August 2005. The cleanup work, which
      began in the third quarter of 2005, is expected to take about four to five
      years
      to complete and will require excavation of contaminated soils and stream
      sediments, shipment of excavated materials to a licensed disposal facility
      and
      restoration of affected areas.




***Financial
      Reserves*** - ****** As
      of
      December 31, 2005, the company had reserves of $87  million
      for costs related to the West Chicago facility and vicinity properties. This
      includes approximately $12  million
      added to the reserve in 2005 as a result of additional volumes of contaminated
      materials being identified at the Kress Creek site and the agreement described
      above requiring the company to reimburse local communities for certain cleanup
      costs. Although actual costs may differ from current estimates, the amount
      of
      any revisions in remediation costs cannot be reasonably estimated at this time.
      The amount of the reserve is not reduced by reimbursements expected from the
      federal government under Title X of the Energy Policy Act of 1992 (Title
      X) (discussed below).




***Government
      Reimbursement*** - ****** Pursuant
      to Title X, the U.S. Department of Energy (DOE) is obligated to reimburse Tronox
      LLC for certain decommissioning and cleanup costs incurred in connection with
      the West Chicago sites in recognition of the fact that about 55% of the
      facility's production was dedicated to U.S. government contracts. The amount
      authorized for reimbursement under Title X is $365 million plus inflation
      adjustments. That amount is expected to cover the government's
      full share of West Chicago cleanup costs. Through December 31, 2005, Tronox
      LLC had been reimbursed approximately $281million
      under Title X.







Reimbursements
      under Title X are provided by congressional appropriations. Historically,
      congressional appropriations have lagged the company's cleanup expenditures.
      As
      of December 31, 2005, the government's share of costs incurred by Tronox
      LLC but not yet reimbursed by the DOE totaled approximately $26 million,
      which includes $13  million
      accrued in 2005. The company believes receipt of the $26  million
      government share in due course following additional congressional appropriations
      is probable and has reflected that amount as a receivable in the financial
      statements. The company will recognize recovery of the government's share of
      future remediation costs for the West Chicago sites as it incurs the cash
      expenditures.






**Ambrosia
      Lake, New Mexico**




From
      the late 1950s until 1988, an affiliate of Tronox Worldwide LLC (formerly
      Kerr-McGee Chemical Worldwide LLC) operated a uranium mining and milling
      operation at Ambrosia Lake near Grants, New Mexico, pursuant to a license issued
      by the Atomic Energy Commission (AEC) (now the Nuclear Regulatory Commission
      (NRC)). When the operation was sold, Tronox Worldwide LLC retained
      responsibility for certain environmental conditions existing at the site,
      including mill tailings, selected ponds and groundwater contamination related
      to
      the mill tailings and unlined ponds. Since 1989, the unaffiliated current owner
      of the site, Rio Algom Mining LLC (Rio Algom), has been decommissioning the
      site
      pursuant to the license issued by NRC. Mill tailings, certain impacted surface
      soils, and selected pond sediments have been consolidated in an onsite
      containment unit, and groundwater treatment has been ongoing. Under terms of
      the
      sales agreement, which included provisions capping the liability of Rio Algom,
      Tronox Worldwide LLC became obligated to solely fund the remediation for the
      items described above when total expenditures exceeded $30 million, which
      occurred in late 2000. A request to cease groundwater treatment has been under
      review by the NRC since 2001. In addition, a decommissioning plan for remaining
      impacted soil was submitted by Rio Algom to the NRC in January 2005, and is
      currently under review. If approved, the soil decommissioning plan would take
      two to three years to complete. The State of New Mexico has recently raised
      issues about certain nonradiological constituents in the groundwater at the
      site. The request to cease groundwater treatment, which is being reviewed by
      the
      NRC, was amended to address these nonradiological constituents. Discussions
      regarding these issues are ongoing, and resolution of them could affect
      remediation costs and/or delay ultimate site closure.




In
      addition to those remediation activities described above for which reserves
      have
      been established as described below, Rio Algom is investigating soil
      contamination potentially caused by past discharge of mine water from the site,
      for which no reserve has been established.




***Financial
      Reserves*** - ****** As
      of
      December 31, 2005, the company had reserves of $11  million
      for the costs of the remediation activities described above, including
      groundwater remediation. This includes $8  million
      added to the reserve in 2005, as a result of the discussions between Rio Algom
      and the NRC, and primarily to cover additional costs associated with pond
      closure, rock placement, and surface water channels. Although actual costs
      may
      differ from current estimates, the amount of any revisions in remediation costs
      cannot be reasonably estimated at this time.





***Litigation*** - On
      January 18, 2006, Rio Algom filed suit against Tronox Worldwide LLC in the
      U.S.
      District Court for the District of New Mexico. The suit seeks a determination
      regarding responsibility for certain labor-related and environmental remediation
      costs. The parties have discussed submitting the dispute to binding arbitration
      and negotiations regarding arbitration are ongoing. The company has not provided
      a reserve for this lawsuit because at this time it cannot reasonably determine
      the probability of a loss, and the amount of loss, if any, cannot be reasonably
      estimated. The ultimate resolution of the litigation is not expected to have
      a
      material adverse effect on the company.





**Milwaukee,
      Wisconsin**





In
      1976, Tronox LLC closed a wood-treatment facility it had operated in Milwaukee,
      Wisconsin. Operations at the facility prior to its closure had resulted in
      the
      contamination of soil and groundwater at and around the site with creosote
      and
      other substances used in wood treating. In 1984, EPA designated the Milwaukee
      wood-treatment facility as a Superfund site under CERCLA, listed the site on
      the
      NPL and named Tronox LLC as a PRP. Tronox LLC executed a consent decree in
      1991
      that required it to perform soil and groundwater remediation at and below the
      former wood-treatment area and to address a tributary creek of the Menominee
      River that had become contaminated as a result of the wood-treatment operations.
      Actual remedial activities were deferred until after the decree was finally
      entered in 1996 by a federal court in Milwaukee.







Groundwater
      treatment was initiated in 1996 to remediate groundwater contamination below
      and
      in the vicinity of the former wood-treatment area. It is not possible to
      reliably predict how groundwater conditions will be affected by soil removal
      in
      the vicinity of the former wood-treatment area, which has been completed, and
      by
      ongoing groundwater treatment. It is unknown, therefore, how long groundwater
      treatment will continue. Soil cleanup of the former wood-treatment area began
      in
      2000 and was completed in 2002. Also in 2002, remedial designs for the upper
      portion of the tributary creek were agreed to with EPA, after which Tronox
      LLC
      began the implementation of a remedy to reroute the creek and to remediate
      associated sediment and stream bank soils. Remediation of the upper portion
      of
      the creek is expected to take about three more years. Tronox LLC has not yet
      agreed with relevant regulatory authorities regarding remedial designs for
      the
      lower portion of the tributary creek.




***Financial
      Reserves*** - As
      of December 31, 2005, the company had reserves of $4  million
      for the costs of the remediation work described above. Although actual costs
      may
      differ from current estimates, the amount of any revisions in remediation costs
      cannot be reasonably estimated at this time. The costs associated with
      remediation, if any, of the lower portion of the tributary creek are not
      reasonably estimable.






**New
      Jersey Wood-Treatment Site**




Tronox
      LLC was named in 1999 as a PRP under CERCLA at a former wood-treatment site
      in
      New Jersey at which EPA is conducting a cleanup. On April 15, 2005, Tronox
      LLC and Tronox Worldwide LLC received
      a letter from EPA asserting that they are liable under CERCLA as a former owner
      or operator of the site and demanding reimbursement of costs expended by EPA
      at
      the site. The letter made demand for payment of past costs in the amount of
      approximately $179 million, plus interest, though EPA has informed Tronox
      LLC that it expects final project costs will be approximately $236 million,
      plus
      possible other costs and interest. Tronox LLC did not operate the site, which
      had been sold to a third party before Tronox LLC succeeded to the interests
      of a
      predecessor owner in the 1960's. The predecessor also did not operate the site,
      which had been closed down before it was acquired by the predecessor. Based
      on
      historical records, there are substantial uncertainties about whether or under
      what terms the predecessor assumed liabilities for the site. In addition,
      although it appears there may be other PRPs, the company does not know whether
      the other PRPs have received similar letters from EPA, whether there are any
      defenses to liability available to the other PRPs or whether the other PRPs
      have
      the financial resources necessary to meet their obligations. By letter dated
      December 15, 2005, EPA advised that it currently does not intend to seek
      reimbursement of response costs from Tronox Worldwide LLC, though it still
      seeks
      reimbursement of response costs from Tronox LLC. The company intends to
      vigorously defend against EPA's demand, though the company expects to have
      discussions with EPA that could lead to a settlement or resolution of the EPA
      demand. No reserve for reimbursement of cleanup costs at the site has been
      recorded because it is not possible to reliably estimate the liability, if
      any,
      the company may have for the site because of the aforementioned defenses and
      uncertainties.







**Cushing,
      Oklahoma**




In
      1972, Triple S Refining Corporation (Triple S), an affiliate of Tronox, closed
      a
      petroleum refinery it had operated near Cushing, Oklahoma. Prior to closing
      the
      refinery, Triple S also had produced uranium and thorium fuel and metal at
      the
      site pursuant to licenses issued by the AEC.





In
      1990, Triple S entered into a consent agreement with the State of Oklahoma
      to
      investigate the site and take appropriate remedial actions related to petroleum
      refining and uranium and thorium residuals. Investigation and remediation of
      hydrocarbon contamination is being performed under the oversight of the Oklahoma
      Department of Environmental Quality. Remediation to address hydrocarbon
      contamination in soils is expected to take about four more years. The long-term
      scope, duration and cost of groundwater remediation are uncertain and,
      therefore, additional costs beyond those accrued may be incurred in the future.





In
      1993, Triple S received a decommissioning license from the NRC, the successor
      to
      AEC's licensing authority, to perform certain cleanup of uranium and thorium
      residuals. All
      known radiological contamination has been removed from the site and shipped
      to a
      licensed disposal facility, substantially completing the license requirements.





***Financial
      Reserves*** - ****** As
      of
      December 31, 2005, the company had reserves of $12  million
      for the costs of the ongoing remediation and decommissioning work described
      above. Although actual costs may differ from current estimates, the amount
      of
      any revisions in remediation costs cannot be reasonably estimated at this time.







*Litigation
      and Claims*





**Forest
      Products Litigation**





Between
      December 31, 2002 and May 2, 2005, approximately 250 lawsuits (filed
      on behalf of approximately 5,100 claimants) were filed against Tronox LLC in
      connection with the former wood-treatment plant in Columbus, Mississippi.
      Substantially all of these lawsuits are pending in the U.S. District Court
      for
      the Northern District of Mississippi and have been consolidated for pretrial
      and
      discovery purposes. In addition, a suit filed by the Maranatha Faith Center
      against Tronox LLC and Tronox Worldwide LLC on February 18, 2000, relates to
      the
      former wood-treatment plant in Columbus and is pending in the Circuit Court
      of
      Lowndes County, Mississippi. Between December 31, 2002 and June 25,
      2004, three lawsuits (filed on behalf of approximately 3,300 claimants) were
      filed against Tronox LLC in connection with a former wood-treatment plant
      located in Hattiesburg, Mississippi. These lawsuits were removed to the U.S.
      District Court for the Southern District of Mississippi. Between
      September 9, 2004 and December 28, 2005, four lawsuits (filed on behalf of
      69 claimants) were filed against Tronox LLC in connection with a former
      wood-treatment plant located in Texarkana, Texas. Two of the Texarkana lawsuits
      that were filed in Oklahoma (on behalf of 30 claimants) have been dismissed
      on
      jurisdictional grounds. Between January 3, 2005 and July 26, 2005, 35
      lawsuits (filed on behalf of approximately 4,600 claimants) were filed against
      Tronox LLC and Tronox Worldwide LLC in connection with the former wood-treatment
      plant in Avoca, Pennsylvania. All of these lawsuits seek recovery under a
      variety of common law and statutory legal theories for personal injuries and/or
      property damages allegedly caused by exposure to and/or release of creosote,
      a
      chemical used in the wood-treatment process.




In
      2003, Tronox LLC entered into a settlement agreement that resolved approximately
      1,490 of the Hattiesburg claims, which resulted in aggregate payments by Tronox
      LLC of approximately $600,000. In December 2005, Tronox LLC entered into
      settlement agreements to resolve up to 1,335 of the remaining Hattiesburg claims
      and up to 879 of the Columbus claims. The December 2005 settlement agreements
      require Tronox LLC to pay up to $2.5 million, of which $2 million was paid
      in
      December 2005. In addition, all of the remaining Hattiesburg claims have
      been dismissed without prejudice on the bases of failure to pay filing fees
      and
      failure to disclose information in compliance with court orders. The company
      currently believes that the unresolved claims relating to the Columbus,
      Hattiesburg, Texarkana and Avoca plants are without substantial merit and is
      vigorously defending against them.





***Financial
      Reserves*** - As
      of December 31, 2005, the company had reserves of $7  million
      related to forest products litigation. Although actual costs may differ from
      the
      current estimates, the amount of any revisions in litigation costs cannot be
      reasonably estimated at this time. The company currently believes that the
      ultimate resolution of the forest products litigation is not likely to have
      a
      material adverse effect on the company.





**Kemira**





In
      2000, Tronox LLC acquired its titanium dioxide production facility in Savannah,
      Georgia, from Kemira Pigments Oy, a Finnish company, and its parent, Kemira
      Oyj
      (together, "the Sellers"). After acquiring the facility, the company discovered
      that certain matters associated with environmental conditions and plant
      infrastructure were not consistent with representations made by the Sellers.
      The
      company sought recovery for breach of representations and warranties in a
      proceeding before the London Court of International Arbitration (LCIA). On
      May 9, 2005, the Company received notice from the LCIA that the LCIA had
      found in favor of the company as to liability with respect to certain of the
      claims. The LCIA still must determine the amount of damages, a hearing with
      respect to which has been scheduled for late May 2006. The company currently
      cannot reasonably estimate the amount of damages that will be awarded. The
      company will recognize a receivable, if and when damages are awarded and all
      contingencies associated with any recovery are resolved.




*Other
      Sites and Matters*





In
      addition to the environmental sites described above, Tronox and/or its
      affiliates are responsible for environmental costs related to certain other
      sites. These sites relate primarily to wood-treating, chemical production,
      landfills, mining, and oil and gas refining, distribution and marketing. As
      of
      December 31, 2005, the company and its affiliates had reserves of $73 million
      for the environmental costs in connection with these other sites. This amount
      includes $20 million added to reserves in 2005 for additional costs estimated
      at
      various of these other sites. Although actual costs may differ from current
      estimates, the amount of any revisions in remediation costs cannot be reasonably
      estimated at this time.








The
      company and its affiliates are parties to a number of legal and administrative
      proceedings involving disputes with federal, state and private parties,
      environmental matters and/or other matters pending in various courts or
      agencies. Some of these proceedings are associated with facilities currently
      or
      previously owned, operated or used by the company and/or its predecessors,
      some
      of which include claims for personal injuries, property damages, cleanup costs
      and other environmental matters. These proceedings, individually and in the
      aggregate, are not expected to have a material adverse effect on the
      company.





**Other
      Contingencies of Kerr-McGee**





**Los
      Angeles County, California**





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





***Financial
      Reserves*** -
      As of
      December 31, 2005, environmental reserves for this project totaled
      $23 million. This includes approximately $5 million added to the reserve in
      2005 as a result of identifying additional contaminated locations in the field.
      Although actual costs may differ from current estimates, the amount of any
      revisions in remediation costs cannot be reasonably estimated at this
      time.




*Other
      Sites and Matters*





**Deepwater
      Royalty Relief Act**





In
      1995, the United States Congress passed the Deep Water Royalty Relief Act
      (DWRRA) to stimulate exploration and production of oil and natural gas in the
      deepwater Gulf of Mexico by providing relief from the obligation to pay royalty
      on certain federal leases. In January 2006, the Department of the Interior
      (DOI)
      ordered Kerr-McGee Oil and Gas Corporation (KMOG) to pay oil and gas royalties
      and accrued interest on certain of KMOG’s deepwater Gulf of Mexico production
      for which KMOG believes royalties are suspended under the DWRRA. DOI issued
      the
      Order to Pay based on the assertion that DOI has the discretion to suspend
      royalty relief under the DWRRA with respect to the subject leases when oil
      and
      gas prices reach certain levels specified by DOI. KMOG believes that DOI does
      not have the authority to suspend royalty relief on the subject leases and,
      accordingly, intends to contest the Order to Pay and vigorously defend against
      DOI’s claim for additional royalties. The company has recorded reserves for the
      full amount of the DOI claim, including interest. As of December 31, 2005,
      reserves for royalties and interest potentially payable to the DOI totaled
      $108
      million.





**Other**





In
      addition to the site in Los Angeles County described above, Kerr-McGee and/or
      its affiliates are responsible for environmental costs related to certain other
      sites where exploration and production activities where conducted. As of
      December 31, 2005, the company and its affiliates had reserves of
      $21 million for the environmental costs in connection with these other
      sites. This amount includes $7 million added to reserves in 2005 for
      additional costs estimated at various of these sites. Although actual costs
      may
      differ from current estimates, the amount of any revisions in remediation costs
      cannot be reasonably estimated at this time.





Kerr-McGee
      and its affiliates are parties to a number of legal and administrative
      proceedings involving the False Claims Act and other royalty-related claims
      and
      disputes with federal, state and private parties, environmental matters and/or
      other matters pending in various courts or agencies. Some of these proceedings
      are associated with facilities currently or previously owned, operated or used
      by the company and/or its predecessors, some of which include claims for
      personal injuries, property damages, cleanup costs and other environmental
      matters. These proceedings, individually and in the aggregate, are not expected
      to have a material adverse effect on the company.







**17.** **Commitments**





***Lease
      Obligations and Guarantees*** **** - **** The
      company has various commitments under noncancelable operating lease agreements,
      principally for office space, production and gathering facilities and other
      equipment. The company also has entered into operating lease agreements for
      the
      use of the Nansen, Boomvang and Gunnison spar platforms located in the Gulf
      of
      Mexico. Aggregate minimum annual rentals under all operating leases (including
      the platform leases in effect at December 31, 2005), total $807 million, of
      which $85 million is due in 2006, $66 million in 2007, $65 million in 2008,
      $54
      million in 2009, $42 million in 2010 and $495 million thereafter. Total lease
      rental expense was $98 million in 2005, $84 million in 2004 and $65 million
      in 2003.





The
      company has guaranteed that the Nansen, Boomvang and Gunnison platforms will
      have residual values at the end of the operating leases equal to at least 10%
      of
      the fair value of the platform at the inception of the lease. For Nansen and
      Boomvang, the guaranteed values are $14 million and $8 million, respectively,
      in
      2022, and for Gunnison the guarantee is $15 million in 2024.





Under
      the terms of the Master Separation Agreement, Kerr-McGee agreed to reimburse
      Tronox for a portion of the environmental costs incurred and paid by Tronox
      and
      its subsidiaries prior to November 28, 2012. Additional information about this
      reimbursement obligation is provided in Note 16.





During
      2003 and 2002, the company entered into sale-leaseback arrangements with General
      Electric Capital Corporation (GECC) covering assets associated with a
      gas-gathering system in the Wattenberg field. The 2002 operating lease
      agreements have an initial term of five years, with two 12-month renewal
      options, and the company may elect to purchase the equipment at specified
      amounts after the end of the fourth year. The 2003 operating lease agreement
      has
      an initial term of four years, with two 12-month renewal options. In the event
      the company does not purchase the equipment and it is returned to GECC, the
      company may be required to make payments in connection with residual value
      guarantees ranging from $35 million at the end of the initial terms to $27
      million at the end of the last renewal option. The company recorded no gain
      or
      loss associated with the GECC sale-leaseback agreements. The future minimum
      annual rentals due under noncancelable operating leases shown above include
      payments related to these agreements.





