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, 2003

                         Commission file number 1-16619

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

                  DELAWARE                                     73-1612389
       (State or other jurisdiction                        (I.R.S. Employer
    of incorporation or organization)                     Identification No.)

                KERR-MCGEE CENTER, OKLAHOMA CITY, OKLAHOMA 73125
                    (Address of principal executive offices)

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

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

                                                        NAME OF EACH EXCHANGE ON
     TITLE OF EACH CLASS                                     WHICH REGISTERED
-------------------------------                         ------------------------

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

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

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

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  ____

The aggregate  market value of the voting and  non-voting  common equity held by
non-affiliates  of the registrant  was  approximately  $4.5 billion  computed by
reference  to the price at which the common  equity was last sold as of June 30,
2003, 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 27, 2004,  was
101,373,405.


                       DOCUMENTS INCORPORATED BY REFERENCE

The  definitive  Proxy  Statement for the 2004 Annual  Meeting of  Stockholders,
which will be filed with the Securities and Exchange  Commission within 120 days
after December 31, 2003, 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

Kerr-McGee Corporation is an energy and inorganic chemical holding company whose
consolidated   subsidiaries,   joint  venture   partners  and  other  affiliates
(together,  "affiliates")  have  operations  throughout  the  world.  Kerr-McGee
affiliates  engaged in the energy  business  acquire leases and  concessions and
explore  for,  develop,  produce and market crude oil and natural gas onshore in
the United States and in the Gulf of Mexico,  the United  Kingdom  sector of the
North Sea and China. The company also holds exploration licenses and concessions
in Australia,  Benin, Bahamas,  Brazil, Gabon, Morocco,  Western Sahara, Canada,
the  Danish and  Norwegian  sectors  of the North  Sea,  and  Yemen.  Kerr-McGee
affiliates  engaged in chemical  businesses  produce and market titanium dioxide
pigment  and  certain  other  specialty  chemicals,  heavy  minerals  and forest
products.

Kerr-McGee's  worldwide  businesses are consolidated for financial reporting and
disclosure  purposes.  Accordingly,  the terms  "Kerr-McGee,"  "the company" 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.

On August 1, 2001, in connection with its acquisition of HS Resources, Inc., the
company completed a holding company reorganization in which Kerr-McGee Operating
Corporation,  which was formerly  known as Kerr-McGee  Corporation,  changed its
name and became a wholly owned subsidiary of the company. Filings and references
in this Form 10-K to the company  include  business  activity  conducted  by the
current Kerr-McGee  Corporation and the former Kerr-McGee  Corporation before it
reorganized  as a subsidiary  of the company and changed its name to  Kerr-McGee
Operating  Corporation.  At the end of 2002, another  reorganization  took place
whereby among other changes,  Kerr-McGee Operating  Corporation  distributed its
investment  in  certain  subsidiaries  (primarily  the  oil  and  gas  operating
subsidiaries)  to  a  newly  formed  intermediate  holding  company,  Kerr-McGee
Worldwide Corporation. Kerr-McGee Operating Corporation formed a new subsidiary,
Kerr-McGee Chemical Worldwide LLC and merged into it.

For  a  discussion  of  recent  business  developments,  reference  is  made  to
Management's Discussion and Analysis, which discussion is included in Item 7. of
this Form 10-K, and the  Exploration  and  Production and Chemicals  discussions
below.

                                INDUSTRY SEGMENTS

For financial  information as to business segments of the company,  reference is
made  to Note  28 to the  Consolidated  Financial  Statements,  which  financial
statements are included in Item 8. of this Form 10-K.

                           EXPLORATION AND PRODUCTION

Kerr-McGee  Corporation  owns  oil and gas  operations  worldwide.  The  company
acquires  leases and  concessions  and explores  for,  develops,  produces,  and
markets crude oil and natural gas through its various affiliates.

Kerr-McGee's  offshore oil and gas  exploration  and  production  activities are
conducted in the U.S. Gulf of Mexico,  Alaska,  the U.K. sector of the North Sea
and China.  Oil and gas exploration  activities are also conducted in Australia,
Benin, Brazil, Canada,  Morocco,  Western Sahara, Gabon, Yemen, Bahamas, and the
Danish  and  Norwegian  sectors  of  the  North  Sea.  Onshore  exploration  and
production operations are conducted in the United States and the United Kingdom.

--------------------------------------------------------------------------------
Except for  information or data  specifically  incorporated  herein by reference
under Items 10 through 14, other information and data appearing in the company's
2004 Proxy Statement are not deemed to be filed as part of this annual report on
Form 10-K.
--------------------------------------------------------------------------------

Kerr-McGee's  average daily oil production from  continuing  operations for 2003
was 150,200  barrels,  a 21% decrease  from 2002.  This  decrease in  production
volume is largely the result of a divestiture  program initiated during 2002 and
subsequently  completed in 2003. After adjusting for divestitures,  the 2003 oil
production  volume was relatively  consistent  compared with 2002.  Kerr-McGee's
average  oil price was  $26.04  per  barrel  for 2003,  including  the impact of
hedges, compared with $22.04 per barrel for 2002.

During 2003,  natural gas sales volume  averaged 726 million cubic feet per day,
down 4% from 2002.  This  decrease is also partly the result of the  divestiture
program  discussed above. On a  divestiture-adjusted  basis, 2003 gas sales were
down about 2% compared with 2002.  The 2003 average  natural gas price was $4.37
per thousand cubic feet, including the impact of hedges, compared with $2.95 per
thousand cubic feet in 2002.

Worldwide  gross  acreage  at  year-end  2003 was almost 72  million  acres,  an
increase of 8% compared with year-end 2002. The increase resulted primarily from
the  acquisition of acreage in the Bahamas,  offset by  divestitures  of certain
properties in Kazakhstan and the North Sea.

Discontinued Operations and Asset Disposals
-------------------------------------------

During  2002,  the  company  approved a plan to dispose of its  exploration  and
production  operations in Kazakhstan,  its interest in the Bayu-Undan project in
the East Timor Sea offshore  Australia,  and its interest in the Jabung block of
Sumatra,  Indonesia.  These  divestiture  decisions  were  made  as  part of the
company's  strategic plan to  rationalize  noncore oil and gas  properties.  The
results  of these  operations  have been  reported  separately  as  discontinued
operations in the company's  Consolidated  Statement of Operations for all years
presented,  which  statement is included in Item 8. of this Form 10-K.  Sales of
the company's  interests in the  Bayu-Undan  project and the Sumatra  operations
were  completed  during 2002,  and the sale of its  operations in Kazakhstan was
completed  in March 2003.  The  Kazakhstan  assets  consisted  of one  producing
license, one exploration license and an equity ownership in the Caspian Pipeline
Consortium.

Revenues  applicable  to the  discontinued  operations  totaled $6 million,  $36
million and $72 million for 2003, 2002 and 2001, respectively. Pretax income for
the  discontinued  operations  totaled  nil,  (including  a loss  on  sale of $6
million),  $104  million  (including  gain on sale of $107 million and a loss on
sale of $35  million)  and $52 million for the years ended 2003,  2002 and 2001,
respectively.

In addition,  certain individually insignificant properties for which operations
and cash flows were not clearly  distinguishable  from the company's  operations
were  identified  for  disposal  during  2003.  These  properties  included  the
company's interest in the Liuhua field in the South China Sea and selected other
noncore,  high-cost  properties  in the U.S onshore and Gulf of Mexico  regions.
These decisions were made as part of the company's strategic plan to rationalize
noncore oil and gas  properties,  as well as the  company's  ongoing  efforts to
maintain its high-quality  asset portfolio.  Asset disposals  completed in 2003,
including the Kazakhstan  operations,  resulted in the sale of  approximately 41
million equivalent barrels, or 4% of proved reserves.

Costs  Incurred,  Results  of  Operations,   Sales  Prices,  Lifting  Costs  and
Capitalized Costs
--------------------------------------------------------------------------------

Reference  is  made  to  Notes  29,  30  and 31 to  the  Consolidated  Financial
Statements  included  in  Item  8.  of  this  Form  10-K.  These  notes  contain
information  on the costs  incurred in crude oil and natural gas  activities for
each of the past three years;  results of operations  from crude oil and natural
gas  activities,  average  sales  prices per unit of crude oil and natural  gas,
lifting  costs per  barrel of oil  equivalent  (BOE) for each of the past  three
years; and capitalized costs of crude oil and natural gas activities at December
31, 2003 and 2002.

Reserves
--------

Kerr-McGee's  estimated  proved crude oil,  condensate,  natural gas liquids and
natural gas reserves at December 31, 2003,  and the changes in net quantities of
such  reserves  for the  three  years  then  ended  are  shown in Note 32 to the
Consolidated  Financial  Statements  included  in Item 8.  of  this  Form  10-K.
Estimates  of total  proved  reserves  filed with or  included in reports to any
other Federal  authority or agency during 2003, if any, are within 5% of amounts
shown in this filing.

Undeveloped Acreage
-------------------

As of December 31,  2003,  the company had leases,  concessions,  reconnaissance
permits and other  interests  in  undeveloped  oil and gas leases in the Gulf of
Mexico; onshore United States; the United Kingdom,  Danish and Norwegian sectors
of  the  North  Sea;   offshore  China;   and  onshore  and  offshore  in  other
international areas, as follows:
                                                  Gross                   Net
Location                                         Acreage                Acreage
--------                                        ----------            ----------

United States -
  Offshore                                       3,107,918             1,799,541
  Onshore                                        1,565,728             1,083,999
                                                ----------            ----------
                                                 4,673,646             2,883,540
                                                ----------            ----------

North Sea                                          783,927               368,773
                                                ----------            ----------

China                                            1,686,987             1,487,524
                                                ----------            ----------

Other international -
  Morocco/Western Sahara                        30,245,687            28,021,741
  Australia                                     10,652,553             6,371,482
  Yemen                                          6,037,418             1,911,849
  Canada                                         3,021,825             1,778,128
  Gabon                                          2,471,052               617,763
  Benin                                          2,459,439             1,721,607
  Bahamas                                        6,488,680             6,488,680
  Brazil                                           534,981               267,491
                                                ----------            ----------
                                                61,911,635            47,178,741
                                                ----------            ----------

    Total                                       69,056,195            51,918,578
                                                ==========            ==========


Developed Acreage
-----------------

At December 31, 2003,  the company had leases and  concessions  in developed oil
and gas  acreage in the Gulf of  Mexico,  onshore  United  States and the United
Kingdom sector of the North Sea, as follows:

                                                  Gross                   Net
Location                                         Acreage                Acreage
--------                                        ----------            ----------

United States -
  Offshore                                         566,650               264,498
  Onshore                                        1,594,403             1,087,793
                                                ----------            ----------
                                                 2,161,053             1,352,291
                                                ----------            ----------

North Sea                                          405,427               135,539
                                                ----------            ----------


    Total                                        2,566,480             1,487,830
                                                ==========            ==========


Net Exploratory and Development Wells
-------------------------------------

Domestic and international exploratory and development wells that were completed
as successful or dry holes during the three years ended  December 31, 2003,  are
summarized in the following tables.


                                   Net Exploratory (1)                          Net Development (1)
                              --------------------------------           --------------------------------
                              Productive    Dry Holes    Total           Productive    Dry Holes    Total     Total
                              ----------    ---------    -----           ----------    ---------    -----     -----
                                                                                         

2003 (2)
  United States                      6.7         11.0     17.7                241.6          1.0    242.6     260.3
  North Sea                            -          1.0      1.0                  2.1           .1      2.2       3.2
  Other international                  -          5.0      5.0                   .7            -       .7       5.7
                                     ---         ----    -----                -----          ---    -----     -----
    Total                            6.7         17.0     23.7                244.4          1.1    245.5     269.2
                                     ===         ====    =====                =====          ===    =====     =====

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

2001
  United States                      2.4          4.6      7.0                107.3          6.3    113.6     120.6
  North Sea                            -          2.4      2.4                 16.1            -     16.1      18.5
  Other international                  -          4.4      4.4                  5.2           .3      5.5       9.9
                                     ---         ----    -----                -----          ---    -----     -----
    Total                            2.4         11.4     13.8                128.6          6.6    135.2     149.0
                                     ===         ====    =====                =====          ===    =====     =====


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

(2)  The 2003 net  exploratory  well count does not include 8.6  successful  net
     wells drilled in the United States or 1.2  successful  net wells drilled in
     the  North  Sea that are  currently  suspended,  nor  does it  include  4.3
     successful net wells drilled in China,  1.4 successful net wells drilled in
     the North Sea or 6.0 successful net wells drilled in the United States that
     will not be used for production.

Wells in Process of Drilling
----------------------------

The following table shows the number of wells in the process of drilling and the
number of wells suspended or awaiting completion as of December 31, 2003:


                         Wells in Process of              Wells Suspended or
                              Drilling                    Awaiting Completion
                      --------------------------      --------------------------
                      Exploration    Development      Exploration    Development
                      -----------    -----------      -----------    -----------
United States
  Gross                       3.0            8.0             30.0           25.0
  Net                         1.5            7.5             17.2           19.7

North Sea
  Gross                         -              -              2.0            2.0
  Net                           -              -              1.2             .2

China
  Gross                         -            6.0                -              -
  Net                           -            2.4                -              -

Total
                              ---           ----             ----           ----
  Gross                       3.0           14.0             32.0           27.0
                              ===           ====             ====           ====
  Net                         1.5            9.9             18.4           19.9
                              ===           ====             ====           ====


Gross and Net Wells
-------------------

The number of productive  oil and gas wells in which the company had an interest
at December 31, 2003,  is shown in the following  table.  These wells include 96
gross or 17.4 net wells associated with improved  recovery  projects,  and 2,356
gross or 2,278.7 net wells that have  multiple  completions  but are included as
single wells.

Location                     Crude Oil          Natural Gas                Total
--------                     ---------          -----------                -----
United States
  Gross                          1,765                3,051                4,816
  Net                            1,513                2,448                3,961

North Sea
  Gross                            266                    5                  271
  Net                               49                    -                   49

Total
                                 -----                -----                -----
  Gross                          2,031                3,056                5,087
                                 =====                =====                =====
  Net                            1,562                2,448                4,010
                                 =====                =====                =====


Crude Oil and Natural Gas Sales
-------------------------------

The following table  summarizes the sales of the company's crude oil and natural
gas sales from  continuing  operations for each of the three years in the period
ended December 31, 2003:

(Millions)                                        2003         2002         2001
----------                                    --------     --------     --------

Crude oil and condensate - barrels
  United States                                   27.9         29.7         28.4
  North Sea                                       26.1         37.2         37.3
  China                                             .8          1.2          1.4
  Other international                                -          1.4          2.0
                                              --------     --------     --------
                                                  54.8         69.5         69.1
                                              ========     ========     ========

Crude oil and condensate sales revenues (1)
  United States                               $  728.4     $  639.6     $  625.5
  North Sea                                      673.9        832.8        865.6
  China                                           23.2         29.5         30.3
  Other international                                -         28.9         38.6
                                              --------     --------     --------
                                              $1,425.5     $1,530.8     $1,560.0
                                              ========     ========     ========

Natural gas - Mcf
  United States                                  229.5        240.8        194.9
  North Sea                                       35.4         36.7         22.8
                                              --------     --------     --------
                                                 264.9        277.5        217.7
                                              ========     ========     ========

Natural gas sales revenues (1)
  United States                               $1,046.9     $  732.7     $  777.2
  North Sea                                      109.3         86.4         56.2
                                              --------     --------     --------
                                              $1,156.2     $  819.1     $  833.4
                                              ========     ========     ========

(1)  Includes the results of the company's hedging program, which began in 2002.


Product Sales and Marketing
---------------------------

The company's crude oil and natural gas is sold at prevailing market prices, and
the realized revenue on the physical sale is adjusted for any gains or losses on
hedging contracts.

The company  markets all of its crude oil under a  combination  of spot and term
contracts to refiners,  marketers and end-users under market-reflective  prices.
Kerr-McGee's  single  largest  purchaser  of crude oil  during  2003 was BP PLC,
accounting for approximately 31% of total crude oil sales and 21% of total crude
oil and natural gas sales.  The  creditworthiness  of each successful  bidder is
reviewed prior to delivery of product.

Kerr-McGee's  single  largest  purchaser  of  domestic  natural  gas is  Cinergy
Marketing & Trading LLC, whose  purchases are guaranteed by its parent  company,
Cinergy Corporation. Purchases by Cinergy represented approximately 68% of total
gas  sales  and  30% of  total  crude  oil  and  natural  gas  sales  for  2003.
Additionally,  Kerr-McGee manages its single-customer  exposure through a credit
risk insurance policy.

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

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

Improved Recovery
-----------------

As part  of the  company's  strategic  plan to  rationalize  noncore,  high-cost
assets, Kerr-McGee's  improved-recovery projects in Texas were sold during 2003.
As of December 31, 2003, the company participated in 17 active improved-recovery
projects  located in the United  Kingdom  sector of the North Sea. Most of these
improved-recovery operations incorporate water injection.

Exploration and Development Activities
--------------------------------------

Gulf of Mexico:

Kerr-McGee has been one of the pioneering  exploration  companies in the Gulf of
Mexico since 1947, when the company drilled the first successful well out of the
sight of land.  This tradition has continued with the  advancement of technology
and the pursuit of oil and gas farther  offshore and in deeper water. To achieve
and maintain its competitive advantage, Kerr-McGee has continued to utilize new,
cost-efficient  production  and  drilling  technology,  allowing  the company to
explore for new oil and gas  resources  in water  depths of almost  10,000 feet.
Kerr-McGee was the first company to utilize floating  production spar technology
in the Gulf of Mexico in 1997 for its Neptune  development at Viosca Knoll block
826.  Kerr-McGee has continued to advance this technology through utilization of
improved  truss spar designs for its  developments  at the Nansen,  Boomvang and
Gunnison  discoveries,  which were  sanctioned for development in 2000 and 2001.
Kerr-McGee  sanctioned the Red Hawk  development  in 2002,  which will use a new
cell spar  design.  New  technology,  such as the cell spar,  lowers the reserve
threshold for economic development of deepwater reservoirs, allowing the company
to exploit new resources cost effectively.

In 2003, Gulf of Mexico  production  represented 38% of the company's  worldwide
crude oil and condensate  production and 38% of its natural gas sales.  The Gulf
of Mexico represents about 35% of Kerr-McGee's total worldwide proved reserves.

Kerr-McGee  is  one  of  the  largest  independent  exploration  and  production
companies  operating  in the Gulf of Mexico,  with  leases  covering  almost 3.7
million gross acres. In 2003,  Kerr-McGee maintained its position as the largest
independent  leaseholder  in the  deepwater  Gulf  of  Mexico  with  almost  480
deepwater blocks. The company believes this extensive acreage holding provides a
significant  competitive  advantage  in its  effort to  maintain  and  develop a
high-quality prospect inventory.

In 2003, Kerr-McGee was an active explorer in the Gulf of Mexico,  participating
in the drilling of 37 gross  exploration  wells, with 25 of those in water depth
greater than 1,000 feet.  The prospects  were a mixture of near-field  wildcats,
appraisal  wells and deeper  pool  tests,  as well as larger  new-field  wildcat
prospects  that  would  require  the  installation  of  new  infrastructure  for
development.  Successful wells were drilled in Breton Sound,  Main Pass,  Garden
Banks 197 and 216, East Breaks 598 and 686,  Ewing Bank 1006,  Viosca Knoll 990,
and at the Constitution prospect in Green Canyon 679/680.

During  2003,  Kerr-McGee  continued  drilling  under  terms of a  joint-venture
agreement  with Devon Energy  (following the merger of Ocean Energy with Devon),
which covers an area comprised of 181 blocks. Kerr-McGee and Devon drilled three
exploratory  wells in 2003,  with Devon paying a  disproportionate  share of the
drilling  cost to earn its equity  interest in the  venture.  Two of these wells
were unsuccessful,  and the third (Yorktown prospect in Mississippi Canyon block
886) was  temporarily  suspended  during the year.  The company  plans to resume
drilling on this prospect in 2004. The joint-venture arrangement with Devon will
continue for approximately two more years.

The majority of geological and geophysical  expenditures in 2003 were focused on
acquiring  regional  3-D  seismic  data and on the  continued  development  of a
high-potential  prospect inventory.  Much of the geologic section above salt has
been heavily  explored in the Gulf of Mexico,  and numerous  subsalt  trends are
emerging  through  industry  activity.  In  2003,  Kerr-McGee  also  focused  on
acquisition of geophysical data aimed at developing subsalt prospects. This data
is currently  being used to build the company's  prospect  inventory in this new
play.

In 2003,  Kerr-McGee  continued to capitalize  on its appraisal and  development
expertise in the Gulf of Mexico,  resulting in a new development  project at its
Constitution  discovery  in Green Canyon  block  679/680.  During 2003, a second
exploration test and discovery were made on the Constitution prospect.  This was
followed by a successful  appraisal  program,  which led to  sanctioning  of the
Constitution  development in January 2004. Development of infrastructure for the
Constitution  discovery  will provide a new  operating hub for  Kerr-McGee,  and
additional drilling  opportunities in this area are being evaluated for the 2004
exploration program.

Kerr-McGee's development activity in the deepwater Gulf of Mexico also continued
at a high  level  during  2003 in terms of capital  outlay,  wells  drilled  and
construction  activity.  Installation  of a truss spar was completed at Gunnison
during  2003,  and  significant  progress  was  made on the Red Hawk  cell  spar
construction.  Subsea wells were completed for Gunnison,  Red Hawk,  East Breaks
598,  East Breaks 686 and Viosca  Knoll 869 (Triton)  during 2003.  In addition,
Kerr-McGee  finalized  plans  for  construction  of a new  truss  spar  for  the
Constitution  project.  Well  completion  activities  at the Nansen and Boomvang
fields were also  completed  during the year. A summary of these and other major
producing fields, including Kerr-McGee's working interest, follows:

Nansen  field,  East  Breaks  blocks  602 and 646 (50%):  The  Nansen  field was
sanctioned for  development in March 2000, and first  production was achieved in
January 2002.  Average 2003 gross  production  was 26,000 barrels of oil per day
and 140 million cubic feet of gas per day.  Completion  activities  concluded in
August 2003, and the completion rig was  demobilized.  The Nansen field has nine
dry-tree  producers  and three  subsea wells tied back to the spar from a subsea
cluster.

Boomvang  field,  East Breaks (EB) blocks 642,  643 and 688 (30%):  The Boomvang
field was  sanctioned for  development  in July 2000,  and first  production was
achieved in June 2002.  Average 2003 gross  production was 33,200 barrels of oil
per day and 158  million  cubic  feet  of gas  per  day.  Completion  activities
concluded at Boomvang in March 2003, and the completion rig was demobilized from
the spar. The Boomvang field has five dry-tree  producers and three subsea wells
tied back to the spar from two subsea clusters.  During 2003, a development well
was drilled on EB 688 and was completed in the fourth quarter of 2003. This well
will begin  production in early 2004 from one of the existing  subsea  clusters.
Two exploration wells were successfully drilled on Kerr-McGee leases adjacent to
the Boomvang  field in 2003.  EB 686 (42%) and EB 598 (50%) have been  completed
and will be tied back to the Boomvang spar in 2004. The EB 686 well will be tied
back through an existing subsea cluster and pipeline  system,  while EB 598 will
be tied back to the spar through a new subsea pipeline and cluster  system.  The
EB 598 well will share the new subsea system with another successful exploration
well previously drilled on EB 599.

Navajo field, East Breaks 690 area (50%): The Navajo field cluster is located on
East Breaks blocks 646, 689 and 690. The Navajo discovery well, located in block
690, was drilled in September 2001. Following discovery,  the well was completed
and tied back to the Nansen  spar  located  approximately  5 miles to the north.
First  production from Navajo was achieved in June 2002. Two previously  drilled
exploration wells were completed and began production  through the Navajo subsea
system in 2003. Gross  production from Navajo,  West Navajo and Northwest Navajo
wells averaged 47 million cubic feet of gas per day and 4,200 barrels of oil per
day in 2003.

Gunnison  field,  Garden  Banks  block  668  area  (50%):  The  Gunnison  field,
sanctioned  for  development  in  October  2001,  incorporates  a truss spar and
processing  facilities  with a capacity of 40,000 barrels of oil per day and 200
million  cubic feet of  natural  gas per day.  The  development  includes  seven
dry-tree wells and three subsea wells. The Gunnison spar,  located in 3,100 feet
of water,  is  Kerr-McGee's  third truss spar in the  deepwater  Gulf of Mexico.
Development  during 2003 included the final  development well drilled in January
2003 and completion of the three subsea wells prior to the  installation  of the
spar.  First  production  was  achieved in December  2003 from the three  subsea
wells.  By year-end  2003,  the average  gross  production  rate was about 3,600
barrels  of oil per  day  and 125  million  cubic  feet  of gas per  day.  Gross
production is expected to peak at 30,000  barrels of oil per day and 180 million
cubic feet of gas per day by year-end 2004.

Red Hawk field,  Garden Banks block 877 (50%):  Development  of Red Hawk, a 2001
discovery,  was sanctioned in July 2002 utilizing a new spar design  referred to
as a cell spar. Located in approximately  5,300 feet of water, the field will be
developed using two subsea  development wells that will be tied back to the cell
spar.  Development  drilling was completed in the first quarter of 2003, and the
two  wells  were  completed  during  the  summer  of  2003.  At  year-end  2003,
construction  of the  cell  spar and  production  facilities  was more  than 75%
complete.   First  production  is  anticipated  in  mid-2004,  with  peak  gross
production rates estimated at 120 million cubic feet of gas per day.

Neptune field, Viosca Knoll block 826 (50%):  Average 2003 gross production from
the Neptune field was 14,000 barrels of oil per day and 23 million cubic feet of
gas per day.  Production  from the  Neptune  field  began in March 1997 from the
world's first floating  production  spar.  Presently there are 12 dry-tree wells
and three subsea  satellite wells  producing  through the Neptune spar. A fourth
subsea well  (Viosca  Knoll 869 No. 1) was drilled and  completed  in late 2003,
with first production expected in early 2004.

Conger field,  Garden Banks block 215 (25%):  Average 2003 gross production from
the Conger field was 28,500  barrels of oil per day and 90 million cubic feet of
gas per day. First  production from the Conger field began in December 2000 from
the first of three subsea wells. The three-well subsea  development is the first
multi-well,  15,000-psi subsea development and is located in approximately 1,460
feet of water.  One  additional  well, a sidetrack of the Garden Banks 215 No. 6
well, was completed in late 2003 and was producing  6,600 barrels of oil per day
and 20 million cubic feet of gas per day at year-end.

Baldpate field, Garden Banks block 260 (50%): Average 2003 gross production from
the Baldpate field,  including the Penn State subsea satellite wells, was 20,100
barrels of oil per day and 40 million cubic feet of gas per day. The field is in
1,690 feet of water and is producing  from an  articulated  compliant  tower.  A
successful  exploration  well was drilled in late 2003 in Garden Banks 216 (Penn
State)  and was  completed  at  year-end.  This  well  will be tied  back to the
existing Penn State subsea  system,  with first  production  scheduled for early
2004.

Pompano field, Viosca Knoll block 989 area (25%):  Average 2003 gross production
from the Pompano  field was 23,500  barrels of oil per day and 55 million  cubic
feet of gas per day.  One well was drilled in the Pompano  field during 2003 and
was  successfully  brought  on-line in early July 2003 at a production rate of 5
million cubic feet of gas per day.