In
      connection with certain contracts and agreements, the company has entered into
      indemnifications related to title claims, environmental matters, litigation
      and
      other claims. The company has recorded no material obligations in connection
      with its indemnification agreements.





***Purchase
      Obligations*** - In
      the normal course of business, the company enters into contractual agreements
      to
      purchase raw materials, pipeline capacity, utilities and other services.
      Aggregate future payments under these contracts total $1.484 billion, of which
      $481 million is expected to be paid in 2006, $337 million in 2007, $255 million
      in 2008, $161 million in 2009, $109 million in 2010, and $141 million
      thereafter.





***Drilling
      Rig Commitments*** **** -
      During the normal course of business, the company enters into arrangements
      to
      participate in the use of various drilling rigs. The commitment with respect
      to
      these arrangements totals up to $749 million, depending on partner utilization,
      of which $226 million is expected to be paid in 2006, $392 million in 2007,
      $36
      million in 2008, $26 million in 2009, $26 million in 2010, and $43 million
      thereafter. Subsequent to December 31, 2005, the company entered into additional
      agreements totaling $19 million, of which $6 million is due in 2006, $8 million
      is due in 2007 and $5 million is due in 2008.





***Letters
      of Credit and Other*** - **** At
      December 31, 2005, outstanding letters of credit totaled $114 million (including
      $34 million issued by Tronox). Most of these letters of credit have been granted
      by financial institutions to support international drilling commitments,
      environmental remediation activities and insurance agreements. As of February
      28, 2006, outstanding letters of credit totaled $144 million, which included
      $40
      million associated with Tronox.








**18. 
      Capital Stock**




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





As
      discussed in Note 1, in March 2005, the company’s Board of Directors authorized
      a share repurchase program initially set at $1 billion, with an expectation
      to expand
      the program as the chemical business separation proceeded. Before terminating
      this program in
      connection with the Board’s approval of the tender offer discussed below, the
      company repurchased 3.1 million shares of its common stock in the open market
      at
      an aggregate cost of $250 million. Shares repurchased under this program are
      held in treasury.





On
      April 18, 2005, the company commenced a tender offer to repurchase 43.5 million
      shares of its common stock at a price not lower than $85 or higher than $92
      per
      share. The company exercised its right to increase the number of shares
      purchased pursuant to the tender offer by 3.2 million shares, which resulted
      in
      repurchasing 46.7 million shares of common stock at $85 per share, for an
      aggregate cost of approximately $4 billion (including transaction costs of
      approximately $3 million). All of the shares repurchased under the tender
      offer were retired immediately. The cost of the repurchase was financed with
      a
      portion of the net proceeds of the borrowings under the Credit Agreement
      discussed in Note 10 and cash on hand.





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





Changes
      in common stock issued and treasury stock held for 2005, 2004 and 2003 are
      as
      follows:





Common
            
            Treasury(Thousands
                of shares)
            
            Stock
            
            StockBalance
                at December 31, 2002
            
            
            100,391
            
            
            7Stock
                option exercises
            
            
            18
            
            
            -Issuance
                of restricted stock
            
            
            483
            
            
            -Forfeiture
                of restricted stock
            
            
            -
            
            
            25Balance
                at December 31, 2003
            
            
            100,892
            
            
            32Shares
                issued in Westport merger
            
            
            48,949
            
            
            -Stock
                option exercises
            
            
            1,725
            
            
            -Issuance
                of restricted stock
            
            
            483
            
            
            -Forfeiture
                of restricted stock
            
            
            -
            
            
            128Balance
                at December 31, 2004
            
            
            **152,049**
            
            
            **160**Stock
                option exercises
            
            
            **4,078**
            
            
            **-**Issuance
                of restricted stock
            
            
            **452**
            
            
            **-**Forfeiture
                of restricted stock
            
            
            **-**
            
            
            **152**Shares
                issued upon conversion of 5.25% debentures
            
            
            **9,818**
            
            
            **-**Purchases
                of treasury shares
            
            
            **-**
            
            
            **3,145**Shares
                repurchased and retired
            
            
            **(46,728**
            **)**
            
            **-**Balance
                at December 31, 2005
            
            
            **119,669**
            
            
            **3,457**





There
      are 1,107,692 shares of the company’s common stock registered in the name of a
      wholly-owned subsidiary of the company. These shares are not included in the
      number of shares shown in the preceding table or in the Consolidated Balance
      Sheet. These shares are not entitled to be voted.







***Preferred
      Share Purchase Rights Plan*** ** -
      The
      company has had a stockholders’ rights plan since 1986. The current rights plan
      is dated July 26, 2001, and replaced the previous plan prior to its expiration.
      Rights were distributed as a dividend at the rate of one right for each share
      of
      the company’s common stock and continue to trade together with each share of
      common stock. Generally, the rights become exercisable the earlier of 10 days
      after a public announcement that a person or group has acquired, or a tender
      offer has been made for, 15% or more of the company’s then-outstanding stock. If
      either of these events occurs, each right would entitle the holder (other than
      a
      holder owning more than 15% of the outstanding stock) to buy the number of
      shares of the company’s common stock having a market value two times the
      exercise price. The exercise price is $215. Generally, the rights may be
      redeemed at $.01 per right until a person or group has acquired 15% or more
      of
      the company’s stock. The rights expire in July 2006.





**19. 
        Employee Stock-Based Compensation Plans**


***Overview*** - The
      2005 Long-Term Incentive Plan (Plan) authorizes the issuance of shares of the
      company’s common stock to certain employees and non-employee directors any time
      prior to May 10, 2015, in the form of fixed-price stock options, restricted
      stock or performance awards. The options may be accompanied by stock
      appreciation rights. A total of 10 million shares of the company’s common stock
      is authorized to be issued under the Plan, of which a maximum of 3 million
      shares of common stock is authorized for issuance in connection with awards
      of
      restricted stock and performance awards to employees. The Plan also includes
      certain limitations on the size of awards to an individual employee and to
      non-employee directors as a group. Subject to these limits, a committee of
      the
      Board of Directors administering the Plan (Committee) determines the size and
      types of awards to be issued.





The
      maximum period for exercise of an option granted under the Plan may not be
      more
      than ten years from the date the grant is authorized by the Committee and the
      exercise price may not be less than the fair value of the shares underlying
      the
      option on the grant authorization date. Performance awards may be granted in
      the
      form of performance shares or performance units, with performance period of
      no
      less than one year. Subject to the Plan provisions, the Committee determines
      the
      terms of the awards, such as dates on which the awards become fully vested
      and,
      for performance awards, performance period and performance goal(s) to be
      achieved to receive a specified benefit from the award.





At
      December 31, 2005, approximately 10 million shares of Kerr-McGee stock were
      available to be granted under the Plan. Prior to the approval of the Plan by
      the
      company’s stockholders, stock-based awards were granted under similar plans, all
      of which have been terminated. Although no more awards can be issued under
      those
      plans, their termination had no effect on awards previously issued and
      outstanding.





Stock-based
      awards granted by the company to its employees and non-employee directors during
      the last three years generally had the following terms:





Contractual
            Vesting
            
            
            Cash-
                orLife
            Period
            Vesting
            
            Stock-
            Vesting
                and Other(years)
            (years)
            Term
            
            Settled
            ConditionsStock
                options
            10
            3
            Graded
            (1)
            Stock
            Employee
                serviceRestricted
                stock
            not
                applicable
            3
            Cliff
            (2)
            Stock
            Employee
                servicePerformance
                units(3)
            3
            3
            Cliff
            (2)
            Cash
            Employee
                service andachievement of specifiedstockholder return
              targets





(1)
            An
                employee vests in one third of the award at the end of each year
                of
                service.




(2)
            An
                employee vests in the entire award at the end of the three-year service
                period.




(3)
            Performance
                unit awards provide an employee with a potential cash payment at
                the end
                of a three-year performance cycle based on Kerr-McGee's total stockholder
                return (stockholder return assuming dividend reinvestment) relative
                to
                selected peer companies. Payout levels vary depending upon Kerr-McGee's
                rank relative to its peers.







The
      following summarizes stock-based compensation expense recognized in income
      from
      continuing operations for the years ended December 31, 2005, 2004 and 2003,
      determined based on the intrinsic value of the awards. As discussed in Note
      1,
      as a result of implementing a new accounting standard effective January 1,
      2006,
      stock-based compensation expense in future periods will be based on the fair
      value of the awards.





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Stock
                options
            
            **$**
            **9**
            
            $
            1
            
            $
            -Restricted
                stock
            
            
            **22**
            
            
            15
            
            
            10Performance
                units
            
            
            **19**
            
            
            2
            
            
            -Total
            
            **$**
            **50**
            
            $
            18
            
            $
            10





***Effect
      of Tronox Separation*** - As
      provided in the Employee Benefits Agreement between Kerr-McGee and Tronox,
      except for vested stock options and performance unit awards, Kerr-McGee
      stock-based awards held by Tronox employees at the date of the Distribution
      will
      be forfeited and replaced with stock-based awards of comparable value issued
      by
      Tronox. The conversion ratio will be determined on the effective date of the
      Distribution based on the relative values of Kerr-McGee common stock and Tronox
      Class A common stock. Generally, Tronox employees holding vested options to
      purchase Kerr-McGee common stock as of the date of the Distribution may exercise
      such options for the lesser of three months after the effective date of the
      Distribution or the remaining term of the option award. Vested options not
      exercised during the specified time period will expire.





***Restricted
      Stock*** - The
      following summarizes information about shares of restricted stock granted during
      the last three years:





**2005**
            
            2004
            
            2003Restricted
                shares granted
            
            
            **452,000**
            
            
            483,000
            
            
            483,000Weighted
                average grant-date fair value per share
            
            **$**
            **68.80**
            
            $
            49.97
            
            $
            43.18





At
      December 31, 2005, 1.2 million unvested shares of restricted stock were
      outstanding. In the first quarter of 2006, the company granted 241,000
      additional shares with an estimated grant-date fair value per share of $98.58.
      Approximately 92,000 shares of Kerr-McGee’s restricted stock held by Tronox
      employees at December 31, 2005 are expected to be forfeited, as discussed
      under *Effect of Tronox Separation* above.





***Performance
      Units*** -
      The
      following summarizes information about the company's performance unit awards
      for
      2005, 2004 and 2003:




**2005**
            
            2004
            
            2003Performance
                units granted during the year
            
            
            **16,274,800**
            
            
            11,061,700
            
            
            11,331,000Performance
                units outstanding at year-end
            
            
            **33,545,679**
            
            
            19,151,627
            
            
            10,809,000Per-unit
                liability at year-end
            
            **$**
            **.63**
            
            $
            .11
            
            $
            -





At
      December 31, 2005, the carrying value of the company's aggregate liability
      for
      performance units was $21 million, $8 million of which was paid to eligible
      employees in January 2006. In the first quarter of 2006, the company granted
      an
      additional 17 million performance units to its employees. The terms of
      performance units issued in 2006 are consistent with previously issued awards.
      It is expected that approximately 2.5 million performance units held by Tronox
      employees as of December 31, 2005 will be forfeited, as discussed above under *Effect
      of Tronox Separation* .







***Stock
      Options*** - The
      following table summarizes the stock option transactions during 2005, 2004
      and
      2003 under Kerr-McGee’s compensation plans and in connection with the Westport
      merger. As discussed in Note 4, on June 25, 2004, the company completed its
      merger with Westport. In connection with the merger, the company exchanged
      Westport options outstanding as of the merger date for Kerr-McGee options based
      on the exchange factor set forth in the merger agreement.





**2005**
            
            2004
            
            2003**Options**
            
            **Price********(1)**
            
            Options
            
            Price(1)
            
            Options
            
            Price(1)Outstanding,
                beginning of year
            
            
            **7,516,655**
            
            **$**
            **53.63**
            
            
            6,418,719
            
            $
            56.02
            
            
            5,406,424
            
            $
            59.27Issued
                in Westport merger
            
            
            **-**
            
            
            **-**
            
            
            1,901,988
            
            
            29.55
            
            
            -
            
            
            -Granted
            
            
            **1,663,490**
            
            
            **56.57**
            
            
            1,385,536
            
            
            49.45
            
            
            1,353,100
            
            
            42.93Exercised
            
            
            **(4,077,929**
            **)**
            
            **55.36**
            
            
            (1,744,179
            )
            
            32.42
            
            
            (18,500
            )
            
            44.55Forfeited
            
            
            **(288,637**
            **)**
            
            **52.39**
            
            
            (183,545
            )
            
            47.26
            
            
            (189,638
            )
            
            55.35Expired
            
            
            **(14,455**
            **)**
            
            **57.93**
            
            
            (261,864
            )
            
            60.99
            
            
            (132,667
            )
            
            57.78Outstanding,
                end of year
            
            
            **4,799,124**
            
            
            **53.21**
            
            
            7,516,655
            
            
            53.63
            
            
            6,418,719
            
            
            56.02Exercisable,
                end of year
            
            
            **2,103,823**
            
            
            **54.59**
            
            
            4,636,210
            
            
            56.89
            
            
            3,382,550
            
            
            59.81





(1)
            Represents
                weighted average exercise price.





The
      following table summarizes information about stock options issued under the
      plans described above that are outstanding and exercisable at December 31,
      2005.
      Approximately 160,000 Kerr-McGee options held by Tronox employees are expected
      to be forfeited, as discussed above under *Effect
      of Tronox Separation* .





Options
                Outstanding
            
            Options
                ExercisableRange of
            
            
            
            ContractualExercise
                Prices
            
            Options
            
            Life
                (years) (1)
            
            Price
                (1)
            
            Options
            
            Price
                (1)$15.00
                - $29.99
            
            
            127,538
            
            
            5.1
            
            $
            26.77
            
            
            91,334
            
            $
            26.0530.00 - 39.99
            
            
            41,316
            
            
            3.0
            
            
            33.62
            
            
            38,003
            
            
            33.6440.00 - 49.99
            
            
            1,758,267
            
            
            7.2
            
            
            46.48
            
            
            583,393
            
            
            44.8050.00 - 59.99
            
            
            1,961,773
            
            
            8.0
            
            
            56.25
            
            
            480,863
            
            
            55.2760.00 - 69.99
            
            
            832,362
            
            
            4.9
            
            
            63.45
            
            
            832,362
            
            
            63.4570.00 - 79.99
            
            
            77,868
            
            
            1.3
            
            
            72.65
            
            
            77,868
            
            
            72.654,799,124
            
            
            6.9
            
            
            53.21
            
            
            2,103,823
            
            
            54.59





(1)
            Represents
                weighted average remaining contractual life or weighted average exercise
                price, as applicable.





***Employee
      Stock Ownership Plan*** - In
      1989, the company’s Board of Directors approved a leveraged Employee Stock
      Ownership Plan (ESOP) into which the company’s matching contribution for the
      employees’ contributions to the Kerr-McGee Corporation Savings Investment Plan
      (SIP) is paid. Most of the company’s employees are eligible to participate in
      the SIP and matching contributions to the ESOP fund are contingent upon
      participants’ contributions to the SIP.





In
      1989, the ESOP trust borrowed $125 million from a group of lending institutions
      and used the proceeds to purchase approximately 3 million shares of the
      company’s treasury stock. The company used the $125 million in proceeds from the
      sale of the stock to acquire shares of its common stock in open-market and
      privately negotiated transactions. In 1996, a portion of the third-party
      borrowings was replaced with a note payable to the company (sponsor financing),
      which was fully paid in 2003. The third-party borrowings were repaid in
      2005.





In
      1999, the company merged with Oryx Energy Company, which sponsored the Oryx
      Capital Accumulation Plan (CAP). CAP was a combined stock bonus and leveraged
      employee stock ownership plan available to substantially all U.S. employees
      of
      the former Oryx operations. During 1999, the company merged the Oryx CAP into
      the ESOP and SIP. In 1989, Oryx privately placed $110 million of notes pursuant
      to the provisions of the CAP. Oryx loaned the proceeds to the CAP, which used
      the funds to purchase Oryx common stock that was placed in a trust. Because
      this
      loan represents sponsor financing, it does not appear in the accompanying
      balance sheet. The remaining balance of the sponsor financing is $25 million
      at
      year-end 2005.







Shares
      of stock allocated to the ESOP participants’ accounts and in the loan suspense
      account are as follows:





(Thousands
                of shares)
            
            **2005**
            
            2004Participants’
                accounts
            
            
            **1,119**
            
            
            1,432Loan
                suspense account
            
            
            **187**
            
            
            246





The
      shares in the loan suspense account at December 31, 2005, included approximately
      11,000 released shares that were allocated to participants’ accounts in January
      2006. At December 31, 2004, the shares in the loan suspense account included
      approximately 17,000 released shares that were allocated to participants’
accounts in January 2005.





Compensation
      expense related to the plan was $14 million, $13 million and $33 million in
      2005, 2004 and 2003, respectively. These amounts include interest expense
      incurred on the third-party ESOP debt, which was not material for 2005, 2004
      or
      2003. The company contributed $14 million, $17 million and $42 million to the
      ESOP in 2005, 2004 and 2003, respectively. Included in the respective
      contributions were $8 million, $10 million and $37 million for principal and
      interest payments on the financings. The cash contributions are net of $1
      million, $3 million and $4 million for the dividends paid on the company stock
      held by the ESOP trust in 2005, 2004 and 2003, respectively.





**20. 
        Reporting by Business Segments and Geographic
        Locations**





The
      company has three operating segments: oil and gas exploration and production,
      production and marketing of titanium dioxide pigment, and production and
      marketing of other chemical products. These segments are managed separately
      because of their distinctly different products, operating environments and
      capital expenditure requirements. We routinely review the operating results
      of
      these segments individually to make decisions about resources to be allocated
      to
      the segment and to assess their individual performance. The exploration and
      production unit explores for, develops, produces and markets crude oil and
      natural gas, with major areas of operation in the United States and China.
      Exploration efforts also extend to the North Slope of Alaska and offshore West
      Africa, Brazil and Trinidad and Tobago. The chemical business is conducted
      by
      Tronox and its subsidiaries. Tronox primarily produces and markets titanium
      dioxide pigment and has production facilities in the United States, Australia,
      Germany and the Netherlands. Other chemical products segment represents Tronox’s
      U.S. electrolytic manufacturing and marketing operations. Segment performance
      is
      evaluated based on operating profit (loss), which represents results of
      operations before considering general corporate expenses, interest and debt
      expense, environmental provisions related to businesses in which the company’s
      affiliates are no longer engaged, other income (expense) and income
      taxes.








For
      the
      years ended December 31, 2005, 2004 and 2003, natural gas sales to Cinergy
      Marketing & Trading totaled $1.4 billion, $1 billion and $0.8 billion,
      respectively. Sales to subsidiary companies are eliminated as described in
      Note
      1.