North Sea:

Kerr-McGee  has been active in the North Sea area since 1976. As of December 31,
2003,  Kerr-McGee  had  interests in 20 producing  fields in the United  Kingdom
sector. In 2003, North Sea production represented 48% of the company's worldwide
crude oil and  condensate  production  and 13% of its gas  sales.  The North Sea
represents about 27% of Kerr-McGee's total worldwide proved reserves.

During 2003, the company launched a six-well North Sea exploration and appraisal
program with the drilling of five operated wells and one nonoperated  well. Four
of these wells were successful.  In addition,  the company was successful in the
United Kingdom 21st Licence Round with the awards of block 21/4b, licence P.1104
(100%,  operator);  block 30/7b,  licence  P.1123  (100%,  operator);  and block
16/13b, license P.1094 (50%, operator).

Business  development  initiatives  during 2003 to strengthen the North Sea core
area included  acquiring an 85% interest and  operatorship  of block 30/14 and a
39.9%  interest  in  Norwegian  block  1/5.   Kerr-McGee  also  acquired  a  30%
nonoperated  interest  in  block  30/13  area  C.  These  blocks  contain  known
hydrocarbon  discoveries which the company believes may have future appraisal or
development potential.  In addition,  Kerr-McGee increased its equity holding in
the  operated  Gryphon  field  (9/18a,  9/18b) by acquiring  an  additional  25%
interest, increasing Kerr-McGee's total equity interest to 86.5%.

During 2003, production began on the Braemar field, in which Kerr-McGee has a 5%
interest.  The field was developed using a subsea tieback to the East Brae field
(7.3%  Kerr-McGee  interest).  First oil on Braemar  occurred in September 2003.
Average gross production in 2003 from first oil was 3,900 barrels of oil per day
and 55.6 million cubic feet of gas per day.

The following is a summary of the company's five key  developments  in the North
Sea. These  developments  contributed  approximately  76% of total net North Sea
production.

Gryphon area, blocks 9/18a, 9/18b, 9/19 and 9/23a (Maclure field 33.3%,  Gryphon
field 86.5%,  South Gryphon  field 89.9% and Tullich  field 100%):  Average 2003
gross  production  from the Gryphon  area was 29,400  barrels of oil per day and
10.5  million  cubic  feet  of gas per  day.  The  Maclure  and  Tullich  subsea
satellites  began production in August 2002. The Gryphon area is produced into a
floating production, storage and offloading (FPSO) vessel, with oil exported via
shuttle  tanker.  Gas is exported to the Leadon  facility  for fuel usage and/or
sold on the spot market via the St. Fergus  terminal.  An additional  25% equity
interest was acquired in the Gryphon field in 2003.

Janice  field,  block 30/17a  (75.3%):  Average 2003 gross  production  from the
Janice field was 12,100  barrels of oil per day and 1 million  cubic feet of gas
per day.

Leadon field,  block 9/14a and 9/14b (100%):  Average 2003 gross production from
the Leadon  field was 10,700  barrels of oil per day.  The Leadon field is being
produced into an FPSO vessel, and the oil is exported via shuttle tanker.

Harding field, block 9/23b (30%): Average 2003 gross production from the Harding
field was 48,900 barrels of oil per day. The Harding field  provides  Kerr-McGee
with additional infrastructure in the strategically important quadrant 9 area of
the North Sea. Within the same quadrant, Kerr-McGee also has equity interests in
the Gryphon, Leadon, Buckland,  Skene, Maclure, Tullich, Blue Sky and Blue Sky 2
fields.

Skene field,  block 9/19 (33.3%):  The Skene field began  production in December
2001.  Average 2003 gross field production was 135 million cubic feet of gas per
day and 6,500 barrels of oil per day. The Skene field is being produced  through
a subsea  tieback to the Beryl Alpha  platform.  The oil is exported via shuttle
tanker, while the gas is exported via pipeline to the St. Fergus terminal.

U.S. Onshore:

Kerr-McGee is active in the U.S.  onshore region with  production  operations in
Texas,  Oklahoma,  New Mexico,  Louisiana and Colorado.  In 2003,  U.S.  onshore
production represented 49% of the company's worldwide gas production, 13% of its
oil production, and 34% of total proved reserves.

Following is a summary of key U.S. onshore developments:

Wattenberg   field  (94%):   The   Wattenberg   gas  field  is  located  in  the
Denver-Julesburg  (DJ)  basin  in  northeast  Colorado.  Kerr-McGee's  2003  net
production  from this  field was 10,400  barrels of oil per day and 184  million
cubic  feet of gas per day.  During  2003,  the  company  completed  nearly  500
development projects in the field, including deepenings,  fracture stimulations,
recompletions and an aggressive  infill drilling program.  The J Sand infill and
Codell refracture programs continue to supply significant  low-risk  development
opportunities.  In  addition,  significant  success  was  achieved  in  2003  by
performing a third fracture  stimulation  operation,  or "tri-frac," on existing
Codell  producers.  Likewise,  initial results  indicated a 50-well pilot infill
drilling program in the Codell was highly successful, leading to substantial new
exploitation opportunities in the field.

In support of the ongoing DJ basin exploitation  program,  the company continued
the successful integration of the Wattenberg Gathering System into its operating
activities. During 2003, one new compressor was added, bringing the total system
horsepower to 65,000.  This  addition,  combined with several  modifications  to
existing  compressor units,  reduced the overall pipeline system pressure by 10%
and reduced production  downtime  associated with pipeline pressure  variations.
Kerr-McGee operates more than 3,100 wells in the DJ basin, nearly 2,100 of which
are  connected  to  the  Wattenberg   Gathering  System.  The   company-operated
production  represents about 70% of the total system throughput of approximately
255 million cubic feet of natural gas per day, 30 million cubic feet of which is
processed at the company's Ft. Lupton plant.

Flores and Jeffress fields, Starr and Hidalgo counties, Texas (80%): The company
completed  nine new wells and an  additional 31 workover  projects  during 2003.
More  than 60  wells  have  been  drilled  since  2001.  Kerr-McGee's  2003  net
production from both fields averaged 2,200 barrels of oil per day and 41 million
cubic feet of gas per day.

Rincon field, Starr County,  Texas (40%):  Kerr-McGee  acquired this interest in
2003. The company  initiated a development  drilling program at year-end 2003 in
this field,  which is  expected  to  continue  to enhance its  position in South
Texas.

Chambers  County,  Texas  (75%):  Four new wells and an  additional  15 workover
projects  were  completed in 2003.  Kerr-McGee's  net  production  from the area
during 2003  averaged  1,000 barrels of oil per day and 20 million cubic feet of
gas per day.

Kerr-McGee  participated in eight  exploratory wells during 2003 in the Northern
Rockies area.  This activity  included five wells in the  northeastern  Colorado
Niobrara play, one in western Colorado and two in southwest Wyoming.  Production
has been established from the western Colorado well, and development drilling is
planned  for 2004.  The Wind  River  basin  well in  central  Wyoming  was being
completed at year-end  2003.  Three  discoveries  in the  northeastern  Colorado
Niobrara  play were  successful  and are  currently  under  evaluation.  Further
exploration  activity  is planned  for 2004 in four  prospect  areas,  including
additional  wells in both the Wind  River  basin and the  northeastern  Colorado
Niobrara prospects.

Kerr-McGee  signed  a  participation  agreement  with  Armstrong  Oil and Gas on
December 24, 2003, to jointly  explore areas of the prolific Alaska North Slope.
Kerr-McGee   acquired  a  70%  working   interest  in  eight   leases   totaling
approximately  12,000  acres off the Alaska  coast,  northwest  of Prudhoe  Bay.
Kerr-McGee will operate the leases and spud an exploratory  well during February
2004.  The agreement  includes the right to acquire an interest in 13 additional
leases in the area, totaling 54,000 acres.

China:

Bohai Bay block 04/36  (81.8%  contractor  interest):  During  2003,  Kerr-McGee
gained  government  approval  for the  development  of the CFD 11-1 and CFD 11-2
fields.  Development  drilling began in November 2003 on CFD 11-1. Both platform
jackets and pipelines have been installed. Construction of the topsides for both
jackets has  progressed,  and  installation  is planned in the second quarter of
2004.  Construction  of the FPSO was  initiated  in 2003 and is  progressing  as
planned.   First  production  is  expected  in  late  2004  following   offshore
installation  of the Single Point Mooring system and the FPSO. Also during 2003,
Kerr-McGee was granted a two-year  extension by the China National  Offshore Oil
Company (CNOOC) for the third  exploration  phase of the 04/36 Block concession.
The extension runs through September 2005.

Exploration efforts continued during 2003 with the discovery of the CFD 11-5 and
CFD 11-6 fields. The results of CFD 11-5, along with the results of the adjacent
CFD 11-3 area, are being  integrated  into a formal report on Oil In Place (OIP)
for  submission  to the Chinese  government  by the end of the first  quarter of
2004.  The CFD 11-3 area was discovered in 2002 and is located  approximately  3
kilometers  from  the CFD  11-1  FPSO.  Evaluation  of  resource  potential  was
initiated for the CFD 11-6 field,  which is located  approximately 15 kilometers
from the FPSO. A combined OIP report for the CFD 11-6 field in 04/36 and the CFD
12-1/12-1S field in 05/36 is in progress. Appraisal wells drilled in 2003 on the
CFD 16-1 and CFD 2-1 discoveries were unsuccessful;  however,  CFD 16-1 is still
under evaluation.

Bohai Bay block  05/36  (50%  contractor  interest):  Two  appraisal  wells were
successfully  drilled in the CFD  12-1/12-1S  field  during  2003.  Two  wildcat
exploration  wells drilled  during the year were  unsuccessful.  Evaluation of a
combined  development  program to include  the CFD 12-1 and CFD 12-1S  fields as
well as the CFD 11-6  field  in  04/36  is  ongoing.  New  prospects  are  being
evaluated for drilling in 2004.

Bohai Bay block 09/18 (100% contractor  interest):  The first  exploration phase
has been extended from  September 2003 to September  2004. The 2003  exploration
program  included one wildcat well for phase one,  which was  unsuccessful.  Two
exploration wells are planned for 2004 on this 550,000-acre block.

Bohai Bay block  09/06 (100%  contractor  interest):  The  company  signed a new
exploration  contract  in August 2003 for this  440,000-acre  block in Bohai Bay
adjacent to the other concessions operated by Kerr-McGee. Seismic data have been
purchased,  including 146 square  kilometers of 3-D and 2,220  kilometers of 2-D
data. Additional data purchase and geological and geophysical  evaluation are in
progress.

Liuhua field, South China Sea (24.5% contractor interest):  Gross production for
2003 was 9,200 barrels of oil per day. One sidetrack and one extended-reach well
were  drilled in 2003.  The  company  completed  the  divestiture  of its Liuhua
interest in July 2003.

Other International:

Australia

WA 278P (39%): At year end, a retention lease  application was being  negotiated
with the Australian government for the areas around Kerr-McGee's  Prometheus and
Rubicon wells. These wells,  drilled in 2000,  successfully  encountered natural
gas but were considered noncommercial.

WA 295 (50%):  Kerr-McGee  operated this 3.5 million-acre block in the Carnarvon
basin.  Acquisition  of 4,800  kilometers  of 2-D seismic data was  completed in
2001, and a two-well drilling program was initiated in late 2002. The first well
of the program  was  unsuccessful,  and the  company's  obligation  to drill the
second well was eliminated through  negotiation with the Australian  government.
The block was surrendered in October 2003.

WA 301, 302, 303, 304 and 305 (50%):  Kerr-McGee  has an interest in 6.4 million
acres in the deepwater Browse basin. The first exploration well,  Maginnis,  was
drilled  early  in  2003  and  was  unsuccessful.  Kerr-McGee  has  successfully
renegotiated  and entered into phase two of exploration,  and has acquired a new
3-D seismic survey over a portion of two blocks.

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  began
over both blocks in late 2003.

EPP 33 (100%): In late 2003,  Kerr-McGee was awarded an interest in 1.35 million
acres in the deepwater Otway basin.

Bahamas

On June 25,  2003,  Kerr-McGee  signed  an  exploration  contract  (100%) on 6.5
million acres in northern  Bahamian waters,  90 miles east of the Florida coast.
Water depths range from 650 feet to 7,000 feet.  Kerr-McGee  began a speculative
seismic acquisition program in late 2003.

Benin

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

Brazil

BM-ES-9 (50%): This offshore block was acquired in 2001 and extends over 535,000
acres  in the Espirito  Santo  basin in water depths  ranging from 4,400 feet to
9,600 feet.  During 2002,  3-D seismic data was acquired and is currently  being
evaluated. Kerr-McGee plans to drill one well on the block in 2004.

BM-C-7 (33 1/3%):  In  December  2003,  Kerr-McGee  acquired  an interest in the
BM-C-7 block in the Campos  basin,  subject to  government  approvals.  In 2004,
Kerr-McGee  expects to participate in one exploratory well on this  161,000-acre
block in approximately 400 feet of water. EnCanBrasil operates the block with 66
2/3% interest.

Gabon

Olonga Marin block (25%):  Kerr-McGee and partners  conducted seismic operations
in  2003.  The  company  intends  to  relinquish  its  acreage  when  the  first
exploration period expires in March 2004.

Morocco and Western Sahara

Cap Draa block (25%):  Kerr-McGee  and  partners  have an  exploration  contract
covering  approximately  3 million acres along the deepwater shelf edge offshore
Morocco,  in water  depths  ranging  from 650 feet to 6,500 feet.  A 3-D seismic
acquisition was completed in 2002 and is currently being  evaluated.  Kerr-McGee
plans to  participate  in the  drilling  of one  exploratory  well in  2004.  In
February 2004, the company  executed a farm-out  agreement with Shell,  reducing
its interest in this block to 11.25%.

Boujdour block (100%):  In October 2001,  Kerr-McGee  acquired a  reconnaissance
permit covering  approximately 27 million acres offshore Western Sahara from the
shoreline  to a water depth of more than 10,000 feet.  A  reconnaissance  permit
allows  Kerr-McGee  to perform  seismic and related  activities  for  evaluation
purposes.  Kerr-McGee  completed its  acquisition of a large 2-D seismic grid in
early 2003. A new seismic and drop core survey will begin in early 2004.

Nova Scotia, Canada

EL2383,  EL2386,  EL2393  and  EL2396  (50%):  Kerr-McGee  is  operator  of four
deepwater blocks covering  approximately 1.5 million acres offshore Nova Scotia,
Canada,  in water  depths  ranging  from 500 feet to 9,200  feet.  A 3-D seismic
survey across two of the blocks was interpreted in 2001.  Additional 2-D seismic
data is being acquired outside the area covered by the current 3-D survey.

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

Yemen

Block 50 (47.5%):  Kerr-McGee and Nexen (operator) farmed out a portion of their
interest to Petronas  Carigali  Overseas Sdn Bhd. in 2002. Terms of the farm-out
arrangement called for Petronas to pay a disproportionate share of forward costs
for seismic data and  exploratory  wells.  The company intends to relinquish its
interest in block 50 in April 2004.



                                    CHEMICALS

Kerr-McGee  Corporation's  chemical  operations consist of two segments (pigment
and  other)  that  produce  and market  inorganic  industrial  chemicals,  heavy
minerals and forest  products  through its affiliates  Kerr-McGee  Chemical LLC,
KMCC Western Australia Pty. Ltd.,  Kerr-McGee Pigments GmbH, Kerr-McGee Pigments
International GmbH, Kerr-McGee Pigments Ltd., Kerr-McGee Pigments (Holland) B.V.
and  Kerr-McGee  Pigments  (Savannah)  Inc.  Many of the  pigment  products  are
manufactured using proprietary chloride technology developed by the company.

Industrial  chemicals  include titanium  dioxide,  synthetic  rutile,  manganese
dioxide,  boron and sodium  chlorate.  Heavy  minerals  produced  are  ilmenite,
natural rutile,  leucoxene and zircon. Forest products operations treat railroad
crossties and other hardwood products and provide other wood-treating services.

On December 16, 2002, the company  announced  plans to exit the forest  products
business due to the strategic  focus on the growth of the core  businesses,  oil
and gas  exploration and production and the production and marketing of titanium
dioxide  pigment.  Four of the company's  five  wood-treatment  facilities  were
closed  during  2003 and the fifth  will  cease  operations  by the end of 2004.
During 2003 and 2002, the company took  after-tax  charges of $9 million and $15
million, respectively,  for plant and equipment impairment,  decommissioning and
environmental expenses.

In June 2003,  Kerr-McGee closed its synthetic rutile plant in Mobile,  Alabama.
This plant  closure  was  another  step in the  company's  plan to  enhance  its
operating  profitability.  The Mobile plant  processed and supplied a portion of
the feedstock for the company's  titanium  dioxide  pigment plants in the United
States.  Through ongoing supply-chain  initiatives,  Kerr-McGee can now purchase
the feedstock  more  economically  than it could be  manufactured  at the Mobile
plant. In connection with the shutdown,  the company took an after-tax charge of
$30 million for severance,  accelerated  depreciation and other  decommissioning
expenses  during  2003.  As a result of these  steps,  the  company  anticipates
significant savings.

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

In January  2004,  the company  announced  the  temporary  idling of its sulfate
process titanium dioxide pigment production train at the Savannah  manufacturing
facility,  which is one of two sulfate  process  trains  operated by the company
worldwide. Production is expected to resume as market conditions improve.


Titanium Dioxide Pigment
------------------------

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

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

Titanium  dioxide  is  produced  using one of two  different  technologies,  the
chloride process and the sulfate process,  both of which are used by Kerr-McGee.
Because of market considerations,  chloride-process  capacity has increased to a
substantially  higher  level than  sulfate-process  capacity  during the past 20
years.  The  chloride  process  currently  makes up about 60% of total  industry
capacity and accounts for  approximately  76% of the company's gross  production
capacity.

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


                                  TiO2 Capacity
                              As of January 1, 2004
                             (Gross tonnes per year)

Facility                                 Capacity                       Process
--------                                 --------                       --------
Hamilton, Mississippi                     225,000                       Chloride
Savannah, Georgia                         110,000                       Chloride
Kwinana, Western Australia (1)            100,000                       Chloride
Botlek, Netherlands                        72,000                       Chloride
Uerdingen, Germany                        107,000                        Sulfate
Savannah, Georgia                          54,000                        Sulfate
                                          -------
        Total                             668,000
                                          =======

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


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

Heavy minerals are mined from 8,513 hectares (21,037 acres) leased by the Tiwest
Joint Venture. The company's 50% interest in the properties'  remaining in-place
proven and probable reserves is 6 million tonnes of heavy minerals  contained in
215 million  tonnes of sand averaging  2.8% heavy  minerals.  The valuable heavy
minerals are composed of 61% ilmenite,  4.5% natural rutile,  3.4% leucoxene and
10% zircon,  with the remaining  21.1% of heavy  minerals  having no significant
value.

Heavy-mineral concentrate from the mine is processed at a 750,000 tonne-per-year
dry  separation  plant.  Some of the recovered  ilmenite is upgraded at a nearby
synthetic  rutile  facility,  which has a capacity  of 220,000  tonnes per year.
Synthetic rutile is a high-grade  titanium dioxide  feedstock.  The Tiwest Joint
Venture provides synthetic rutile feedstock to a 100,000 tonne-per-year titanium
dioxide plant  located at Kwinana,  Western  Australia.  Production of ilmenite,
synthetic  rutile,  natural  rutile and  leucoxene in excess of the Tiwest Joint
Venture's  requirements  is sold to third  parties,  as well as to Kerr-McGee as
part of its feedstock  requirement for TiO2 under a long-term agreement executed
in September 2000.

Information regarding heavy-mineral reserves,  production and average prices for
the three years ended  December 31, 2003, 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)                      2003            2002             2001
--------------------------------------------------------------------------------
Proven and probable reserves              5,970           5,700            5,800
Production                                  294             289              280
Average market price (per tonne)           $152            $150             $143


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

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

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

Stored Power
------------

The company owns a 50% interest in AVESTOR,  a joint  venture  formed in 2001 to
produce and  commercialize  a solid-state  lithium-metal-polymer  (LMP) battery.
Compared with traditional lead-acid batteries,  AVESTOR's no-maintenance battery
offers superior  performance at one-third the size, one-fifth the weight and two
to four times the life. The batteries also provide an environmentally  preferred
alternative  since they  contain no acid or liquid  that may spill or leak.  The
AVESTOR  joint  venture  began  battery  sales in late 2003 from its plant  near
Montreal and expects to increase  production during 2004.  Initial battery sales
and customer feedback indicate strong demand in the telecommunications industry,
the initial target market.  Battery  quality and  performance  will be carefully
monitored and evaluated as production  rates  increase.  Development  of AVESTOR
batteries for industrial, utility and electric vehicle markets is under way.

Other Products
--------------

The other  segment  within the  chemical  operations  consists of the  company's
electrolytic operations and forest products business.

Electrolytic Products - Plants at the company's Hamilton,  Mississippi,  complex
include a 135,000  tonne-per-year  sodium chlorate facility.  Sodium chlorate is
used in the  environmentally  preferred  chlorine  dioxide process for bleaching
pulp.  Sodium  chlorate  demand in the United  States is  expected  to  increase
approximately  2% to 3% per year in the near term as the pulp and paper industry
recovers and completes conversion to the chlorine dioxide process.

The company operates  facilities at Henderson,  Nevada,  producing  electrolytic
manganese dioxide and boron  trichloride.  Annual production  capacity is 29,500
tonnes for manganese dioxide and 340,000 kilograms for boron trichloride.  Boron
trichloride is used in the production of pharmaceuticals  and in the manufacture
of semiconductors.

Manganese  dioxide is a major  component of alkaline  batteries.  The  company's
share of the North American manganese dioxide market is approximately one-third.
Demand  is  being  driven  by the  need  for  alkaline  batteries  for  portable
electronic devices.

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

Forest  Products - The  principal  product of the forest  products  business  is
treated railroad crossties.  Other products include railroad crossing materials,
bridge timbers and utility poles. As previously discussed, the company is in the
process of closing its plants and exiting the forest products business. Only one
of the  company's  five wood-treating  plants,  located in The  Dalles,  Oregon,
remained  in  operation  at  December  31,  2003.  The Dalles  plant is a leased
facility,  and the company will continue operations at the plant for the term of
the lease, which expires November 30, 2004.


                                      OTHER

Research and Development
------------------------

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

Employees
---------

On  December  31,  2003,  the company and its  affiliates  had 3,915  employees.
Approximately  1,025,  or 26%, of these  employees were  represented by chemical
industry collective bargaining agreements in the United States and Europe.

Competitive Conditions
----------------------

The petroleum  industry is highly  competitive,  and competition exists from the
initial  process of bidding for leases to the sale of crude oil and natural gas.
Competitive factors include finding and developing petroleum reserves, producing
crude oil and natural gas  efficiently,  transporting the produced crude oil and
natural  gas,  and  developing  successful  marketing  strategies.  Many  of the
company's competitors have substantially larger financial resources,  staffs and
facilities  than  Kerr-McGee,  which test  Kerr-McGee's  ability to compete with
them.

The  titanium  dioxide  pigment  business is highly  competitive.  The number of
competitors in the industry has declined due to recent consolidations,  and this
trend is expected to continue.  Significant consolidation among the consumers of
titanium dioxide has also taken place during the past five years and is expected
to  continue.  Worldwide,  Kerr-McGee  is one of only  five  producers  that own
proprietary  chloride-process  technology to produce  titanium  dioxide pigment.
Cost  efficiency and product  quality as well as technical and customer  service
are key competitive factors in the titanium dioxide business.

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


                GOVERNMENT REGULATIONS AND ENVIRONMENTAL MATTERS

General
-------

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

Environmental Matters
---------------------

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

During 2003, direct capital and operating  expenditures related to environmental
protection  and  cleanup of  existing  sites  totaled  $37  million.  Additional
expenditures totaling $104 million were charged to environmental reserves. While
it is difficult  to estimate the total direct and indirect  costs to the company
of government environmental regulations, the company presently estimates that in
2004 it will incur $13 million in direct  capital  expenditures,  $10 million in
operating  expenditures  and $98 million in  expenditures  charged to  reserves.
Additionally,  the  company  estimates  that in 2005 it will incur $5 million in
direct  capital  expenditures,  $4 million  in  operating  expenditures  and $66
million in expenditures charged to reserves.

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  in  the  United  States  and  other
jurisdictions. These include proceedings associated with facilities currently or
previously  owned,  operated or used by the  company's  affiliates  and/or their
predecessors,  some of which include  claims for personal  injuries and property
damages.  The current and former  operations  of the company's  affiliates  also
involve   management   of  regulated   materials  and  are  subject  to  various
environmental  laws and  regulations.  These laws and  regulations  obligate the
company's  affiliates  to clean up various  sites at which  petroleum  and other
hydrocarbons, chemicals, low-level radioactive substances and/or other materials
have been  contained,  disposed  of or  released.  Some of these sites have been
designated  Superfund sites by the U.S.  Environmental  Protection  Agency (EPA)
pursuant  to  the  Comprehensive  Environmental  Response,   Compensation,   and
Liability  Act of 1980  (CERCLA)  and are listed on the National  Priority  List
(NPL).

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

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

o    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;

o    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;

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

o    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;

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

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

o    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 now reliably estimate the amount of future additions
to the  reserves.  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.  The company has not established reserves for such
sites.

For an  expanded  discussion  of  environmental  matters,  see  "Item  3.  Legal
Proceedings,"  "Item  7.  Management's  Discussion  and  Analysis  of  Financial
Condition and Results of Operations," and Note 16 to the Consolidated  Financial
Statements contained in Item 8. to this Form 10-K.


                                  RISK FACTORS

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

Volatile Product Prices and Markets Could Adversely Affect Results
------------------------------------------------------------------

The company's  results of operations  are highly  dependent on the prices of and
demand for oil and gas and the company's  chemical products.  Historically,  the
markets  for oil and gas have been  volatile  and are likely to  continue  to be
volatile in the future. Accordingly,  the prices received by the company for its
oil and gas production  depend on numerous  factors that are beyond its control.
These factors  include,  but are not limited to, the domestic and foreign supply
of oil  and  natural  gas,  the  level  of  ultimate  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,  weather  conditions,  and the  overall  economic  environment.  A
sustained decline in prices for oil and gas could have a material adverse effect
on the company's  financial  condition,  revenues,  results of operations,  cash
flows and quantities of reserves recoverable on an economic basis.

Demand for titanium dioxide depends on the demand for finished products that use
titanium dioxide pigment.  This demand generally depends on the condition of the
economy.  The  profitability  of the  company's  products  depends  on the price
realized for them, the efficiency of manufacturing processes, and the ability to
acquire feedstock at a competitive price.

Should the industries in which the company operates experience significant price
declines  or other  adverse  market  conditions,  the company may not be able to
generate  sufficient  cash flow from operations to meet its obligations and make
planned capital expenditures.  In order to manage its exposure to price risks in
the  sale of oil and  gas,  the  company  may  from  time  to  time  enter  into
commodities  contracts to hedge a portion of its crude oil and natural gas sales
volume.  Any such hedging  activities may prevent the company from realizing the
benefits of price increases above the levels reflected in such hedges.