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Revenues
                -Exploration
                and production
            
            **$**
            **4,563**
            
            $
            3,096
            
            $
            2,132Chemical
                -Pigment
            
            
            **1,267**
            
            
            1,209
            
            
            1,079Other
            
            
            **97**
            
            
            93
            
            
            78Total
                chemical
            
            
            **1,364**
            
            
            1,302
            
            
            1,157Total
            
            **$**
            **5,927**
            
            $
            4,398
            
            $
            3,289Operating
                profit (loss) -Exploration
                and production
            
            **$**
            **1,755**
            
            $
            973
            
            $
            649Chemical
                -Pigment
            
            
            **100**
            
            
            (80
            )
            
            (13
            )Other
            
            
            **(6**
            **)**
            
            (2
            )
            
            (23
            )Total
                chemical
            
            
            **94**
            
            
            (82
            )
            
            (36
            )Total
            
            
            **1,849**
            
            
            891
            
            
            613Interest
                and debt expense
            
            
            **(253**
            **)**
            
            (244
            )
            
            (250
            )Loss
                on early repayment and modification of debt
            
            
            **(42**
            **)**
            
            -
            
            
            -Corporate
                expenses
            
            
            **(201**
            **)**
            
            (130
            )
            
            (151
            )Provision
                for environmental remediation and restoration,net
                of reimbursements(1)
            
            
            **(23**
            **)**
            
            (82
            )
            
            (47
            )Other
                income (expense)(2)
            
            
            **104**
            
            
            (34
            )
            
            (25
            )Benefit
                (provision) for income taxes
            
            
            **(487**
            **)**
            
            (137
            )
            
            15Minority
                interest, net of taxes
            
            
            **(1**
            **)**
            
            -
            
            
            -Income
                from continuing operations
            
            **$**
            **946**
            
            $
            264
            
            $
            155Depreciation,
                depletion and amortization -Exploration
                and production(3)
            
            **$**
            **930**
            
            $
            695
            
            $
            463Chemical
                -Pigment
            
            
            **91**
            
            
            182
            
            
            110Other
            
            
            **12**
            
            
            14
            
            
            15Total
                chemical
            
            
            **103**
            
            
            196
            
            
            125Other
            
            
            **11**
            
            
            9
            
            
            8Discontinued
                operations
            
            
            **133**
            
            
            224
            
            
            218Total
            
            **$**
            **1,177**
            
            $
            1,124
            
            $
            814





(1)
            Includes
                provisions, net of reimbursements, related to various businesses
                in which
                the company’s affiliates are no longer engaged; for example, the refining
                and marketing of oil and gas and associated petroleum products, and
                the
                mining and processing of uranium and thorium. See Note
                16.




(2)
            The
                company owns a 50% interest in Avestor, a joint venture involved
                in
                production of lithium-metal-polymer batteries. Investment in Avestor
                is
                accounted for under the equity method. The company’s equity in the net
                losses of Avestor amounts to $37 million, $39 million and $28 million
                in
                2005, 2004 and 2003, respectively. The carrying value of the company’s
                investment in Avestor at December 31, 2005 and 2004 was $69 million
                and
                $60 million, respectively.




(3)
            Includes
                amortization of nonproducing leasehold costs that is reported in
                exploration expense in the Consolidated Statement of Income.










(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Capital
                expenditures -Exploration
                and production
            
            **$**
            **1,432**
            
            $
            1,027
            
            $
            776Chemical
                -Pigment
            
            
            **79**
            
            
            83
            
            
            90Other
            
            
            **9**
            
            
            9
            
            
            7Total
                chemical
            
            
            **88**
            
            
            92
            
            
            97Other
            
            
            **15**
            
            
            18
            
            
            15Discontinued
                operations
            
            
            **216**
            
            
            125
            
            
            93Total
            
            **$**
            **1,751**
            
            $
            1,262
            
            $
            981Total
                assets -Exploration
                and production
            
            **$**
            **11,127**
            
            $
            10,260
            
            $
            5,348Chemical
                -Pigment
            
            
            **1,507**
            
            
            1,359
            
            
            1,521Other
            
            
            **243**
            
            
            184
            
            
            213Total
                chemical
            
            
            **1,750**
            
            
            1,543
            
            
            1,734Corporate
                and other assets
            
            
            **1,399**
            
            
            726
            
            
            1,127Discontinued
                operations
            
            
            **-**
            
            
            1,989
            
            
            2,041Total
            
            **$**
            **14,276**
            
            $
            14,518
            
            $
            10,250Revenues
                -U.S.
                operations
            
            **$**
            **5,007**
            
            $
            3,720
            
            $
            2,755International
                operations -China
                - exploration and production
            
            
            **312**
            
            
            92
            
            
            23Europe
                - pigment
            
            
            **369**
            
            
            361
            
            
            313Australia
                - pigment
            
            
            **239**
            
            
            225
            
            
            198**920**
            
            
            678
            
            
            534Total
            
            **$**
            **5,927**
            
            $
            4,398
            
            $
            3,289Operating
                profit (loss) -U.S.
                operations
            
            **$**
            **1,696**
            
            $
            880
            
            $
            634International
                operations -China
                - exploration and production
            
            
            **198**
            
            
            41
            
            
            1Other
                - exploration and production
            
            
            **(61**
            **)**
            
            (52
            )
            
            (66
            )Europe
                - pigment
            
            
            **(12**
            **)**
            
            (16
            )
            
            14Australia
                - pigment
            
            
            **28**
            
            
            38
            
            
            30**153**
            
            
            11
            
            
            (21
            )Total
            
            **$**
            **1,849**
            
            $
            891
            
            $
            613Net
                property, plant and equipment -U.S.
                operations
            
            **$**
            **8,612**
            
            $
            8,425
            
            $
            4,973International
                operations -China
                - exploration and production
            
            
            **252**
            
            
            226
            
            
            165Other
                - exploration and production
            
            
            **48**
            
            
            26
            
            
            4Europe
                - pigment
            
            
            **274**
            
            
            303
            
            
            281Australia
                - pigment
            
            
            **89**
            
            
            93
            
            
            102**663**
            
            
            648
            
            
            552Total
            
            **$**
            **9,275**
            
            $
            9,073
            
            $
            5,525








**21. 
        Costs Incurred in Crude Oil and Natural Gas
        Activities**




The
        following reflects total expenditures, both capitalized and expensed, for
        crude
        oil and natural gas property acquisition, exploration and development activities
        for the three years ended December 31, 2005.





(Millions
                of dollars)
            
            Property
              Acquisition
              Costs
            
            Exploration
                Costs(2)
            
            Development
                Costs(3)
            
            Total2005
                -Continuing
                operations -United
                States
            
            $
            56
            
            $
            373
            
            $
            1,212
            
            $
            1,641China
            
            
            -
            
            
            21
            
            
            81
            
            
            102Other
                international
            
            
            14
            
            
            64
            
            
            -
            
            
            78Total
                - continuing operations
            
            
            70
            (1)
            
            458
            
            
            1,293
            
            
            1,821
            (4)Discontinued
                operations
            
            
            21
            
            
            57
            
            
            141
            
            
            219Total
                costs incurred
            
            $
            91
            
            $
            515
            
            $
            1,434
            
            $
            2,0402004
                -Continuing
                operations -United
                States
            
            $
            3,477
            
            $
            231
            
            $
            757
            
            $
            4,465China
            
            
            1
            
            
            19
            
            
            75
            
            
            95Other
                international
            
            
            25
            
            
            51
            
            
            -
            
            
            76Total
                - continuing operations
            
            
            3,503
            (1)
            
            301
            
            
            832
            
            
            4,636
            (4)Discontinued
                operations
            
            
            4
            
            
            36
            
            
            110
            
            
            150Total
                costs incurred
            
            $
            3,507
            
            $
            337
            
            $
            942
            
            $
            4,7862003
                -Continuing
                operations -United
                States
            
            $
            122
            
            $
            357
            
            $
            475
            
            $
            954China
            
            
            1
            
            
            31
            
            
            45
            
            
            77Other
                international
            
            
            1
            
            
            49
            
            
            -
            
            
            50Total
                - continuing operations
            
            
            124
            (1)
            
            437
            
            
            520
            
            
            1,081
            (4)Discontinued
                operations
            
            
            54
            
            
            43
            
            
            55
            
            
            152Total
                costs incurred
            
            $
            178
            
            $
            480
            
            $
            575
            
            $
            1,233








(1)
            Includes
                $24 million, $2.374 billion and $60 million applicable to purchases
                of
                proved reserves in place in 2005, 2004 and 2003,
                respectively.





(2)
            Exploration
                costs include delay rentals, exploratory dry holes, dry hole and
                bottom
                hole contributions, geological and geophysical costs, costs of carrying
                and retaining properties, and capital expenditures, such as costs
                of
                drilling and equipping successful exploratory
                wells.





(3)
            Development
                costs include costs incurred to obtain access to proved reserves
                (surveying, clearing ground, building roads), to drill and equip
                development wells, and to acquire, construct and install production
                facilities and improved-recovery systems. Development costs also
                include
                costs of developmental dry holes.





(4)
            Assetretirementcosts of $37 million, $83 million and $3 million for 2005, 2004,
                and 2003,
                respectively, represent the noncash increase in property, plant and
                equipment recognized when initially recording a liability for abandonment
                obligations (discounted) associated with the company’s oil and gas wells
                and platforms. Asset retirement costs are depleted on a unit-of-production
                basis over the useful life of the related field.








**22.** **Results
        of Operations from Crude Oil and Natural Gas
        Activities**





The
      results of operations from crude oil and natural gas activities for the years
      ended December 31, 2005, 2004 and 2003 were as follows:





Loss
                (Gain) on
            
            Income
            
            Results
                ofProduction
            
            
            
            
            
            Depreciation,
            
            Asset
                Sales
            
            Tax
            
            Operations,(Lifting)
            
            Other
            
            Exploration
            
            Depletion
                and
            
            and
            
            Expense
            
            Producing(Millions
                of dollars)
            
            Revenues
            
            Costs
            
            Costs
            
            Expenses
            
            Accretion
            
            Impairments
            
            (Benefit)
            
            Activities2005
                -United
                States
            
            $
            3,374
            
            $
            560
            
            $
            256
            
            $
            298
            
            $
            789
            
            $
            (194
            )
            $
            583
            
            $
            1,082China
            
            
            312
            
            
            33
            
            
            2
            
            
            23
            
            
            56
            
            
            -
            
            
            65
            
            
            133Other
                international
            
            
            -
            
            
            -
            
            
            15
            
            
            56
            
            
            -
            
            
            -
            
            
            (29
            )
            
            (42
            )Total
                crude oil andnatural
                gas activities
            
            
            3,686
            
            
            593
            
            
            273
            (1)
            
            377
            
            
            845
            
            
            (194
            )
            
            619
            
            
            1,173Other
                (2)
            
            
            877
            
            
            -
            
            
            899
            
            
            -
            
            
            15
            
            
            -
            
            
            (13
            )
            
            (24
            )Total
                - continuingoperations
            
            
            4,563
            
            
            593
            
            
            1,172
            
            
            377
            
            
            860
            
            
            (194
            )
            
            606
            
            
            1,149Discontinued
                operations
            
            
            994
            
            
            171
            
            
            50
            
            
            30
            
            
            137
            
            
            (2,240
            )
            
            1,026
            
            
            1,820Total
            
            $
            5,557
            
            $
            764
            
            $
            1,222
            
            $
            407
            
            $
            997
            
            $
            (2,434
            )
            $
            1,632
            
            $
            2,9692004
                -United
                States
            
            $
            2,520
            
            $
            385
            
            $
            189
            
            $
            265
            
            $
            620
            
            $
            50
            
            $
            355
            
            $
            656China
            
            
            92
            
            
            13
            
            
            5
            
            
            11
            
            
            22
            
            
            (1
            )
            
            14
            
            
            28Other
                international
            
            
            -
            
            
            -
            
            
            6
            
            
            48
            
            
            1
            
            
            -
            
            
            (19
            )
            
            (36
            )Total
                crude oil andnatural
                gas activities
            
            
            2,612
            
            
            398
            
            
            200
            (1)
            
            324
            
            
            643
            
            
            49
            
            
            350
            
            
            648Other
                (2)
            
            
            484
            
            
            -
            
            
            498
            
            
            -
            
            
            11
            
            
            -
            
            
            (7
            )
            
            (18
            )Total
                - continuingoperations
            
            
            3,096
            
            
            398
            
            
            698
            
            
            324
            
            
            654
            
            
            49
            
            
            343
            
            
            630Discontinued
                operations
            
            
            759
            
            
            158
            
            
            55
            
            
            32
            
            
            230
            
            
            8
            
            
            120
            
            
            156Total
            
            $
            3,855
            
            $
            556
            
            $
            753
            
            $
            356
            
            $
            884
            
            $
            57
            
            $
            463
            
            $
            7862003-United
                States
            
            $
            1,775
            
            $
            236
            
            $
            149
            
            $
            249
            
            $
            400
            
            $
            (4
            )
            $
            255
            
            $
            490China
            
            
            23
            
            
            5
            
            
            8
            
            
            19
            
            
            2
            
            
            (12
            )
            
            1
            
            
            -Other
                international
            
            
            -
            
            
            -
            
            
            6
            
            
            59
            
            
            1
            
            
            -
            
            
            (22
            )
            
            (44
            )Total
                crude oil andnatural
                gas activities
            
            
            1,798
            
            
            241
            
            
            163
            (1)
            
            327
            
            
            403
            
            
            (16
            )
            
            234
            
            
            446Other
                (2)
            
            
            334
            
            
            -
            
            
            354
            
            
            -
            
            
            11
            
            
            -
            
            
            (11
            )
            
            (20
            )Total
                - continuingoperations
            
            
            2,132
            
            
            241
            
            
            517
            
            
            327
            
            
            414
            
            
            (16
            )
            
            223
            
            
            426Discontinued
                operations
            
            
            797
            
            
            146
            
            
            63
            
            
            27
            
            
            220
            
            
            (9
            )
            
            150
            
            
            200Total
            
            $
            2,929
            
            $
            387
            
            $
            580
            
            $
            354
            
            $
            634
            
            $
            (25
            )
            $
            373
            
            $
            626








(1)
            Includes
                transportation, general and administrative expense, and taxes other
                than
                income taxes associated with oil and natural gas producing
                activities.





(2)
            Includes
                gas marketing activities, gas processing plants, pipelines and other
                items
                that do not fit the definition of crude oil and natural gas producing
                activities but have been included above to reconcile to the segment
                presentations.







The
      table below presents the company’s average per-unit sales price of crude oil and
      natural gas and lifting costs (lease operating expense and production and ad
      valorem taxes) per barrel of oil equivalent for continuing operations for each
      of the three years in the period ended December 31, 2005. Natural gas production
      has been converted to a barrel of oil equivalent based on approximate relative
      heating value (6 Mcf equals 1 barrel).





**2005**
            
            2004
            
            2003Average
                realized price of crude oil (per barrel)(1)-United
                States
            
            **$**
            **42.55**
            
            $
            29.11
            
            $
            26.14China
            
            
            **44.45**
            
            
            32.37
            
            
            29.66Average
                - continuing operations
            
            
            **42.89**
            
            
            29.38
            
            
            26.24Average
                realized price of natural gas (per Mcf)(1)-United
                States
            
            **$**
            **6.66**
            
            $
            5.24
            
            $
            4.56Lifting
                costs (per barrel of oil equivalent) -United
                States
            
            **$**
            **6.12**
            
            $
            4.63
            
            $
            3.57China
            
            
            **4.79**
            
            
            4.37
            
            
            6.02Average
                - continuing operations
            
            
            **6.03**
            
            
            4.63
            
            
            3.61





(1)
            Includes
                the results of the company’s hedging program, which reduced the average
                price of crude oil sold by $5.68, $8.03 and $2.48 per barrel and
                natural
                gas sold by $1.21, $.82 and $.63 per Mcf in 2005, 2004 and 2003,
                respectively.





**23.** **Results
        of Operations from Crude Oil and Natural Gas
        Activities**





Capitalized
      costs related to crude oil and natural gas activities and the related reserves
      for depreciation, depletion and amortization at the end of 2005 and 2004 are
      set
      forth in the table below. Capitalized costs presented as assets held for sale
      at
      December 31, 2004 primarily relate to the North Sea oil and gas business, which
      was sold in 2005, as discussed in Note 2.





(Millions
                of dollars)
            
            **2005**
            
            2004Capitalized
                costs -Proved
                properties
            
            **$**
            **11,615**
            
            $
            10,467Unproved
                properties
            
            
            **1,427**
            
            
            1,674Other
            
            
            **448**
            
            
            412**13,490**
            
            
            12,553Assets
                held for sale
            
            
            **8**
            
            
            4,183Total
            
            
            **13,498**
            
            
            16,736Accumulated
                depreciation, depletion and amortization -Proved
                properties
            
            
            **4,744**
            
            
            4,154Unproved
                properties
            
            
            **248**
            
            
            190Other
            
            
            **116**
            
            
            99**5,108**
            
            
            4,443Assets
                held for sale
            
            
            **3**
            
            
            2,424Total
            
            
            **5,111**
            
            
            6,867Net
                capitalized costs
            
            **$**
            **8,387**
            
            $
            9,869








**Exploratory
      Drilling Costs**





Under
      the successful efforts method of accounting, the costs of drilling an
      exploratory well are capitalized pending determination of whether proved
      reserves can be attributed to the discovery. In the case of onshore wells and
      offshore wells in relatively shallow water, that determination usually can
      be
      made upon or shortly after cessation of exploratory drilling operations.
      However, such determination may take longer in other areas (specifically,
      deepwater exploration and international locations) depending upon, among other
      things, (i) the amount of hydrocarbons discovered, (ii) the outcome of planned
      geological and engineering studies, (iii) the need for additional appraisal
      drilling to determine whether the discovery is sufficient to support an economic
      development plan and (iv) the requirement for government sanctioning in certain
      international locations before proceeding with development activities. As a
      consequence, the company has capitalized costs associated with exploratory
      wells
      on its Consolidated Balance Sheet at any point in time that may be charged
      to
      earnings in a future period if management determines that commercial quantities
      of hydrocarbons have not been discovered.





***Initial
      and Ongoing Assessment of Deferred Exploratory Drilling
      Costs*** ** -
      When
      initial drilling operations are complete, management determines whether the
      well
      has discovered oil and gas reserves and, if so, whether those reserves can
      be
      classified as proved. Often, the determination of whether proved reserves can
      be
      recorded under strict Securities and Exchange Commission (SEC) guidelines cannot
      be made when drilling is completed. In those situations where management
      believes that commercial hydrocarbons have not been discovered, the exploratory
      drilling costs are reflected in the Consolidated Statement of Income as dry
      hole
      costs (a component of exploration expense). Where sufficient hydrocarbons have
      been discovered to justify further exploration and/or appraisal activities,
      exploratory drilling costs are deferred on the Consolidated Balance Sheet
      pending the outcome of those activities.





At
      the
      end of each quarter, operating and financial management review the status of
      all
      deferred exploratory drilling costs in light of ongoing exploration activities
      -
      in particular, whether the company is making sufficient progress in its ongoing
      exploration and appraisal efforts or, in the case of discoveries requiring
      government sanctioning, whether development negotiations are under way and
      proceeding as planned. If management determines that future appraisal drilling
      or development activities are not likely to occur in the future, any associated
      exploratory well costs are expensed in that period.