Failure to Fund Continued Capital  Expenditures  Could Decrease  Production Over
Time and Adversely Affect Results
--------------------------------------------------------------------------------

Maintaining  the company's  current  level of oil and gas reserves  requires the
successful  exploration  and  development  and/or  acquisition  of oil  and  gas
producing  properties.  As such, the company expects to continue to make capital
expenditures  for the  acquisition,  exploration  and development of oil and gas
reserves.  If its revenues  substantially  decrease as a result of lower oil and
gas prices or other  factors,  the company may have a limited  ability to expend
the capital  necessary  to replace its  reserves  or to maintain  production  at
current levels,  resulting in a decrease in production over time.  Historically,
the company has  financed  expenditures  for the  acquisition,  exploration  and
development of oil and gas reserves primarily with cash flow from operations and
proceeds  from debt and equity  financings,  asset  sales,  and sales of partial
interests in foreign concessions. Management believes that the company will have
sufficient  cash flow  from  operations,  available  drawings  under its  credit
facilities and other debt financings to fund capital  expenditures.  However, if
the company's cash flow from operations is not sufficient to satisfy its capital
expenditure  requirements,  there can be no assurance  that  additional  debt or
equity  financing  or other  sources of capital  will be available to meet these
requirements.  If the company is not able to fund its capital expenditures,  its
interests in some  properties  may be reduced or forfeited.  Failure to find and
develop reserves may have a material adverse effect on the company's  ability to
generate future cash flows.

Oil and Gas Reserve  Information  Is  Estimated,  and Material  Inaccuracies  in
Assumptions and/or Estimates Could Adversely Affect Results
--------------------------------------------------------------------------------

The  proved  oil and gas  reserve  information  included  in this  Form  10-K is
estimated.  These  estimates  are based  primarily  on reports  prepared  by the
company's geologists and 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 associated  future net cash flows  necessarily  depend on a
number of variable factors and assumptions, including:

o    historical  production  from the area compared with  production  from other
     similar producing areas;
o    the assumed effects of regulations by governmental agencies;
o    assumptions concerning future oil and gas prices; and
o    assumptions  concerning future operating costs, severance and excise taxes,
     development costs, and workover and remedial costs.

Because  all  reserve  estimates  are to  some  degree  subjective,  each of the
following items may differ materially from those assumed in estimating reserves:

o    the quantities of oil and gas that are ultimately recovered;
o    the production and operating costs incurred;
o    the amount and timing of future development expenditures; and
o    future oil and gas sales prices.

Furthermore,  different  reserve  engineers  may  make  different  estimates  of
reserves and cash flows based on the same available  data. The company's  actual
production,  revenues and  expenditures  with respect to reserves will likely be
different from estimates,  and the  differences may be material.  The discounted
future net cash flows included in this Form 10-K should not be considered as the
current market value of the estimated oil and gas reserves  attributable  to the
company's properties. As required by the U.S. Securities and Exchange Commission
(SEC), the estimated  discounted  future net cash flows from proved reserves are
based on prices and costs as of the date of the  estimate,  while actual  future
prices and costs may be materially higher or lower. Actual future net cash flows
also will be affected by factors such as:

o    the amount and timing of actual production;
o    supply and demand for oil and gas;
o    increases or decreases in consumption; and
o    changes in governmental regulations or taxation.

The 10%  discount  factor,  which is required by the SEC to be used to calculate
discounted future net cash flows for reporting purposes,  is not necessarily the
most appropriate  discount factor based on interest rates in effect from time to
time and  risks  associated  with the  company  or the oil and gas  industry  in
general.

The Company's Debt Level May Limit Its Financial Flexibility
------------------------------------------------------------

The company  incurs debt from time to time in  connection  with the financing of
company operations, acquisitions,  recapitalizations and refinancings. The level
of the company's debt could have several important effects on future operations,
including,  among others:  a portion of the company's cash flow from  operations
will be applied to the payment of  principal  and  interest on the debt and will
not be available for other purposes;  credit-rating  agencies have changed,  and
may  continue  to  change,  their  ratings  of  the  company's  debt  and  other
obligations,  which  in  turn  impacts  the  costs,  terms  and  conditions  and
availability  of financing;  covenants  contained in the company's  existing and
future debt  arrangements  will require the company to meet financial tests that
may  affect its  flexibility  in  planning  for and  reacting  to changes in its
business, including possible acquisition opportunities; the company's ability to
obtain  additional   financing  for  working  capital,   capital   expenditures,
acquisitions, general corporate and other purposes may be limited or burdened by
increased  costs  or  more  restrictive  covenants;  the  company  may  be  at a
competitive  disadvantage  to similar  companies  that have less  debt;  and the
company's   vulnerability  to  adverse  economic  and  industry  conditions  may
increase.

Many of the Company's  Competitors Have Greater  Resources,  Which Could Make It
Difficult For The Company to Compete In Its Industries
--------------------------------------------------------------------------------

The oil and gas  business  and the titanium  dioxide  pigment  business are each
highly  competitive.  The  company  competes  with  major  integrated  and other
independent  oil and gas companies for the acquisition of oil and gas leases and
other properties;  for the equipment and personnel required to explore,  develop
and produce from those  properties;  and in the marketing of oil and natural gas
production.  Likewise,  the company  competes  with  chemical  companies  in the
development, production and marketing of titanium dioxide. Many of the company's
competitors have substantially larger financial resources, staffs and facilities
than Kerr-McGee,  which may give them a competitive advantage when responding to
market conditions and capitalizing on operating efficiencies.

Oil and Gas Operations Involve Substantial Operating and Economic Risks
-----------------------------------------------------------------------

Drilling for oil and gas involves  numerous  risks,  including the risk that the
company will not encounter  commercially  productive oil or gas reservoirs.  The
costs of drilling,  completing  and  operating  wells are often  uncertain,  and
drilling  operations  may be  curtailed,  delayed or  canceled  as a result of a
variety of factors,  including:  unexpected drilling  conditions;  unanticipated
pressure  or  geologic   irregularities;   equipment   failures  or   accidents;
miscalculations;  fires,  explosions,  blow-outs and surface  cratering;  marine
risks such as currents,  capsizing,  collisions  and  hurricanes;  other adverse
weather conditions;  and shortages or delays in the delivery of equipment.  This
could  result  in a  total  loss of the  company's  investment  in a  particular
property. If certain exploration efforts are unsuccessful in establishing proved
reserves and exploration  activities cease, the amounts  accumulated as unproved
property costs would be charged against earnings as impairments.

While all drilling, whether developmental or exploratory,  involves these risks,
exploratory  drilling  involves  greater  risks of dry holes or  failure to find
commercial  quantities of hydrocarbons.  As a part of its strategy,  the company
explores  for oil and gas  offshore,  often in deep  water  or at deep  drilling
depths,  where  operations are more difficult and costly than on land or than at
shallower depths and in shallower waters. Deepwater operations generally require
a  significant  amount of time between a discovery and the time that the company
can  produce  and market the oil or gas,  increasing  both the  operational  and
financial risks associated with these  activities.  In addition,  because a high
percentage of the company's capital budget is devoted to higher-risk exploratory
projects, it is likely that the company will continue to experience  significant
exploration and dry hole expenses.

Kerr-McGee May Not Be Insured  Against All Operating Risks to Which Its Business
Is Exposed
--------------------------------------------------------------------------------

As protection  against  financial loss resulting  from  operating  hazards,  the
company  maintains  insurance  coverage,   including  certain  physical  damage,
comprehensive  general liability and worker's compensation  insurance.  However,
because of deductibles and other  limitations,  the company is not fully insured
against all risks in its business. The occurrence of a significant event against
which the company is not fully insured could have a material  adverse  effect on
its results of operations and/or financial position.

Kerr-McGee  Operates  in Foreign  Countries  and Will Be  Subject to  Political,
Economic and Other Uncertainties
--------------------------------------------------------------------------------

The company conducts significant  operations in foreign countries and may expand
its  foreign  operations  in the future.  Operations  in foreign  countries  are
subject to political, economic and other uncertainties, including:

o    the  risk  of  war,  acts  of  terrorism,   revolution,   border  disputes,
     expropriation, renegotiation or modification of existing contracts, import,
     export and transportation regulations and tariffs;
o    taxation policies,  including royalty and tax increases and retroactive tax
     claims;
o    exchange controls,  currency  fluctuations and other uncertainties  arising
     out of foreign  government  sovereignty  over the  company's  international
     operations;
o    laws and policies of the United States  affecting  foreign trade,  taxation
     and investment; and
o    the  possibility of being subject to the exclusive  jurisdiction of foreign
     courts in  connection  with legal  disputes and the  possible  inability to
     subject foreign persons to the jurisdiction of courts in the United States.

Foreign countries have occasionally  asserted rights to land,  including oil and
gas properties,  through border disputes. If a country claims superior rights to
oil and gas leases or concessions granted to the company by another country, the
company's  interests could be lost or 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. This could adversely affect the company's
interests.  The  company  seeks to manage  these risks by,  among other  things,
concentrating its international  exploration  efforts in areas where the company
believes that the existing  government is stable and favorably  disposed towards
U.S. exploration and production companies.

Regulation of Chemical  Manufacturing  Operations,  Oil and Gas  Development and
Surface Development Conflicts Could Adversely Affect Results
--------------------------------------------------------------------------------

Regulatory authorities have established rules and regulations  governing,  among
other things, the operation of chemical  manufacturing  facilities,  permits for
drilling and  production,  operations,  performance  bonds,  reports  concerning
operations,  discharge,  disposal and other waste-related permits, well spacing,
unitization  and  pooling of  operations,  surface use of  properties  where the
company has mineral  interests,  taxation,  and  environmental  and conservation
matters.  The company's continued compliance with amended, new or more stringent
requirements, as well as stricter interpretations of existing requirements,  may
require  the  company to make  material  expenditures  or subject the company to
liabilities beyond that which is currently anticipated. In addition, any failure
by the company to comply with  existing or future laws could  result in civil or
criminal fines and other enforcement actions.

Kerr-McGee Is Subject to Significant  Environmental  Compliance and  Remediation
Costs That Can Adversely Affect the Cost of Doing Business
--------------------------------------------------------------------------------

As more fully  detailed below in Item 7,  Management's  Discussion and Analysis,
the company's plants and operations are subject to numerous laws and regulations
relating to the  protection of the  environment.  The company has incurred,  and
will continue to incur,  substantial  operating,  maintenance,  remediation  and
capital  expenditures as a result of these laws and  regulations.  The company's
continued compliance with amended, new or more stringent  requirements,  as well
as stricter interpretations of existing requirements, may require the company to
make material  expenditures  or subject the company to  liabilities  beyond that
which is  currently  anticipated.  In  addition,  any  failure by the company to
comply with existing or future laws could result in civil or criminal  fines and
other enforcement actions.

The Company Is Subject to Lawsuits and Claims
---------------------------------------------

A number of lawsuits and claims are pending  against the company,  some of which
seek large amounts of damages.  Although  management  believes that none of them
will have a material  adverse  effect on the  company's  financial  condition or
liquidity, litigation is inherently uncertain, and the lawsuits and claims could
have a material  adverse  effect on the company's  results of operations for the
accounting  period or  periods  in which one or more of them  might be  resolved
adversely.

                AVAILABILITY OF REPORTS AND GOVERNANCE DOCUMENTS

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

Item 3.     Legal Proceedings

A.  In 2001, the company's chemical  affiliate  (Chemical)  received a Notice of
Violation  (NOV) from EPA,  Region 9. The NOV claims that  Chemical  has been in
continuous  violation  of the  Clean  Air Act  new  source  review  requirements
applicable to the construction in 1994 and continued operation of an open-hearth
furnace at its Henderson,  Nevada,  facility.  Chemical operated the open-hearth
furnace in  compliance  with  state-issued  permits and believes that the NOV is
without substantial merit.  Chemical is vigorously  defending against the claims
made in the NOV and  believes  that any fines and  penalties  related to the NOV
will not have a material adverse effect on the company.

B.  In 2002, Tiwest Pty Ltd, an Australian joint venture that produces  titanium
dioxide  and  in  which  Chemical  indirectly  has a 50%  interest,  received  a
complaint and notice of violation  from the Department of  Environmental  Waters
and  Catchment  Protection  in  Western  Australia  alleging  violations  of the
Environmental  Protection Act (1986).  This matter concerns an alleged  chlorine
release at the facility.  Tiwest  defended the  proceeding in the Court of Petty
Sessions,  Perth, Western Australia, and expects a decision in the matter around
the end of the first quarter.  As currently  filed, the maximum fine is $625,000
(Australian  dollars),  but the liability of the joint venture and the amount of
any monetary fine are uncertain.

C.  On  December  15,  2003,  the  District  Court  of  Rotterdam,  Netherlands,
determined that Kerr-McGee Pigments (Holland) B.V., an affiliate of the company,
had violated  regulations  imposed by the Netherlands  Environmental  Management
Act. The violations primarily relate to the failure to notify authorities of the
release of process gases from the affiliate's  facility in Botlek,  Netherlands,
as required by the facility's  environmental permit. The Court imposed a fine of
(euro)80,000, which concludes the case.

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

E.  On September 8, 2003, the Environmental  Protection  Division of the Georgia
Department of Natural Resources (EPD) issued a unilateral  Administrative  Order
to  Kerr-McGee  Pigments  (Savannah)  Inc.,  claiming  that the  Savannah  plant
exceeded emission  allowances provided for in the facility's Title V air permit.
The EPD is seeking  monetary  penalties of approximately  $178,000.  The company
appealed  the order on October 8, 2003,  which stayed the  effectiveness  of the
order. Meanwhile, the company is vigorously defending against the claims made in
the  order  and  believes  that any  penalties  related  to them will not have a
material adverse effect on the company.

F.  For a discussion of other legal proceedings and contingencies,  reference is
made to (1) the  Environmental  Matters section of  Management's  Discussion and
Analysis of Financial  Condition and Results of  Operations  included in Item 7.
and (2) Note 16 to the Consolidated  Financial Statements included in Item 8. of
this 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 2003.

                      Executive Officers of the Registrant

The following is a list of executive officers, their ages, and their positions
and offices as of March 1, 2004:

        Name                Age                      Office
-----------------------     ---     --------------------------------------------

Luke R. Corbett              57      Chief   Executive   Officer   since   1997.
                                     Chairman  of the  Board  since May 1999 and
                                     from 1997 to February  1999.  President and
                                     Chief  Operating  Officer  from 1995  until
                                     1997.

Kenneth W. Crouch            60      Executive Vice President  since March 2003.
                                     Senior  Vice  President  from 1996 to 2003.
                                     Senior  Vice  President,   Exploration  and
                                     Production  Operations,  from 1998 to 2003.
                                     Senior Vice  President,  Exploration,  from
                                     1996 to 1998.

David A. Hager               47      Senior  Vice   President,  Exploration  and
                                     Production  Operations,  since  March 2003.
                                     Vice   President   of    Exploration    and
                                     Production, 2002 to 2003. Vice President of
                                     Gulf  of  Mexico  and  Worldwide  Deepwater
                                     Exploration and  Production,  2001 to 2002;
                                     Vice   President  of  Worldwide   Deepwater
                                     Exploration and  Production,  2000 to 2001;
                                     Vice President of International Operations,
                                     2000;  previously Vice President of Gulf of
                                     Mexico  operations.  Joined  Sun  Oil  Co.,
                                     predecessor  of  Oryx  Energy  Company,  in
                                     1981.

Gregory F. Pilcher           43      Senior Vice President, General  Counsel and
                                     Corporate  Secretary  since July 2000. Vice
                                     President,  General  Counsel and  Corporate
                                     Secretary from 1999 to 2000. Deputy General
                                     Counsel for Business Transactions from 1998
                                     to   1999.    Associate/Assistant   General
                                     Counsel    for    Litigation    and   Civil
                                     Proceedings from 1996 to 1998.

Carol A. Schumacher          47      Senior Vice  President of Corporate Affairs
                                     since February  2002.  Prior to joining the
                                     company in 2002,  served as Vice  President
                                     of  Public  Relations  for The Home  Depot,
                                     1998 to 2001;  Executive Vice President and
                                     General Manager,  Atlanta office of Edelman
                                     Worldwide, 1997 to 1998; and Executive Vice
                                     President  of Cohn & Wolfe,  a division  of
                                     Young & Rubicam, Inc.

Robert M. Wohleber           53      Senior Vice  President and Chief  Financial
                                     Officer  since  December  1999.   Prior  to
                                     joining  the  company  in 1999,  served  as
                                     Executive    Vice   President   and   Chief
                                     Financial   Officer   of   Freeport-McMoRan
                                     Exploration  Company,  President  and Chief
                                     Executive   Officer   of   Freeport-McMoRan
                                     Sulfur  and  Senior   Vice   President   of
                                     Freeport-McMoRan     Gold    and     Copper
                                     Corporation.

W. Peter Woodward            55      Senior Vice  President  since 1997.  Senior
                                     Vice  President of Marketing for Kerr-McGee
                                     Chemical from 1996 to 1997.

George D. Christiansen       59      Vice  President,  Safety and  Environmental
                                     Affairs,   since  1998.   Vice   President,
                                     Environmental  Assessment and  Remediation,
                                     from 1996 to 1998.

Fran G. Heartwell            57      Vice  President of  Human  Resources  since
                                     March 2003;  Director  of Human  Resources,
                                     Kerr-McGee  Oil & Gas, from  September 2002
                                     to January  2003;  Vice  President of Human
                                     Resources and  Administration,  Oryx Energy
                                     Company, from 1995 until the 1999 merger of
                                     Oryx and Kerr-McGee.

J. Michael Rauh              54      Vice President since 1987. Controller since
                                     January  2002 and  1987 to 1996.  Treasurer
                                     from 1996 to 2002.

John F. Reichenberger        51      Vice President,  Deputy General Counsel and
                                     Assistant   Secretary   since   July  2000.
                                     Assistant   Secretary  and  Deputy  General
                                     Counsel from 1999 to 2000.  Deputy  General
                                     Counsel   from  1998  to  1999.   Associate
                                     General Counsel from 1996 to 1999.

Elizabeth T. Wilkinson       46      Vice President and Treasurer since November
                                     2002.   Previously   Assistant  Treasurer -
                                     Corporate      Finance,       GlobalSantaFe
                                     Corporation  (Global Marine Inc. until 2001
                                     merger);  Manager of Planning  and Analysis
                                     from 1998 to 1999 and  Manager  of  Budgets
                                     and  Planning  from  1994 to  1998,  Global
                                     Marine Inc.

There is no family relationship between any of the executive officers.


           CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS


Statements in this Form 10-K regarding the company's or management's intentions,
beliefs  or  expectations,  or  that  otherwise  speak  to  future  events,  are
"forward-looking  statements"  within  the  meaning  of the  Private  Securities
Litigation Reform Act of 1995. These  forward-looking  statements  include those
statements  preceded  by,  followed  by or  that  otherwise  include  the  words
"believes,"  "expects,"   "anticipates,"   "intends,"  "estimates,"  "projects,"
"target,"  "budget,"  "goal,"  "plans,"  "objective,"  "outlook,"  "should,"  or
similar words. In addition,  any statements  regarding  possible  commerciality,
development  plans,  capacity  expansions,   drilling  of  new  wells,  ultimate
recoverability  of  reserves,  future  production  rates,  future cash flows and
changes in any of the foregoing are forward-looking  statements.  Future results
and  developments  discussed  in these  statements  may be  affected by numerous
factors and risks,  such as the accuracy of the  assumptions  that  underlie the
statements,  the success of the oil and gas exploration and production  program,
drilling risks,  the market value of  Kerr-McGee's  products,  uncertainties  in
interpreting   engineering   data,   demand  for  consumer  products  for  which
Kerr-McGee's  businesses  supply  raw  materials,  the  financial  resources  of
competitors,  changes  in laws  and  regulations,  the  ability  to  respond  to
challenges in  international  markets,  including  changes in currency  exchange
rates,  political or economic  conditions  in areas where  Kerr-McGee  operates,
trade and regulatory matters, general economic conditions, and other factors and
risks discussed  herein and in the company's  other SEC filings.  Actual results
and developments  may differ  materially from those expressed or implied in this
Form 10-K.


                                     PART II


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

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

Quarterly dividends declared totaled $1.80 per share for each of the years 2003,
2002 and 2001. Cash dividends have been paid continuously since 1941 and totaled
$181 million in 2003, $181 million in 2002 and $173 million in 2001.

For  information  required  under Item 201(d) of  Regulation  S-K related to the
company's  securities  authorized for issuance under equity  compensation plans,
reference is made to Item 12. of this Form 10-K.


Item 6.     Selected Financial Data

Information regarding selected financial data required in this item is presented
in the schedule  captioned  "Ten-Year  Financial Summary" included in Item 8. of
this Form 10-K.


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

Management's Discussion and Analysis
--------------------------------------------------------------------------------

Overview

Kerr-McGee  Corporation is one of the largest U.S.-based independent oil and gas
exploration and production companies and the world's third-largest  producer and
marketer of titanium dioxide pigment.  The company has three reportable business
segments,  oil and gas exploration  and production,  production and marketing of
titanium dioxide pigment  (chemical - pigment),  and production and marketing of
other chemicals (chemical - other). The company's assets total approximately $10
billion.  Proved oil and gas reserves are approximately 1 billion barrels of oil
equivalent and the company's  equity  production  capacity for titanium  dioxide
pigment  is  618,000  tonnes  per  year.  For  2003,  revenues  from  continuing
operations  totaled $4.2  billion,  of which $2.9 billion (69%) was generated by
the company's oil and gas exploration and production operations and $1.3 billion
(31%) was  generated  by the  company's  chemical  operations.  Revenues for the
exploration and production  operations are generated  primarily from the sale of
crude oil and natural gas, as well as  marketing  revenues  associated  with the
company's sale of nonequity gas. Revenues for the company's chemical  operations
are  generated  from the sale of titanium  dioxide  pigment  and other  chemical
products.  An  overview  of each  operating  unit  and  certain  other  economic
considerations  are  included  below  to  provide  background  for  the  various
discussions  that  will  follow  in  Management's  Discussion  and  Analysis  of
Financial  Condition and Results of Operations (MD&A). A detailed  discussion of
each operating  unit's business and properties is included in Items 1. and 2. of
this Form 10-K.

Exploration and Production - The company's  exploration and production  business
is primarily  focused on finding and  developing  new oil and gas reserves.  The
success of the company depends heavily on a successful exploration program. As a
benchmark,  the company  works to replace at least 100% of its  production  each
year through a combination of its drilling and development programs and tactical
acquisitions.  During  2003,  Kerr-McGee  replaced  135% of its  2003  worldwide
production from continuing  operations,  of which 105% resulted from replacement
through  the  company's  exploration  program.   Kerr-McGee  has  established  a
competitive  average  finding,  development  and  acquisition  cost of $7.19 per
barrel of oil equivalent (BOE) and annual average production replacement of 192%
over the past five  years,  and remains  focused on adding  value to its reserve
base.  The company faces many  challenges in executing a successful  exploration
program,  including  obtaining accurate and reliable  geological and geophysical
data,  understanding  reservoir  complexity,  and inherent risks associated with
deepwater exploration,  among others.  Consequently,  a portion of the company's
total exploration costs is dry hole cost for unsuccessful drilling activity. The
company  works to mitigate  these risks by  attracting  and  retaining  talented
exploration and engineering  personnel with wide ranging  experience in its core
exploration  areas.  The company  utilizes  advanced  technology to maximize the
impact of its  exploration  efforts  including  both  extensive  geological  and
geophysical   data   acquisition  and  analysis  as  well  as   state-of-the-art
visualization  interpretation  techniques. In addition,  Kerr-McGee maintains an
extensive  world-wide  acreage position which the company  believes  provides it
with a significant competitive advantage in its effort to maintain and develop a
high-quality prospect inventory.  The company believes its prospect inventory is
a key component in mitigating the inherent risk of its exploration program.

In  addition,  profitability  and cash  flows  for  exploration  and  production
operations are heavily dependent on market prices for crude oil and natural gas,
as well as production  costs,  taxation  levels and other  operating  costs.  To
mitigate  uncertainties  related to commodity  price  fluctuations,  the company
hedged the sales price of a  substantial  portion of its 2003 oil and gas sales.
The company has entered into additional hedge contracts for 2004 to maximize the
predictability  of its cash flows. In addition to hedging,  the company monitors
its cost performance in an effort to maximize overall  profitability  and ensure
its ability to compete  within the industry.  In 2003,  the company  completed a
major divestiture  program which was partially  directed at reducing the overall
production cost of its asset portfolio.  Completion of this program  contributed
to a 12%  reduction  in the  company's  per unit  production  costs.  Changes in
operating  costs  from  year to year are  discussed  in the  Segment  Operations
section below.

While the company's  drilling  program and subsequent  development of successful
projects  generally  yield  attractive  economic  returns,  they  do  require  a
substantial capital commitment.  An overview of historical capital spending,  as
well as a discussion of the 2004 capital  spending  budget,  major  projects and
exploratory  drilling  program are included in the Capital  Spending  section of
MD&A below.  On an ongoing basis,  the carrying  values of the company's oil and
gas  properties are evaluated for  recoverability  relative to their future cash
flows.  Likewise,  reservoir performance and reserve quantities are periodically
reviewed.  Negative  revisions to reserve  quantities or negative changes in the
market  prices of crude oil and natural gas can  adversely  affect the company's
estimates of future cash flows and may result in asset  impairments.  Because of
the large  capital  investment  required  to develop  oil and gas fields and the
uncertain  mineral  resources  associated  with  each  field,  asset  impairment
evaluations  are  common  in the oil  and gas  industry  and are  indicative  of
projects for which previous capital  investments are no longer recoverable under
current economic conditions.  Such impairments may occur in the future; however,
the company  cannot  predict the timing or magnitude of future asset  impairment
charges.

Chemical - The chemical  operating unit has focused its strategy on its titanium
dioxide  pigment  operations.  As part of this strategic  decision,  the company
continues to investigate  divestiture options for the electrolytic  business and
plans to exit the forest products  business by the end of 2004 when the lease on
its only facility still in operation expires.

The profitability of the company's pigment operations is tied to consumption of,
and demand for, titanium dioxide pigment, which generally follow global economic
trends (discussed in the Operating  Environment and Outlook section below).  The
profitability of the company's pigment  operations also depends on the company's
ability to manage  operating  costs. As part of its efforts to manage  operating
costs, the company closed its synthetic rutile plant in Mobile, Alabama, in June
2003.  The Mobile plant  supplied a portion of the  feedstock  for the company's
pigment  plants in the United  States;  however,  through  ongoing  supply-chain
initiatives,  feedstock can now be purchased more  economically than it could be
manufactured at the Mobile plant.  In connection with the shutdown,  the company
recorded   after-tax   charges  of  $30  million  for   severance,   accelerated
depreciation and other decommissioning expenses during 2003.

Chemical  is working  on  technological  advancements  that will allow it to add
plant  capacity  with  low-cost  expansions  to take  advantage of future market
growth.  As  a  result  of  these  efforts,   production  began  through  a  new
high-productivity  oxidation  line at the Savannah,  Georgia,  chloride  process
pigment  plant in January  2004.  This new  technology  is expected to result in
low-cost,  incremental  capacity  increases  through  modification  of  existing
chloride  oxidation lines and should allow for improved  operating  efficiencies
through  simplification  of  hardware  configurations  and  reduced  maintenance
requirements.