***Financial
      Statement Balances*** - The
      following table presents the amount of capitalized exploratory drilling costs
      relating to continuing operations at December 31 for each of the last three
      years, and changes in those amounts during the years then ended (excluding
      costs
      incurred and either reclassified to proved oil and gas properties or charged
      to
      expense in the same year):





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Balance
                at January 1
            
            **$**
            **130**
            
            $
            135
            
            $
            116Additions,
                pending determination of proved reserves
            
            
            **139**
            
            
            76
            
            
            64Reclassification
                to proved oil and gas properties
            
            
            **(53**
            **)**
            
            (14
            )
            
            (39
            )Capitalized
                exploratory well costs charged to expense
            
            
            **(8**
            **)**
            
            (67
            )
            
            (6
            )Balance
                at December 31
            
            **$**
            **208**
            
            $
            130
            
            $
            135








At
      December 31, 2005, the company had capitalized costs of approximately $208
      million associated with ongoing exploration and/or appraisal activities,
      primarily in the deepwater Gulf of Mexico, Alaska, Brazil and China. The
      following table presents the total amount of exploratory drilling costs at
      year-end 2005 by geographic area, including the length of time such costs have
      been carried on the Consolidated Balance Sheet:








Costs
                Incurred(Millions
                of dollars)
            
            **Total**
            
            2005
            
            2004
            
            2003Gulf
                of Mexico(1)
            
            **$**
            **98**
            
            $
            68
            
            $
            5
            
            $
            25Alaska
            
            
            **68**
            
            
            48
            
            
            20
            
            
            -Brazil
            
            
            **30**
            
            
            20
            
            
            10
            
            
            -China
            
            
            **8**
            
            
            (1
            )
            
            9
            
            
            -Other
            
            
            **4**
            
            
            4
            
            
            -
            
            
            -Total
                capitalized exploratory drilling costs
            
            **$**
            **208**
            
            $
            139
            
            $
            44
            
            $
            25


(1)
            Approximately
                $43 million is associated with properties to be sold to W&T in 2006 as
                part of the Gulf of Mexico shelf
                divestiture.





***Analysis
      of Exploratory Costs at December 31, 2005*** - The
      majority of exploratory drilling costs deferred at year-end are associated
      with
      wells that are either (i) drilling at December 31, (ii) in an area requiring
      a
      major capital expenditure or additional appraisal activities before recording
      proved reserves such as the deepwater Gulf of Mexico, Alaska, Brazil and China,
      or (iii) subject to government review and approval of our development plans.
      The
      company has no deferred drilling costs associated with areas that require gas
      sales contracts or project financing in order to proceed with development plans.
      The following discussion describes major projects shown in the table above
      with
      costs deferred beyond one year from the balance sheet date.





*Deepwater
      Gulf of Mexico* -
      Costs incurred in the deepwater Gulf of Mexico prior to 2004 ($25 million)
      relate to an exploration well located in an area requiring additional appraisal
      activity before the determination of proved reserves can be made. The drilling
      rig for this well was released in October 2003 after successfully encountering
      hydrocarbons. The company is conducting appraisal activities at this time.
      Management expects that appraisal drilling may occur during 2006; however,
      if
      management determines during the year that future appraisal drilling is not
      likely to occur, all capitalized costs will be charged to exploration expense.





*Alaska* -
      Costs incurred in Alaska prior to 2005 ($20 million) are associated with the
      company’s Nikaitchuq discovery on Alaska’s North Slope. The discovery well was
      followed by an appraisal well drilled during 2004. Further appraisal drilling
      and flow testing was carried out in 2005. Development assessment and planning
      for this discovery is under way. The company is working towards possible
      development sanctioning in 2006.





*Brazil* -
      Costs incurred prior to 2005 ($10 million) are associated with the BMC-7
      discovery located in the Campos Basin offshore Brazil. The original discovery
      well was drilled in 2004, followed by two successful appraisal wells in 2005.
      A
      successful flow test of one of these wells was also conducted during 2005.
      Development planning is under way and these costs have been deferred pending
      formal approval of a development plan.





*China
      -* Costs
      incurred in China prior to 2005 ($9 million) are associated with the CFD 14-5-1
      discovery drilled in late 2004. Further assessment of the discovery is under
      way
      utilizing 3-D seismic data obtained to the west of the discovery well to develop
      an appraisal plan. If management determines that future appraisal drilling
      is
      not likely to occur, all capitalized costs will be charged to exploration
      expense.








**24. 
      Crude Oil, Condensate, Natural Gas Liquids and Natural Gas Net Reserves
      (Unaudited)**




The
      following tables show estimates of proved reserves prepared by the company’s
      engineers in accordance with the SEC definitions. Data is shown for crude oil
      in
      millions of barrels, for natural gas in billions of cubic feet (Bcf) at a
      pressure base of 14.73 pounds per square inch and for total proved reserves
      in
      millions of barrels of oil equivalent. For total proved reserves, natural gas
      is
      converted to barrels of oil equivalent using a conversion factor of six thousand
      cubic feet of natural gas per barrel.





During
      2005, the company expanded the involvement of third-party engineers in its
      reserve estimation processes. In July 2004, the company engaged Netherland,
      Sewell & Associates, Inc. (NSAI) to provide independent third-party review
      of the company’s procedures and methods for reserves estimation. During 2004,
      NSAI performed a procedures and methods review of about 43% of the company’s
      year-end 2004 proved reserves. In 2005, NSAI’s review was expanded to 75% of the
      company’s year-end proved reserves. The purpose of NSAI’s ongoing review is to
      verify that reserve estimates prepared by the company’s internal technical staff
      are in accordance with the guidelines and definitions of the SEC using generally
      accepted petroleum engineering and evaluation principles. As a result of its
      review, NSAI determined that the procedures and methods were reasonable and
      estimates had been prepared in accordance with Rule 4-10(a) of SEC Regulation
      S-X and generally accepted petroleum engineering and evaluation principles.
      A
      copy of the NSAI report is included as exhibit 99 to this Annual Report on
      Form 10-K.
      In 2006 the company plans to continue third-party review of its reserves
      estimation procedures and methods.





The
      company’s estimates of proved reserves are derived from data prepared by its
      engineers using available geological and reservoir data, as well as production
      performance data. These estimates are reviewed annually and revised, either
      upward or downward, as warranted by additional data. Revisions of previous
      estimates can occur due to changes in, among other things, reservoir
      performance, prices, economic conditions and governmental restrictions. For
      example, a decrease in commodity price could result in a decrease in proved
      reserves as the economic limit of a reservoir might be reached sooner.
      Conversely, an improvement in reservoir performance could result in an increase
      in proved reserves, indicating higher ultimate recovery from previous
      estimates.





The
      company’s engineering staff is highly skilled with average industry experience
      of more than 20 years. The company relies primarily on its internal engineering
      expertise, augmented by third-party engineering oversight and advice to ensure
      objective estimates of the company’s proved reserves. The company mitigates the
      inherent risks associated with reserve estimation through a comprehensive
      reserves administration process. The company’s process includes:





·
            Independent
                third-party procedures and methods assessment


·
            Internal
                peer review and third-party assessment of all individually significant
                reserve additions (defined as those in excess of 5 million barrels
                of oil
                equivalent on a net basis)


·
            Annual
                internal review of about 80% of the company’s total proved
                reserves





The
      following tables summarize changes in the estimated quantities of proved
      reserves for the three years ended December 31, 2005. As more fully discussed
      in
      Note 2, in 2005, the company divested its North Sea oil and gas business, which
      is reported as a discontinued operation for all periods presented, and certain
      onshore oil and gas properties in the United States. In January 2006, Kerr-McGee
      announced an agreement to sell its interest in Gulf of Mexico shelf oil and
      natural gas properties to W&T as discussed in Note 2. The transaction, which
      is subject to customary closing conditions and regulatory approvals, is expected
      to close in the second quarter of 2006. Proved reserves for the company’s Gulf
      of Mexico shelf assets are included in the following tables and are less than
      10% of the company’s total proved reserves at year-end 2005. As described in
      Note 4, we completed a merger with Westport in 2004, which resulted in reserve
      additions of 281 million barrels of oil equivalent.











Continuing
                Operations**Crude
                Oil, Condensate and Natural Gas Liquids**
            
            United
            
            
            
            
            
            Discontinued(Millions
                of barrels)
            
            States
            
            China
            
            Total
            
            Operations
            
            Total**Proved
                developed and undeveloped reserves -**Balance
                at December 31, 2002
            
            
            241
            
            
            35
            
            
            276
            
            
            211
            
            
            487Revisions
                of previous estimates
            
            
            7
            
            
            2
            
            
            9
            
            
            (7
            )
            
            2Purchases
                of reserves in place
            
            
            3
            
            
            -
            
            
            3
            
            
            12
            
            
            15Sales
                of reserves in place
            
            
            (16
            )
            
            (3
            )
            
            (19
            )
            
            (9
            )
            
            (28
            )Extensions,
                discoveries and other additions
            
            
            55
            
            
            6
            
            
            61
            
            
            14
            
            
            75Production
            
            
            (28
            )
            
            (1
            )
            
            (29
            )
            
            (26
            )
            
            (55
            )Balance
                at December 31, 2003
            
            
            262
            
            
            39
            
            
            301
            
            
            195
            
            
            496Revisions
                of previous estimates
            
            
            9
            
            
            1
            
            
            10
            
            
            6
            
            
            16Purchases
                of reserves in place
            
            
            67
            
            
            -
            
            
            67
            
            
            -
            
            
            67Sales
                of reserves in place
            
            
            (10
            )
            
            -
            
            
            (10
            )
            
            -
            
            
            (10
            )Extensions,
                discoveries and other additions
            
            
            14
            
            
            -
            
            
            14
            
            
            1
            
            
            15Production
            
            
            (32
            )
            
            (3
            )
            
            (35
            )
            
            (23
            )
            
            (58
            )Balance
                at December 31, 2004
            
            
            310
            
            
            37
            
            
            347
            
            
            179
            
            
            526Revisions
                of previous estimates
            
            
            31
            
            
            2
            
            
            33
            
            
            1
            
            
            34Purchases
                of reserves in place
            
            
            1
            
            
            -
            
            
            1
            
            
            4
            
            
            5Sales
                of reserves in place
            
            
            (27
            )
            
            -
            
            
            (27
            )
            
            (168
            )
            
            (195
            )Extensions,
                discoveries and other additions
            
            
            40
            
            
            8
            
            
            48
            
            
            3
            
            
            51Production
            
            
            (33
            )
            
            (7
            )
            
            (40
            )
            
            (19
            )
            
            (59
            )Balance
                at December 31, 2005
            
            
            322
            
            
            40
            
            
            362
            
            
            -
            
            
            362**Natural
                Gas**(Billions
                of cubic feet)**Proved
                developed and undeveloped reserves -**Balance
                at December 31, 2002
            
            
            2,779
            
            
            -
            
            
            2,779
            
            
            496
            
            
            3,275Revisions
                of previous estimates
            
            
            (10
            )
            
            -
            
            
            (10
            )
            
            11
            
            
            1Purchases
                of reserves in place
            
            
            57
            
            
            -
            
            
            57
            
            
            30
            
            
            87Sales
                of reserves in place
            
            
            (77
            )
            
            -
            
            
            (77
            )
            
            -
            
            
            (77
            )Extensions,
                discoveries and other additions
            
            
            152
            
            
            -
            
            
            152
            
            
            8
            
            
            160Production
            
            
            (230
            )
            
            -
            
            
            (230
            )
            
            (35
            )
            
            (265
            )Balance
                at December 31, 2003
            
            
            2,671
            
            
            -
            
            
            2,671
            
            
            510
            
            
            3,181Revisions
                of previous estimates
            
            
            86
            
            
            -
            
            
            86
            
            
            (98
            )
            
            (12
            )Purchases
                of reserves in place
            
            
            1,289
            
            
            -
            
            
            1,289
            
            
            -
            
            
            1,289Sales
                of reserves in place
            
            
            (27
            )
            
            -
            
            
            (27
            )
            
            -
            
            
            (27
            )Extensions,
                discoveries and other additions
            
            
            59
            
            
            -
            
            
            59
            
            
            -
            
            
            59Production
            
            
            (306
            )
            
            -
            
            
            (306
            )
            
            (31
            )
            
            (337
            )Balance
                at December 31, 2004
            
            
            3,772
            
            
            -
            
            
            3,772
            
            
            381
            
            
            4,153Revisions
                of previous estimates
            
            
            128
            
            
            -
            
            
            128
            
            
            26
            
            
            154Purchases
                of reserves in place
            
            
            19
            
            
            -
            
            
            19
            
            
            9
            
            
            28Sales
                of reserves in place
            
            
            (208
            )
            
            -
            
            
            (208
            )
            
            (396
            )
            
            (604
            )Extensions,
                discoveries and other additions
            
            
            273
            
            
            -
            
            
            273
            
            
            3
            
            
            276Production
            
            
            (351
            )
            
            -
            
            
            (351
            )
            
            (23
            )
            
            (374
            )Balance
                at December 31, 2005
            
            
            3,633
            
            
            -
            
            
            3,633
            
            
            -
            
            
            3,633










Continuing
                Operations**Crude
                Oil, Condensate and Natural Gas Liquids**
              (Millions
                of barrels)
            
            United
                States
            
            China
            
            Total
            
            Discontinued
                Operations
            
            Total**Proved
                developed reserves -**December
                31, 2003
            
            
            122
            
            
            -
            
            
            122
            
            
            125
            
            
            247December
                31, 2004
            
            
            197
            
            
            16
            
            
            213
            
            
            120
            
            
            333December
                31, 2005
            
            
            234
            
            
            19
            
            
            253
            
            
            -
            
            
            253**Natural
                Gas**(Billions
                of cubic feet)**Proved
                developed reserves -**December
                31, 2003
            
            
            1,502
            
            
            -
            
            
            1,502
            
            
            113
            
            
            1,615December
                31, 2004
            
            
            2,620
            
            
            -
            
            
            2,620
            
            
            135
            
            
            2,755December
                31, 2005
            
            
            2,560
            
            
            -
            
            
            2,560
            
            
            -
            
            
            2,560





The
      following presents the company’s barrel of oil equivalent proved developed and
      undeveloped reserves based on approximate heating value (6 Mcf equals 1
      barrel).





Continuing
                Operations**Barrels
                of Oil Equivalent**(Millions of barrels)
            
            United
                States
            
            China
            
            Total
            
            Discontinued
                Operations
            
            Total**Proved
                developed and undeveloped reserves -**Balance
                at December 31, 2002
            
            
            704
            
            
            35
            
            
            739
            
            
            294
            
            
            1,033Revisions
                of previous estimates
            
            
            5
            
            
            2
            
            
            7
            
            
            (5
            )
            
            2Purchases
                of reserves in place
            
            
            12
            
            
            -
            
            
            12
            
            
            17
            
            
            29Sales
                of reserves in place
            
            
            (29
            )
            
            (3
            )
            
            (32
            )
            
            (9
            )
            
            (41
            )Extensions,
                discoveries and other additions
            
            
            81
            
            
            6
            
            
            87
            
            
            15
            
            
            102Production
            
            
            (66
            )
            
            (1
            )
            
            (67
            )
            
            (32
            )
            
            (99
            )Balance
                at December 31, 2003
            
            
            707
            
            
            39
            
            
            746
            
            
            280
            
            
            1,026Revisions
                of previous estimates
            
            
            24
            
            
            1
            
            
            25
            
            
            (11
            )
            
            14Purchases
                of reserves in place
            
            
            282
            
            
            -
            
            
            282
            
            
            -
            
            
            282Sales
                of reserves in place
            
            
            (15
            )
            
            -
            
            
            (15
            )
            
            -
            
            
            (15
            )Extensions,
                discoveries and other additions
            
            
            24
            
            
            -
            
            
            24
            
            
            1
            
            
            25Production
            
            
            (83
            )
            
            (3
            )
            
            (86
            )
            
            (28
            )
            
            (114
            )Balance
                at December 31, 2004
            
            
            939
            
            
            37
            
            
            976
            
            
            242
            
            
            1,218Revisions
                of previous estimates
            
            
            52
            
            
            2
            
            
            54
            
            
            5
            
            
            59Purchases
                of reserves in place
            
            
            4
            
            
            -
            
            
            4
            
            
            6
            
            
            10Sales
                of reserves in place
            
            
            (61
            )
            
            -
            
            
            (61
            )
            
            (234
            )
            
            (295
            )Extensions,
                discoveries and other additions
            
            
            85
            
            
            8
            
            
            93
            
            
            4
            
            
            97Production
            
            
            (91
            )
            
            (7
            )
            
            (98
            )
            
            (23
            )
            
            (121
            )Balance
                at December 31, 2005
            
            
            928
            
            
            40
            
            
            968
            
            
            -
            
            
            968





Continuing
                Operations(Millions
                of equivalent barrels)
            
            United
                States
            
            China
            
            Total
            
            Discontinued
                Operations
            
            Total**Proved
                developed reserves -**December
                31, 2003
            
            
            372
            
            
            -
            
            
            372
            
            
            144
            
            
            516December
                31, 2004
            
            
            634
            
            
            16
            
            
            650
            
            
            142
            
            
            792December
                31, 2005
            
            
            661
            
            
            19
            
            
            680
            
            
            -
            
            
            680**Proved
                undeveloped reserves -**December
                31, 2003
            
            
            335
            
            
            39
            
            
            374
            
            
            136
            
            
            510December
                31, 2004
            
            
            305
            
            
            21
            
            
            326
            
            
            100
            
            
            426December
                31, 2005
            
            
            267
            
            
            21
            
            
            288
            
            
            -
            
            
            288







**25. 
      Standardized Measure of and Reconciliation of Changes in Discounted Future
      Net
      Cash Flows (Unaudited)**




The
        standardized measure of future net cash flows presented in the following
        table
        was computed using year-end prices and costs and a 10% discount factor. The
        future income tax expense was computed by applying the appropriate year-end
        statutory rates, with consideration of future tax rates already legislated,
        to
        the future pretax net cash flows less the tax basis of the associated
        properties. However, the company cautions that actual future net cash flows
        may
        vary considerably from these estimates. Although the company’s estimates of
        total proved reserves, development costs and production rates were based
        on the
        best information available, the development and production of the oil and
        gas
        reserves may not occur in the periods assumed. Actual prices realized, costs
        incurred and production quantities may vary significantly from those used.
        Therefore, such estimated future net  cash
        flow computations should not be considered to represent the company’s estimate
        of the expected revenues or the current value of existing proved
        reserves.


StandardizedFuture
            
            
            
            Measure
                ofFuture
            
            Future
            
            Future
            
            Future
            
            Net
            
            10%
            
            DiscountedCash
            
            Production
            
            Development
            
            Income
            
            Cash
            
            Annual
            
            Future
                Net(Millions
                of dollars)
            
            Inflows
                (1)
            
            Costs
            
            Costs
            
            Taxes
            
            Flows
            
            Discount
            
            Cash
                Flows2005
                -United
                States
            
            $
            48,739
            
            $
            10,722
            
            $
            3,232
            
            $
            11,661
            
            $
            23,124
            
            $
            9,402
            
            $
            13,722China
            
            
            1,821
            
            
            415
            
            
            98
            
            
            363
            
            
            945
            
            
            319
            
            
            626Total
            
            $
            50,560
            
            $
            11,137
            
            $
            3,330
            
            $
            12,024
            
            $
            24,069
            
            $
            9,721
            
            $
            14,348
            (2)2004
                -United
                States
            
            $
            33,512
            
            $
            7,976
            
            $
            2,752
            
            $
            7,158
            
            $
            15,626
            
            $
            6,549
            
            $
            9,077China
            
            
            986
            
            
            306
            
            
            83
            
            
            113
            
            
            484
            
            
            148
            
            
            336Total
                - continuing operations
            
            
            34,498
            
            
            8,282
            
            
            2,835
            
            
            7,271
            
            
            16,110
            
            
            6,697
            
            
            9,413Discontinued
                operations
            
            
            8,927
            
            
            2,988
            
            
            999
            
            
            1,863
            
            
            3,077
            
            
            934
            
            
            2,143Total
            
            $
            43,425
            
            $
            11,270
            
            $
            3,834
            
            $
            9,134
            
            $
            19,187
            
            $
            7,631
            
            $
            11,5562003
                -United
                States
            
            $
            23,850
            
            $
            5,002
            
            $
            2,067
            
            $
            5,467
            
            $
            11,314
            
            $
            4,721
            
            $
            6,593China
            
            
            1,114
            
            
            306
            
            
            130
            
            
            178
            
            
            500
            
            
            208
            
            
            292Total
                - continuing operations
            
            
            24,964
            
            
            5,308
            
            
            2,197
            
            
            5,645
            
            
            11,814
            
            
            4,929
            
            
            6,885Discontinued
                operations
            
            
            7,770
            
            
            2,437
            
            
            790
            
            
            1,552
            
            
            2,991
            
            
            970
            
            
            2,021Total
            
            $
            32,734
            
            $
            7,745
            
            $
            2,987
            
            $
            7,197
            
            $
            14,805
            
            $
            5,899
            
            $
            8,906





(1)
            Future
                cash inflows from sales of crude oil and natural gas are based on
                average
                year-end prices of $53.96, $37.02 and $29.05 per barrel of oil and
                $8.56,
                $5.78 and $5.77 per Mcf of natural gas for 2005, 2004 and 2003,
                respectively.