Based on the future outcome of these technological advancements, the company may
need to review its existing  configuration at the Savannah plant to optimize the
plant's  resources  in  relation  to capacity  requirements.  The  company  will
evaluate  the  performance  of  the  new  high-productivity  line,  analyze  the
implications   on  the  capacity  of  existing   assets  and  have  a  plan  for
reconfiguration,   if  any,   by  the   latter   part  of   2004.   If  the  new
high-productivity  line  performs  as  expected,  the outcome of this review may
result in the  redeployment  of certain assets to alternate uses and/or the need
to idle certain  other  assets.  If this occurs,  the future useful life of such
assets may be adjusted, resulting in the acceleration of depreciation expense.

The AVESTOR  joint venture was created by Kerr-McGee  and  Hydro-Quebec,  one of
North   America's   largest   utilities,   to   commercialize   and   produce  a
lithium-metal-polymer  battery.  The  company's  investment in the joint venture
aligns core competencies with new business expansion  opportunities.  Commercial
battery  production and sales  commenced in late 2003 to the  telecommunications
industry.  It is expected that production will continue to increase during 2004.
AVESTOR's unique technical and product offering capability is expected to create
additional  high-market-value  opportunities in the utility and industrial power
generation markets. With market demand growing, the company anticipates sales to
match plant capacity.

Other Economic  Considerations  - Other  challenges  facing  Kerr-McGee  include
balancing its  opportunities  for growth with the company's desire to maintain a
lower debt structure,  reducing the company's  overall cost structure to improve
longer-term   profitability,   managing   ongoing   and   legacy   environmental
obligations,  and  maintaining  the  over-funded  status  of its U.S.  qualified
pension plan.

Strategically, Kerr-McGee has committed its focus to growing its exploration and
production  operations and improving the  profitability  of its titanium dioxide
pigment  business.  This has been achieved through selective  acquisitions,  the
success of the company's exploration program and technological advancements.  At
the same time, the company must balance the capital commitment  required to grow
its core operations with its goal of reducing the company's total debt burden to
remain  competitive and to increase  financial  flexibility.  Discussions of the
company's cash flow,  liquidity and debt-reduction plans in 2004 are included in
the Financial Condition section below.

In the  global  marketplace,  economic  pressures  continue  and the  economy is
recovering more slowly than  anticipated.  In order to remain  competitive,  the
company has taken a  disciplined  approach in reviewing  its cost  structure and
initiated a work-force  reduction  plan during the third  quarter of 2003.  As a
result of the program, the company's eligible U.S.  nonbargaining work force was
reduced by approximately 9%, or 271 employees.  The reduction  consisted of both
voluntary  retirements  and  involuntary   terminations.   Qualifying  employees
terminated  under this  program are eligible  for  enhanced  benefits  under the
company's pension and postretirement  plans, along with severance payments.  The
program was  substantially  completed by the end of 2003, with certain  retiring
employees  staying  into the  first  half of 2004 for  transition  purposes.  In
connection  with the work-force  reduction,  the company took a pretax charge of
$56 million  during 2003, of which $34 million was for  curtailment  and special
termination  benefits  associated  with the company's  retirement  plans and $22
million was for severance-related costs.

Because of the nature of  Kerr-McGee's  current and historical  operations,  the
company has significant environmental remediation responsibilities and continues
to provide  reserves for these  remediation  projects.  During 2003, the company
expensed an additional  $62 million (net of  reimbursements)  for  environmental
costs and funded $104 million of expenditures  associated with its environmental
projects.  A  discussion  of the  status  and  circumstances  surrounding  these
projects is included in the Environmental Matters discussion below.

With the substantial stock market losses experienced between 2000 and 2002, many
corporations  are facing a significant  financial  challenge with respect to the
funded status of their pension plans. The company's U.S.  qualified pension plan
remains over funded and estimated  returns on plan assets continue to exceed the
company's  other  periodic  pension  costs,  generating a net  periodic  pension
benefit of $38 million in 2003. No contributions to the company's U.S. qualified
pension  plan  will be  necessary  in 2004.  The  critical  assumptions  used in
measuring  the  company's  pension  and   postretirement   obligations  and  the
sensitivity of the various estimates associated with the company's benefit plans
are discussed in the Critical Accounting Policies section below.

--------------------------------------------------------------------------------
Operating Environment and Outlook

Oil and Gas Exploration and Production

During 2003, global geopolitical  uncertainties affected investment decisions in
the oil and gas industry.  However,  these risks were mitigated by  consistently
strong  oil  and  gas  prices.  The  near-month  futures  price  of  West  Texas
Intermediate  (WTI)  crude oil closed at or above $30 per barrel for most of the
year, and natural gas  maintained an average price above $5 per million  British
thermal units (MMBtu) during 2003.

Crude Oil - During 2003,  disruptions  to crude oil  production in Venezuela and
Nigeria due to political unrest and ethnic violence, combined with uncertainties
linked to the war in Iraq,  created global  uncertainty about the reliability of
crude oil  supply.  U.S.  crude oil  inventories  began  2003  below the  normal
operating  range  resulting from a reduction in U.S.  imports due to a strike in
Venezuela and strong demand for distillates during the 2003 U.S. heating season.
In January  2003,  OPEC  announced  plans to increase  production by 1.5 million
barrels per day to  compensate  for the  Venezuelan  shortfalls.  However,  this
increase  was not enough to overcome a perceived  shortfall in supply due to low
U.S.  inventories  and  expectation of a war in Iraq.  Crude oil WTI prices were
near $38 per barrel by the end of the 2003 first quarter. Following the onset of
the Iraqi war,  prices fell sharply to  approximately  $25 per barrel due to the
war's short  duration,  coupled  with  increases in crude oil imports from Saudi
Arabia and Venezuela.

Decreasing  U.S.  domestic  oil  production,  delays  in  Iraqi  oil  production
increases  and the  effect  of OPEC's  April  2003  production  cut of 2 million
barrels per day resulted in WTI crude futures prices recovering to above $30 per
barrel early in the 2003 third quarter.  Prices generally remained at this level
for the remainder of the year.

Numerous  factors are expected to influence  the U.S.  crude oil market in 2004.
Oil production in Nigeria, Venezuela and Iraq continued to recover, although not
to full capacity.  OPEC's recent  remarks  concerning the intention to shift its
strategy to revenue  enhancement  from market share protection could also impact
crude oil markets. Finally, a continued rebound in global economies could absorb
some oversupply.

Natural  Gas -  Higher-trending  natural  gas  prices in 2003 are the  result of
fundamental  shifts in the  natural  gas supply and demand  balance.  Gas prices
began the year at about  $5.25 per MMBtu and  reached a high of more than $9 per
MMBtu during  February due to storage levels falling to record lows.  This event
heightened   concerns   regarding  the  decline  of  U.S.  gas   supplies,   and
deliverability issues continued to underpin market activity throughout the year.

By fall 2003, U.S. gas storage volumes had recovered to comfortable  levels, but
fears of the previous winter's supply shortfall, as well as reports of declining
domestic production, kept prices strong. Throughout summer and fall, natural gas
prices remained above $4.50 per MMBtu, maintaining a range of $4.50 to $6.50 per
MMBtu until  December,  when seasonally cold winter weather began to push prices
up towards $7 per MMBtu.

The 2004  environment for U.S.  natural gas prices remains  volatile and will be
influenced by several factors,  including the balance between supply and demand,
weather  patterns,  the rate and  development of liquefied  natural gas imports,
crude oil and distillate prices, and government policy.

To mitigate the above uncertainties  related to price fluctuations,  the company
has entered into hedges  covering  approximately  80% of expected 2004 worldwide
crude oil and condensate production, and 75% of the U.S. natural gas production.
By ensuring greater  predictability  of cash flows to fund major exploration and
capital  programs,  hedging  enhances the  company's  ability to meet  financial
requirements. Details of the company's commodity hedging program are included in
the Market Risks section below.

Chemicals

In  the  global  titanium   dioxide  pigment   industry,   the  company  is  the
third-largest  producer and marketer and one of five companies that own chloride
technology.  The chloride  process  produces a pigment  with optical  properties
preferred  by the  paint,  coatings  and  plastics  industries.  In early  2004,
chloride technology  accounted for 76% of the company's gross pigment production
capacity. The remaining capacity is sulfate-process  production,  which produces
pigment used primarily in paper and specialty products.

Titanium  dioxide is a  quality-of-life  product,  and its  consumption  follows
general  economic  trends.  Throughout  2003,  challenging  business  conditions
existed  for  the  company's  chemical   operations  due  to   near-recessionary
conditions  in Europe,  high energy  prices,  the effect of the SARS epidemic on
economic  conditions  in Asia and continued  weakness in the U.S.  manufacturing
sector. These economic forces placed pressure on product prices, overall product
demand and  profitability.  While overall global economic growth was stagnant to
recessionary  during the first half of 2003,  the last quarter of 2003 did begin
to show  improvement  as observed in the leading U.S.  economic  indicators  and
Euro-zone GDP. General  economic  conditions are expected to improve in 2004 for
North America and Europe, with continued growth in the Asian markets.

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

--------------------------------------------------------------------------------
Results of Consolidated Operations

Net income (loss) and per-share  amounts for each of the years in the three-year
period ended December 31, 2003, were as follows:


(Millions of dollars, except per-share amounts)           2003     2002     2001
--------------------------------------------------------------------------------

Net income (loss)                                         $219    $(485)    $486
Net income (loss) per share -
     Basic                                                2.18    (4.84)    5.01
     Diluted                                              2.17    (4.84)    4.74

The major  variances  in net income on an  operating  unit basis  (after  income
taxes) are outlined in the table below.  The variances in individual  line items
in the  Consolidated  Statement of Operations  are explained in the section that
follows.

                                                       Favorable (Unfavorable)
                                                              Variance
                                                      -------------------------
                                                       2003                2002
                                                     Versus              Versus
(Millions of dollars)                                  2002                2001
--------------------------------------------------------------------------------
Net operating profit -
  Exploration and production                          $ 898               $(850)
  Chemical - pigment                                    (17)                 25
  Chemical - other                                       (7)                 (4)
Net interest expense                                     15                 (56)
Other income/expense                                    (24)               (202)
Discontinued operations                                (126)                 96
Cumulative effect of accounting change                  (35)                 20
                                                      -----               -----
       Net income                                     $ 704               $(971)
                                                      =====               =====

The 2003  increase  in  exploration  and  production  net  operating  profit  is
primarily due to a decrease in asset impairments of $385 million in 2003 and net
gains  associated with assets held for sale of $29 million in 2003 versus losses
of $167 million in 2002. The remaining $317 million  increase is due to the 2002
deferred  tax effect of $132 million  resulting  from a 33% increase in the U.K.
corporate tax rate for oil and gas  companies,  combined  with lower  production
costs and depreciation  and depletion  expense and higher average realized sales
prices for both crude oil and natural gas in 2003, partially offset by lower oil
and gas sales volumes and higher exploration expense.

The decline in chemical - pigment net  operating  profit in 2003 is  principally
the result of plant  closure and  workforce  reduction  provisions  totaling $42
million and higher average per-unit production costs, partially offset by higher
pigment sales prices.

Lower interest  expense in 2003 is due to lower average debt  outstanding  and a
slightly lower weighted average  interest rate. The negative  variance for other
income/expense  is  mainly  due to  higher  general  and  administrative  costs,
workforce reduction costs and lower net gains on the revaluation of nonoperating
derivatives and trading  securities,  partially  offset by lower 2003 litigation
provisions and a gain on sale of Devon Energy Corporation (Devon) shares.

Discontinued operations for all three years resulted from the company's decision
in  early  2002 to  dispose  of its  exploration  and  production  interests  in
Indonesia and Kazakhstan and its interest in the Bayu-Undan  project in the East
Timor Sea offshore Australia.  These divestiture  decisions were made as part of
the company's strategic plan to rationalize noncore oil and gas properties.  The
negative variance from discontinued operations in 2003 and the positive variance
in 2002 are both due  primarily to the $107 million gain on sale in 2002 related
to the disposals in Indonesia and Australia.

The 2003  cumulative  effect of change in accounting  principle is the result of
the company's adoption of the Financial  Accounting  Standards Board's Statement
No.  143,  "Accounting  for Asset  Retirement  Obligations"  (FAS 143).  See the
New/Revised Accounting Standards section below for a discussion of the adoption.

The 2002 decline in exploration  and production  net operating  profit  resulted
from asset  impairments of $394 million,  losses associated with assets held for
sale of $167  million and the  deferred  tax effect of $132 million for the U.K.
corporate tax law change,  as well as higher lease operating  expense,  shipping
and handling expense,  depreciation and depletion, and exploration expenses. The
improvement in chemical's  pigment net operating  profit in 2002 was principally
the result of higher pigment sales volumes and lower average per-unit production
costs.  Higher interest expense in 2002 was due to significantly  higher average
debt  outstanding and lower  capitalized  interest,  partially offset by a lower
overall average interest rate.

The 2002 negative variance for other  income/expense  was mainly due to the 2001
adoption  of  FAS  133,  "Accounting  for  Derivative  Instruments  and  Hedging
Activities,"  which  resulted  in the  company  recognizing  a $118  million net
unrealized gain on shares of Devon reclassified to "trading" from the "available
for sale" category of investments.  Additionally,  a 2002 net-of-tax  litigation
provision of $47 million and after-tax  foreign  currency  losses of $33 million
contributed to the other income/expense variance for 2002 versus 2001.

The 2002 positive variance from the change in accounting principle also resulted
from the  company's  adoption of FAS 133 in 2001.  This  standard  required  the
recording of all derivative  instruments as assets or  liabilities,  measured at
fair value.  Kerr-McGee  recorded the fair value of all its outstanding  foreign
currency forward contracts and the fair value of the options associated with the
company's  debt  exchangeable  for  common  stock  (DECS) of Devon  owned by the
company. The net effect of recording these fair values resulted in a $20 million
decrease in income as a cumulative  effect of a change in  accounting  principle
and a $3  million  reduction  in equity  (other  comprehensive  income)  for the
foreign currency contracts designated as hedges.

--------------------------------------------------------------------------------
Statement of Operations Comparisons

(Billions of dollars)                                   2003      2002      2001
---------------------                                   ----      ----      ----
Revenues                                                $4.2      $3.6      $3.6

The increase in 2003 revenues was primarily due to higher average realized sales
prices for crude oil, natural gas and titanium  dioxide  pigment,  combined with
higher gas marketing  sales revenue.  These  increases were partially  offset by
lower  production  quantities due primarily to oil and gas  properties  divested
during 2002 and 2003.  Revenues in 2002  increased  slightly  over 2001 due to a
full year of revenues  from the Rocky  Mountain  region  compared with only five
months in 2001  following the  acquisition  of HS  Resources,  combined with the
favorable  impact of  higher  pigment  sales  volumes,  partially  offset by the
recognition  of lower  revenues  from  properties  divested  during 2002.  These
variances are discussed in more detail in the segment  discussions  that follow.
See  Note  1 to  the  Consolidated  Financial  Statements  for a  discussion  of
reclassifications made to revenues for 2002 and 2001.


(Millions of dollars)                                2003       2002       2001
----------------------------                        ------     ------     ------
Costs and Operating Expenses                        $1,668     $1,456     $1,264

Costs and  operating  expenses  for 2003  increased  $212 million over the prior
year, primarily due to higher gas marketing product costs of $233 million (which
offsets higher  third-party gas marketing  revenues),  higher pigment production
costs of $51 million and 2003 shutdown provisions of $42 million associated with
the closure of Chemical's Mobile facility and forest products operations.  These
increases were partially offset by lower lease operating expense of $114 million
mainly due to oil and gas property  divestitures.  Costs and operating  expenses
increased $192 million in 2002 from the 2001 level,  resulting  principally from
higher gas marketing,  gathering and pipeline costs of $74 million (full year of
Rocky  Mountain  operations  in 2002 versus five months in 2001),  higher  lease
operating  expenses of $80 million (full year of Rocky  Mountain  operations and
new natural gas  production  brought online in the Gulf of Mexico  region),  and
higher pigment  production  cost of $91 million  (increased  pigment  production
volumes).


(Millions of dollars)                                   2003      2002      2001
-------------------------------------------             ----      ----      ----
Selling, General and Administrative Expenses            $371      $313      $228


For 2003,  selling,  general and  administrative  expenses increased $58 million
over the prior year,  resulting  primarily from provisions  totaling $58 million
associated  with the 2003  work-force  reduction  plan and other  transition and
severance-related  costs,  together with additional  compensation expense of $17
million  resulting  from loan  prepayments  required to release  shares from the
company's  employee stock ownership plan. Also contributing to the increase were
higher corporate and exploration and production general and administrative costs
of $24  million  and  $14  million,  respectively,  partially  offset  by  lower
litigation  provisions of $63 million  (prior-year forest products  litigation).
The 2003 increase in corporate general and administration was principally due to
higher  compensation-related  costs  of  $16  million  related  mostly  to  2003
performance bonus and amortization of restricted stock compensation,  along with
higher general and auto liability  costs of $5 million.  The increase in general
and  administrative  costs for the exploration and production  operations of $14
million is due primarily to lower 2003 billings of costs on operated  properties
to partners, which were partially offset by lower cost for contract services and
direct labor.  Selling,  general and administrative  expenses for 2002 increased
$85  million  primarily  as a result of the $72 million  reserve for  litigation
established  mainly in connection  with certain  forest  products  litigation in
Mississippi, Louisiana and Pennsylvania. This litigation is discussed in Note 16
to the financial statements.

Shipping and handling  expenses for 2003, 2002 and 2001 were $140 million,  $125
million and $111 million, respectively. The increase in 2003 is primarily due to
higher costs for transportation from new deepwater fields in the Gulf of Mexico,
including  Nansen,  Boomvang and Navajo,  and increased  costs in the U.K. North
Sea, as well as higher pigment  shipping costs. The increase in pigment shipping
costs is  primarily  related  to  higher  ocean  freight  prices  due to  supply
constraints on the  availability  of vessels.  The 2002 increase was also due to
higher  transportation for new deepwater fields in the Gulf of Mexico,  combined
with  higher  costs in the  Rocky  Mountain  region  due to a full year of costs
related to the former HS Resources operations.

Abandonment expense of $40 million and $34 million associated with the company's
exploration  and  production  operations  has been  reclassified  from costs and
operating  expenses  to  depreciation  and  depletion  for  2002  and 2001 to be
consistent with the 2003 presentation after adoption of FAS 143.


(Millions of dollars)                                   2003      2002      2001
--------------------------                              ----      ----      ----
Depreciation and Depletion                              $745      $814      $747

Depreciation and depletion expense totaled $745 million in 2003, $814 million in
2002 and $747 million in 2001.  The decrease for 2003 is due to lower  depletion
expense  for  divested  or  held-for-sale  properties  of $49  million and lower
depletion  on the  Leadon  field of $36  million,  partially  offset  by  higher
depletion  expense  in the Gulf of Mexico  region of $24  million  mainly due to
higher  production  from the  Nansen,  Boomvang  and Navajo  fields  which began
producing in 2002. The 2002 increase was due to higher depletion expense for the
Rocky  Mountain  region of $75 million (full year of ownership) and for the U.K.
region of $11 million. Partially offsetting these increases was lower expense in
the Gulf of Mexico  region of $24 million due to normal  declines in  production
and  held-for-sale  properties,  which  more  than  offset  the  impact  of  new
production from the Nansen, Boomvang and Navajo fields.

Impairment  losses on  held-for-use  assets  totaled $14  million in 2003,  $652
million  in 2002 and $76  million in 2001.  These  impairments  were  related to
assets with remaining  investments  that were no longer expected to be recovered
through future cash flows. Impairments in 2003 were related primarily to various
mature oil and gas fields in the U.S.  onshore and Gulf of Mexico  shelf  areas.
The  impairments in 2002 included $541 million for the Leadon field in the North
Sea,  $82 million for certain  nonoperated  fields in the North Sea, $23 million
for several older Gulf of Mexico shelf properties, and $6 million related to the
company's  planned  shutdown  of  the  forest  products  operations.   The  2001
impairments  were comprised of $47 million  associated with the shut-down of the
North Sea Hutton  field and $29  million  for  certain  chemical  facilities  in
Belgium and the U.S.

During 2003, the company  selectively  marketed its  100%-owned  Leadon field to
third parties. Although no divestiture negotiations are currently under way, the
company  continues  to  review  its  options  with  respect  to the  field  and,
particularly,  the associated floating production, storage and offloading (FPSO)
facility.  Management  presently intends to continue operating and producing the
field until such time as the operating cash flow generated by the field does not
support continued production or until a higher value option is identified. Given
the  significant  value  associated  with the FPSO  relative  to the size of the
entire  project,  the company will continue to pursue a long-term  solution that
achieves  maximum  value for Leadon - which may include  disposing of the field,
monetizing  the FPSO by selling  it as a  development  option for a  third-party
discovery, or redeployment in other company operations. As of December 31, 2003,
the carrying  value of the Leadon field assets  totaled $374 million.  Given the
uncertainty  concerning  possible outcomes,  it is reasonably  possible that the
company's  estimate  of future cash flows from the Leadon  field and  associated
fair  value  could  change  in the near term due to,  among  other  things,  (i)
unfavorable  changes in commodity prices or operating  costs,  (ii) a production
profile that  declines  more rapidly than  currently  anticipated,  and/or (iii)
unsuccessful  results of continued  marketing  activities or failure to locate a
strategic buyer (or suitable redeployment opportunity).  Accordingly, management
anticipates that the Leadon field will be subject to periodic  impairment review
until such time as the field is abandoned or sold.  If future cash flows or fair
value decrease from that presently  estimated,  an additional  write-down of the
Leadon field could occur in the future.

In connection with the company's  divestiture program initiated in 2002, certain
oil  and  gas  properties   were  identified  for  disposal  and  classified  as
held-for-sale  properties.  Upon  classification as held-for-sale,  the carrying
value of the related  properties is analyzed in relation to the  estimated  fair
value less costs to sell, and losses are recognized, if necessary. Upon ultimate
disposal of the  properties,  any gain or additional loss on sale is recognized.
Losses of $23  million  and gains of $68 million  were  recognized  in 2003 upon
conclusion  of the  divestiture  program in the U.S.  and North Sea, and for the
sale of the company's  interest in the South China Sea (Liuhua  field) and other
noncore U.S.  properties  (onshore and Gulf of Mexico shelf areas).  The company
recognized losses of $176 million in 2002 associated with oil and gas properties
held for sale in the U.S.  (onshore  and Gulf of Mexico shelf  areas),  the U.K.
North Sea and  Ecuador.  Proceeds  realized  from these  disposals  totaled $119
million in 2003 and $374  million in 2002.  The  proceeds  from the sale of such
properties have been used to reduce long-term debt. From time to time, other oil
and gas  properties  may be  identified  for disposal when such  properties  are
considered noncore or nearing the end of their productive lives.


(Millions of dollars)                                   2003      2002      2001
---------------------                                   ----      ----      ----
Exploration Expense                                     $354      $273      $210

Exploration  costs were $354  million,  $273  million and $210 million for 2003,
2002 and 2001, respectively.  The 2003 increase was due to higher dry hole costs
of $68 million,  primarily exploratory drilling in the deepwater Gulf of Mexico,
and higher  exploration  department costs of $11 million.  The 2002 increase was
due to higher dry hole costs of $41 million,  mainly exploratory drilling in the
deepwater  Gulf of Mexico and in the North Sea,  higher  nonproducing  leasehold
amortization of $11 million, and higher geophysical costs of $5 million.

Interest and debt expense totaled $251 million in 2003, $275 million in 2002 and
$195 million in 2001. The $24 million  decrease in 2003 was due to lower average
borrowings   under  revolving   credit   facilities  and  commercial   paper  of
approximately  $570 million and slightly  lower  average  interest  rates on the
company's  long-term debt. The $80 million increase in 2002 was due to an annual
average debt balance that was approximately $1.4 billion higher than 2001 due to
the acquisition of HS Resources in August 2001 and capitalized interest that was
lower by $23 million,  partially  offset by overall average  interest rates that
were approximately 1% lower than in the prior year.

Other  income  (expense)  includes  the  following  for each of the years in the
three-year period ended December 31, 2003:

(Millions of dollars)                                    2003     2002     2001
--------------------------------------------------------------------------------
Foreign currency translation gain (loss)                 $(41)    $(38)    $  3
Loss from equity affiliates                               (33)     (25)      (5)
Gain on sale of Devon stock                                17        -        -
Unrealized gain on Devon stock reclassified to
   "trading" category of investments                        -        -      181
Exchangeable debt embedded options and Devon
   stock revaluations                                       8       27       17
Gains (losses) on non-hedge natural gas derivatives        (4)       8       27
Other                                                      (6)      (7)       1
                                                         ----     ----     ----
         Other income (expense)                          $(59)    $(35)    $224
                                                         ====     ====     ====

The  majority of the 2003 and 2002 foreign  currency  losses  resulted  from the
company's U.K. operations, where the company has experienced unfavorable changes
in the U.S.  dollar/British  pound sterling exchange rates. The loss from equity
affiliates for 2003, 2002 and 2001 was primarily the result of the investment in
the AVESTOR  joint venture  formed in 2001 to develop new  lithium-metal-polymer
batteries.  The  2003  gain on sale of  Devon  stock  resulted  from the sale of
approximately  1 million  shares  that were in  excess of the total  shares  the
company believes will be required to extinguish the debt exchangeable for common
stock due in August 2004. The company sold its remaining Devon shares in January
2004 for a pretax  gain of $9  million.  All  other  Devon  shares  will be held
through August 2004 in connection with the maturity of the debt exchangeable for
common stock.

The  effective  tax rate for 2003 was 42.7%,  compared  with  (7.0)% in 2002 and
36.7% in 2001. The 2003  effective  rate is higher than the U.S.  statutory rate
primarily  due to the impact of  taxation  on foreign  operations.  The 2002 tax
benefit was reduced from the U.S.  statutory rate due to the deferred tax effect
of $132 million for the 33% increase in the U.K.  corporate tax rate for oil and
gas companies, together with the impact of taxation on foreign operations.

--------------------------------------------------------------------------------
Segment Operations

Operating profit (loss) from each of the company's segments is summarized in the
following table:

(Millions of dollars)                         2003           2002          2001
--------------------------------------------------------------------------------

Operating profit (loss) -
  Exploration and production                $1,002          $(140)         $922
                                            ------          -----          ----
  Chemicals -
    Pigment                                    (13)            24           (22)
    Other                                      (35)           (23)          (17)
                                            ------          -----          ----
      Total Chemicals                          (48)             1           (39)
                                            ------          -----          ----

Operating profit (loss)                     $  954          $(139)         $883
                                            ======          =====          ====


Exploration and Production

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


(Millions of dollars, except per-unit amounts)      2003        2002        2001
--------------------------------------------------------------------------------

Revenues -
  Crude oil and condensate sales                  $1,426      $1,531      $1,560
  Natural gas sales                                1,156         819         833
  Gas marketing activities                           298          70          22
  Other                                               43          30          13
                                                  ------      ------      ------
    Total                                         $2,923      $2,450      $2,428
                                                  ======      ======      ======

Production -
  Crude oil and condensate (thousands
    of barrels per day)                              150         191         189
  Natural gas (MMcf per day)                         726         760         596

  Total equivalent barrels of oil (thousands
    of barrels per day)                              271         318         288

Average Prices -
  Crude oil and condensate (per barrel) (1)       $26.04      $22.04      $22.60
  Natural gas (per Mcf) (1)                       $ 4.37      $ 2.95      $ 3.83

(1)  Includes  the  results  of the  company's  oil  and gas  commodity  hedging
     program,  which began in 2002.  In 2003,  hedges  reduced the average sales
     price of crude oil and  natural  gas sold by $2.46 per  barrel and $.55 per
     Mcf, respectively.  In 2002, hedge activity reduced the average sales price
     of crude oil and  natural  gas sold by $1.13 per  barrel  and $.01 per Mcf,
     respectively.