(2)
            Approximately
                10% of the total standardized measure of discounted future net cash
                flows
                is associated with the company’s Gulf of Mexico shelf assets, which the
                company expects to sell in 2006, as discussed in Note
                2.





The
      changes in the standardized measure of future net cash flows are presented
      below
      for each of the past three years:





(Millions
                of dollars)
            
            **2005**
            
            2004
            
            2003Net
                change in sales prices and production costs
            
            **$**
            **7,760**
            
            $
            2,069
            
            $
            3,308Sales
                revenues less production costs
            
            
            **(4,891**
            **)**
            
            (3,454
            )
            
            (2,383
            )Purchases
                of reserves in place
            
            
            **222**
            
            
            3,850
            
            
            344Extensions,
                discoveries and other additions
            
            
            **2,061**
            
            
            438
            
            
            1,183Revisions
                in quantity estimates
            
            
            **808**
            
            
            (66
            )
            
            63Sales
                of reserves in place
            
            
            **(4,042**
            **)**
            
            (204
            )
            
            (255
            )Current-period
                development costs incurred
            
            
            **1,398**
            
            
            928
            
            
            573Changes
                in estimated future development costs
            
            
            **(913**
            **)**
            
            (852
            )
            
            (472
            )Accretion
                of discount
            
            
            **1,696**
            
            
            1,323
            
            
            1,033Change
                in income taxes
            
            
            **(1,761**
            **)**
            
            (1,097
            )
            
            (978
            )Timing
                and other
            
            
            **454**
            
            
            (285
            )
            
            (572
            )Net
                change
            
            
            **2,792**
            
            
            2,650
            
            
            1,844Total
                at beginning of year
            
            
            **11,556**
            
            
            8,906
            
            
            7,062Total
                at end of year
            
            **$**
            **14,348**
            
            $
            11,556
            
            $
            8,906







**26.  Condensed
      Consolidating Financial Information**


The
      company’s Notes (as defined in Note 10, under *Modification
      to Guarantee Provisions* )
      with
      an aggregate principal amount of $2.1 billion have been fully and
      unconditionally guaranteed by Kerr-McGee Rocky Mountain Corporation, a
      wholly-owed subsidiary of Kerr-McGee Corporation. As a result of these guarantee
      arrangements, the company is required to present condensed consolidating
      financial information.





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





As
      discussed in Note 10, Tronox Worldwide LLC was released from its guarantee
      of
      the Notes in November 2005 upon the IPO of its parent, Tronox
      Incorporated.





**Condensed
                Consolidating Statement of Income for the Year Ended December 31,
                2005**(Millions
                of dollars)
            
            Kerr-McGee
              Corporation
            
            Guarantor
              Subsidiary
            
            Non-Guarantor
              Subsidiaries
            
            Eliminations
            
            Consolidated**Revenues**
            
            $
            -
            
            $
            1,504
            
            $
            4,423
            
            $
            -
            
            $
            5,927**Costs
                and Expenses**Costs
                and operating expenses
            
            
            -
            
            
            920
            
            
            1,384
            
            
            -
            
            
            2,304Selling,
                general and administrative expenses
            
            
            -
            
            
            (2
            )
            
            457
            
            
            -
            
            
            455Shipping
                and handling expenses
            
            
            -
            
            
            12
            
            
            133
            
            
            -
            
            
            145Depreciation
                and depletion
            
            
            -
            
            
            118
            
            
            834
            
            
            -
            
            
            952Accretion
                expense
            
            
            -
            
            
            3
            
            
            20
            
            
            -
            
            
            23Asset
                impairments
            
            
            -
            
            
            2
            
            
            15
            
            
            -
            
            
            17Gain
                on sale of assets
            
            
            -
            
            
            -
            
            
            (211
            )
            
            -
            
            
            (211
            )Exploration,
                including exploratory dry holesand
                amortization of undeveloped leases
            
            
            -
            
            
            11
            
            
            366
            
            
            -
            
            
            377Taxes,
                other than income taxes
            
            
            -
            
            
            39
            
            
            163
            
            
            -
            
            
            202Provision
                for environmental remediation andrestoration,
                net of reimbursements
            
            
            -
            
            
            4
            
            
            34
            
            
            -
            
            
            38Interest
                and debt expense
            
            
            211
            
            
            8
            
            
            501
            
            
            (467
            )
            
            253Loss
                on early repayment and modification of debt
            
            
            42
            
            
            -
            
            
            -
            
            
            -
            
            
            42Total
                Costs and Expenses
            
            
            253
            
            
            1,115
            
            
            3,696
            
            
            (467
            )
            
            4,597(253
            )
            
            389
            
            
            727
            
            
            467
            
            
            1,330**Other
                Income (Expense)**
            
            
            3,463
            
            
            5
            
            
            485
            
            
            (3,849
            )
            
            104**Income
                from Continuing Operations****before
                Income Taxes**
            
            
            3,210
            
            
            394
            
            
            1,212
            
            
            (3,382
            )
            
            1,434**Benefit
                (Provision) for Income Taxes**
            
            
            61
            
            
            (138
            )
            
            (410
            )
            
            -
            
            
            (487
            )**Minority
                Interest, net of taxes**
            
            
            -
            
            
            -
            
            
            (1
            )
            
            -
            
            
            (1
            )**Income
                from Continuing Operations**
            
            
            3,271
            
            
            256
            
            
            801
            
            
            (3,382
            )
            
            946**Income
                (Loss) from Discontinued****Operations,
                net of taxes**
            
            
            (60
            )
            
            -
            
            
            2,325
            
            
            -
            
            
            2,265**Net
                Income**
            
            $
            3,211
            
            $
            256
            
            $
            3,126
            
            $
            (3,382
            )
            $
            3,211










Condensed
                  Consolidating Statement of Income for the Year Ended December 31,
                  2004(Millions
                  of dollars)
              
              Kerr-McGee
                  Corporation
              
              Guarantor
                  Subsidiary
              
              Non-Guarantor
                  Subsidiaries
              
              Eliminations
              
              Consolidated**Revenues**
              
              $
              -
              
              $
              864
              
              $
              3,534
              
              $
              -
              
              $
              4,398**Costs
                  and Expenses**Costs
                  and operating expenses
              
              
              -
              
              
              519
              
              
              1,278
              
              
              (3
              )
              
              1,794Selling,
                  general and administrative expenses
              
              
              1
              
              
              2
              
              
              322
              
              
              -
              
              
              325Shipping
                  and handling expenses
              
              
              -
              
              
              8
              
              
              120
              
              
              -
              
              
              128Depreciation
                  and depletion
              
              
              -
              
              
              120
              
              
              722
              
              
              -
              
              
              842Accretion
                  expense
              
              
              -
              
              
              3
              
              
              16
              
              
              -
              
              
              19Asset
                  impairments
              
              
              -
              
              
              3
              
              
              25
              
              
              -
              
              
              28Loss on sale of assets
              
              
              -
              
              
              -
              
              
              29
              
              
              -
              
              
              29Exploration,
                  including exploratory dry holes andamortization
                  of undeveloped leases
              
              
              -
              
              
              14
              
              
              310
              
              
              -
              
              
              324Taxes
                  other than income taxes
              
              
              -
              
              
              37
              
              
              107
              
              
              -
              
              
              144Provision
                  for environmental remediation andrestoration,
                  net of reimbursements
              
              
              -
              
              
              -
              
              
              86
              
              
              -
              
              
              86Interest
                  and debt expense
              
              
              138
              
              
              35
              
              
              304
              
              
              (233
              )
              
              244Total
                  Costs and Expenses
              
              
              139
              
              
              741
              
              
              3,319
              
              
              (236
              )
              
              3,963(139
              )
              
              123
              
              
              215
              
              
              236
              
              
              435**Other
                  Income (Expense)**
              
              
              793
              
              
              -
              
              
              116
              
              
              (943
              )
              
              (34
              )**Income
                  from Continuing Operations****before
                  Income Taxes**
              
              
              654
              
              
              123
              
              
              331
              
              
              (707
              )
              
              401**Provision
                  for Income Taxes**
              
              
              (250
              )
              
              (43
              )
              
              (114
              )
              
              270
              
              
              (137
              )**Income
                  from Continuing Operations**
              
              
              404
              
              
              80
              
              
              217
              
              
              (437
              )
              
              264**Income
                  from Discontinued Operations,****net
                  of taxes**
              
              
              -
              
              
              -
              
              
              140
              
              
              -
              
              
              140**Net
                  Income**
              
              $
              404
              
              $
              80
              
              $
              357
              
              $
              (437
              )
              $
              404




Condensed
                  Consolidating Statement of Income for the Year Ended December 31,
                  2003(Millions
                  of dollars)
              
              Kerr-McGee
                  Corporation
              
              Guarantor
                  Subsidiary
              
              Non-Guarantor
                  Subsidiaries
              
              Eliminations
              
              Consolidated**Revenues**
              
              $
              -
              
              $
              694
              
              $
              2,595
              
              $
              -
              
              $
              3,289**Costs
                  and Expenses**Costs
                  and operating expenses
              
              
              -
              
              
              351
              
              
              1,065
              
              
              -
              
              
              1,416Selling,
                  general and administrative expenses
              
              
              -
              
              
              3
              
              
              347
              
              
              -
              
              
              350Shipping
                  and handling expenses
              
              
              -
              
              
              9
              
              
              87
              
              
              -
              
              
              96Depreciation
                  and depletion
              
              
              -
              
              
              122
              
              
              410
              
              
              -
              
              
              532Accretion
                  expense
              
              
              -
              
              
              2
              
              
              13
              
              
              -
              
              
              15Asset
                  impairments
              
              
              -
              
              
              -
              
              
              14
              
              
              -
              
              
              14Loss (gain) on sale of assets
              
              
              -
              
              
              1
              
              
              (31
              )
              
              -
              
              
              (30
              )Exploration,
                  including exploratory dry holes andamortization
                  of undeveloped leases
              
              
              -
              
              
              15
              
              
              312
              
              
              -
              
              
              327Taxes
                  other than income taxes
              
              
              -
              
              
              25
              
              
              69
              
              
              -
              
              
              94Provision
                  for environmental remediation andrestoration,
                  net of reimbursements
              
              
              -
              
              
              -
              
              
              60
              
              
              -
              
              
              60Interest
                  and debt expense
              
              
              116
              
              
              35
              
              
              277
              
              
              (178
              )
              
              250Total
                  Costs and Expenses
              
              
              116
              
              
              563
              
              
              2,623
              
              
              (178
              )
              
              3,124(116
              )
              
              131
              
              
              (28
              )
              
              178
              
              
              165**Other
                  Income (Expense)**
              
              
              506
              
              
              (3
              )
              
              82
              
              
              (610
              )
              
              (25
              )**Income
                  from Continuing Operations****before
                  Income Taxes**
              
              
              390
              
              
              128
              
              
              54
              
              
              (432
              )
              
              140**Benefit
                  (Provision) for Income Taxes**
              
              
              (171
              )
              
              (46
              )
              
              45
              
              
              187
              
              
              15**Income
                  from Continuing Operations**
              
              
              219
              
              
              82
              
              
              99
              
              
              (245
              )
              
              155**Income
                  from Discontinued Operations,****net
                  of taxes**
              
              
              -
              
              
              -
              
              
              99
              
              
              -
              
              
              99**Cumulative
                  Effect of Change in Accounting****Principle,
                  net of taxes**
              
              
              -
              
              
              (1
              )
              
              (34
              )
              
              -
              
              
              (35
              )**Net
                  Income**
              
              $
              219
              
              $
              81
              
              $
              164
              
              $
              (245
              )
              $
              219











**Condensed
                  Consolidating Balance Sheet as of December 31,
                  2005**(Millions
                  of dollars)
              
              Kerr-McGee
                Corporation
              
              Guarantor
                Subsidiary
              
              Non-Guarantor
                Subsidiaries
              
              Eliminations
              
              Consolidated**ASSETS****Current
                  Assets**Cash
                  and cash equivalents
              
              $
              1
              
              $
              -
              
              $
              1,052
              
              $
              -
              
              $
              1,053Accounts
                  receivable
              
              
              1
              
              
              245
              
              
              823
              
              
              -
              
              
              1,069Inventories
              
              
              -
              
              
              3
              
              
              349
              
              
              -
              
              
              352Derivatives
                  and other current assets
              
              
              -
              
              
              14
              
              
              180
              
              
              -
              
              
              194Deferred
                  income taxes
              
              
              -
              
              
              2
              
              
              579
              
              
              -
              
              
              581Total
                  Current Assets
              
              
              2
              
              
              264
              
              
              2,983
              
              
              -
              
              
              3,249**Property,
                  Plant and Equipment - Net**
              
              
              -
              
              
              1,915
              
              
              7,360
              
              
              -
              
              
              9,275**Investments
                  in Subsidiaries**
              
              
              8,688
              
              
              -
              
              
              -
              
              
              (8,688
              )
              
              -**Deferred
                  Charges, Derivatives and Other Assets**
              
              
              25
              
              
              1
              
              
              562
              
              
              (80
              )
              
              508**Goodwill
                  and Other Intangible Assets**
              
              
              -
              
              
              346
              
              
              893
              
              
              -
              
              
              1,239**Assets
                  Held for Sale**
              
              
              -
              
              
              -
              
              
              5
              
              
              -
              
              
              5Total
                  Assets
              
              $
              8,715
              
              $
              2,526
              
              $
              11,803
              
              $
              (8,768
              )
              $
              14,276
  **LIABILITIES
                  AND STOCKHOLDERS’ EQUITY****Current
                  Liabilities**Intercompany
                  borrowings
              
              $
              2,459
              
              $
              183
              
              $
              3,037
              
              $
              (5,679
              )
              $
              -Accounts
                  payable
              
              
              6
              
              
              69
              
              
              652
              
              
              -
              
              
              727Long-term
                  debt due within one year
              
              
              306
              
              
              -
              
              
              2
              
              
              -
              
              
              308Derivative
                  liabilities
              
              
              -
              
              
              14
              
              
              1,494
              
              
              -
              
              
              1,508Accrued
                  liabilities
              
              
              (72
              )
              
              239
              
              
              1,221
              
              
              -
              
              
              1,388Total Current Liabilities
              
              
              2,699
              
              
              505
              
              
              6,406
              
              
              (5,679
              )
              
              3,931**Long-Term
                  Debt**
              
              
              1,801
              
              
              -
              
              
              1,024
              
              
              -
              
              
              2,825**Noncurrent
                  Liabilities**Deferred
                  income taxes
              
              
              (9
              )
              
              517
              
              
              1,016
              
              
              -
              
              
              1,524Derivative
                  liabilities
              
              
              -
              
              
              -
              
              
              663
              
              
              -
              
              
              663Other
                  noncurrent liabilities
              
              
              -
              
              
              78
              
              
              928
              
              
              -
              
              
              1,006Total Noncurrent Liabilities
              
              
              (9
              )
              
              595
              
              
              2,607
              
              
              -
              
              
              3,193**Minority
                  Interest in Tronox**
              
              
              -
              
              
              -
              
              
              212
              
              
              -
              
              
              212**Stockholders’
                  Equity**
              
              
              4,224
              
              
              1,426
              
              
              1,554
              
              
              (3,089
              )
              
              4,115Total
                  Liabilities and Stockholders’ Equity
              
              $
              8,715
              
              $
              2,526
              
              $
              11,803
              
              $
              (8,768
              )
              $
              14,276








**Condensed
                  Consolidating Balance Sheet as of December 31,
                  2004**(Millions
                  of dollars)
              
              Kerr-McGee
                Corporation
              
              Guarantor
                Subsidiary
              
              Non-Guarantor
                Subsidiaries
              
              Eliminations
              
              Consolidated**ASSETS****Current
                  Assets**Cash
                  and cash equivalents
              
              $
              2
              
              $
              -
              
              $
              74
              
              $
              -
              
              $
              76Intercompany
                  receivables
              
              
              -
              
              
              -
              
              
              58
              
              
              (58
              )
              
              -Accounts
                  receivable
              
              
              -
              
              
              140
              
              
              685
              
              
              -
              
              
              825Inventories
              
              
              -
              
              
              5
              
              
              309
              
              
              -
              
              
              314Derivatives
                  and other current assets
              
              
              4
              
              
              24
              
              
              123
              
              
              -
              
              
              151Deferred
                  income taxes
              
              
              2
              
              
              13
              
              
              312
              
              
              -
              
              
              327Assets held for sale
              
              
              -
              
              
              -
              
              
              194
              
              
              -
              
              
              194Total Current Assets
              
              
              8
              
              
              182
              
              
              1,755
              
              
              (58
              )
              
              1,887**Property,
                  Plant and Equipment - Net**
              
              
              -
              
              
              1,947
              
              
              7,126
              
              
              -
              
              
              9,073**Investments
                  in Subsidiaries**
              
              
              6,306
              
              
              -
              
              
              599
              
              
              (6,905
              )
              
              -**Deferred
                  Charges, Derivatives and Other Assets**
              
              
              17
              
              
              5
              
              
              542
              
              
              (80
              )
              
              484**Goodwill
                  and Other Intangible Assets**
              
              
              -
              
              
              352
              
              
              936
              
              
              -
              
              
              1,288**Assets
                  Held for Sale**
              
              
              -
              
              
              -
              
              
              1,786
              
              
              -
              
              
              1,786Total
                  Assets
              
              $
              6,331
              
              $
              2,486
              
              $
              12,744
              
              $
              (7,043
              )
              $
              14,518
  **LIABILITIES
                  AND STOCKHOLDERS’ EQUITY****Current
                  Liabilities**Intercompany
                  borrowings
              
              $
              68
              
              $
              598
              
              $
              1,233
              
              $
              (1,899
              )
              $
              -Accounts
                  payable
              
              
              68
              
              
              55
              
              
              484
              
              
              -
              
              
              607Long-term
                  debt due within one year
              
              
              354
              
              
              -
              
              
              109
              
              
              -
              
              
              463Derivative
                  liabilities
              
              
              6
              
              
              71
              
              
              273
              
              
              -
              
              
              350Accrued
                  liabilities
              
              
              10
              
              
              123
              
              
              760
              
              
              -
              
              
              893Liabilities
                  associated with assets held for sale
              
              
              -
              
              
              -
              
              
              192
              
              
              -
              
              
              192Total Current Liabilities
              
              
              506
              
              
              847
              
              
              3,051
              
              
              (1,899
              )
              
              2,505**Long-Term
                  Debt**
              
              
              2,125
              
              
              -
              
              
              1,111
              
              
              -
              
              
              3,236**Noncurrent
                  Liabilities**Deferred
                  income taxes
              
              
              (2
              )
              
              592
              
              
              1,137
              
              
              -
              
              
              1,727Derivative
                  liabilities
              
              
              -
              
              
              59
              
              
              149
              
              
              -
              
              
              208Other
                  noncurrent liabilities
              
              
              -
              
              
              85
              
              
              825
              
              
              (3
              )
              
              907Liabilities
                  associated with assets held for sale
              
              
              -
              
              
              -
              
              
              617
              
              
              -
              
              
              617Total
                  Noncurrent Liabilities
              
              
              (2
              )
              
              736
              
              
              2,728
              
              
              (3
              )
              
              3,459**Stockholders’
                  Equity**
              
              
              3,702
              
              
              903
              
              
              5,854
              
              
              (5,141
              )
              
              5,318Total
                  Liabilities and Stockholders’ Equity
              
              $
              6,331
              
              $
              2,486
              
              $
              12,744
              
              $
              (7,043
              )
              $
              14,518













**Condensed
                Consolidating Statement of Cash Flows for the Year Ended December
                31,
                2005**(Millions
                of dollars)
            
            Kerr-McGee
                Corporation
            
            Guarantor
                Subsidiary
            
            Non-Guarantor
                Subsidiaries
            
            Eliminations
            
            Consolidated**Cash
                Flow from Operating Activities**Net
                income
            
            $
            3,211
            
            $
            256
            
            $
            3,126
            
            $
            (3,382
            )
            $
            3,211Adjustments
                to reconcile net income to net cashprovided
                by operating activities -Depreciation,
                depletion and amortization
            
            
            -
            
            
            120
            
            
            1,057
            
            
            -
            
            
            1,177Deferred
                income taxes
            
            
            (6
            )
            
            (1
            )
            
            90
            
            
            -
            
            
            83Unrealized
                loss on derivatives
            
            
            -
            
            
            -
            
            
            200
            
            
            -
            
            
            200Dry
                hole expense
            
            
            -
            
            
            1
            
            
            184
            
            
            -
            
            
            185Noncash
                stock-based compensation and ESOPexpense
            
            
            -
            
            
            -
            
            
            54
            
            
            -
            
            
            54Asset
                impairments
            
            
            -
            
            
            2
            
            
            15
            
            
            -
            
            
            17Gain
                on sale of the North Sea oil and gas business
            
            
            -
            
            
            -
            
            
            (2,240
            )
            
            -
            
            
            (2,240
            )Gain
                on sale of assets
            
            
            -
            
            
            -
            
            
            (327
            )
            
            -
            
            
            (327
            )Loss
                on early repayment and modification of debt
            
            
            42
            
            
            -
            
            
            -
            
            
            -
            
            
            42Accretion
                expense
            
            
            -
            
            
            3
            
            
            27
            
            
            -
            
            
            30Equity
                in earnings of subsidiaries
            
            
            (3,382
            )
            
            -
            
            
            -
            
            
            3,382
            
            
            -Provision
                for environmental remediation andrestoration,
                net of reimbursements
            
            
            -
            
            
            4
            
            
            45
            
            
            -
            
            
            49Other
                noncash items affecting net income
            
            
            (9
            )
            
            46
            
            
            79
            
            
            -
            
            
            116Changes
                in assets and liabilities
            
            
            (70
            )
            
            40
            
            
            536
            
            
            -
            
            
            506Net
                cash provided by (used in) operatingactivities
            
            
            (214
            )
            
            471
            
            
            2,846
            
            
            -
            
            
            3,103**Cash
                Flow from Investing Activities**Capital
                expenditures
            
            
            -
            
            
            (124
            )
            
            (1,627
            )
            
            -
            
            
            (1,751
            )Dry
                hole costs
            
            
            -
            
            
            -
            
            
            (169
            )
            
            -
            
            
            (169
            )Net
                proceeds
                from sale of the North Sea oil and gas business
            
            
            -
            
            
            -
            
            
            3,305
            
            
            -
            
            
            3,305Proceeds
                from sale of assets
            
            
            -
            
            
            13
            
            
            691
            
            
            -
            
            
            704Accounts
                receivable purchase and collection
            
            
            (165
            )
            
            -
            
            
            165
            
            
            -
            
            
            -Other
                investing activities
            
            
            -
            
            
            -
            
            
            (8
            )
            
            -
            
            
            (8
            )Net
                cash provided by (used) in investingactivities
            
            
            (165
            )
            
            (111
            )
            
            2,357
            
            
            -
            
            
            2,081**Cash
                Flow from Financing Activities**Issuance
                of common stock upon exercise of stock options
            
            
            225
            
            
            -
            
            
            -
            
            
            -
            
            
            225Sale
                of Tronox stock
            
            
            -
            
            
            -
            
            
            225
            
            
            -
            
            
            225Purchases
                of treasury stock
            
            
            (250
            )
            
            -
            
            
            -
            
            
            -
            
            
            (250
            )Repurchases
                of common stock under the tender offer
            
            
            (3,975
            )
            
            -
            
            
            -
            
            
            -
            
            
            (3,975
            )Dividends
                paid
            
            
            (153
            )
            
            -
            
            
            -
            
            
            -
            
            
            (153
            )Increase
                (decrease) in intercompany notes payable
            
            
            4,962
            
            
            (360
            )
            
            (4,602
            )
            
            -
            
            
            -Repayment
                of debt
            
            
            (4,600
            )
            
            -
            
            
            (151
            )
            
            -
            
            
            (4,751
            )Proceeds
                from borrowings
            
            
            4,250
            
            
            -
            
            
            550
            
            
            -
            
            
            4,800Debt
                issuance costs and other
            
            
            (59
            )
            
            -
            
            
            (12
            )
            
            -
            
            
            (71
            )Cash
                paid for modification of debt
            
            
            (22
            )
            
            -
            
            
            -
            
            
            -
            
            
            (22
            )Settlement
                of Westport derivatives
            
            
            -
            
            
            -
            
            
            (238
            )
            
            -
            
            
            (238
            )Net
                cash provided by (used in) financingactivities
            
            
            378
            
            
            (360
            )
            
            (4,228
            )
            
            -
            
            
            (4,210
            )**Effects
                of Exchange Rate Changes on Cash and Cash****Equivalents**
            
            
            -
            
            
            -
            
            
            3
            
            
            -
            
            
            3**Net
                Increase (Decrease) in Cash and Cash Equivalents**
            
            
            (1
            )
            
            -
            
            
            978
            
            
            -
            
            
            977**Cash
                and Cash Equivalents at Beginning of Year**
            
            
            2
            
            
            -
            
            
            74
            
            
            -
            
            
            76**Cash
                and Cash Equivalents at End of Year**
            
            $
            1
            
            $
            -
            
            $
            1,052
            
            $
            -
            
            $
            1,053








**Condensed
                Consolidating Statement of Cash Flows for the Year Ended December
                31,
                2004**(Millions
                of dollars)
            
            Kerr-McGee
                Corporation
            
            Guarantor
                Subsidiaries
            
            Non-Guarantor
                Subsidiaries
            
            Eliminations
            
            Consolidated**Cash
                Flow from Operating Activities**Net
                income
            
            $
            404
            
            $
            80
            
            $
            357
            
            $
            (437
            )
            $
            404Adjustments
                to reconcile net income to net cashprovided
                by operating activities -Depreciation,
                depletion and amortization
            
            
            -
            
            
            125
            
            
            999
            
            
            -
            
            
            1,124Deferred
                income taxes
            
            
            2
            
            
            13
            
            
            93
            
            
            -
            
            
            108Unrealized
                loss on derivatives
            
            
            -
            
            
            (1
            )
            
            13
            
            
            -
            
            
            12Dry
                hole expense
            
            
            -
            
            
            2
            
            
            159
            
            
            -
            
            
            161Noncash
                stock-based compensation and ESOPexpense
            
            
            -
            
            
            -
            
            
            25
            
            
            -
            
            
            25Asset
                impairments
            
            
            -
            
            
            3
            
            
            33
            
            
            -
            
            
            36(Gain)
                loss on sale of assets
            
            
            -
            
            
            (1
            )
            
            21
            
            
            -
            
            
            20Accretion
                expense
            
            
            -
            
            
            3
            
            
            27
            
            
            -
            
            
            30Provision
                for environmental remediation andrestoration,
                net of reimbursements
            
            
            -
            
            
            -
            
            
            92
            
            
            -
            
            
            92Equity
                in earnings of subsidiaries
            
            
            (439
            )
            
            -
            
            
            -
            
            
            439
            
            
            -Other
                noncash items affecting net income
            
            
            2
            
            
            109
            
            
            36
            
            
            -
            
            
            147Changes
                in assets and liabilities
            
            
            (19
            )
            
            30
            
            
            (118
            )
            
            (2
            )
            
            (109
            )Net
                cash provided by (used in) operatingactivities
            
            
            (50
            )
            
            363
            
            
            1,737
            
            
            -
            
            
            2,050**Cash
                Flow from Investing Activities**Capital
                expenditures
            
            
            -
            
            
            (108
            )
            
            (1,154
            )
            
            -
            
            
            (1,262
            )Dry
                hole costs
            
            
            -
            
            
            (2
            )
            
            (76
            )
            
            -
            
            
            (78
            )Acquisitions,
                net of cash acquired
            
            
            -
            
            
            -
            
            
            43
            
            
            -
            
            
            43Proceeds
                from sale of assets
            
            
            -
            
            
            7
            
            
            16
            
            
            -
            
            
            23Other
                investing activities
            
            
            -
            
            
            -
            
            
            12
            
            
            -
            
            
            12Net
                cash used in investing activities
            
            
            -
            
            
            (103
            )
            
            (1,159
            )
            
            -
            
            
            (1,262
            )**Cash
                Flow from Financing Activities**Issuance
                of common stock upon exercise of stock options
            
            
            55
            
            
            -
            
            
            -
            
            
            -
            
            
            55Dividends
                paid
            
            
            (205
            )
            
            -
            
            
            -
            
            
            -
            
            
            (205
            )Increase
                (decrease) in intercompany notes payable
            
            
            (436
            )
            
            (260
            )
            
            696
            
            
            -
            
            
            -Repayment
                of debt
            
            
            -
            
            
            -
            
            
            (1,278
            )
            
            -
            
            
            (1,278
            )Proceeds
                from borrowings
            
            
            645
            
            
            -
            
            
            41
            
            
            -
            
            
            686Debt
                issuance costs and other
            
            
            (9
            )
            
            -
            
            
            1
            
            
            -
            
            
            (8
            )Settlement
                of Westport derivatives
            
            
            -
            
            
            -
            
            
            (101
            )
            
            -
            
            
            (101
            )Net
                cash provided by (used in) financingactivities
            
            
            50
            
            
            (260
            )
            
            (641
            )
            
            -
            
            
            (851
            )**Effects
                of Exchange Rate Changes on Cash and Cash****Equivalents**
            
            
            -
            
            
            -
            
            
            (3
            )
            
            -
            
            
            (3
            )**Net
                Decrease in Cash and Cash Equivalents**
            
            
            -
            
            
            -
            
            
            (66
            )
            
            -
            
            
            (66
            )**Cash
                and Cash Equivalents at Beginning of Year**
            
            
            2
            
            
            -
            
            
            140
            
            
            -
            
            
            142**Cash
                and Cash Equivalents at End of Year**
            
            $
            2
            
            $
            -
            
            $
            74
            
            $
            -
            
            $
            76











**Condensed
                Consolidating Statement of Cash Flows for the Year Ended December
                31,
                2003**(Millions
                of dollars)
            
            Kerr-McGee
                Corporation
            
            Guarantor
                Subsidiaries
            
            Non-Guarantor
                Subsidiaries
            
            Eliminations
            
            Consolidated**Cash
                Flow from Operating Activities**Net
                income
            
            $
            219
            
            $
            81
            
            $
            164
            
            $
            (245
            )
            $
            219Adjustments
                to reconcile net income to net cashprovided
                by operating activities -Depreciation,
                depletion and amortization
            
            
            -
            
            
            127
            
            
            687
            
            
            -
            
            
            814Deferred
                income taxes
            
            
            (6
            )
            
            23
            
            
            139
            
            
            -
            
            
            156Unrealized
                loss on derivatives
            
            
            -
            
            
            4
            
            
            1
            
            
            -
            
            
            5Dry
                hole expense
            
            
            -
            
            
            -
            
            
            181
            
            
            -
            
            
            181Noncash
                stock-based compensation and ESOPexpense
            
            
            -
            
            
            -
            
            
            42
            
            
            -
            
            
            42Asset
                impairments
            
            
            -
            
            
            -
            
            
            14
            
            
            -
            
            
            14Gain
                on sale of assets
            
            
            -
            
            
            -
            
            
            (40
            )
            
            -
            
            
            (40
            )Accretion
                expense
            
            
            -
            
            
            2
            
            
            23
            
            
            -
            
            
            25Cumulative
                effect of change in accounting principle
            
            
            -
            
            
            1
            
            
            34
            
            
            -
            
            
            35Provision
                for environmental remediation andrestoration,
                net of reimbursements
            
            
            -
            
            
            -
            
            
            62
            
            
            -
            
            
            62Equity
                in earnings of subsidiaries
            
            
            (245
            )
            
            -
            
            
            -
            
            
            245
            
            
            -Other
                noncash items affecting net income
            
            
            1
            
            
            1
            
            
            95
            
            
            -
            
            
            97Changes
                in assets and liabilities
            
            
            3
            
            
            (13
            )
            
            (82
            )
            
            -
            
            
            (92
            )Net
                cash provided by (used in) operatingactivities
            
            
            (28
            )
            
            226
            
            
            1,320
            
            
            -
            
            
            1,518**Cash
                Flow from Investing Activities**Capital
                expenditures
            
            
            -
            
            
            (129
            )
            
            (852
            )
            
            -
            
            
            (981
            )Dry
                hole costs
            
            
            -
            
            
            -
            
            
            (181
            )
            
            -
            
            
            (181
            )Acquisitions,
                net of cash acquired
            
            
            -
            
            
            -
            
            
            (110
            )
            
            -
            
            
            (110
            )Proceeds
                from sale of assets
            
            
            -
            
            
            8
            
            
            296
            
            
            -
            
            
            304Other
                investing activities
            
            
            -
            
            
            -
            
            
            17
            
            
            -
            
            
            17Net
                cash used in investing activities
            
            
            -
            
            
            (121
            )
            
            (830
            )
            
            -
            
            
            (951
            )**Cash
                Flow from Financing Activities**Dividends
                paid
            
            
            (181
            )
            
            -
            
            
            -
            
            
            -
            
            
            (181
            )Increase
                (decrease) in intercompany notes payable
            
            
            226
            
            
            (105
            )
            
            (121
            )
            
            -
            
            
            -Repayment
                of debt
            
            
            (18
            )
            
            -
            
            
            (351
            )
            
            -
            
            
            (369
            )Proceeds
                from borrowings
            
            
            -
            
            
            -
            
            
            31
            
            
            -
            
            
            31Other
                financing activities
            
            
            -
            
            
            -
            
            
            (1
            )
            
            -
            
            
            (1
            )Net
                cash provided by (used in) financingactivities
            
            
            27
            
            
            (105
            )
            
            (442
            )
            
            -
            
            
            (520
            )**Effects
                of Exchange Rate Changes on Cash and Cash****Equivalents**
            
            
            -
            
            
            -
            
            
            5
            
            
            -
            
            
            5**Net
                Increase (Decrease) in Cash and Cash Equivalents**
            
            
            (1
            )
            
            -
            
            
            53
            
            
            -
            
            
            52**Cash
                and Cash Equivalents at Beginning of Year**
            
            
            3
            
            
            -
            
            
            87
            
            
            -
            
            
            90**Cash
                and Cash Equivalents at End of Year**
            
            $
            2
            
            $
            -
            
            $
            140
            
            $
            -
            
            $
            142








**27. 
        Quarterly Financial Information (Unaudited)**





A
      summary of quarterly consolidated results for 2005 and 2004 is presented below.
      Net income for the third and fourth quarters of 2005 includes after-tax gains
      on
      sale of the company’s North Sea oil and gas business of $283 million and $1.8
      billion, respectively. Refer to Note 2 for additional information regarding
      the
      effects of disposals of discontinued businesses. The quarterly per-share amounts
      do not add to the annual amounts due to the effects of the weighted average
      of
      stock issued and the anti-dilutive effect of convertible debentures in certain
      quarters.








Income
                fromIncome
                from
            
            
            
            Continuing
                Operations(Millions
                of dollars,
            
            
            
            Operating
            
            Continuing
            
            Net
            
            per
                Common Shareexcept
                per-share amounts)
            
            Revenues(1)
            
            Profit(1)
            
            Operations(1)
            
            Income
            
            Basic(1)
            
            Diluted(1)**2005
                Quarter Ended -****March
                31**
            
            **$**
            **1,405**
            
            **$**
            **497**
            
            **$**
            **250**
            
            **$**
            **355**
            
            **$**
            **1.61**
            
            **$**
            **1.56****June
                30**
            
            
            **1,539**
            
            
            **541**
            
            
            **267**
            
            
            **371**
            
            
            **1.90**
            
            
            **1.87****September
                30**
            
            
            **1,208**
            
            
            **202**
            
            
            **53**
            
            
            **359**
            
            
            **.46**
            
            
            **.46****December
                31**
            
            
            **1,775**
            
            
            **609**
            
            
            **376**
            
            
            **2,126**
            
            
            **3.28**
            
            
            **3.22****Total**
            
            **$**
            **5,927**
            
            **$**
            **1,849**
            
            **$**
            **946**
            
            **$**
            **3,211**
            
            
            **7.22**
            
            
            **7.07**2004
                Quarter Ended -March
                31
            
            $
            891
            
            $
            254
            
            $
            110
            
            $
            152
            
            $
            1.10
            
            $
            1.03June
                30
            
            
            912
            
            
            204
            
            
            72
            
            
            111
            
            
            .70
            
            
            .67September
                30
            
            
            1,203
            
            
            157
            
            
            (24
            )
            
            7
            
            
            (.16
            )
            
            (.16
            )December
                31
            
            
            1,392
            
            
            276
            
            
            106
            
            
            134
            
            
            .71
            
            
            .69Total
            
            $
            4,398
            
            $
            891
            
            $
            264
            
            $
            404
            
            
            2.09
            
            
            2.08





(1)
            As
                discussed in Note 2, in the third quarter of 2005, criteria for presenting
                results of operations of the company’s North Sea oil and gas business as a
                discontinued operation were met. Therefore, revenues, income from
                continuing operations and per-share data in the above table differ
                from
                the quarterly amounts disclosed in the respective Forms
                10-Q.




