Oil sales revenues  declined $105 million in 2003 compared with 2002,  primarily
as a result of lower  production due to the  divestiture of various  properties.
This 21% decrease in oil  production  was  partially  offset by higher  realized
prices. The average realized price for oil increased $4 per barrel,  adding $220
million to oil revenues,  while lower oil  production  reduced  revenues by $325
million.

The 2003 oil production decline was primarily due to the sale of various noncore
properties  during 2003 and 2002.  The company  began a  divestiture  program in
mid-2002  to  improve  the  overall  quality of its asset  portfolio,  targeting
high-operating-cost, noncore assets. The program was completed in 2003. Property
sales were concentrated in the U.S. onshore region, Gulf of Mexico shelf and the
U.K. North Sea, as well as Ecuador and the South China Sea. After  adjusting for
divestitures, 2003 oil production was approximately the same as 2002.

Oil sales revenues for 2002 declined $29 million  compared with 2001,  primarily
driven by lower  realized  prices of $.56 per  barrel.  The 2002 oil  production
volumes remained relatively flat compared with 2001.

Natural gas sales revenues increased $337 million in 2003, primarily as a result
of a $1.42 per Mcf  increase in the  average  realized  price for  natural  gas,
partially offset by a 5% decline in production  volumes.  Higher realized prices
increased revenue by $374 million,  while lower gas production  reduced revenues
by  $37  million.   Production   declines   resulted   primarily  from  property
divestitures  concentrated  mainly in the U.S onshore  and Gulf of Mexico  shelf
areas. After adjusting for divestitures, 2003 gas production volumes declined by
2% compared with 2002.

Natural gas sales  revenue  decreased  $14 million in 2002  compared  with 2001.
Lower 2002 realized prices of $.88 per Mcf resulted in a revenue decline of $243
million that was  partially  offset by an increase of $229 million due to higher
sales volumes. In 2002, gas sales volumes increased 28% or 164 MMcf/day over the
2001 levels,  primarily due to a full year of gas production from the Wattenberg
field in Colorado, which was acquired in August 2001.

The variances in revenues from gas marketing activities are discussed in the Gas
Marketing Activities section below.

Operating Costs and Expenses - Operating costs and expenses relating to the sale
of crude oil, condensate and natural gas are shown in the following table.

(Millions of dollars)                                 2003       2002       2001
--------------------------------------------------------------------------------

Lease operating expense                             $  334     $  448     $  368
Production taxes                                        52         67         74
                                                    ------     ------     ------
   Total lifting costs                                 386        515        442

Transportation expense                                  94         84         71
Depreciation, depletion and amortization               609        690        619
Accretion expense (abandonment obligations)             25          -          -
General and administrative expense                     127         87         72
Exploration expense                                    354        273        210
Impairments on assets held for use                      14        646         47
Loss (gain) associated with assets held for sale       (45)       176          -
Gas gathering, pipeline and other                       66         61         28
                                                    ------     ------     ------
   Total operating cost and expenses                $1,630     $2,532     $1,489
                                                    ======     ======     ======

Lease Operating  Expense - During 2003, lease operating expense decreased 25% or
$114 million  compared with 2002. On a per-unit basis,  lease operating  expense
decreased by about 13% to $3.37 per barrel of oil equivalent  (BOE) sold in 2003
from  $3.87  per  BOE  in  2002.  Lower  costs  were  primarily  related  to the
divestiture of noncore,  high-operating-cost properties. Lease operating expense
increased $80 million in 2002  compared  with 2001,  resulting in costs of $3.87
and $3.50 per BOE, respectively.  Higher lease operating expense in 2002 was the
result of new  production  from the Nansen and Boomvang  fields in the deepwater
Gulf of Mexico and from a full year of  production  from the Leadon field in the
U.K.  North  Sea,  which  commenced  production  in late  2001.  A full  year of
operating  expenses  from the  Wattenberg  field  (acquired in August 2001) also
contributed to the increase.

Production  Taxes - During  2003,  production  taxes  decreased  by $15 million,
primarily due to the elimination of royalty  payments in the U.K. North Sea area
and lower  production  volumes.  These factors were  partially  offset by higher
commodity prices as production taxes are generally based on sales revenue.

Production  taxes in 2002 decreased by $7 million compared with 2001 as a result
of lower commodity prices  (primarily  natural gas prices),  partially offset by
higher sales volumes.

Transportation  Expense - Transportation  costs,  representing the costs paid to
third-party providers to transport oil and gas production, increased $10 million
during 2003.  Transportation costs in 2002 reflected a $13 million increase over
2001 levels.  The increase for both periods resulted from  transportation  costs
associated with new deepwater Gulf of Mexico  producing fields such as Boomvang,
Nansen  and  Navajo as well as  increased  costs in the U.K  North Sea area.  In
addition, 2002 transportation costs include a full year of costs associated with
the Wattenberg field.

Depreciation,   Depletion  and   Amortization  -  Depreciation,   depletion  and
amortization  (DD&A) expense  decreased $81 million in 2003,  representing a 12%
decline compared with 2002. The decrease in DD&A expense is primarily the result
of production  declines  associated with the  divestiture  program that began in
mid-2002 and asset  impairments that were recorded in 2002 (primarily the Leadon
field).  On a per-unit  basis,  DD&A  increased 3% to $6.16 per BOE in 2003 from
$5.97 per BOE in 2002.  Although total DD&A expense was lower, higher unit costs
resulted  from  the  company's  divestiture  activity  and  the  overall  mix of
producing  properties  between  2003 and 2002.  In  accordance  with  accounting
standards, depreciation was not recorded for various assets that were designated
as  held-for-sale  in 2003 and 2002,  although  production  quantities for these
properties continued to be included in the calculation of total unit DD&A.

DD&A  expense in 2002 was $71 million  higher than in 2001.  This  increase  was
primarily due to higher  production in 2002. On a per-unit  basis,  DD&A expense
increased  to $5.97 per BOE in 2002 from $5.89 per BOE in 2001.  The increase in
unit costs was due  primarily  to higher  DD&A rates for various new fields that
were  brought  on  production  in late 2002 and 2001,  including  the Nansen and
Boomvang  fields in the Gulf of Mexico as well as the  Leadon  field in the U.K.
North Sea. In addition,  a full year of  production  from the  Wattenberg  field
(acquired in August 2001) contributed to the increase.

Accretion  Expense - Accretion  expense of $25 million in 2003 is related to the
company's  discounted  abandonment  liability  recognized in 2003 as a result of
implementing  FAS 143.

General and Administrative  Expenses - General and administrative (G&A) expenses
were $40 million  higher in 2003  compared  with 2002.  This  resulted  from $27
million of nonrecurring  employee severance and related costs in 2003 associated
with the company's work-force reduction plan. Additionally, the company incurred
higher costs associated with employee  benefits and the pension plan, as well as
lower  billings of costs on operated  properties  to partners.  These costs were
partially offset by lower costs for direct labor and contract services.

G&A expense in 2002 was $15 million  higher than in 2001,  primarily as a result
of higher contract services and increased labor and benefits costs.

Exploration Expense - Exploration expense in 2003 was $81 million higher than in
2002 primarily as a result of higher dry hole costs from  increased  exploration
activity  during the year. In addition,  staffing  levels were increased  during
2003 to support  the  company's  worldwide  exploration  efforts  and  continued
development of the company's high-potential prospect inventory.

Exploration  expense in 2002 increased $63 million  compared with the prior year
primarily  as a result of  higher  dry hole  costs  from  increased  exploration
activity  during  the  year.  In  addition,   higher  amortization  expense  for
nonproducing  leaseholds  and increased  costs for  geological  and  geophysical
projects contributed to the increase.

Impairments on held-for-use  assets and the gain or loss on assets held for sale
have been discussed in the Statement of Operations Comparisons section above.

Gas Marketing  Activities - In the Rocky Mountain region,  Kerr-McGee  purchases
third-party  natural  gas for  aggregation  and  sale  with  the  company's  own
production from the Wattenberg  field in Colorado.  In addition,  Kerr-McGee has
purchased  transportation  capacity to markets in the Midwest to facilitate sale
of its  natural  gas outside the  immediate  vicinity  of its  production.  This
activity began with the company's acquisition of HS Resources in August 2001 and
has  increased  since that time.  Revenues  (from sale of  third-party  gas) and
associated  gas purchase cost relating to gas marketing  activities are shown in
the following table.

(Millions of dollars)                                 2003       2002      2001
--------------------------------------------------------------------------------

Gas marketing revenues                              $  298     $   70     $  22
Gas purchase costs (including transportation)         (291)       (58)      (17)
                                                    ------     ------     -----
    Net marketing margin                            $    7     $   12     $   5
                                                    ======     ======     =====

Marketing volumes (thousand MMBtu/day)                 178         77        29
                                                    ------     ------     -----

Marketing  revenues  increased $228 million in 2003 compared with 2002 primarily
due to higher  purchase and resale of natural gas in the Rocky Mountain area and
higher natural gas prices. Gas purchase costs increased  proportionately for the
same period, an increase of $233 million.

Marketing revenues  increased $48 million in 2002 compared with 2001,  primarily
as a result of a full year of  marketing  activity  in the Rocky  Mountain  area
after the HS Resources acquisition. Gas purchase costs also increased in 2002 by
$41 million in proportion to the higher level of marketing activity.


Chemicals

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

(Millions of dollars)                                 2003       2002      2001
--------------------------------------------------------------------------------

Revenues -
    Pigment                                         $1,079     $  995    $  931
    Other                                              183        201       196
                                                    ------     ------    ------
         Total                                      $1,262     $1,196    $1,127
                                                    ======     ======    ======

Operating profit (loss) -
    Pigment                                         $  (13)    $   24    $  (22)
    Other                                              (35)       (23)      (17)
                                                    ------     ------    ------
         Total                                      $  (48)    $    1    $  (39)
                                                    ======     ======    ======

Titanium dioxide pigment production
    (thousands of tonnes)                              532        508       483

Pigment - Revenues increased $84 million,  or 8%, in 2003 to $1.079 billion from
$995  million in 2002.  Of the total  increase,  $94  million  resulted  from an
increase in average sales prices, partially offset by a $10 million decrease due
to lower sales volumes. The increase in average sales prices in 2003 was largely
due to the effect of foreign  currency  exchange rates.  Excluding the effect of
foreign currency exchange rates,  average selling prices in local currencies for
2003 were 3% higher than in 2002.  Sales volumes for 2003 were  approximately 1%
lower than in the prior year.

Titanium  dioxide pigment  revenues for 2002 increased $64 million,  or 7%, over
2001,  resulting  from a $149  million  increase  due to  higher  sales  volume,
combined with an offsetting  decrease of $85 million resulting from weaker sales
prices in 2002,  of which $13 million was due to the effect of foreign  currency
exchange rates. While poor overall market conditions persisted through the first
quarter of 2002,  product demand increased through the remainder of the year. As
demand  accelerated,  the company announced multiple price increases through the
second half of 2002.

The chemical - pigment  operating unit recorded an operating loss of $13 million
in 2003,  compared with operating profit of $24 million in 2002. The $94 million
increase in  revenues  due to higher  sales  prices was  partially  offset by an
increase in average product costs of $51 million and an increase in shipping and
handling costs and selling, general and administrative costs of $18 million over
2002.  Additionally,  operating  results in 2003 were impacted by $47 million in
plant  closure  provisions  related  to the  synthetic  rutile  plant in Mobile,
Alabama,  together with a $23 million charge for work-force  reduction and other
compensation costs. The $47 million shutdown provision for the Mobile operations
included $6 million for curtailment costs related to pension and  postretirement
benefits.  The 2002  operating  profit  included  $12  million  in  charges  for
abandoned  chemical  engineering  projects,  $3 million for  severance and other
costs and a $5 million  reversal of environmental  reserves  associated with the
Savannah operations.

Operating  profit for 2002  improved  $46 million  over 2001.  Higher 2002 sales
volume,  combined  with  lower  average  per-unit  production  costs,  increased
operating profit by $57 million,  offset by reductions due to lower sales prices
of  $85  million.   Shipping  and  handling  costs  and  selling,   general  and
administrative  costs  decreased  $5 million from 2001.  In  addition,  the 2002
operating  profit  included a  provision  of $12  million  related to  abandoned
chemical engineering projects, a $5 million reversal of environmental  reserves,
and $3 million for severance and other costs,  compared with  provisions in 2001
for closure of a pigment  plant in Belgium,  asset  impairments,  severance  and
other costs totaling $79 million.

Other - Operating  loss for 2003 was $35  million on  revenues of $183  million,
compared with operating loss of $23 million on revenues of $201 million in 2002.
Of the decrease in sales, $27 million resulted from lower forest products sales,
partially  offset by a $9 million  increase  in  electrolytic  operations  sales
volumes.  The increased volumes were  predominantly  achieved in sodium chlorate
and boron  products,  17% and 37%,  respectively.  The $12  million  increase in
operating loss for 2003 was primarily due to 2003 work-force reduction and other
compensation  charges of $8 million and higher electrolytic  product costs of $8
million,   partially  offset  by  lower   environmental  costs  of  $5  million.
Environmental  provisions  in both 2003 and 2002  related  primarily to ammonium
perchlorate  remediation  associated  with  the  company's  Henderson,   Nevada,
operations  (See Note  16).  The 2003  operating  results  were also  negatively
affected  by  an  operating  loss  of  $12  million  from  the  forest  products
operations,  which includes shutdown provisions of $14 million,  compared with a
2002 operating loss of $10 million,  which included $23 million for shutdown and
impairment  provisions.  The 2003  forest  products  shutdown  provision  of $14
million  included  $8 million  for  curtailment  costs  related  to pension  and
postretirement benefits.

Operating  loss for 2002 was $23 million on revenues of $201  million,  compared
with  operating  loss of $17 million on revenues  of $196  million in 2001.  The
increase in operating loss was primarily due to 2002 provisions for the shutdown
and impairment of the forest products  business of $23 million and environmental
provisions of $15 million,  compared with 2001 provisions of $25 million for the
termination of manganese metal production and $5 million for severance and asset
impairment charges.

During  the  third  quarter  of  2003,   Kerr-McGee   Chemical  LLC  placed  its
electrolytic  manganese  dioxide  (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,  Kerr-McGee Chemical 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 will continue to monitor market conditions.

--------------------------------------------------------------------------------
Financial Condition

(Millions of dollars)                              2003        2002        2001
--------------------------------------------------------------------------------

Current ratio                                  0.8 to 1    0.8 to 1    1.2 to 1
Total debt                                       $3,655      $3,904      $4,574
Total debt less cash (net debt)                   3,513       3,814       4,483
Total debt less cash and DECS                     3,187       3,496       4,173
Stockholders' equity                             $2,636      $2,536      $3,174
Net debt to total capitalization                     57%         60%         59%
Total debt less cash and DECS to total
  capitalization                                     55%         58%         57%
Floating-rate debt to total debt (including
  fixed-rate debt with interest rate swap to
  variable rate)                                     14%         16%         28%

The negative  working capital at the end of 2003 and 2002 is not indicative of a
lack of liquidity as the company maintains  sufficient  current assets to settle
current liabilities when due. Current asset balances are minimized as one way to
finance capital  expenditures and lower borrowing costs. If needed,  the company
also has unused lines of credit and revolving credit  facilities as discussed in
the Liquidity section that follows.

Kerr-McGee  operates with the  philosophy  that over a five-year plan period the
company's capital  expenditures and dividends should be paid from cash generated
by operations. On a cumulative basis, the cash generated from operations for the
past five years has exceeded the  company's  capital  expenditures  and dividend
payments.   Debt  and  equity   transactions   are  utilized   for   acquisition
opportunities and short-term needs due to timing of cash flow.


(Percentages)                                           2003      2002      2001
--------------------------------                        ----      ----      ----
Net Debt to Total Capitalization                         57%       60%       59%

(Net debt to total  capitalization is total debt less cash divided by total debt
less cash plus stockholders' equity.)

A reduction in net debt of $301 million from 2002,  combined with an increase in
stockholders'  equity  of  $100  million  resulted  in a 3%  improvement  in the
percentage  of net  debt to  total  capitalization  as  compared  to  2002.  The
company's goal is to reduce its  percentage of net debt to total  capitalization
to 50% or below by the end of 2004.  Although debt was reduced $670 million from
2001 to 2002, a decrease in equity  resulting  primarily  from the 2002 net loss
and dividends  declared  resulted in a slightly higher percentage of net debt to
total capitalization in 2002 compared with 2001.


Cash Flow

(Millions of dollars)                                  2003      2002      2001
-----------------------------------                   ------    ------    ------
Cash Flow from Operating Activities                   $1,518    $1,448    $1,143

(Cash flow from operating  activities has increased  significantly over the past
two years.)

Cash flow from operating activities  increased $70 million,  from $1.448 billion
in 2002 to  $1.518  billion  in 2003,  primarily  due to an  increase  in income
excluding noncash items,  partially offset by changes in various working capital
items.  Year-end  2003  cash was $142  million,  compared  with $90  million  at
December 31, 2002.

The company  invested $1.2 billion in its 2003 capital  program,  which included
$181 million of unsuccessful exploratory drilling costs. The capital program for
2003 was $110 million  lower than in the prior year,  resulting  primarily  from
lower capital  expenditures  in the North Sea, Rocky  Mountain and U.S.  onshore
regions,  partially offset by higher capital  expenditures in the Gulf of Mexico
and China and higher dry hole costs.  During  2003,  the company  completed  the
divestiture  of several  oil and gas  properties  and other  assets,  generating
proceeds of $304 million.  These  proceeds were used primarily to pay down debt.
The  company  also  invested  $110  million  in  selected  oil and gas  property
acquisitions  related to the  acquisition of an additional  interest in the U.K.
Gryphon and South Gryphon  fields and an onshore  property  acquisition in South
Texas. Cash outlays for investing activities include a $34 million investment by
the chemical unit in AVESTOR, its lithium-metal-polymer battery joint venture in
Canada. Other investing cash inflows included $47 million in proceeds related to
the sale of Devon stock.


(Millions of dollars)                                  2003      2002      2001
-----------------------------------                   ------    ------    ------
Total Debt                                            $3,655    $3,904    $4,574

(From  year-end 2001 to 2003,  the company  reduced total debt by more than $900
million.)

During 2003, the company reduced its variable  interest rate commercial paper by
$68 million.  Other debt was reduced $301 million,  which included  repayment of
current year borrowings on revolving credit facilities of $31 million.  Included
in the  total  2003  repayments  of  $301  million  is $64  million  related  to
open-market  repurchases  of  long-term  debt  issuances  on which  the  company
recorded a loss of $7 million for early  extinguishment  in other expense in the
Consolidated  Statement of  Operations.  However,  by executing the  open-market
repurchases, the company will avoid approximately $10 million in future interest
expense.  The company added $75 million in debt at December 31, 2003, due to the
consolidation of the Kerr-McGee Gunnison Trust. This synthetic lease arrangement
was  restructured  to an operating  lease  arrangement  in January 2004, and the
related debt will no longer be reflected on the  company's  balance  sheet.  The
consolidation,  which  resulted in a noncash  increase in debt and property,  is
discussed in more detail in the Off-Balance  Sheet  Arrangements  section below.
Cash flow was used to pay the company's dividends of $181 million in 2003.

As of December 31, 2003,  the company's  senior  unsecured debt was rated BBB by
Standard & Poor's and Fitch and Baa3 by  Moody's.  See Note 9 for details of the
company's  debt.  At December  31,  2001,  the  company's  outstanding  debt had
increased  significantly  from  prior-year  levels to fund the acquisition of HS
Resources  and major  development  projects  in the Gulf of Mexico and the North
Sea. Throughout 2002 and 2003, the company  aggressively pursued its strategy of
divesting  noncore,  high-cost  assets,  the proceeds  from which have been used
primarily  to reduce the  company's  outstanding  debt.  The company  expects to
further  reduce debt by  approximately  $550 million during 2004 by using excess
cash flows and by using Devon common stock to repay the $330 million face amount
of debt exchangeable for Devon common stock (DECS) owned by the company.

Liquidity

The company  believes  that it has the  ability to provide  for its  operational
needs and its long- and short-term  capital  programs through its operating cash
flow (partially protected by the company's hedging program),  borrowing capacity
and ability to raise  capital.  The company's  primary  source of funds has been
from operating cash flow, which could be adversely  affected by declines in oil,
natural gas and pigment prices, all of which can be volatile as discussed in the
preceding Outlook section.  Should operating cash flows decline, the company may
reduce its capital  expenditures  program,  borrow  under its  commercial  paper
program,  draw  upon  revolving  credit  facilities  and/or  consider  selective
long-term borrowings or equity issuances. Kerr-McGee's commercial paper programs
are backed by the revolving  credit  facilities  currently in place.  Should the
company's  commercial  paper or debt rating be downgraded,  borrowing costs will
increase,  and the company may experience loss of investor  interest in its debt
instruments  as  evidenced  by a  reduction  in the number of  investors  and/or
amounts they are willing to invest.

At December  31,  2003,  the company  had unused  lines of credit and  committed
amounts under revolving  credit  agreements  totaling $1.4 billion.  The company
maintains two revolving credit agreements consisting of a five-year $650 million
facility signed January 12, 2001, and a 364-day $700 million facility renewed on
November 14, 2003. In addition,  the company had other unused credit  facilities
of $50 million at December 31, 2003. Of the total of $1.4 billion,  $870 million
and $490 million can be used to support  commercial paper borrowings in the U.S.
and  Europe,  respectively,   by  certain  wholly  owned  subsidiaries  and  are
guaranteed by the parent  company.  The borrowings can be made in U.S.  dollars,
British pound sterling, euros or local European currencies. Interest for each of
the revolving credit facilities and lines of credit is payable at varying rates.

The company holds derivative financial  instruments that require margin deposits
if unrealized  losses exceed limits  established  with  individual  counterparty
institutions.  From time to time, the company may be required to advance cash to
its  counterparties to satisfy margin deposit  requirements.  No margin deposits
were  outstanding  at December 31, 2003.  Between  January 1, 2004, and March 5,
2004,  margin calls totaled $7 million;  however,  these amounts have since been
refunded to the company.

At December  31,  2002,  the company  classified  $68 million of its  short-term
obligations as long-term  debt.  The company has the intent and the ability,  as
evidenced by committed  credit  agreements,  to refinance this type of debt on a
long-term  basis. The company's  practice has been to continually  refinance its
commercial paper or draw on its backup facilities,  while maintaining  borrowing
levels believed to be appropriate.

The company  issued 5 1/2% notes  exchangeable  for common stock in August 1999,
which  allow 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.  As of February 27, 2004,  Devon common stock was trading at $56.78
per share.  Embedded  options in the DECS  provide  the company a floor price on
Devon's common stock of $33.19 per share (the put option).  The company also has
the right to retain up to 15% of the  shares if Devon's  stock  price is greater
than $39.16 per share (the DECS holders  have an embedded  call option on 85% of
the shares). If Devon's stock price at maturity is greater than $33.19 per share
but less than $39.16 per share,  the company's  right to retain Devon stock will
be reduced  proportionately.  The  company is not  entitled  to retain any Devon
stock if the price of Devon  stock at  maturity  is less than or equal to $33.19
per share.  Using the Black-Scholes  valuation model, the company recognizes any
gains or losses  resulting  from  changes  in the fair value of the put and call
options  in  other  income.  The  fluctuation  in the  value of the put and call
derivative  financial  instruments will generally offset the increase or decease
in the market  value of the Devon stock  classified  as trading.  The  remaining
Devon shares,  accounted for as  available-for-sale  securities,  were partially
liquidated in December 2003, with the remaining shares sold in January 2004. The
available-for-sale  Devon  shares  were in  excess of the  number of shares  the
company  believes will be required to extinguish the DECS;  however,  should the
price of the stock fall below $39.16 per share at the maturity of the DECS,  the
company would be required to either purchase  additional  Devon shares to settle
the DECS or settle a portion of the DECS with cash.

The company also has  available,  to issue and sell, a total of $1.65 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.

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.  Also,  the  company  entered  into an  accounts  receivable
monetization  program to sell its receivables  from certain  pigment  customers.
Each of these  transactions  has provided  specific  financing for the company's
business  needs and/or  projects and does not expose the company to  significant
additional risks or commitments. The leases have provided a tax-efficient method
of financing a portion of these major development projects,  and the sale of the
pigment receivables offers an attractive low-cost source of liquidity.

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, the
company 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,  the  company's  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  platform  and related  equipment.  During  2002,  the Nansen and  Boomvang
synthetic leases were converted to operating lease  arrangements upon completion
of  construction  of the  respective  production  platforms.  Completion  of the
Gunnison  platform  occurred  in December  2003,  at which time a portion of the
Gunnison  synthetic  lease was  converted to an operating  lease.  The remaining
portion of the Gunnison  synthetic  lease was converted to an operating lease on
January 15, 2004. 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.
However, since only a portion of the Gunnison synthetic lease had been converted
to an  operating  lease  structure  as of  year-end,  the  remaining  assets and
liabilities  of the  synthetic  lessor trust are  consolidated  in the company's
Consolidated  Balance Sheet at December 31, 2003,  which includes $83 million in
property, plant and equipment, $4 million in accrued liabilities, $75 million in
long-term debt and $4 million in minority  interest.  The  consolidation  of the
synthetic  lessor  trust  occurred  in  connection  with the  adoption  of a new
accounting standard as discussed in the New/Revised Accounting Standards section
below. Since the remaining portion of the Gunnison synthetic lease was converted
to an operating lease structure in January,  the related  property and debt will
not be reflected in the company's Consolidated Balance Sheet in 2004.

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.

In December 2000, the company began an accounts receivable  monetization program
for its pigment business through the sale of selected accounts receivable with a
three-year,  credit-insurance-backed  asset securitization  program. On July 30,
2003, the company  restructured the existing  accounts  receivable  monetization
program to include the sale of receivables  originated by the company's European
chemical operations.  The maximum available funding under the amended program is
$165 million. In addition, certain other terms of the program have been modified
as  part  of  the  restructuring.  Under  the  terms  of the  program,  selected
qualifying customer accounts receivable may be sold monthly to a special-purpose
entity  (SPE),  which  in turn  sells an  undivided  ownership  interest  in the
receivables to a third-party  multi-seller commercial paper conduit sponsored by
an independent financial institution. The company sells, and retains an interest
in, excess receivables to the SPE as over-collateralization for the program. The
company's  retained  interest  in the SPE's  receivables  is  recorded  in trade
accounts receivable in the Consolidated  Balance Sheet. The retained interest is
subordinate to, and provides  credit  enhancement  for, the conduit's  ownership
interest  in the SPE's  receivables,  and is  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 termination.  However,
the company believes that the risk of credit loss is very low since its bad-debt
experience  has  historically  been   insignificant.   The  company  also  holds
preference stock in the special-purpose  entity equal to 3.5% of the receivables
sold. The preference  stock is essentially a retained deposit to provide further
credit enhancements,  if needed, but is otherwise  recoverable by the company at
the end of the program. The company records a loss on the receivable sales equal
to the  difference  in the cash  received  plus the fair  value of the  retained
interests and the carrying value of the receivables  sold. The fair value of the
retained  interests  (servicing fees, excess receivables and preference stock of
the SPE) is based on the  discounted  present  value of future  cash  flows.  At
year-end 2003 and 2002, the  outstanding  balance on receivables  sold under the
program totaled $165 million and $111 million, respectively.

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 Rocky Mountain  region.  The lease  agreements were
entered into for the purpose of monetizing the related  assets.  The sales price
for the 2003  equipment was $6 million.  The sales price for the 2002  equipment
was $71  million;  however,  an $18 million  settlement  obligation  existed for
equipment  previously  covered  by the lease  agreement,  resulting  in net cash
proceeds of $53 million in 2002. 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  guarantees a
residual  value  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.  Estimated  future
minimum annual rentals under this agreement and the residual value guarantee are
shown in the table of contractual obligations below.

In  conjunction  with the company's 2002 sale of its  Ecuadorean  assets,  which
included the company's  nonoperating interest in the Oleoducto de Crudos Pesados
Ltd.  (OCP)  pipeline,  the  company has entered  into a  performance  guarantee
agreement  with  the  buyer  for the  benefit  of OCP.  Under  the  terms of the
agreement,  the  company  guarantees  payment of any claims from OCP against the
buyer upon default by the buyer and its parent  company.  Claims would generally
be for the buyer's  proportionate  share of construction  costs of OCP; however,
other claims may arise in the normal  operations of the  pipeline.  Accordingly,
the  amount  of any such  future  claims  cannot  be  reasonably  estimated.  In
connection with this  guarantee,  the buyer's parent company has issued a letter
of credit in favor of the company up to a maximum of $50 million, upon which the
company  can draw in the event it is  required  to perform  under the  guarantee
agreement.  The company  will be  released  from this  guarantee  when the buyer
obtains a specified credit rating as stipulated under the guarantee agreement.

In addition, the company enters 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.

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 unrelated parties. As part of the company's project-oriented exploration and
production  business,  Kerr-McGee  routinely  enters into  contracts for certain
aspects of a project,  such as  engineering,  drilling,  subsea work, etc. These
contracts are generally not unconditional obligations; thus, the company accrues
for the value of work done at any point in time, a portion of which is billed to
partners.  Kerr-McGee's commitments and obligations as of December 31, 2003, are
summarized in the following table:

(Millions of dollars)                             Payments due by period
--------------------------------------------------------------------------------
                                                            2005   2007    After
Type of Obligation                         Total   2004    -2006  -2008     2008
------------------                        ------   ----   ------   ----   ------
Long-term debt (1)                        $3,580   $574   $  767   $150   $2,089
Operating leases for Nansen,
  Boomvang and Gunnison                      599     17       51     54      477
All other operating leases                   342     33       80     66      163
Drilling rig commitments                       9      9        -      -        -
Purchase obligations -
  Ore contracts                              477    168      235     74        -
  Gas purchase and transportation
    contracts                                112     49       21     17       25
  Other purchase obligations                 405    128      158     67       52
Leased equipment residual value
   guarantees                                 72      -        -     35       37
                                          ------   ----   ------   ----   ------
     Total                                $5,596   $978   $1,312   $463   $2,843
                                          ======   ====   ======   ====   ======

(1)  Excludes the $75 million of debt  associated  with the Gunnison  Trust.  As
     discussed above, the synthetic lease was restructured to an operating lease
     in January 2004.  The related  future  minimum lease  payments are included
     with operating leases for Gunnison.

--------------------------------------------------------------------------------
Capital Spending

Capital expenditures are summarized as follows:

(Millions of dollars)                       Est. 2004     2003     2002     2001
--------------------------------------------------------------------------------
Exploration and production, including
   dry hole costs                              $  920   $1,050   $1,101   $1,629
Chemicals                                          95       97       86      153
Other, including discontinued operations           20       15       85       82
                                               ------   ------   ------   ------
     Total                                     $1,035   $1,162   $1,272   $1,864
                                               ======   ======   ======   ======

Capital spending, excluding acquisitions, totaled $4.3 billion in the three-year
period ended  December 31, 2003,  and dividends paid totaled $535 million in the
same three-year period, which compares with $4.1 billion of net cash provided by
operating  activities during the same period.  During the three-year period, the
company made one major  acquisition -- the 2001  acquisition of HS Resources for
$955 million cash plus common stock and assumed debt.

Kerr-McGee has budgeted  approximately $1.035 billion for its capital program in
2004. Management  anticipates that the 2004 capital program,  dividends and debt
reduction can be provided for through internally  generated funds. The available
capacity for borrowings may be used for selective  acquisitions that support the
company's  growth  strategy  or to support  the  company's  capital  expenditure
program should internally  generated cash flow fall short in any one measurement
period.

Oil and Gas

The  company's  exploration  and  production  capital  spending  continues to be
focused on global  growth and deepwater  projects.  Successful  exploration  and
appraisal  drilling  in  the  deepwater  Gulf  of  Mexico  has  resulted  in the
development  of three  major  projects  during the last two years - Nansen  (50%
working  interest),  Boomvang (30%),  and Gunnison (50%). The Red Hawk (50%) and
Constitution  (100%)  projects  currently  under  development  are  also  in the
deepwater  Gulf of Mexico.  Constitution  will be  developed  with a truss spar,
capitalizing  on the  success of the truss  spar  technology  introduced  at the
Nansen,  Boomvang and Gunnison  fields,  while Red Hawk is being developed using
innovative  cell  spar  technology.  Red  Hawk  is  expected  to  reach  initial
production in mid-2004, while Constitution is expected to reach first production
by mid-2006. The company expects initial production at its Bohai Bay development
by the end of 2004.  Two  Bohai  Bay  discoveries  are  being  developed  with a
centrally located floating production, storage and offloading vessel, along with
fixed platforms for dry wellheads.  Kerr-McGee  operates this development with a
40% working interest. Of the $920 million total budget for 2004, $330 million is
allocated to the Gulf of Mexico,  $180 million to the North Sea, $155 million to
U.S.  onshore,  $125  million to other  international  projects,  $10 million to
technology  enhancements  and $120 million for dry hole costs. In addition,  the
company has budgeted  approximately $130 million (excluding noncash amortization
of nonproducing leasehold costs) for other exploration program expenses in 2004.
The company's  exploration  program is expected to fund  approximately 50 wells,
with emphasis on balancing risks and potential  rewards in both shallow and deep
waters and U.S. onshore.

Chemicals

Capital  expenditures  for chemical  operations  are budgeted at $95 million for
2004. Process and technology improvements that increase productivity and enhance
product quality will account for  approximately  30% of the 2004 capital budget.
This   includes   the   remaining   estimated   expenditures   related   to  the
high-productivity  oxidation  line that began  production in January 2004 at the
Savannah,  Georgia,  chloride-process  pigment plant. Chemical has also budgeted
$38 million of additional investment in AVESTOR for 2004.

--------------------------------------------------------------------------------
Market Risks

The company is exposed to a variety of market risks, including credit risks, the
effects of movements in foreign  currency  exchange  rates,  interest  rates and
certain commodity  prices.  The company addresses its risks through a controlled
program of risk  management  that includes the use of insurance  and  derivative
financial  instruments.  See Notes 1 and 18 for  additional  discussions  of the
company's financial instruments, derivatives and hedging activities.

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. Periodically, the company enters into forward contracts
to buy and sell foreign  currencies.  Certain of these  contracts  (purchases of
Australian  dollars and  British  pound  sterling,  and sales of euro) have been
designated and have  qualified as cash flow hedges of the company's  anticipated
future cash flow needs for a portion of its capital  expenditures,  raw material
purchases and operating costs. These contracts  generally have durations of less
than three years.  The  resulting  changes in fair value of these  contracts are
recorded in accumulated other comprehensive income.

Selected pigment receivables have been sold in an asset  securitization  program
at their equivalent U.S. dollar value at the date the receivables were sold. The
company  is  collection  agent and  retains  the risk of foreign  currency  rate
changes  between the date of sale and collection of the  receivables.  Under the
terms of the asset  securitization  agreement,  the company is required to enter
into forward  contracts for the value of the  euro-denominated  receivables sold
into the program to mitigate its foreign  currency risk.  Gains or losses on the
forward contracts are recognized currently in earnings.  The company has entered
into other forward contracts to sell foreign currencies, which will be collected
as a result of pigment sales  denominated  in foreign  currencies,  primarily in
European  currencies.  These  contracts have not been  designated as hedges even
though they do protect the company from changes in foreign currency rates.

Following   are  the   notional   amounts  at  the  contract   exchange   rates,
weighted-average  contractual  exchange rates and estimated  contract values for
open contracts at year-end 2003 and 2002 to purchase (sell) foreign  currencies.
Contract values are based on the estimated  forward  exchange rates in effect at
year-end. All amounts are U.S. dollar equivalents.


                                                                                                           Estimated
(Millions of dollars,                                 Notional           Weighted-Average                   Contract
except average contract rates)                          Amount              Contract Rate                      Value
--------------------------------------------------------------------------------------------------------------------
                                                                                                       
Open contracts at December 31, 2003 -
     Maturing in 2004 -
         British pound sterling                           $139                     1.6372                       $148
         Australian dollar                                  38                      .5366                         51
         Euro                                             (113)                    1.1358                       (106)
         British pound sterling                             (1)                    1.6876                         (1)
         Japanese yen                                       (2)                     .0092                         (2)
         New Zealand dollar                                 (1)                     .6121                         (1)
     Maturing in 2005 -
         British pound sterling                             77                     1.5995                         82

Open contracts at December 31, 2002 -
     Maturing in 2003 -
         British pound sterling                            113                     1.5454                        115
         Australian dollar                                  63                      .5606                         62
         Euro                                              (10)                     .9833                        (10)
         British pound sterling                             (1)                    1.5432                         (1)
         Japanese yen                                       (1)                     .0080                         (1)
         New Zealand dollar                                 (1)                     .4807                         (1)
     Maturing in 2004 -
         Australian dollar                                  38                      .5366                         38


Interest Rate Risk

The  company's  exposure  to changes in  interest  rates  relates  primarily  to
long-term  debt  obligations.  The table below  presents  principal  amounts and
related  weighted-average  interest  rates by  maturity  date for the  company's
long-term debt  obligations  outstanding at year-end 2003. All borrowings are in
U.S. dollars.


                                                                                      There-                Fair Value
(Millions of dollars)          2004       2005       2006       2007       2008        after      Total       12/31/03
----------------------------------------------------------------------------------------------------------------------
                                                                                        
Fixed-rate debt -
   Principal amount            $474       $110       $307       $150       $  -       $2,089     $3,130         $3,550
   Weighted-average
      interest rate            6.41%      8.15%      5.88%      6.63%         -         6.67%      6.61%

Variable-rate debt - (1)
   Principal amount            $100       $350       $ 75       $  -       $  -       $    -     $  525         $  525
   Weighted-average
      interest rate            1.92%      2.03%      1.93%         -          -            -       1.99%


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

At December 31, 2002,  long-term debt included fixed-rate debt of $3.286 billion
(fair value - $3.706 billion) with a weighted-average interest rate of 6.67% and
$618  million of  variable-rate  debt,  which  approximated  fair value,  with a
weighted-average interest rate of 2.56%.

In connection with the issuance of $350 million 5.375% notes due April 15, 2005,
the company entered into an interest rate swap arrangement in 2002. The terms of
the agreement  effectively  change the interest the company will pay on the debt
until  maturity from the fixed rate to a variable rate of LIBOR plus .875%.  The
company considers the swap to be a hedge against the change in fair value of the
debt as a result of  interest  rate  changes.  The  estimated  fair value of the
interest rate swap was $15 million at December 31, 2003.

During  February 2004, the company  reviewed the  composition of its outstanding
debt and entered into additional interest rate swaps, converting an aggregate of
$566 million in fixed-rate debt to  variable-rate  debt. Under the interest rate
swaps,  $150 million of 6.625%  notes due October 15, 2007,  will pay a variable
rate of LIBOR plus 3.35%;  $109  million of 8.125%  notes due October 15,  2005,
will pay a variable  rate of LIBOR plus 5.86%;  and $307 million of 5.875% notes
due  September  15,  2006,  will pay a variable  rate of LIBOR  plus  3.1%.  The
interest rate swaps have been  designated as hedges against  changes in the fair
value of the related debt  resulting  from interest rate changes.  The estimated
fair value of the interest rate swaps,  including the original swap  outstanding
at December 31, 2003, totaled $21 million as of February 29, 2004.

Commodity Price Risk

The company is exposed to market risk from fluctuations in crude oil and natural
gas prices.  To  increase  the  predictability  of its cash flows and to support
capital  projects,   the  company  initiated  a  hedging  program  in  2002  and
periodically enters into financial derivative instruments that generally fix the
commodity  prices to be received for a portion of its oil and gas  production in
the future. At December 31, 2003, the outstanding  commodity-related derivatives
accounted  for as hedges had a liability  fair value of $168  million,  which is
recorded as a current liability.  The fair value of these derivative instruments
at December 31, 2003, was determined based on prices actively quoted,  generally
NYMEX and Dated Brent  prices.  At December 31, 2003,  the company had after-tax
deferred  losses of $106  million  in  accumulated  other  comprehensive  income
associated  with these  contracts.  The company expects to reclassify the entire
amount of these  losses  into  earnings  during the next 12 months,  assuming no
further changes in fair market value of the contracts.  During 2003, the company
realized a $71 million loss on U.S. oil hedging, a $64 million loss on North Sea
oil hedging and a $144  million loss on U.S.  natural gas hedging.  During 2002,
the company realized a $28 million loss on U.S. oil hedging,  a $50 million loss
on North Sea oil hedging and a $2 million loss on U.S. natural gas hedging.  The
losses  offset the higher oil and  natural gas prices  realized on the  physical
sale of  crude  oil and  natural  gas.  Losses  for  hedge  ineffectiveness  are
recognized as a reduction of revenue in the Consolidated Statement of Operations
and were not material for 2003 or 2002.

At December 31, 2003, the following commodity-related  derivative contracts were
outstanding:

                                                         Daily           Average
Contract Type (1)                           Period      Volume             Price
--------------------------------------------------------------------------------

Natural Gas                                             MMBtu            $/MMBtu
-----------                                            -------           -------
  Fixed-price swaps (NYMEX)              Q1 - 2004     195,000             $5.33
                                         Q2 - 2004     565,000             $4.74
                                       Q3,4 - 2004     575,000             $4.75


  Costless collars (NYMEX)               Q1 - 2004     360,000     $4.79 - $6.47

  Basis swaps (CIG and Northwest)        Q1 - 2004     135,000             $0.57
                                       Q2,3 - 2004      55,000             $0.47
                                         Q4 - 2004      41,739             $0.38

Crude Oil                                                 Bbl             $/Bbl
---------                                               ------            ------
  Fixed-price swaps (WTI)                Q1 - 2004      48,000            $28.57
                                         Q2 - 2004      48,000            $27.65
                                         Q3 - 2004      45,000            $27.29
                                         Q4 - 2004      30,000            $26.96

  Fixed-price swaps (Brent)              Q1 - 2004      45,000            $26.38
                                         Q2 - 2004      46,500            $25.86
                                         Q3 - 2004      39,750            $25.98
                                         Q4 - 2004      32,000            $25.65

(1)  These  contracts  may be  subject  to margin  calls  above  certain  limits
     established with individual counterparty institutions.

After  December 31, 2003,  the following  derivative  contacts were added to the
company's  2004 hedging  program and,  combined with the hedges  outstanding  at
December 31, 2003, cover  approximately 80% of expected 2004 worldwide crude oil
and condensate production, and 75% of the U.S. natural gas production.

                                                         Daily           Average
Contract Type (1)                           Period      Volume             Price
--------------------------------------------------------------------------------

Crude Oil                                                 Bbl              $/Bbl
---------                                               ------            ------
    Fixed-price swaps (WTI)              Q1 - 2004       4,352            $34.13
                                         Q2 - 2004       6,300            $32.67
                                         Q3 - 2004       5,915            $31.18
                                         Q4 - 2004      20,015            $30.28

    Fixed-price swaps (Brent)            Q1 - 2004       4,286            $30.77
                                         Q2 - 2004       5,300            $29.92
                                         Q3 - 2004       7,100            $29.07
                                         Q4 - 2004      20,000            $28.41

(1)  These  contracts  may be  subject  to margin  calls  above  certain  limits
     established with individual counterparty institutions.

In addition to the company's  hedging  program,  Kerr-McGee Rocky Mountain Corp.
holds certain gas basis swaps settling  between 2004 and 2008.  Through December
2003, the company  treated these gas basis swaps as non-hedge  derivatives,  and
changes in fair value were  recognized  in earnings.  On December 31, 2003,  the
company  designated those swaps settling in 2004 as hedges since the basis swaps
have been  coupled  with  natural gas  fixed-price  swaps,  while the  remainder
settling  between  2005  and 2008  will  continue  to be  treated  as  non-hedge
derivatives.  At December 31, 2003, these derivatives are recorded at their fair
value of $23 million, of which $8 million is recorded as a current asset and $15
million is recorded in investments - other assets.  At December 31, 2002,  these
derivatives  were  recorded at their fair value of $21 million in  investments -
other assets. The net gains associated with these non-hedge  derivatives were $2
million,  $8 million and $27 million in 2003, 2002 and 2001,  respectively,  and
are included in other income in the Consolidated Statement of Operations.

The company's marketing subsidiary,  Kerr-McGee Energy Services (KMES),  markets
natural gas (primarily  equity gas) in the Denver area.  Existing  contracts for
the physical  delivery of gas at fixed prices have not been designated as hedges
and are marked to market in accordance  with FAS 133. KMES has also entered into
natural gas swaps and basis swaps that offset its  fixed-price  risk on physical
contracts.  These derivative  contracts lock in the margins  associated with the
physical sale. The company believes that risk associated with these  derivatives
is minimal due to the  credit-worthiness  of the  counterparties.  The net asset
fair value of these derivative instruments was not material at year-end 2003 and
2002. The fair values of the outstanding  derivative instruments at December 31,
2003, were based on prices actively quoted. During 2003, the net loss associated
with these  derivative  contracts  totaled $12  million,  of which $7 million is
included as a reduction  of revenue and $5 million is included in other  income.
For 2002 and 2001,  the net loss  associated  with  these  derivative  contracts
totaled  $20  million  and  $24  million,  respectively,  and is  included  as a
reduction of revenue in the Consolidated Statement of Operations.  The losses on
the derivative  contracts are substantially  offset by the fixed prices realized
on the physical sale of the natural gas.

--------------------------------------------------------------------------------
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.  However, the
accounting  principles used by the company generally do not impact the company's
reported cash flows or liquidity.  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 done and  judgments  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  assessment  of unproved oil and gas  properties  for  impairment,
crude oil and natural  gas  reserve  estimation,  site  dismantlement  and asset
retirement  obligations,  recoverability of assets,  environmental  remediation,
derivative   instruments,   litigation,   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.

Successful Efforts Method of Accounting

The company has elected to use the  successful  efforts method of accounting for
its oil and gas exploration and development  activities.  Exploration  expenses,
including geological and geophysical costs,  rentals, and exploratory dry holes,
are charged  against income as incurred.  Costs of successful  wells and related
production  equipment and  developmental dry holes are capitalized and amortized
by field using the  unit-of-production  method as oil and gas is  produced.  The
successful efforts method reflects the inherent  volatility in exploring for and
producing oil and gas. The accounting method may yield  significantly  different
operating results than the full-cost method.

Under the successful  efforts method,  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 drilling  operations.  However,  such  determination may take
longer depending on, among other things, the amount of hydrocarbons encountered,
results of future appraisal drilling and proximity to existing  infrastructure -
especially  in  the  case  of  deepwater  and  international  exploration.  As a
consequence, the company has capitalized costs associated with exploratory wells
on its  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.  At December 31, 2003,  the company had
capitalized  costs of  approximately  $143 million  associated with such ongoing
exploration activities, primarily in the deepwater Gulf of Mexico and China.

Oil and Gas Reserves and Standardized Measure of Future Cash Flows

The estimates of oil and gas reserves and  associated  future net cash flows are
prepared by the  company's  geologists  and  engineers.  Only proved oil and gas
reserves are included in any financial statement disclosure. The U.S. Securities
and Exchange Commission has defined proved reserves as the estimated  quantities
of  crude  oil,  natural  gas and  natural  gas  liquids  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 the company's geologists and engineers are knowledgeable
and follow authoritative  guidelines for estimating  reserves,  they must make a
number of subjective  assumptions based on professional  judgments in developing
the reserve  estimates.  Reserve  estimates  are updated at least  annually  and
consider recent  production  levels and other technical  information  about each
field.  Revisions  in the  estimated  reserves  and  future  cash  flows  may be
necessary  due to a number of  factors,  including  reservoir  performance,  new
drilling,  oil and gas  prices and cost  changes,  technological  advances,  new
geological or geophysical data, or other economic  factors.  See Notes 32 and 33
to the Consolidated  Financial Statements for information  concerning historical
changes in reserve  estimates and standardized  measure of future cash flows for
each of the last three years.  The company  cannot predict the amounts or timing
of future reserve revisions.

Depreciation  and depletion  rates are  calculated  using both reserve  quantity
estimates and the capitalized  costs of producing  properties.  As the estimated
reserves are adjusted,  the  depreciation  and depletion  expense for a property
will change,  assuming no change in production volumes or the costs capitalized.
Estimated  reserves  also are used as the basis  for  calculating  the  expected
future cash flows from a property,  which are further used to analyze a property
for  potential  impairment.  In  addition,  reserves  are used to  estimate  the
company's  supplemental  disclosure  of the  standardized  measure of discounted
future net cash flows relating to its oil and gas producing activities.  Changes
in  estimated  reserves  are  considered  changes in  estimates  for  accounting
purposes and are reflected on a prospective basis.

Site Dismantlement and Asset Retirement Obligations

The company has significant obligations for the dismantlement and removal of its
oil and gas production and related  facilities.  Estimating future asset removal
costs is difficult and requires management to make estimates and judgments since
most of the removal  activities  will occur several  years in the future.  Asset
removal  technologies  and  costs are  constantly  changing,  as are  political,
environmental,  safety and public relations  considerations  that may ultimately
impact the amount of the  obligation.  In June  2001,  the FASB  issued FAS 143,
"Accounting  for Asset  Retirement  Obligations,"  which the company  adopted on
January  1, 2003.  The impact of this new  standard  is  discussed  below in the
New/Revised Accounting Standards section.

Impairment of Assets

All  long-lived  assets are assessed  for  potential  impairment  when events or
changes in  circumstances  indicate that the carrying  value of the asset may be
greater than its future net cash flows.  The  evaluations  involve a significant
amount of judgment since the results are based on estimated future events,  such
as future sales prices for oil, gas or chemicals;  future costs to produce these
products; estimates of future oil and gas reserves to be recovered;  development
costs and the timing thereof;  the economic and regulatory  climates;  and other
factors.  The need to test a property for impairment may result from significant
declines  in sales  prices,  unfavorable  adjustments  to oil and gas  reserves,
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 approves the 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 assets' carrying value.  Estimates of anticipated sales prices are
highly judgmental and subject to material  revision in future periods.  Goodwill
is tested annually for impairment,  or more frequently if impairment  indicators
arise.  The company  completed  its annual test for  impairment  of goodwill and
indefinite-lived  intangible assets as of June 30, 2003, with no impairment loss
indicated.  The company cannot predict when or if future impairment  charges for
held-for-use  assets,  goodwill  or  intangibles,   or  losses  associated  with
held-for-sale properties will be recorded.

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
flow,  from time to time the company enters into certain  derivative  contracts,
primarily swaps and collars for a portion of its oil and gas production, forward
contracts  to buy and sell foreign  currencies,  and  interest  rate swaps.  The
company  accounts  for all its  derivative  instruments,  including  hedges,  in
accordance  with FAS 133,  "Accounting  for Derivative  Instruments  and Hedging
Activities."  The  commodity,  foreign  currency and interest rate contracts are
measured at fair value and recorded as assets or liabilities in the Consolidated
Balance Sheet. When available, quoted market prices are used in determining fair
value; however, if quoted market prices are not available, the company estimates
fair value using  either  quoted  market  prices of financial  instruments  with
similar  characteristics  or other valuation  techniques.  The counterparties to
these contractual arrangements generally are limited to major institutions.

Environmental Remediation, Litigation and Other Contingency Reserves

Kerr-McGee   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.  It is not
possible for management to reliably estimate the amount and timing of all future
expenditures related to environmental, legal or other contingent matters because
of continually changing laws and regulations,  inherent uncertainties associated
with  court and  regulatory  proceedings  as well as  cleanup  requirements  and
related work, the possible existence of other potentially  responsible  parties,
and the changing political and economic environment.  For these reasons,  actual
environmental,  litigation and other  contingency  costs can vary  significantly
from the company's  estimates.  For additional  information about contingencies,
refer to the Environmental Matters section that follows and Note 16.

Tax Accruals

The company has operations in several  countries around the world and is subject
to income and other  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

The company provides defined benefit  retirement plans and certain  nonqualified
benefits  for  employees  in the U.S.,  U.K.,  Germany and the  Netherlands  and
accounts for these plans in accordance with FAS 87,  "Employers'  Accounting for
Pensions."  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 pension obligations associated with the retirement plans.

One of the  significant  assumptions  used to account for the company's  pension
plans is the  expected  long-term  rate of return on plan  assets.  The expected
long-term  rate of return  forecasting  methodology  is based on a capital asset
pricing model using  historical  data.  Based on this  information,  the company
selected 8.5% for 2003 and 2004 for U.S. pension plans.

Another significant assumption for pension plan accounting is the discount rate.
The company  selects a discount rate as of December 31 each year for U.S.  plans
to reflect average rates available on high-quality fixed income debt instruments
during  December of that year. The average  Moody's  Long-Term AA Corporate Bond
Yield for December is used as a guide in the  selection of the discount rate for
U.S.  pension  plans.  For  December  2002,  the average  Moody's  Long-Term  AA
Corporate Bond Yield was 6.63%, and the company chose 6.75% as its discount rate
at the end of  2002.  For  December  2003,  the  average  Moody's  Long-Term  AA
Corporate Bond Yield was 6.04%, and the company chose 6.25% as its discount rate
at the end of 2003.  This decrease in the discount rate  effective  December 31,
2003, is expected to increase  2004 net periodic  pension cost by $5 million but
not affect expected contributions to fund the pension plans.

The rate of compensation increase is another significant  assumption used in the
development of accounting  information for pension plans. The company determines
this  assumption  based on its long-term  plans for  compensation  increases and
current economic  conditions.  Based on this  information,  the company selected
4.5% at December 31, 2002 and 2003, for U.S. pensions plans.