Five-Year
                  Financial Summary(Millions
                  of dollars, except per-share amounts)
              
              **2005**
              
              2004
                  (1)
              
              2003
              
              2002
              
              2001
                  (2)**Statement
                  of income summary**Revenues
              
              **$**
              **5,927**
              
              $
              4,398
              
              $
              3,289
              
              $
              2,579
              
              $
              2,516Costs
                  and operating expenses
              
              
              **4,302**
              
              
              3,719
              
              
              2,874
              
              
              2,486
              
              
              2,113Interest
                  and debt expense (3)
              
              
              **295**
              
              
              244
              
              
              250
              
              
              267
              
              
              186Total
                  costs and expenses
              
              
              **4,597**
              
              
              3,963
              
              
              3,124
              
              
              2,753
              
              
              2,299**1,330**
              
              
              435
              
              
              165
              
              
              (174
              )
              
              217Other
                  income (expense)
              
              
              **104**
              
              
              (34
              )
              
              (25
              )
              
              15
              
              
              219Benefit
                  (provision) for income taxes
              
              
              **(487**
              **)**
              
              (137
              )
              
              15
              
              
              62
              
              
              (157
              )Minority
                  interest, net of taxes
              
              
              **(1**
              **)**
              
              -
              
              
              -
              
              
              -
              
              
              -Income
                  (loss) from continuing operations
              
              **$**
              **946**
              
              $
              264
              
              $
              155
              
              $
              (97
              )
              $
              279**Effective
                  income tax rate**
              
              
              **34.0**
              **%**
              
              34.2
              %
              
              (10.7
              )%
              
              (39.0
              )%
              
              36.0
              %**Income
                  (loss) from continuing operations per common
                  share**Basic
              
              **$**
              **7.22**
              
              $
              2.09
              
              $
              1.55
              
              $
              (0.97
              )
              $
              2.87Diluted
              
              **$**
              **7.07**
              
              $
              2.08
              
              $
              1.54
              
              $
              (0.97
              )
              $
              2.80**Shares
                  outstanding at year-end (thousands)**
              
              
              **116,212**
              
              
              151,889
              
              
              100,860
              
              
              100,384
              
              
              100,185**Per
                  share information -**Dividends
                  declared
              
              **$**
              **.60**
              
              $
              1.80
              
              $
              1.80
              
              $
              1.80
              
              $
              1.80Stockholders’
                  equity(4)
              
              
              **35.17**
              
              
              32.86
              
              
              23.79
              
              
              23.01
              
              
              28.83Market
                  prices -High
              
              
              **98.83**
              
              
              63.24
              
              
              48.59
              
              
              63.58
              
              
              74.10Low
              
              
              **55.38**
              
              
              46.92
              
              
              37.82
              
              
              38.02
              
              
              46.94Year-end
              
              
              **90.86**
              
              
              57.79
              
              
              46.49
              
              
              44.30
              
              
              54.80**Balance
                  sheet information -**Property,
                  plant and equipment - net
              
              **$**
              **9,275**
              
              $
              9,073
              
              $
              5,525
              
              $
              5,066
              
              $
              4,492Total
                  assets
              
              
              **14,276**
              
              
              14,518
              
              
              10,250
              
              
              9,909
              
              
              11,076Long-term
                  debt
              
              
              **2,825**
              
              
              3,236
              
              
              3,081
              
              
              3,798
              
              
              4,540Total
                  debt
              
              
              **3,133**
              
              
              3,699
              
              
              3,655
              
              
              3,904
              
              
              4,574Stockholders’
                  equity
              
              
              **4,115**
              
              
              5,318
              
              
              2,636
              
              
              2,536
              
              
              3,174**Cash
                  flow information -**Net
                  cash provided by operating activities
              
              **$**
              **3,103**
              
              $
              2,050
              
              $
              1,518
              
              $
              1,448
              
              $
              1,143Capital
                  expenditures (5)
              
              
              **1,920**
              
              
              1,340
              
              
              1,162
              
              
              1,272
              
              
              1,864Dividends
                  paid
              
              
              **153**
              
              
              205
              
              
              181
              
              
              181
              
              
              173Repurchases
                  of Kerr-McGee stock
              
              
              **4,225**
              
              
              -
              
              
              -
              
              
              -
              
              
              -**Ratios
                  -**Current
                  ratio
              
              
              **.8**
              
              
              .8
              
              
              .8
              
              
              .8
              
              
              1.2Average
                  price/earnings ratio
              
              
              **3.2**
              
              
              17.3
              
              
              19.9
              
              
              NM
              
              
              12.8Debt
                  to total capitalization (6)
              
              
              **42**
              **%**
              
              41
              %
              
              58
              %
              
              61
              %
              
              59
              %








(1)
            As
                described in Note 4 to the Consolidated Financial Statements, on
                June 25,
                2004, the company completed a merger with Westport Resources
                Corporation.





(2)
            On
                August 1, 2001, the company completed an acquisition of HS Resources
                for a
                total cost of $1.8 billion, consisting of cash of $955 million, assumption
                of debt of $506 million and issuance of 5.1 million common shares.
                Additionally, effective January 1, 2001, the company implemented
                FAS 133,
                “Accounting for Derivatives and Hedging Activities” (FAS 133), as amended.
                In conjunction with implementation, the company recorded the fair
                value of
                its derivative instruments on the balance sheet, including options
                embedded in the company’s debt exchangeable for stock (DECS) of Devon
                Energy Corporation owned by the company. Further, the company chose
                to
                reclassify a portion of Devon shares owned from available-for-sale
                to
                trading category. As a result, the company recognized, as a component
                of
                other income (expense), an unrealized gain on securities of $181
                million.





(3)
            Includes
                losses on early repayment and modification of
                debt.





(4)
            Stockholder’s
                equity per share for all periods presented reflects the effect of
                potential dilution, assuming potentially issuable shares are issued
                at the
                end of the reporting period.





(5)
            Inclusive
                of dry hole costs and exclusive of acquisition cost (net of cash
                acquired).





(6)
            Determined
                as total debt plus total stockholders’ equity and, in 2005, minority
                stockholders’ interest in net assets of
                Tronox.







**Five-Year
                  Operating Summary****2005**
              
              2004
              
              2003
              
              2002
              
              2001Crude
                  oil and condensate production(thousands
                  of barrels per day) -United
                  States
              
              
              **90**
              
              
              88
              
              
              77
              
              
              81
              
              
              78China
              
              
              **19**
              
              
              8
              
              
              2
              
              
              3
              
              
              4Other
                  international
              
              
              **-**
              
              
              -
              
              
              -
              
              
              4
              
              
              5Total
                  - continuing operations
              
              
              **109**
              
              
              96
              
              
              79
              
              
              88
              
              
              87Average
                  price of crude oil (per barrel) -United
                  States
              
              **$**
              **42.55**
              
              $
              29.11
              
              $
              26.14
              
              $
              21.56
              
              $
              22.05China
              
              
              **44.45**
              
              
              32.37
              
              
              29.66
              
              
              24.84
              
              
              21.94Other
                  international
              
              
              **-**
              
              
              -
              
              
              -
              
              
              20.28
              
              
              19.14Average
                  - continuing operations
              
              **$**
              **42.89**
              
              $
              29.38
              
              $
              26.24
              
              $
              21.62
              
              $
              21.91U.S.
                  natural gas production (MMcf per day)
              
              
              **962**
              
              
              836
              
              
              629
              
              
              660
              
              
              534U.S.
                  average price of natural gas (per Mcf)
              
              **$**
              **6.66**
              
              $
              5.24
              
              $
              4.56
              
              $
              3.04
              
              $
              4.00Net
                  exploratory wells drilled(1)-Productive
              
              
              **13.8**
              
              
              13.6
              
              
              6.7
              
              
              4.8
              
              
              2.4Dry
              
              
              **16.3**
              
              
              15.3
              
              
              17.0
              
              
              17.2
              
              
              11.4Total
              
              
              **30.1**
              
              
              28.9
              
              
              23.7
              
              
              22.0
              
              
              13.8Net
                  development wells drilled(1)-Productive
              
              
              **457.5**
              
              
              429.8
              
              
              244.4
              
              
              196.3
              
              
              128.6Dry
              
              
              **9.9**
              
              
              7.5
              
              
              1.1
              
              
              1.4
              
              
              6.6Total
              
              
              **467.4**
              
              
              437.3
              
              
              245.5
              
              
              197.7
              
              
              135.2Undeveloped
                  net acreage (thousands)(1)-United
                  States
              
              
              **3,336**
              
              
              3,367
              
              
              2,884
              
              
              2,399
              
              
              2,382North
                  Sea
              
              
              **-**
              
              
              392
              
              
              369
              
              
              871
              
              
              932China
              
              
              **3,873**
              
              
              1,469
              
              
              1,488
              
              
              1,046
              
              
              917Other
                  international
              
              
              **23,787**
              
              
              30,455
              
              
              47,178
              
              
              41,514
              
              
              50,450Total
              
              
              **30,996**
              
              
              35,683
              
              
              51,919
              
              
              45,830
              
              
              54,681Developed
                  net acreage (thousands)(1)-United
                  States
              
              
              **2,010**
              
              
              2,134
              
              
              1,352
              
              
              1,266
              
              
              1,192North
                  Sea
              
              
              **-**
              
              
              122
              
              
              136
              
              
              109
              
              
              149China
              
              
              **9**
              
              
              9
              
              
              -
              
              
              17
              
              
              17Other
                  international
              
              
              **-**
              
              
              -
              
              
              -
              
              
              1
              
              
              639Total
              
              
              **2,019**
              
              
              2,265
              
              
              1,488
              
              
              1,393
              
              
              1,997Estimated
                  proved reserves(1)-(millions
                  of equivalent barrels)
              
              
              **968**
              
              
              1,218
              
              
              1,026
              
              
              1,033
              
              
              1,509





(1)
            Includes
                discontinued operations.




**Item
        9** .  **Changes
        in and Disagreements with Accountants on Accounting and Financial
        Disclosure**


None.




**Item
      9A.**  **Controls
      and Procedures**





As
      of
      the end of the period covered by this report, an evaluation was carried out
      under the supervision and with the participation of the company's management,
      including its chief executive officer and chief financial officer, of the
      effectiveness of the company's disclosure controls and procedures pursuant
      to
      Exchange Act Rule 13a-15. Based on that evaluation, the chief executive officer
      and chief financial officer concluded that the company's disclosure controls
      and
      procedures are effective in alerting them in a timely manner to material
      information relating to the company (including its consolidated subsidiaries)
      required to be included in the company's periodic SEC filings. There was no
      change in the company's internal control over financial reporting that occurred
      during the fourth quarter of 2005 that has materially affected or is reasonably
      likely to materially affect the company’s internal control over financial
      reporting.





**Management’s
      Report on Internal Control over Financial Reporting**





This
      report is included in Item 8 on page 74 of this report and is incorporated
      by
      reference.





**PART
      III**





**Item
      10.**  **Directors
      and Executive Officers of the Registrant**





(a)  Identification
      of directors -





For
      information required under this section, reference is made to the "Director
      Information" section of the company's proxy statement made in connection with
      its Annual Stockholders' Meeting to be held on May 9, 2006.





(b)  Identification
      of executive officers -





The
      information required under this section is set forth in the caption "Executive
      Officers of the Registrant" on pages 27 and 28 of this Annual Report on Form
      10-K pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General
      Instruction G(3) to Form 10-K.





(c)  Compliance
      with Section 16(a) of the 1934 Act -





For
      information required under this section, reference is made to the "Section
      16(a)
      Beneficial Ownership Reporting Compliance" section of the company's proxy
      statement made in connection with its Annual Stockholders' Meeting to be held
      on
      May 9, 2006.





(d)  Code
      of
      Ethics for the Chief Executive Officer and Principal Financial Officers
      -





Information
      regarding the Code of Ethics for the Chief Executive Officer and Principal
      Financial Officers can be found in Items 1 and 2 of this Annual Report on Form
      10-K under "Availability of Reports and Governance Documents."





**Item
      11.**  **Executive
      Compensation**





For
      information required under this section, reference is made to the executive
      compensation sections of the company's proxy statement made in connection with
      its Annual Stockholders' Meeting to be held on May 9, 2006.








**Item
        12.**  **Security
        Ownership of Certain Beneficial Owners and Management** **and
        Related Stockholder Matters**





Information
      regarding Kerr-McGee common stock that may be issued under the company’s equity
      compensation plans as of December 31, 2005, is included in the following
      table:





Number
                of shares of common stock to be issued upon exercise of outstanding
                options, warrants and rights
            Weighted-average
                exercise price of outstanding options, warrants and rights
            Number
                of shares remaining available for future issuance under equity
                compensation plans (1)Equity
                compensation plans approvedby
                security holders
            4,344,311
            $56.15
            9,998,180Equity
                compensation plans notapproved
                by security holders
            454,813
            46.15
            -Total
            4,799,124
            53.21
            9,998,180





(1)
            Excludes
                shares to be issued upon exercise of outstanding options, warrants
                and
                rights.





The
      Kerr-McGee Corporation Performance Share Plan was approved by the Board of
      Directors in January 1998 but was not approved by the company's stockholders.
      The plan was terminated in September 2005. This plan was a broad-based stock
      option plan that provided for the granting of options to purchase the company's
      common stock to full-time, nonbargaining-unit employees, except officers. A
      total of 1,500,000 shares of common stock were authorized to be issued under
      this plan. A copy of the plan document was attached as exhibit 10.19 to the
      company's December 31, 2002 Form 10-K and is incorporated by reference in
      exhibit 10.18 to the company’s December 31, 2005 Form 10-K.





Awards
      under certain equity compensation plans of Oryx Energy Company and Westport
      Resources Corporation were assumed by the company in connection with its
      acquisitions of Oryx and Westport. The terms of those awards are governed by
      the
      Oryx and Westport plans, respectively. The plans, which provided for the
      granting of stock options to officers and employees of Oryx and Westport, did
      not require approval of Kerr-McGee stockholders. No further grants may be made
      under the Oryx or Westport plans.





For
      information required under Item 403 of Regulation S-K, reference is made to
      the
      "Ownership of Stock of the Company" section of the company's proxy statement
      made in connection with its Annual Stockholders' Meeting to be held on May
      9,
      2006.





**Item
      13.**  **Certain
      Relationships and Related Transactions**





For
      information required under this section, reference is made to the “Transactions
      with Management and Others” section of the company's proxy statement made in
      connection with its Annual Stockholders' Meeting to be held on May 9,
      2006.





**Item
      14.**  **Principal
      Accountant Fees and Services**





For
      information required under this section, reference is made to the “Fees Paid to
      the Independent Auditors” section of the company's proxy statement made in
      connection with its Annual Stockholders' Meeting to be held on May 9,
      2006.







**PART
      IV**





**Item
                15.**
            
            **Exhibits,
                Financial Statement Schedules, and Reports on Form
                8-K**(a)
            1.
            Financial
                Statements - See the Index to the Consolidated Financial Statements
                included in Item 8 of this Annual Report on Form 10-K.(a)
            2.
            Financial
                Statement Schedules - See the Index to the Financial Statement Schedules
                included in Item 8 of this Annual Report on Form 10-K.(a)
            3.
            Exhibits
                - The following documents are filed under Security and Exchange Commission
                file numbers 1-16619 and 1-3939 as part of this
                report.





Exhibit
                No.3.1
            Amended
                and restated Certificate of Incorporation of Kerr-McGee Corporation,
                filed
                as Exhibit 4.1 to the Registration Statement on Form S-4 dated June
                28,
                2001, and incorporated herein by reference.3.2
            Certificate
                of Amendment of Amended and Restated Certificate of Incorporation
                of
                Kerr-McGee Corporation, filed as Exhibit 3.1 to the Current Report
                onForm
                8-K dated May 12, 2005, and incorporated herein by
                reference.3.3
            Amended
                and Restated ByLaws of Kerr-McGee Corporation, filed as Exhibit 3.1
                to the
                Current Report on Form 8-K dated April 14, 2005, and incorporated
                herein
                by reference.4.1
            Rights
                Agreement dated as of July 26, 2001, by and between the company and
                UMB
                Bank, N.A., filed as Exhibit 4.1 to the Registration Statement on
                Form 8-A
                filed on July 27, 2001, and incorporated herein by
                reference.4.2
            First
                Amendment to Rights Agreement, dated as of July 30, 2001, by and
                between
                the company and UMB Bank, N.A., filed as Exhibit 4.1 to the Registration
                Statement on Form 8-A/A filed on August 1, 2001, and incorporated
                herein
                by reference.4.3
            Indenture
                dated as of August 1, 1982, filed as Exhibit 4 to the Registration
                Statement on Form S-3, effective August 27, 1982, Registration Statement
                No. 2-78952, and incorporated herein by reference, and the first
                supplement thereto dated May 7, 1996, between the company and Citibank,
                N.A., as trustee, relating to the company’s 6.625% notes due October 15,
                2007, and 7.125% debentures due October 15, 2027, filed as Exhibit
                4.1 to
                the Current Report on Form 8-K filed July 27, 1999, and incorporated
                herein by reference.4.4
            Indenture
                dated as of August 1, 2001, between the company and Citibank, N.A.,
                as
                trustee, relating to the company's $325 million, 5-7/8% notes due
                September 15, 2006; $675 million, 6-7/8% notes due September 15,
                2011;
                $500 million 7-7/8% notes due September 15, 2031; and $650 million,
                6.95%
                notes due July 1, 2024, filed as Exhibit 4.1 to the Pre-effective
                Amendment No. 1 to the Registration Statement on Form S-3 filed August
                30,
                2001, and incorporated herein by reference.4.5
            Supplemental
                Indenture, dated September 21, 2005, amending the Indenture dated
                as of
                August 1, 2001, between the company and Citibank, N.A., as Trustee,
                filed
                as Exhibit 99.1 to the Current Report on Form 8-K dated September
                27,
                2005, and incorporated herein by reference.










Exhibit
                  No.4.6
              The
                  company agrees to furnish to the Securities and Exchange Commission,
                  upon
                  request, copies of each of the following instruments defining the
                  rights
                  of the holders of certain long-term debt of the Registrant: the
                  Note
                  Agreement dated as of November 29, 1989, among the Kerr-McGee Corporation
                  Employee Stock Ownership Plan Trust, referred to as the Trust,
                  and several
                  lenders, providing for a loan guaranteed by the company of $125
                  million to
                  the Trust; and the Credit Agreement dated as of January 9, 2006,
                  among the
                  company and various banks providing for revolving credit up to
                  $1.25
                  billion through January 9, 2011. The total amount of securities
                  authorized
                  under each of such instruments does not exceed 10% of the total
                  assets of
                  the Registrant and its subsidiaries on a consolidated
                  basis.4.7
              Kerr-McGee
                  Corporation Direct Purchase and Dividend Reinvestment Plan filed
                  on
                  September 9, 2001, pursuant to Rule 424(b)(2) of the Securities
                  Act of
                  1933 as the Prospectus Supplement to the Prospectus dated August
                  31, 2001,
                  andincorporated
                  herein by reference.10.1*
              Kerr-McGee
                  Corporation Deferred Compensation Plan for Non-Employee Directors
                  as
                  amended and restated effective January 1, 2003, filed as Exhibit
                  10.1 to
                  the Annual Report on Form 10-K for the year ended December 31,
                  2002, and
                  incorporated herein by reference.10.2*
              Amendment
                  No. 1 to the Kerr-McGee Corporation Deferred Compensation Plan
                  for
                  Non-Employee Directors as amended and restated effective January
                  1, 2003,
                  dated December 14, 2005.10.3*
              Kerr-McGee
                  Corporation Executive Deferred Compensation Plan as amended and
                  restated
                  effective January 1, 2003, filed as Exhibit 10.4 to the Annual
                  Report on
                  Form 10-K for the year ended December 31, 2002, and incorporated
                  herein by
                  reference.10.4*
              Amendment
                  No. 1 to the Kerr-McGee Corporation Executive Deferred Compensation
                  Plan
                  as amended and restated effective January 1, 2003, dated December
                  14,
                  2005.10.5*
              Benefits
                  Restoration Plan as amended and restated effective May 1, 1999,
                  filed as
                  Exhibit 10.3 to the Annual Report on Form 10-K for the year ended
                  December
                  31, 2003, and incorporated herein by reference.10.6*
              First
                  Supplement to Benefits Restoration Plan as amended and restated
                  effective
                  January 1, 2000, filed as Exhibit 10.4 to the Annual Report on
                  Form 10-K
                  for the year ended December 31, 2003, and incorporated herein by
                  reference.10.7*
              Second
                  Supplement to Benefits Restoration Plan as amended and restated
                  effective
                  January 1, 2001, filed as Exhibit 10.5 to the Annual Report on
                  Form 10-K
                  for the year ended December 31, 2003, and incorporated herein by
                  reference.10.8*
              Kerr-McGee
                  Corporation Supplemental Executive Retirement Plan as amended and
                  restated
                  effective February 26, 1999, filed as Exhibit 10.6 to the Annual
                  Report on
                  Form 10-K for the year ended December 31, 2001, and incorporated
                  herein by
                  reference.10.9*
              First
                  Supplement to the Kerr-McGee Corporation Supplemental Executive
                  Retirement
                  Plan as amended and restated effective February 26, 1999, filed
                  as Exhibit
                  10.7 to the Annual Report on Form 10-K for the year ended December
                  31,
                  2001, and incorporated herein by
                  reference.
  