The net effect the U.S.  pension plans had on results of operations for 2003 was
$32  million  of income due to the  expected  return on assets  exceeding  other
pension  charges.  The total expected return on assets of the U.S. pension plans
for 2003 was $117  million,  compared  with an actual  return  of $189  million.
During 2003,  the company's  contributions  to the  retirement  plans totaled $5
million for certain U.S. nonqualified plans and foreign plans.

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.
As of January 1, 2004, the amount of unrecognized  losses on U.S. pension assets
was $188  million.  As these 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 $16 million in 2005 through 2008.

A 25 basis point  increase/decrease  in the company's expected long-term rate of
return  assumption  as of the  beginning  of 2004  would  decrease/increase  net
periodic pension cost for U.S. pension plans for 2004 by $3 million.  The change
would not affect  expected  contributions  to fund the  company's  U.S.  pension
plans.

The company also provides certain  postretirement health care and life insurance
benefits  and  accounts  for the  related  plans  in  accordance  with  FAS 106,
"Employers'  Accounting for  Postretirement  Benefits Other Than  Pensions." The
postretirement  benefit cost and  obligation are also dependent on the company's
assumptions  used  in the  actuarially  determined  amounts.  These  assumptions
include  discount  rates  (discussed  above),  health  care  cost  trend  rates,
inflation rates, retirement rates, mortality rates and other factors. 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.  Assumed
inflation  rates are  based on an  evaluation  of  external  market  indicators.
Retirement and mortality  rates are based  primarily on actual plan  experience.
See Note 24 for a discussion of the Medicare Prescription Drug,  Improvement and
Modernization Act of 2003 as it relates to the company's  postretirement  health
care plan.

The above  description  of the  company's  critical  accounting  policies is not
intended to be an all-inclusive  discussion of the uncertainties  considered and
estimates  made by management in applying  accounting  principles  and policies.
Results may vary  significantly if different  policies were used or required and
if new or different information becomes known to management.

--------------------------------------------------------------------------------
Environmental Matters

The  company's  affiliates  are  subject  to  various   environmental  laws  and
regulations in the United States and in 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 due to 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's  operations  or  financial
condition.

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, 2003, 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
liability. 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 are also 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  oil and gas  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  the  company's  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.

Discontinued Businesses

The company's affiliates  historically have held interests in various businesses
in  which  they are no  longer  engaged  or  which  they  intend  to exit.  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,  and other  activities.  Additionally,  the
company  expects to complete its exit from the forest  products  business by the
end of 2004. Although the company's  affiliates are no longer engaged in certain
businesses  or  have  announced  their  intention  to exit  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
company  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 owned  and/or
operated  before  exiting the refining and marketing  business in 1995.  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.  Additionally,  the  company's
chemical   affiliate  may  be  required  to   decommission   and  remediate  its
wood-treatment  facilities  as part of its  plan to  exit  the  forest  products
business.

Environmental Costs

Expenditures for environmental protection and cleanup for each of the last three
years and for the three-year period ended December 31, 2003, are as follows:

(Millions of dollars)                            2003     2002     2001    Total
--------------------------------------------------------------------------------
Charges to environmental reserves                $104     $128     $142     $374
Recurring expenses                                 19       37       57      113
Capital expenditures                               18       22       21       61
                                                 ----     ----     ----     ----
     Total                                       $141     $187     $220     $548
                                                 ====     ====     ====     ====

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
costs 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, 2003,  the  company's  financial  reserves for all active and
inactive  sites totaled $259  million.  This includes $105 million added in 2003
for active and inactive sites. In the Consolidated  Balance Sheet,  $161 million
of the total reserve is classified as a deferred  credit,  and the remaining $98
million is included in current  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
determine  that the  liability  is probable  and/or  reasonably  estimable.  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
some ongoing  financial  involvement  in  investigation  and/or  remediation  at
year-end  2003. In the table,  aggregated  information  is presented for certain
sites that are individually not significant  (having a remaining reserve balance
of less than $10  million) or for which the  company has not  recorded a reserve
because the  liability  is not probable  and/or  reasonably  estimable.  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,  which  financial  statements  are  included in Item 8. of this Form
10-K.



                                                                                                             Remaining
                                                                                                               Reserve
                                                                                               Total        Balance at
                                                                                           Expenditures   December 31,
                                                                                           Through 2003           2003         Total
                                                                                           -----------------------------------------
Location of Site                          Stage of Investigation/Remediation                      (Millions of dollars)
------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                  
EPA Superfund sites on
National Priority List (NPL)
  West Chicago, Ill.
    Vicinity areas                     Remediation  of   thorium   tailings   at
                                       Residential  Areas and Reed-Keppler  Park
                                       is substantially  complete.  An agreement
                                       in  principle   for  cleanup  of  thorium
                                       tailings   at  Kress   Creek  and  Sewage
                                       Treatment  Plant  has been  reached  with
                                       relevant    agencies;    court   approval
                                       expected in 2004.                                         $  113           $ 84        $  197

  Milwaukee, Wis.                      Completed  soil  cleanup  at former wood-
                                       treatment facility  and  began cleanup of
                                       offsite   tributary  creek.   Groundwater
                                       remediation is continuing.                                    31             11            42

  Other sites                          Sites  where the company has been named a
                                       PRP, including  landfills,  wood-treating
                                       sites,  a mine site and an oil  recycling
                                       refinery.  These  sites  are  in  various
                                       stages of investigation/remediation.                          33             12            45
                                                                                                 ------           ----        ------
                                                                                                    177            107           284
                                                                                                 ------           ----        ------
Sites under consent order, license
or agreement, not on EPA Superfund
NPL
  West Chicago, Ill.
    Former manufacturing               Excavation   of  contaminated   soils  at
    facility                           former  thorium  mill  is   substantially
                                       complete, and soil removal is expected to
                                       be   substantially   completed  in  2004.
                                       Groundwater monitoring and/or remediation
                                       will continue.                                               424             12           436

  Cushing, Okla.                       Remediation  of thorium  and  uranium re-
                                       siduals is  expected  to be substantially
                                       completed  in  2004.   Investigation  and
                                       remediation  addressing  hydrocarbon con-
                                       tamination is continuing.                                    123             22           145

  Henderson, Nev.                      Groundwater  treatment  to  address  per-
                                       chlorate contamination is being conducted
                                       under    consent    order   with   Nevada
                                       Department of Environmental Protection.                      106             23           129

  Mobile, Ala.                         Groundwater treatment in  compliance with
                                       NPDES   permit  and  closure  of  surface
                                       impoundments is ongoing.                                       -             11            11

  Other sites                          Sites related to wood-treatment, chemical
                                       production,  landfills,  mining,  oil and
                                       gas production,  and petroleum  refining,
                                       distribution  and marketing.  These sites
                                       are  in various  stages of investigation/
                                       remediation.                                                 297             84           381
                                                                                                 ------           ----        ------
                                                                                                    950            152         1,102
                                                                                                 ------           ----        ------
                                            Total                                                $1,127           $259        $1,386
------------------------------------------------------------------------------------------------------------------------------------


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,  which financial statements are included in
Item 8. of this  Form  10-K.  Any  discussion  in Note 16 of the  West  Chicago,
Illinois;  Henderson,  Nevada;  Milwaukee,  Wisconsin;  Cushing,  Oklahoma;  and
Mobile, Alabama, sites is incorporated herein by reference and made fully a part
hereof.

--------------------------------------------------------------------------------
New/Revised Accounting Standards

In June 2001, the Financial  Accounting  Standards Board (FASB) issued Statement
of  Financial   Accounting  Standards  (FAS)  No.  143,  "Accounting  for  Asset
Retirement  Obligations."  FAS 143 requires that an asset retirement  obligation
(ARO)  associated  with  the  retirement  of  a  tangible  long-lived  asset  be
recognized  as a  liability  in the  period in which it is  incurred  or 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 initially  recognized  asset  retirement cost, is depreciated over
the useful life of the asset.  The ARO is recorded at fair value,  and accretion
expense will be recognized over time as the discounted  liability is accreted to
its  expected  settlement  value.  The fair value of the ARO is  measured  using
expected  future  cash  outflows  discounted  at the  company's  credit-adjusted
risk-free interest rate.

The company adopted FAS 143 on January 1, 2003, which resulted in an increase in
net property of $108 million,  an increase in  abandonment  liabilities  of $161
million and a decrease in deferred  income tax  liabilities of $18 million.  The
net impact of these changes  resulted in an after-tax  charge to earnings of $35
million to recognize the  cumulative  effect of  retroactively  applying the new
accounting  principle.  In accordance with the provisions of FAS 143, Kerr-McGee
accrues  an  abandonment  liability  associated  with its oil and gas  wells and
platforms when those assets are placed in service, rather than its past practice
of accruing the expected  abandonment costs on a  unit-of-production  basis over
the productive  life of the associated oil and gas field. No market risk premium
has been included in the company's  calculation of the ARO for oil and gas wells
and  platforms  since  no  reliable  estimate  can be  made by the  company.  In
connection with the change in accounting  principle,  abandonment expense of $40
million  in 2002 and $34  million in 2001 has been  reclassified  from costs and
operating  expenses to depreciation and depletion in the Consolidated  Statement
of Operations to be consistent with the 2003 presentation.  In January 2003, the
company  announced  its plan to close  the  synthetic  rutile  plant in  Mobile,
Alabama,  and closed the plant in June 2003.  Since the plant had a  determinate
closure  date,  the  company  accrued an  abandonment  liability  of $18 million
associated with its plans to decommission the Mobile facility in connection with
the adoption of FAS 143.

In November 2002, the FASB issued FASB Interpretation (FIN) No. 45, "Guarantor's
Accounting  and  Disclosure  Requirements  for  Guarantees,  Including  Indirect
Guarantees of Indebtedness of Others - an  Interpretation of FASB Statements No.
5, 57,  and 107 and  Rescission  of FASB  Interpretation  No.  34." For  certain
guarantees,  FIN 45 requires  recognition  at the  inception of a guarantee of a
liability for the fair value of the obligation assumed in issuing the guarantee.
FIN 45 also requires expanded  disclosures for outstanding  guarantees,  even if
the likelihood of the guarantor  having to make any payments under the guarantee
is considered  remote.  The recognition  provisions of FIN 45 were effective for
guarantees  issued or modified  after  December  31,  2002.  The company has not
issued or modified  any  material  guarantees  within the scope of FIN 45 during
2003;  therefore,  implementation  of this new  standard  has not  impacted  its
consolidated financial condition or results of operations.

In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest
Entities - an Interpretation of ARB No. 51." This  interpretation  clarifies the
application of ARB 51, "Consolidated  Financial Statements," to certain entities
in which  equity  investors  do not have the  characteristics  of a  controlling
financial  interest or do not have  sufficient  equity at risk for the entity to
finance its activities  without additional  subordinated  financial support from
other parties.  Because application of the majority voting interest  requirement
in ARB 51 may not identify the party with a  controlling  financial  interest in
situations where controlling financial interest is achieved through arrangements
not involving voting interests,  this  interpretation  introduces the concept of
variable  interests and requires  consolidation by an enterprise having variable
interests in a previously  unconsolidated entity if the enterprise is considered
the primary  beneficiary,  meaning the enterprise  will absorb a majority of the
variable interest  entity's  expected losses or residual  returns.  For variable
interest  entities in  existence as of February 1, 2003,  FIN 46, as  originally
issued,  required  consolidation by the primary beneficiary in the third quarter
of 2003. In October 2003,  the FASB deferred the effective date of FIN 46 to the
fourth quarter.

In accordance  with the provisions of FIN 46, the company has  consolidated  the
business  trust  created  to  construct  and  finance  the  Gunnison  production
platform.  Accordingly, the assets and liabilities of the trust are reflected in
the company's  Consolidated  Balance Sheet at December 31, 2003,  which includes
$83 million in property, plant and equipment, $4 million in accrued liabilities,
$75 million in long-term  debt and $4 million in minority  interest (See Notes 1
and 9). The  company  has  reviewed  the effects of FIN 46 relative to its other
relationships  with  possible  variable  interest  entities,  such as the lessor
trusts that are party to the Nansen and  Boomvang  operating  leases and certain
joint-venture  arrangements,  and has  determined  that  consolidation  of these
entities is not required.

The company  applies the  provisions of FAS No. 19,  "Financial  Accounting  and
Reporting by Oil and Gas Producing Companies," for the accounting of oil and gas
mineral rights held by lease or contract and accordingly classifies these assets
as property,  plant and equipment.  This classification is the long standing and
current  industry  standard and is consistent  with most mineral rights case law
(that is, mineral rights generally are treated as interests in real property and
real property laws are used to interpret the leases). However, the SEC has asked
that the Emerging Issues Task Force (EITF)  consider  whether mineral rights are
intangible  assets  under  the  guidance  provided  by FAS  No.  141,  "Business
Combinations," and FAS No. 142, "Goodwill and Other Intangible  Assets." If such
interests  are deemed to be  intangible  assets by the EITF,  mineral  rights to
extract  oil  and gas for  both  undeveloped  and  developed  leaseholds  may be
reclassified separately as intangible assets.

Even  though   management   believes  the   company's   current   balance  sheet
classification  is required  under  generally  accepted  accounting  principles,
reclassification  may be  necessary  in the  future  when  further  guidance  is
provided by the EITF.  However,  it is not currently  clear which mineral rights
might  have  to  be  reclassified  as  intangible  assets  - all  producing  and
nonproducing  leaseholds,   only  nonproducing  leaseholds  or  only  leaseholds
acquired in business  combinations  since the effective date of FAS No. 141. Any
such  reclassification  would not affect the company's total assets,  net worth,
cash flows or results of operations.  A reclassification could negatively impact
one of the company's debt  covenants and certain  contractual  obligations  that
require the company to maintain a certain  level of tangible  net worth,  absent
waiver or amendment of such  provisions.  These mineral rights would continue to
be amortized in accordance  with FAS No. 19. At December 31, 2003 and 2002,  the
company  had  total  producing   leasehold   costs  for  mineral   interests  of
approximately $1.6 billion, net of accumulated  depletion and amortization,  and
nonproducing  leasehold costs of approximately  $.5 billion,  net of accumulated
depletion  and  amortization.   Of  these  amounts,   leasehold  costs,  net  of
accumulated depletion and amortization,  acquired in business combinations since
the  effective  date of FAS No. 141 were  approximately  $1.3  billion  and $1.4
billion  of   producing   leasehold   costs  at  December  31,  2003  and  2002,
respectively,  and $.1 billion of nonproducing  leasehold costs at both December
31, 2003 and 2002.

Item 7a.    Quantitative and Qualitative Disclosure about Market Risk

For  information  required under this section,  reference is made to the "Market
Risks"  section of  Management's  Discussion and Analysis,  which  discussion is
included in Item 7. of this Form 10-K.


Item 8.     Financial Statements and Supplementary Data

Index to the Consolidated Financial Statements                              PAGE
----------------------------------------------                              ----

Responsibility for Financial Reporting                                        57
Report of Independent Auditors                                                58
Consolidated Statement of Operations for the years ended
  December 31, 2003, 2002 and 2001                                            59
Consolidated Statement of Comprehensive Income
  and Stockholders' Equity for the years ended
  December 31, 2003, 2002 and 2001                                            60
Consolidated Balance Sheet at December 31, 2003 and 2002                      61
Consolidated Statement of Cash Flows for the years ended
  December 31, 2003, 2002 and 2001                                            62
Notes to Financial Statements                                                 63

Index to Supplementary Data
---------------------------

Ten-Year Financial Summary                                                   117
Ten-Year Operating Summary                                                   118

Index to the Financial Statement Schedules
------------------------------------------

Schedule II - Valuation Accounts and Reserves                                126

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

--------------------------------------------------------------------------------
Responsibility for Financial Reporting

The company's management is responsible for the integrity and objectivity of the
financial data contained in the financial statements. These financial statements
have been prepared in conformity with generally accepted  accounting  principles
appropriate  under the  circumstances  and, where  necessary,  reflect  informed
judgments and estimates of the effects of certain events and transactions  based
on currently  available  information at the date the financial  statements  were
prepared.

The company's  management depends on the company's system of internal accounting
controls to assure itself of the  reliability of the financial  statements.  The
internal  control  system  is  designed  to  provide  reasonable  assurance,  at
appropriate  cost, that assets are safeguarded and  transactions are executed in
accordance with management's  authorizations and are recorded properly to permit
the preparation of financial  statements in accordance  with generally  accepted
accounting  principles.  Periodic  reviews are made of internal  controls by the
company's staff of internal auditors, and corrective action is taken if needed.

The Board of Directors  reviews and monitors  financial  statements  through its
audit  committee,  which is composed solely of directors who are not officers or
employees of the company and who satisfy the  independence  requirements  of the
Securities and Exchange  Commission and the New York Stock  Exchange.  The audit
committee meets regularly with the independent  auditors,  internal auditors and
management  to review  internal  accounting  controls,  auditing  and  financial
reporting matters.

The  independent  auditors are engaged to provide an objective  and  independent
review of the company's financial  statements and to express an opinion thereon.
Their audits are  conducted  in  accordance  with  generally  accepted  auditing
standards, and their report is included below.

--------------------------------------------------------------------------------
Report of Independent Auditors

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, 2003 and 2002,  and the  related  consolidated
statements of operations,  comprehensive  income and stockholders'  equity,  and
cash flows for each of the three years in the period  ended  December  31, 2003.
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 auditing standards generally accepted
in the 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, 2003 and 2002, and the  consolidated  results of its
operations  and its cash flows for each of the three  years in the period  ended
December 31, 2003, in conformity with accounting  principles  generally accepted
in the United  States.  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  Notes  1 and 13 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
Notes 1, 9 and 17 to the consolidated  financial statements,  effective December
31, 2003,  the Company  adopted FASB  Interpretation  No. 46,  Consolidation  of
Variable Interest  Entities.  As discussed in Notes 1 and 18 to the consolidated
financial  statements,  effective January 1, 2001, the Company adopted Statement
of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities.

                                                           /s/ ERNST & YOUNG LLP


Oklahoma City, Oklahoma
March 3, 2004




Consolidated Statement of Operations
-------------------------------------------------------------------------------------------------------------------------------

(Millions of dollars,
except per-share amounts)                                                               2003             2002             2001
-------------------------------------------------------------------------------------------------------------------------------
                                                                                                                
Revenues                                                                               $4,185           $3,646           $3,555
                                                                                       ------           ------           ------
Costs and Expenses
  Costs and operating expenses                                                          1,668            1,456            1,264
  Selling, general and administrative expenses                                            371              313              228
  Shipping and handling expenses                                                          140              125              111
  Depreciation and depletion                                                              745              814              747
  Accretion expense                                                                        25                -                -
  Impairments on assets held for use                                                       14              652               76
  Loss (gain) associated with assets held for sale                                        (45)             176                -
  Exploration, including dry holes and
    amortization of undeveloped leases                                                    354              273              210
  Taxes, other than income taxes                                                           98              104              114
  Provision for environmental remediation and restoration,
    net of reimbursements                                                                  62               80               82
  Interest and debt expense                                                               251              275              195
                                                                                       ------           ------           ------
      Total Costs and Expenses                                                          3,683            4,268            3,027
                                                                                       ------           ------           ------
                                                                                          502             (622)             528
Other Income (Expense)                                                                    (59)             (35)             224
                                                                                       ------           ------           ------

Income (Loss) from Continuing Operations
  before Income Taxes                                                                     443             (657)             752
Benefit (Provision) for Income Taxes                                                     (189)              46             (276)
                                                                                       ------           ------           ------
Income (Loss) from Continuing Operations                                                  254             (611)             476
Income from Discontinued Operations, including tax expense
  (benefit) of $(22) in 2002 and $22 in 2001                                                -              126               30
Cumulative Effect of Change in Accounting Principle,
  including tax benefit of $18 in 2003 and $11 in 2001                                    (35)               -              (20)
                                                                                       ------           ------           ------
Net Income (Loss)                                                                      $  219           $ (485)          $  486
                                                                                       ======           ======           ======

Income (Loss) per Common Share
  Basic -
    Continuing operations                                                              $ 2.52           $(6.09)          $ 4.91
    Discontinued operations                                                                 -             1.25              .31
    Cumulative effect of accounting change                                               (.34)               -             (.21)
                                                                                       ------           ------           ------
      Net income (loss)                                                                $ 2.18           $(4.84)          $ 5.01
                                                                                       ======           ======           ======
  Diluted -
    Continuing operations                                                              $ 2.48           $(6.09)          $ 4.65
    Discontinued operations                                                                 -             1.25              .28
    Cumulative effect of accounting change                                               (.31)               -             (.19)
                                                                                       ------           ------           ------
      Net income (loss)                                                                $ 2.17           $(4.84)          $ 4.74
                                                                                       ======           ======           ======

The accompanying notes are an integral part of this statement.





Consolidated Statement of Comprehensive Income and Stockholders' Equity
------------------------------------------------------------------------------------------------------------------------------------

                                                                                  Accumulated
                                                          Capital in                    Other                 Deferred         Total
                                    Comprehensive  Common  Excess of  Retained  Comprehensive   Treasury  Compensation Stockholders'
(Millions of dollars)               Income (Loss)   Stock  Par Value  Earnings  Income (Loss)      Stock     and Other        Equity
------------------------------------------------------------------------------------------------------------------------------------
                                                                                                     
Balance December 31, 2000                            $101     $1,660    $1,233          $ 113      $(383)        $(91)       $2,633
  Net income                                $ 486       -          -       486              -          -             -          486
  Unrealized losses on securities,
    net of $12 tax benefit                    (22)      -          -         -            (22)         -             -          (22)
  Reclassification of unrealized
    gains on securities to net
    income, net of $63 tax provision         (118)      -          -         -           (118)         -             -         (118)
  Record fair value of cash flow
    hedges, net of $1 tax benefit              (3)      -          -         -             (3)         -             -           (3)
  Change in fair value of cash
    flow hedges, net of $5 tax benefit        (15)      -          -         -            (15)         -             -          (15)
  Foreign currency translation
    adjustment                                (17)      -          -         -            (17)         -             -          (17)
  Minimum pension liability
    adjustment, net of $1 tax benefit          (2)      -          -         -             (2)         -             -           (2)
  Shares issued                                 -       6        382         -              -          -             -          388
  Treasury stock cancelled                      -      (7)      (371)        -              -        378             -            -
  Dividends declared ($1.80 per share)          -       -          -      (176)             -          -             -         (176)
  Other                                         -       -          5         -              -          5            10           20
                                            -----    ----     ------    ------          -----      -----         -----       -------
     Total                                  $ 309
                                            =====

Balance December 31, 2001                             100      1,676     1,543            (64)         -           (81)       3,174
  Net loss                                  $(485)      -          -      (485)             -          -             -         (485)
  Unrealized gains on securities,
    net of $4 tax provision                     7       -          -         -              7          -             -            7
  Change in fair value of cash
    flow hedges, net of $23 tax benefit       (39)      -          -         -            (39)         -             -          (39)
  Foreign currency translation
    adjustment                                 48       -          -         -             48          -             -           48
  Minimum pension liability
    adjustment, net of $9 tax benefit         (14)      -          -         -            (14)         -             -          (14)
  Shares issued                                 -       -          5         -              -          -             -            5
  Dividends declared ($1.80 per share)          -       -          -      (181)             -          -             -         (181)
  Other                                         -       -          6         9              -          -             6           21
                                            -----    ----     ------    ------          -----      -----         -----       -------
     Total                                  $(483)
                                            =====

Balance December 31, 2002                             100      1,687       886            (62) (1)     -           (75)       2,536
  Net income                                $ 219       -          -       219              -          -             -          219
  Unrealized gains on securities of $6
    and reclassification of realized
    gains of $(7), net of tax provision        (1)      -          -         -             (1)         -             -           (1)
  Change in fair value of cash
    flow hedges, net of $35 tax benefit       (31)      -          -         -            (31)         -             -          (31)
  Foreign currency translation
    adjustment                                 56       -          -         -             56          -             -           56
  Minimum pension liability
    adjustment, net of $5 tax benefit          (7)      -          -         -             (7)         -             -           (7)
  Shares issued                                 -       -          1         -              -          -             -            1
  Restricted stock activity                     -       1         21         -              -         (1)          (10)          11
  ESOP deferred compensation                    -       -          -         -              -          -            32           32
  Dividends declared ($1.80 per share)          -       -          -      (182)             -          -             -         (182)
  Other                                         -       -         (1)        4              -         (1)            -            2
                                            -----    ----     ------    ------          -----      -----         -----       -------
     Total                                  $ 236
                                            =====
Balance December 31, 2003                            $101     $1,708    $  927          $ (45) (1) $  (2)        $ (53)      $2,636
                                                     ====     ======    ======          =====      =====         =====       ======


(1)  The balance of the items in Accumulated Other  Comprehensive  Income (Loss)
     at December 31, 2003 and 2002,  includes - unrealized  gains on securities,
     $5 million and $6 million;  fair value of cash flow hedges,  $(88)  million
     and $(57) million;  foreign currency translation  adjustments,  $62 million
     and $6 million;  and minimum  pension  liability,  $(24)  million and $(17)
     million, respectively.

The accompanying notes are an integral part of this statement.




Consolidated Balance Sheet
------------------------------------------------------------------------------------------------------

(Millions of dollars)                                                              2003           2002
------------------------------------------------------------------------------------------------------
                                                                                          

ASSETS
Current Assets
  Cash                                                                          $   142         $   90
  Accounts receivable, net of allowance for doubtful
    accounts of $10 in 2003 and 2002                                                583            608
  Inventories                                                                       394            402
  Investment in equity securities                                                   510              -
  Deposits, prepaid expenses and other assets                                       127            133
  Current assets associated with properties held for disposal                         1             57
                                                                                -------         ------
          Total Current Assets                                                    1,757          1,290
Investments
  Equity affiliates                                                                 123            123
  Investment in equity securities                                                     -            457
  Other assets                                                                      125            127
Property, Plant and Equipment - Net                                               7,467          7,036
Deferred Charges                                                                    317            328
Goodwill                                                                            357            356
Long-Term Assets Associated with Properties
  Held for Disposal                                                                  28            192
                                                                                -------         ------
          Total Assets                                                          $10,174         $9,909
                                                                                =======         ======

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
  Accounts payable                                                              $   735         $  772
  Long-term debt due within one year                                                574            106
  Taxes on income                                                                   127            170
  Taxes, other than income taxes                                                     37             40
  Accrued liabilities                                                               759            520
  Current liabilities associated with properties held for disposal                    -              2
                                                                                -------         ------
          Total Current Liabilities                                               2,232          1,610
                                                                                -------         ------

Long-Term Debt                                                                    3,081          3,798
                                                                                -------         ------
Deferred Credits and Reserves
  Income taxes                                                                    1,259          1,145
  Asset retirement obligations                                                      401            222
  Other                                                                             565            582
                                                                                -------         ------
          Total Deferred Credits and Reserves                                     2,225          1,949
                                                                                -------         ------
Long-Term Liabilities Associated with Properties
  Held for Disposal                                                                   -             16
                                                                                -------         ------

Stockholders' Equity
  Common stock, par value $1.00 - 300,000,000 shares authorized,
    100,892,354 shares issued in 2003
    and 100,391,054 shares issued in 2002                                           101            100
  Capital in excess of par value                                                  1,708          1,687
  Preferred stock purchase rights                                                     1              1
  Retained earnings                                                                 927            886
  Accumulated other comprehensive loss                                              (45)           (62)
  Common stock in treasury, at cost - 31,924 shares
    in 2003 and 7,299 shares in 2002                                                 (2)             -
  Deferred compensation                                                             (54)           (76)
                                                                                -------         ------
          Total Stockholders' Equity                                              2,636          2,536
                                                                                -------         ------
            Total Liabilities and Stockholders' Equity                          $10,174         $9,909
                                                                                =======         ======


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

The accompanying notes are an integral part of this balance sheet.