 Exhibit
                  No.10.10*
              Amended
                  and Restated Second Supplement to the Kerr-McGee Corporation Supplemental
                  Executive Retirement Plan as amended and restated effective February
                  26,
                  1999, filed as Exhibit 10.8 to the Annual Report on Form 10-K for
                  the year
                  ended December 31, 2004, and incorporated herein by reference.10.11*
              Amendment
                  No. 1 to the Kerr-McGee Corporation Supplemental Executive Retirement
                  Plan
                  Amended and Restated effective as of February 26, 1999, dated October
                  19,
                  2005, filed as Exhibit 10.9 to the Quarterly Report on Form 10-Q
                  for the
                  quarter ended September 30, 2005, and incorporated herein by
                  reference.10.12*
              The
                  Long Term Incentive Program as amended and restated effective May
                  9, 1995,
                  filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q for
                  the quarter
                  ended March 31, 1995, and incorporated herein by
                  reference.10.13*
              The
                  Kerr-McGee Corporation 1998 Long Term Incentive Plan effective
                  January 1,
                  1998, filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q
                  for the
                  quarter ended March 31, 1998, and incorporated herein by
                  reference.10.14*
              The
                  Kerr-McGee Corporation 2000 Long Term Incentive Plan effective
                  May 1,
                  2000, filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q
                  for the
                  quarter ended March 31, 2000, and incorporated herein by
                  reference.10.15*
              The
                  2002 Long Term Incentive Plan effective May 14, 2002, filed as
                  Exhibit
                  10.2 to the Quarterly Report on Form 10-Q for the quarter ended
                  June 30,
                  2002, and incorporated herein by reference.10.16*
              The
                  2005 Long Term Incentive Plan effective May 10, 2005, filed as
                  Exhibit
                  10.1 to the Current Report on Form 8-K dated May 12, 2005, and
                  incorporated herein by reference.10.17*
              The
                  2002 Annual Incentive Compensation Plan effective May 14, 2002,
                  filed as
                  Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter
                  ended
                  June 30, 2002, and incorporated herein by reference.10.18*
              Kerr-McGee
                  Corporation Performance Share Plan effective January 1, 1998, filed
                  as
                  Exhibit 10.19 to the Annual Report on Form 10-K for the year ended
                  December 31, 2002, and incorporated herein by
                  reference.10.19*
              Oryx
                  Energy Company 1992 Long-Term Incentive Plan, as amended and restated
                  May
                  1, 1997, filed as Exhibit 10.15 to the Annual Report on Form 10-K
                  for the
                  year ended December 31, 2003, and incorporated herein by
                  reference.10.20*
              Oryx
                  Energy Company 1997 Long-Term Incentive Plan, as amended and restated
                  May
                  1, 1997, filed as Exhibit 10.16 to the Annual Report on Form 10-K
                  for the
                  year ended December 31, 2003, and incorporated herein by
                  reference.10.21*
              Amended
                  and Restated Agreement, restated as of January 11, 2000, between
                  the
                  company and Luke R. Corbett filed as Exhibit 10.10 to the Annual
                  Report on
                  Form 10-K for the year ended December 31, 2000, and incorporated
                  herein by
                  reference.10.22*
              Amended
                  and Restated Agreement, restated as of January 11, 2000, between
                  the
                  company and Kenneth W. Crouch filed as Exhibit 10.11 to the Annual
                  Report
                  on Form 10-K for the year ended December 31, 2000, and incorporated
                  herein
                  by reference.








Exhibit
                No.10.23*
            Amended
                and Restated Agreement, restated as of January 11, 2000, between
                the
                company and Robert M. Wohleber filed as Exhibit 10.12 to the Annual
                Report
                on Form 10-K for the year ended December 31, 2000, and incorporated
                herein
                by reference.10.24*
            Amended
                and Restated Agreement, restated as of January 11, 2000, between
                the
                company and Gregory F. Pilcher filed as Exhibit 10.14 to the Annual
                Report
                on Form 10-K for the year ended December 31, 2000, and incorporated
                herein
                by reference.10.25*
            Agreement,
                dated as of September 3, 2002, between the company and David A. Hager
                filed as Exhibit 10.21 to the Annual Report on Form 10-K for the
                year
                ended December 31, 2004, and incorporated herein by
                reference.10.26*
            Registration
                Rights Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation,
                Westport Energy LLC, Medicor Foundation and EQT Investments, LLC,
                filed as
                Exhibit 99.7 to the Current Report on Form 8-K dated April 8, 2004,
                and
                incorporated herein by reference.10.27*
            Compensation
                Arrangements with Non-Employee Directors, filed as Exhibit 10.1 to
                the
                Current Report on Form 8-K dated January 17, 2006, and incorporated
                herein
                by reference.10.28*
            Compensation
                Arrangements with Named Executive Officers, filed as Exhibit 10.2
                to the
                Current Report on Form 8-K dated January 17, 2006, and incorporated
                herein
                by reference.10.29
            Voting
                Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation,
                Belfer
                Corp., Renee Holdings Partnership, L.P., Vantz Limited Partnership,
                LDB
                Two Corp., Belfer Two Corp., Liz Partners, L.P., filed as Exhibit
                99.2 to
                the Current Report on Form 8-K dated April 8, 2004, and incorporated
                herein by reference.10.30
            Voting
                Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation
                and EQT
                Investments, LLC, filed as Exhibit 99.3 to the Current Report on
                Form 8-K
                dated April 8, 2004, and incorporated herein by
                reference.10.31
            Voting
                Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation
                and
                Medicor Foundation, filed as Exhibit 99.4 to the Current Report on
                Form
                8-K dated April 8, 2004, and incorporated herein by
                reference.10.32
            Voting
                Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation
                and
                Westport Energy LLC., filed as Exhibit 99.5 to the Current Report
                on Form
                8-K dated April 8, 2004, and incorporated herein by
                reference.10.33
            Voting
                Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation
                and
                Donald D. Wolf, filed as Exhibit 99.6 to the Current Report on Form
                8-K
                dated April 8, 2004, and incorporated herein by
                reference.10.34
            Amended
                and Restated Gas Purchase Agreement, dated July 1, 1998, among Oryx
                Gas
                Marketing Limited Partnership, Sun Operating Limited Partnership
                and
                Producers Energy Marketing, LLC, filed as Exhibit 10.23 to the Amendment
                to Annual Report on Form 10-K/A for the year ended December 31, 2003,
                and
                incorporated herein by
                reference.








Exhibit
                No10.35
            Amendment
                to Amended and Restated Gas Purchase Agreement, dated May 1, 2000,
                among
                Oryx Gas Marketing Limited Partnership, Kerr-McGee Oil & Gas
                Corporation, Kerr-McGee Oil and Gas Onshore LP, and Cinergy Marketing
                & Trading, LLC, filed as Exhibit 10.24 to the Amendment to Annual
                Report on Form 10-K/A for the year ended December 31, 2003, and
                incorporated herein by reference.10.36
            Amendment
                No. 2 to Amended and Restated Gas Purchase Agreement, dated July
                1, 2002,
                among Oryx Gas Marketing Limited Partnership, Kerr-McGee Oil & Gas
                Corporation, Kerr-McGee Oil and Gas Onshore LP, and Cinergy Marketing
                & Trading, LLC, filed as Exhibit 10.25 to the Amendment to Annual
                Report on Form 10-K/A for the year ended December 31, 2003, and
                incorporated herein by reference.10.37
            Letter
                Agreement, dated May 23, 2003, amending Amended and Restated Gas
                Purchase
                Agreement, dated July 1, 1998, among Kerr-McGee Oil & Gas Corporation,
                Kerr-McGee Oil and Gas Onshore LP, and Cinergy Marketing & Trading,
                LLC, filed as Exhibit 10.26 to the Amendment to Annual Report on
                Form
                10-K/A for the year ended December 31, 2003, and incorporated herein
                by
                reference.10.38*
            Oryx
                Energy Company Executive Retirement Plan, as amended and restated
                January
                1, 1995, filed as Exhibit 10.34A to the Annual Report on Form 10-K
                for the
                year ended December 31, 2004, and incorporated herein by
                reference.10.39
            Agreement,
                dated April 14, 2005, between the Company, Carl C. Icahn, Barberry
                Corporation, Hopper Investments, LLC, High River Limited Partnership,
                Icahn Partners Master Fund LP, Icahn Offshore LP, CCI Offshore LLC,
                Icahn
                Partners LP, Icahn Onshore LP and CCI Onshore LLC and Barry Rosenstein,
                Gary Claar and JANA Partners LLC, filed as Exhibit 10.1 to the Current
                Report on Form 8-K dated April 14, 2005, and incorporated herein
                by
                reference.10.40
            Retirement
                Benefit Preservation Agreement, dated July 18, 2005 between
                Kerr-McGee Corporation and Luke R. Corbett, filed as Exhibit 99.2
                to the
                Current Report on Form 8-K dated July 18, 2005, and incorporated
                herein by
                reference.10.41
            Retirement
                Benefit Preservation Agreement, dated July 18, 2005 between
                Kerr-McGee Corporation and Kenneth W. Crouch, filed as Exhibit 99.3
                to the
                Current Report on Form 8-K dated July 18, 2005, and incorporated
                herein by
                reference.10.42
            Agreement
                and Plan of Merger, dated January 23, 2006, among Kerr-McGee Oil
& Gas
                Corporation, Kerr-McGee Oil & Gas (Shelf) LLC, W&T Offshore, Inc.,
                and W&T Energy V, LLC.10.43
            Sale
                and Purchase Agreement between Kerr-McGee North Sea (U.K.) Limited
                (“KM
                North Sea”) and Centrica Resources Limited (“Centrica”), dated August 6,
                2005, pursuant to which KM North Sea agreed to sell its nonoperating
                interest in the Skene field assets to Centrica, filed as Exhibit
                10.1 to
                the Quarterly Report on Form 10-Q for the quarter ended September
                30,
                2005, and incorporated herein by reference.10.44
            Sale
                and Purchase Agreement between KM North Sea and Centrica, dated August
                6,
                2005, pursuant to which KM North Sea agreed to sell its nonoperating
                interest in the Buckland field assets to Centrica, filed as Exhibit
                10.2
                to the Quarterly Report on Form 10-Q for the quarter ended September
                30,
                2005, and incorporated herein by
                reference.








Exhibit
                No.10.45
            Letter
                Agreement between KM North Sea and Centrica dated August 30, 2005,
                amending (i) the Sale and Purchase Agreement between KM North Sea
                and
                Centrica, dated August 6, 2005, pursuant to which KM North Sea agreed
                to
                sell its nonoperating interest in the Skene field assets to Centrica
                and
                (ii) the Sale and Purchase Agreement between KM North Sea and Centrica,
                dated August 6, 2005, pursuant to which KM North Sea agreed to sell
                its
                nonoperating interest in the Buckland field assets to Centrica, filed
                as
                Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter
                ended
                September 30, 2005, and incorporated herein by
                reference.10.46
            Sale
                and Purchase Agreement between KM North Sea and Talisman North Sea
                Limited
                (“Talisman”), dated September 30, 2005, pursuant to which KM North Sea
                agreed to sell its nonoperating interest in the Andrew field assets
                to
                Talisman, filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q
                for
                the quarter ended September 30, 2005, and incorporated herein by
                reference.10.47
            Sale
                and Purchase Agreement between Kerr-McGee Oil (U.K.) Limited (“KM Oil”)
                and Centrica, dated August 6, 2005, pursuant to which KM Oil agreed
                to
                sell its nonoperating interest in the Brae field assets to Centrica,
                filed
                as Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter
                ended
                September 30, 2005, and incorporated herein by
                reference.10.48
            Sale
                and Purchase Agreement between KM Denmark Overseas ApS (“KM Denmark”) and
                Centrica Canada Limited (“Centrica Canada”), dated August 6, 2005,
                pursuant to which KM Denmark agreed to sell 100% of the stock of
                Kerr-McGee Canada Limited (“KM Canada”) to Centrica Canada, filed as
                Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter
                ended
                September 30, 2005, and incorporated herein by
                reference.10.49
            Sale
                and Purchase Agreement between KM Denmark, Alnery No. 2524 Limited
                (“Maersk”), the Company and A.P. Moller-Maersk A/S, dated August 7, 2005,
                pursuant to which KM Denmark agreed to sell all of the company’s remaining
                North Sea assets through the sale of 100% of the stock of Kerr-McGee
                (G.B.) Limited and Kerr-McGee Norway AS to Maersk, filed as Exhibit
                10.7
                to the Quarterly Report on Form 10-Q for the quarter ended September
                30,
                2005, and incorporated herein by reference.10.50
            Sale
                and Purchase Agreement between KM North Sea and Amerada Hess Limited
                (“Hess”), dated September 30, 2005, pursuant to which KM North Sea agreed
                to sell its nonoperating interest in the UKCS License 103 Area W
                to Hess,
                filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q for the
                quarter
                ended September 30, 2005, and incorporated herein by
                reference.10.51
            Master
                Separation Agreement, dated as of November 28, 2005, among Kerr-McGee
                Corporation, Kerr-McGee Worldwide Corporation, and Tronox
                Incorporated.10.52
            Employee
                Benefits Agreement, dated as of November 28, 2005, by and between
                Kerr-McGee Corporation and Tronox Incorporated.10.53
            Tax
                Sharing Agreement dated as of November 28, 2005, between Kerr-McGee
                Corporation and Tronox Incorporated.10.54
            Transition
                Services Agreement, dated as of November 28, 2005, among Kerr-McGee
                Corporation, Kerr-McGee Worldwide Corporation and Tronox
                Incorporated.








Exhibit
                No.10.55
            2005
                Annual Incentive Compensation Plan Awards, filed as Exhibit 10.1
                to the
                Current Report on Form 8-K dated February 27, 2006, and incorporated
                herein by reference.12
            Computation
                of ratio of earnings to fixed charges.21
            Subsidiaries
                of the Registrant.23.1
            Consent
                of Ernst & Young LLP.23.2
            Consent
                of Netherland, Sewell & Associates, Inc.24
            Powers
                of Attorney.31.1
            Certification
                pursuant to Securities Exchange Act Rule 15d-14(a), as adopted pursuant
                to
                Section 302 of the Sarbanes-Oxley Act of 2002.31.2
            Certification
                pursuant to Securities Exchange Act Rule 15d-14(a), as adopted pursuant
                to
                Section 302 of the Sarbanes-Oxley Act of 2002.32.1
            Certification
                pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002.32.2
            Certification
                pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002.99
            Report
                of Netherland, Sewell & Associates,
                Inc.











*These
      exhibits relate to the compensation plans and arrangements of the
      company.








**SCHEDULE
      II**





**KERR-McGEE
      CORPORATION AND SUBSIDIARY COMPANIES**


**VALUATION
      ACCOUNTS AND RESERVES**








AdditionsBalance
                at
            
            Charged
                to
            
            Charged
                to
            
            Deductions
            
            Balance
                atBeginning
            
            Profit
                and
            
            Other
            
            from
            
            End
                of(Millions
                of dollars)
            
            of
                Year
            
            Loss
            
            Accounts
            
            Reserves
            
            YearYear
                Ended December 31, 2005Deducted
                from asset accountsAllowance
                for doubtful notesand
                accounts receivable
            
            $
            23
            
            $
            2
            
            $
            (1
            )
            $
            -
            
            $
            24Valuation
                allowance fordeferred
                tax assets
            
            
            8
            
            
            -
            
            
            -
            
            
            2
            
            
            6Warehouse
                inventoryobsolescence
            
            
            12
            
            
            2
            
            
            -
            
            
            4
            
            
            10Total
            
            $
            43
            
            $
            4
            
            $
            (1
            )
            $
            6
            
            $
            40Year
                Ended December 31, 2004Deducted
                from asset accountsAllowance
                for doubtful notesand
                accounts receivable
            
            $
            19
            
            $
            4
            
            $
            2
            
            $
            2
            
            $
            23Valuation
                allowance fordeferred
                tax assets
            
            
            9
            
            
            1
            
            
            -
            
            
            2
            
            
            8Warehouse
                inventoryobsolescence
            
            
            8
            
            
            5
            
            
            -
            
            
            1
            
            
            12Total
            
            $
            36
            
            $
            10
            
            $
            2
            
            $
            5
            
            $
            43Year
                Ended December 31, 2003Deducted
                from asset accountsAllowance
                for doubtful notesand
                accounts receivable
            
            $
            19
            
            $
            1
            
            $
            -
            
            $
            1
            
            $
            19Valuation
                allowance fordeferred
                tax assets
            
            
            -
            
            
            9
            
            
            -
            
            
            -
            
            
            9Warehouse
                inventoryobsolescence
            
            
            4
            
            
            6
            
            
            -
            
            
            2
            
            
            8Total
            
            $
            23
            
            $
            16
            
            $
            -
            
            $
            3
            
            $
            36











SIGNATURES





Pursuant
      to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
      1934, the registrant has duly caused this report to be signed on its behalf
      by
      the undersigned, thereunto duly authorized.





KERR-McGEE
                CORPORATIONBy:
            Luke
                R. Corbett*Luke
                R. Corbett, DirectorChief
                Executive OfficerMarch
                15, 2006
            By:
            (Robert
                M. Wohleber)Date
            
            Robert
                M. WohleberSenior
                Vice President andChief
                Financial OfficerBy:
            (John
                M. Rauh)John
                M. RauhVice
                President and Controllerand
                Chief Accounting Officer








*
      By
      his signature set forth below, John M. Rauh has signed this Annual Report on
      Form 10-K as attorney-in-fact for the officer noted above, pursuant to power
      of
      attorney filed with the Securities and Exchange Commission.








By:
            (John
              M.
              Rauh)John
                M. Rauh








Pursuant
      to the requirements of the Securities Exchange Act of 1934, this report has
      been
      signed below by the following persons in the capacities and on the date
      indicated.








By:
            Luke
                R. Corbett*Luke
                R. Corbett, DirectorBy:
            William
                E. Bradford*William
                E. Bradford, DirectorBy:
            Sylvia
                A. Earle*Sylvia
                A. Earle, DirectorBy:
            David
                C. Genever-Watling*David
                C. Genever-Watling, DirectorMarch
                15, 2006
            By:
            Martin
                C. Jischke*Date
            
            Martin
                C. Jischke, DirectorBy:
            Robert
                O. Lorenz*Robert
                O. Lorenz, DirectorBy:
            Michael
                Portillo*Michael
                Portillo, DirectorBy:
            Leroy
                C. Richie*Leroy
                C. Richie, DirectorBy:
            William
                F. Wallace*William
                F. Wallace, DirectorBy:
            Farah
                M. Walters*Farah
                M. Walters, DirectorBy:
            Ian
                L. White-Thomson*Ian
                L. White-Thomson, Director





*
      By
      his signature set forth below, John M. Rauh has signed this Annual Report on
      Form 10-K as attorney-in-fact for the directors noted above, pursuant to the
      powers of attorney filed with the Securities and Exchange
      Commission.








By:
            (John
              M.
              Rauh)John
                M. Rauh