Consolidated Statement of Cash Flows
-------------------------------------------------------------------------------------------------------------------------------

(Millions of dollars)                                                                    2003             2002             2001
-------------------------------------------------------------------------------------------------------------------------------
                                                                                                                
Cash Flow from Operating Activities
  Net income (loss)                                                                    $  219           $ (485)          $  486
  Adjustments to reconcile to net cash
    provided by operating activities -
      Depreciation, depletion and amortization                                            814              884              813
      Accretion expense                                                                    25                -                -
      Deferred income taxes                                                               156             (112)             205
      Dry hole costs                                                                      181              113               72
      Impairments on assets held for use                                                   14              652               76
      (Gain) loss associated with assets held for sale                                    (39)             210                -
      Cumulative effect of change in accounting principle                                  35                -               20
      Provision for environmental remediation
        and restoration, net of reimbursements                                             62               89               82
      Gains on asset retirements and sales                                                 (1)            (110)             (12)
      Noncash items affecting net income                                                  144              100             (189)
      Changes in current assets and liabilities
        and other, net of effects of operations acquired-
          (Increase) decrease in accounts receivable                                       60             (104)             278
          (Increase) decrease in inventories                                               22               37              (51)
          (Increase) decrease in deposits,
            prepaids and other assets                                                      12              185             (201)
          Increase (decrease) in accounts
            payable and accrued liabilities                                               (89)             137             (131)
          Increase (decrease) in taxes payable                                             66               49             (132)
          Other                                                                          (163)            (197)            (173)
                                                                                       ------           ------           ------
            Net cash provided by operating activities                                   1,518            1,448            1,143
                                                                                       ------           ------           ------

Cash Flow from Investing Activities
  Capital expenditures                                                                   (981)          (1,159)          (1,792)
  Dry hole costs                                                                         (181)            (113)             (72)
  Acquisitions                                                                           (110)             (24)            (978)
  Purchase of long-term investments                                                       (39)             (65)             (92)
  Proceeds from sale of long-term investments                                              50               12               18
  Proceeds from sale of assets                                                            304              756               19
  Other investing activities                                                                6                -                -
                                                                                       ------           ------           ------
            Net cash used in investing activities                                        (951)            (593)          (2,897)
                                                                                       ------           ------           ------

Cash Flow from Financing Activities
  Issuance of long-term debt                                                               31              418            2,513
  Issuance of common stock                                                                  -                5               32
  Decrease in short-term borrowings                                                         -               (8)              (9)
  Repayment of long-term debt                                                            (369)          (1,093)            (661)
  Dividends paid                                                                         (181)            (181)            (173)
  Other financing activities                                                               (1)               -                -
                                                                                       ------           ------           ------
            Net cash provided by (used in) financing activities                          (520)            (859)           1,702
                                                                                       ------           ------           ------

Effects of Exchange Rate Changes on Cash and Cash Equivalents                               5                3               (1)
                                                                                       ------           ------           ------
Net Increase (Decrease) in Cash and Cash Equivalents                                       52               (1)             (53)
Cash and Cash Equivalents at Beginning of Year                                             90               91              144
                                                                                       ------           ------           ------
Cash and Cash Equivalents at End of Year                                               $  142           $   90           $   91
                                                                                       ======           ======           ======


The accompanying notes are an integral part of this statement.


Notes to Financial Statements
--------------------------------------------------------------------------------

1.   The Company and Significant Accounting Policies

Kerr-McGee  is an energy and chemical  company  with  worldwide  operations.  It
explores for, develops,  produces and markets crude oil and natural gas, and its
chemical operations  primarily produce and market titanium dioxide pigment.  The
exploration  and  production  unit  produces and explores for oil and gas in the
United States, the United Kingdom sector of the North Sea and China. Exploration
efforts  also extend to  Australia,  Benin,  Bahamas,  Brazil,  Gabon,  Morocco,
Western Sahara,  Canada, Yemen and the Danish and Norwegian sectors of the North
Sea.  The  chemical  unit  has  production  facilities  in  the  United  States,
Australia, Germany and the Netherlands.

On August 1, 2001, the company  completed the acquisition of all the outstanding
shares  of  common  stock of HS  Resources,  Inc.,  an  independent  oil and gas
exploration and production company.  To accomplish the acquisition,  the company
reorganized and formed a new holding  company,  Kerr-McGee  Holdco,  which later
changed its name to Kerr-McGee  Corporation.  All the outstanding  shares of the
former  Kerr-McGee  Corporation  were canceled and the same number of shares was
issued by the new holding company. The former Kerr-McGee Corporation was renamed
and is now a wholly owned subsidiary.

Basis of Presentation

The  consolidated  financial  statements  include the accounts of all subsidiary
companies  that  are more  than  50%  owned,  the  proportionate  share of joint
ventures in which the company has an undivided  interest  and variable  interest
entities  for  which  the  company  is  considered   the  primary   beneficiary.
Investments  in  affiliated  companies  that are 20% to 50% owned are carried as
investments  -  equity  affiliates  in the  Consolidated  Balance  Sheet at cost
adjusted for equity in undistributed earnings.  Except for dividends and changes
in ownership interest,  changes in equity in undistributed earnings are included
in  the  Consolidated   Statement  of  Operations.   All  material  intercompany
transactions have been eliminated.

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.

Discontinued  operations in the consolidated  financial statements represent the
company's  former oil and gas operations in Kazakhstan,  Indonesia and Australia
(see Note 21).

Variable Interest Entities

In January 2003,  the Financial  Accounting  Standards  Board (FASB) issued FASB
Interpretation  (FIN) No. 46,  "Consolidation of Variable Interest Entities - an
Interpretation of ARB No. 51." This interpretation  clarifies the application of
Accounting Research Bulletin (ARB) 51, "Consolidated  Financial  Statements," to
certain entities in which equity investors do not have the  characteristics of a
controlling  financial interest or do not have sufficient equity at risk for the
entity to finance  its  activities  without  additional  subordinated  financial
support from other parties.  Because application of the majority voting interest
requirement  in ARB 51 may not identify the party with a  controlling  financial
interest in situations where controlling  financial interest is achieved through
arrangements not involving voting interests,  this interpretation introduces the
concept of variable interests. Consolidation is required by an enterprise having
variable  interests in a previously  unconsolidated  entity if the enterprise is
considered  the  primary  beneficiary,  meaning  the  enterprise  will  absorb a
majority of the variable  interest entity's expected losses or residual returns.
For variable  interest  entities in existence as of February 1, 2003, FIN 46, as
originally  issued,  required  consolidation  by the primary  beneficiary in the
third quarter of 2003. In October 2003,  the FASB deferred the effective date of
FIN 46 to December 31, 2003.

In accordance  with the provisions of FIN 46, the company has  consolidated  the
business  trust  created  to  construct  and  finance  the  Gunnison  production
platform.  Accordingly, the assets and liabilities of the trust are reflected in
the company's  Consolidated  Balance Sheet at December 31, 2003,  which includes
$83 million in property, plant and equipment, $4 million in accrued liabilities,
$75 million in long-term  debt and $4 million in minority  interest (See Notes 9
and 17).  The company has  reviewed  the effects of FIN 46 relative to its other
relationships  with  possible  variable  interest  entities,  such as the lessor
trusts that are party to the Nansen and  Boomvang  operating  leases and certain
joint-venture  arrangements,  and has  determined  that  consolidation  of these
entities is not required.

Reclassifications

Certain  prior year amounts have been  reclassified  to conform with the current
year presentation.

In 2003,  the company began  reporting the net marketing fee received from sales
of  nonequity  North Sea  crude oil  marketed  on  behalf of other  partners  in
revenues.  Prior to 2003, the company reported  purchases and sales of nonequity
crude oil on a gross basis. The company believes this change in reporting, which
has no impact on net income, better reflects the economic substance of its North
Sea marketing arrangements.  For 2002 and 2001, the company has reclassified $54
million and $11  million,  respectively,  from costs and  operating  expenses to
reduce revenues in the Consolidated  Statement of Operations to conform with the
2003 presentation.

In  connection  with the  adoption  of the  Statement  of  Financial  Accounting
Standards  (FAS)  No.  143,  "Accounting  for  Asset  Retirement   Obligations,"
abandonment  expense of $40  million  for 2002 and $34 million for 2001 has been
reclassified from costs and operating  expenses to depreciation and depletion in
the Consolidated Statement of Operations. This new standard is discussed in more
detail below.

Foreign Currencies

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
Operations. The company recorded net foreign currency transaction gains (losses)
of  $(41)  million,  $(38)  million  and $3  million  in 2003,  2002  and  2001,
respectively.

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 reported  separately in
accumulated  other  comprehensive  income  in  the  Consolidated   Statement  of
Comprehensive Income and Stockholders' Equity.

Cash Equivalents

The company considers all investments with a maturity of three months or less to
be cash  equivalents.  Cash  equivalents  totaling  $72  million in 2003 and $23
million in 2002 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.

Under  an  asset  securitization  program,  Kerr-McGee  sells  selected  pigment
customers'  accounts receivable to a variable interest entity (VIE). The company
does not own any of the common stock of the VIE. When the  receivables are sold,
Kerr-McGee   retains  an   interest   in  excess   receivables   that  serve  as
over-collateralization  for the program and retains  interests for servicing and
in  preference  stock  of the  VIE.  The  interest  in the  preference  stock is
essentially   a  deposit  to  provide   further   credit   enhancement   to  the
securitization  program, if needed, but is otherwise  recoverable by the company
at the end of the program. The servicing fee received is estimated by management
to be adequate  compensation  and is equal to what would otherwise be charged by
an outside  servicing  agent.  The company  records the loss associated with the
receivable  sales by  comparing  cash  received  and fair value of the  retained
interests to the carrying amount of the  receivables  sold. The estimate of fair
value of the  retained  interests  is based on the present  value of future cash
flows  discounted at rates estimated by management to be  commensurate  with the
risks.

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.  Ore  inventories are carried at
actual cost.

Property, Plant and Equipment

Exploration  and  Production - Exploration  expenses,  including  geological and
geophysical costs, rentals and exploratory dry holes, are charged against income
as  incurred.  Costs of  drilling  exploratory  wells  are  capitalized  pending
determination  of whether  proved  reserves can be attributed to the  discovery.
Capitalized  costs associated with exploratory  wells may be charged to earnings
in a future  period if  management  determines  that  commercial  quantities  of
hydrocarbons  have not been  discovered.  At December 31, 2003,  the company had
capitalized  costs of  approximately  $143 million  associated with such ongoing
exploration  activities,  primarily in the  deepwater  Gulf of Mexico and China.
Costs of successful wells and related production equipment and developmental dry
holes are capitalized and amortized by field using the unit-of-production method
as the oil and gas are produced.

Undeveloped  acreage costs are  capitalized  and amortized at rates that provide
full  amortization  on abandonment of  unproductive  leases.  Costs of abandoned
leases  are  charged  to the  accumulated  amortization  accounts,  and costs of
productive leases are transferred to the developed property accounts.

Other -  Property,  plant and  equipment  is stated  at cost less  reserves  for
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.

Depreciation  and Depletion - Property,  plant and equipment is  depreciated  or
depleted over its estimated life by the  unit-of-production or the straight-line
method.  Capitalized  exploratory  drilling and development  costs are amortized
using the  unit-of-production  method based on total estimated  proved developed
oil and gas reserves. Amortization of producing leasehold, platform costs, asset
retirement  costs and  acquisition  costs of proved  properties  is based on the
unit-of-production  method using total estimated proved reserves. In arriving at
rates under the  unit-of-production  method,  the quantities of recoverable oil,
gas and other minerals are established  based on estimates made by the company's
geologists  and  engineers.  Non-oil  and gas assets are  depreciated  using the
straight-line method over the 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. The resulting gain or loss is included
in other income (expense) in the Consolidated Statement of Operations.

Interest  Capitalized - The company capitalizes interest costs on major projects
that require an extended  length of time to complete.  Interest  capitalized  in
2003, 2002 and 2001 was $10 million, $8 million and $31 million, respectively.

Impairments on Assets Held for Use

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 cash flows are estimated by
applying future oil and gas prices to future production quantities,  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 carrying  amount over the estimated fair value of the property
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  and  impaired in a similar
manner as proved oil and gas properties.

Gain or Loss on Assets Held for Sale

Assets are classified as held for sale when  management  approves a plan of sale
that  is  expected  to be  completed  within  one  year.  Upon  transfer  to the
held-for-sale category, long-lived assets are no longer depreciated.  Losses are
measured at the time of transfer, and subsequently thereafter, as the difference
between fair value less costs to sell and the assets' carrying value. Losses may
be reversed up to the original carrying value as estimates are revised; however,
any gain  above  the  assets'  carrying  value at the date of  transfer  is only
recognized upon disposition.

Revenue Recognition

Revenue is  recognized  when title  passes to the  customer.  Natural  gas sales
revenues involving gas-balancing  arrangements with partners are recognized when
the gas is sold using the entitlements method of accounting and are based on the
company's  net  working  interests.  At  December  31,  2003 and 2002,  both the
quantity and dollar amount of gas-balancing arrangements were immaterial.

Income Taxes

Deferred  income  taxes are provided to reflect the future tax  consequences  of
differences  between the tax basis of assets and  liabilities and their reported
amounts in the financial statements.

Remediation, Restoration and Site Dismantlement Costs

As sites of  environmental  concern are  identified,  the company  assesses  the
existing  conditions,  claims  and  assertions,   generally  related  to  former
operations,  and records an estimated  undiscounted liability when environmental
assessments and/or remedial efforts are probable and the associated costs can be
reasonably estimated.

In June 2001,  the FASB issued FAS No.  143,  "Accounting  for Asset  Retirement
Obligations."  FAS  143  requires  that an  asset  retirement  obligation  (ARO)
associated with the retirement of a tangible long-lived asset be recognized as a
liability  in the period in which it is  incurred  or 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
initially  recognized asset retirement cost, is depreciated over the useful life
of the asset. The ARO is recorded at fair value,  and accretion  expense will be
recognized  over time as the  discounted  liability  is accreted to its expected
settlement  value.  The fair value of the ARO is measured using expected  future
cash outflows  discounted at the company's  credit-adjusted  risk-free  interest
rate.

The company adopted FAS 143 on January 1, 2003, which resulted in an increase in
net property of $108 million,  an increase in  abandonment  liabilities  of $161
million and a decrease in deferred  income tax  liabilities of $18 million.  The
net impact of these changes  resulted in an after-tax  charge to earnings of $35
million to  recognize  the  cumulative  effect of  adopting  the new  accounting
standard.  In addition,  accretion  expense of $25 million was  recorded  during
2003.  In  accordance  with the  provisions  of FAS 143,  Kerr-McGee  accrues an
abandonment  liability  associated with its oil and gas wells and platforms when
those  assets are placed in service,  rather than its past  practice of accruing
the expected abandonment costs on a unit-of-production basis over the productive
life of the  associated  oil and gas  field.  No market  risk  premium  has been
included  in the  company's  calculation  of the ARO for oil and gas  wells  and
platforms since no reliable  estimate can be made by the company.  Additionally,
in January 2003,  the company  announced its plan to close the synthetic  rutile
plant in Mobile, Alabama, and closed the plant in June 2003. Since the plant had
a determinate closure date, the company accrued an abandonment  liability of $18
million as of January 1, 2003,  associated  with its plans to  decommission  the
Mobile facility.  Otherwise,  the company has not recognized an asset retirement
obligation  associated with its operating  chemical  facilities,  since there is
either no legal obligation or the life of such facilities is indeterminate.

If the provisions of FAS 143 had been applied retroactively,  pro forma net loss
for 2002 would have been $492 million,  with basic and diluted loss per share of
$4.91.  Pro forma net income for 2001 would have been $484  million,  with basic
and diluted earnings per share of $4.98 and $4.72, respectively.

Employee Stock Option Plan

FAS 123,  "Accounting  for  Stock-Based  Compensation,"  prescribes a fair-value
method of accounting for employee stock options under which compensation expense
is measured based on the estimated fair value of stock options at the grant date
and  recognized  over the period that the options  vest.  The company,  however,
chooses to account for its stock option plans under the optional intrinsic-value
method of Accounting  Principles  Board Opinion  (APB) No. 25,  "Accounting  for
Stock  Issued to  Employees,"  whereby  no  compensation  expense  is  generally
recognized for fixed-price stock options.

If  compensation  expense  for  stock  option  grants  had  been  determined  in
accordance with FAS 123, the resulting  expense would have affected  stock-based
compensation expense, net income and per-share amounts as shown in the following
table.  These amounts may not be representative of future  compensation  expense
using the  fair-value  method of  accounting  for employee  stock options as the
number of options  granted in a  particular  year may not be  indicative  of the
number  of  options  granted  in  future  years,  and the  fair-value  method of
accounting has not been applied to options granted prior to January 1, 1995.

(Millions of dollars,
except per-share amounts)                       2003         2002          2001
--------------------------------------------------------------------------------

Net income (loss) as reported                  $ 219        $ (485)       $ 486
  Less stock-based compensation
    expense determined using a
    fair-value method, net of taxes              (16)          (15)          (8)
                                               -----        ------        -----
Pro forma net income (loss)                    $ 203        $ (500)       $ 478
                                               =====        ======        =====

Net income (loss) per share -
  Basic -
    As reported                                $2.18        $(4.84)       $5.01
    Pro forma                                   2.03         (4.99)        4.92

  Diluted -
    As reported                                 2.17         (4.84)        4.74
    Pro forma                                   2.03         (4.99)        4.66

The fair value of each option granted in 2003, 2002 and 2001 was estimated as of
the date of the grant  using the  Black-Scholes  option  pricing  model with the
following weighted-average assumptions:


                                                   Assumptions
           -------------------------------------------------------------------------------         Weighted-Average
               Risk-Free             Expected               Expected              Expected            Fair Value of
           Interest Rate       Dividend Yield           Life (years)            Volatility          Options Granted
-------------------------------------------------------------------------------------------------------------------
                                                                                              

2003                 3.6%                 3.3%                   5.8                  32.7%                  $11.09
2002                 4.8                  3.4                    5.8                  36.0                    16.97
2001                 5.0                  3.3                    5.8                  42.9                    22.54


Financial Instruments

Investments  in marketable  securities  are  classified  as either  "trading" or
"available for sale," depending on management's  intent.  Unrecognized  gains or
losses on trading  securities  are  recognized in earnings,  while  unrecognized
gains or losses on available-for-sale  securities are recorded as a component of
other comprehensive income (loss) within stockholders' equity.

The company accounts for all its derivative financial  instruments in accordance
with FAS 133,  "Accounting for Derivative  Instruments and Hedging  Activities."
Derivative  financial  instruments  are recorded as assets or liabilities in the
Consolidated  Balance  Sheet,  measured at fair value.  When  available,  quoted
market  prices are used in  determining  fair value;  however,  if quoted market
prices are not available,  the company  estimates fair value using either quoted
market prices of financial  instruments  with similar  characteristics  or other
valuation techniques.

The company uses  futures,  forwards,  options,  collars and swaps to reduce the
effects of fluctuations in crude oil,  natural gas,  foreign  currency  exchange
rates and  interest  rates.  Gains or losses due to changes in the fair value of
instruments  that are  designated as cash flow hedges and that qualify for hedge
accounting  under the  provisions of FAS 133 are recorded in  accumulated  other
comprehensive income (loss). These hedging gains or losses will be recognized in
earnings in the periods during which the hedged forecasted  transactions  affect
earnings. The ineffective portion of the change in fair value of such hedges, if
any, is included in current  earnings.  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 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).

On January 1, 2001,  the company  adopted FAS 133 by recording the fair value of
the options  associated with the company's debt exchangeable for stock (DECS) of
Devon  Energy  Corporation  (Devon).  In  adopting  the  standard,  the  company
recognized  an expense of $20 million as a cumulative  effect of the  accounting
change and a $3 million reduction in equity (other comprehensive income) for the
foreign currency  contracts  designated as hedges.  Also, in accordance with FAS
133, the company chose to reclassify  85% of the Devon shares owned to "trading"
from the "available for sale" category of investments as of January 1, 2001, and
recognized  after-tax income of $118 million for the unrealized  appreciation on
these shares.

Shipping and Handling Fees and Costs

All amounts billed to a customer in a sales transaction  related to shipping and
handling represent  revenues earned and are reported as revenue.  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.

Goodwill and Intangible Assets

In accordance with FAS 142,  "Goodwill and Other  Intangible  Assets," which the
company  adopted  on  January 1, 2002,  goodwill  and  certain  indefinite-lived
intangibles are not amortized but are reviewed annually for impairment,  or more
frequently if impairment  indicators  arise.  The annual test for impairment was
completed in the second  quarter of 2003,  with no impairment  indicated for the
$357 million of goodwill ($346 million, exploration and production; $11 million,
chemical - pigment) or the $55  million of  indefinite-lived  intangible  assets
(chemical - pigment)  associated with patented technology and other intellectual
property.  The  company's  net income  for 2001  would not have been  materially
different had the  indefinite-lived  intangibles and goodwill not been amortized
prior to adoption of FAS 142.  Additionally,  the company had immaterial amounts
of  intangibles  subject to  amortization  ($19 million gross  carrying value at
December  31,  2003 and 2002;  $9 million  and $14  million  net of  accumulated
amortization at December 31, 2003 and 2002, respectively).


2.   Cash Flow Information

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

(Millions of dollars)                             2003        2002         2001
--------------------------------------------------------------------------------

Income tax payments                               $115       $  89         $434
Less refunds received                              (49)       (268)         (19)
                                                  ----       -----         ----
Net income tax payments (refunds)                 $ 66       $(179)        $415
                                                  ====       =====         ====

Interest payments                                 $237       $ 258         $189
                                                  ====       =====         ====

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

(Millions of dollars)                                 2003      2002       2001
--------------------------------------------------------------------------------
Increase (decrease) in fair value of
  embedded options in the DECS (1)                    $ 88      $ 34      $(205)
(Increase) decrease in fair value of
  trading securities (1)                               (96)      (61)         7
Performance incentive provisions                        33        16         27
Compensation expense for ESOP shares
  allocated to participants                             32        14         14
Net periodic postretirement expense                     30        21         18
Net losses on equity method investments                 33        25          5
Litigation reserve provisions                            7        72          -
Net periodic pension credit for qualified plan (2)       -       (48)       (53)
All other (3)                                           17        27        (2)
                                                      ----      ----      -----
        Total                                         $144      $100      $(189)
                                                      ====      ====      =====

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

(Millions of dollars)                                    2003     2002     2001
--------------------------------------------------------------------------------
Environmental expenditures                              $(104)   $(107)    $(94)
Cash abandonment expenditures - exploration
  and production                                          (17)     (48)     (29)
Employer contributions to postretirement plan             (24)     (18)     (20)
All other (3)                                             (18)     (24)     (30)
                                                        -----    -----    -----
        Total                                           $(163)   $(197)   $(173)
                                                        =====    =====    =====

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


(Millions of dollars)                                                                2003        2002         2001
------------------------------------------------------------------------------------------------------------------
                                                                                                    
Noncash investing activities
  Increase (decrease) in fair value of securities available for sale (1)              $ 9         $11        $ (34)
  Increase (decrease) in fair value of trading securities (1)                          96          61         (188)
  Investment in equity affiliate                                                        -           2            -
  Increase in property related to consolidation of Gunnison trust (4)                  83           -            -

Noncash financing activities
  Common stock issued in HS Resources acquisition                                       -           -          355
  Debt assumed in HS Resources acquisition                                              -           -          506
  Debt assumed in relation to consolidation of Gunnison Trust (4)                      75           -            -
  Increase in the valuation of the DECS (1)                                             8           8            8
  Increase (decrease) in fair value of embedded options in
    the DECS (1)                                                                       88          34         (205)
  Dividends declared but not paid                                                       -           -            3


(1)  See Notes 1 and 18 for discussion of FAS 133 adoption.
(2)  Net periodic  pension  credit for 2003 of $(38) million is reflected net of
     curtailment losses of $38 million.
(3)  No other individual item is material to total cash flows from operations.
(4)  See Note 1 for a discussion of the adoption of FIN 46.


3.   Inventories

Major categories of inventories at year-end 2003 and 2002 are:

(Millions of dollars)                                     2003              2002
--------------------------------------------------------------------------------

Chemicals and other products                              $307              $306
Materials and supplies                                      80                89
Crude oil and natural gas liquids                            7                 7
                                                          ----              ----

           Total                                          $394              $402
                                                          ====              ====


4.   Investments - Other Assets

Investments  in other assets  consist of the  following at December 31, 2003 and
2002:

(Millions of dollars)                                     2003              2002
--------------------------------------------------------------------------------

Long-term receivables, net of allowance for
  doubtful notes of $9 in both 2003 and 2002              $101              $ 94
Derivatives (fixed-price and basis swap
  commodity contracts)                                      17                22
Other                                                        7                11
                                                          ----              ----

           Total                                          $125              $127
                                                          ====              ====


5.   Property, Plant and Equipment

Property,  plant and  equipment  and related  reserves at December  31, 2003 and
2002, are as follows:


                                                                      Reserves for
                                                                    Depreciation and
                                         Gross Property                 Depletion                   Net Property
                                     ----------------------        -------------------         ---------------------
(Millions of dollars)                  2003           2002          2003         2002           2003           2002
--------------------------------------------------------------------------------------------------------------------
                                                                                            

Exploration and production           $12,087        $11,585        $5,719       $5,632         $6,368         $5,953
Chemicals                              2,082          1,963         1,068          965          1,014            998
Other                                    184            176            99           91             85             85
                                     -------        -------        ------       ------         ------         ------
     Total                           $14,353        $13,724        $6,886       $6,688         $7,467         $7,036
                                     =======        =======        ======       ======         ======         ======


The company  applies the  provisions of FAS No. 19,  "Financial  Accounting  and
Reporting by Oil and Gas Producing Companies," for the accounting of oil and gas
mineral rights held by lease or contract and accordingly classifies these assets
as property,  plant and equipment.  This classification is the long standing and
current  industry  standard and is consistent  with most mineral rights case law
(that is, mineral rights generally are treated as interests in real property and
real  property  laws  are  used to  interpret  the  leases).  However,  the U.S.
Securities and Exchange Commission has asked that the Emerging Issues Task Force
(EITF) consider whether mineral rights are intangible  assets under the guidance
provided by FAS No. 141, "Business Combinations," and FAS No. 142, "Goodwill and
Other Intangible  Assets." If such interests are deemed to be intangible  assets
by the EITF,  mineral  rights to extract  oil and gas for both  undeveloped  and
developed leaseholds may be reclassified separately as intangible assets.

Even  though   management   believes  the   company's   current   balance  sheet
classification  is required  under  generally  accepted  accounting  principles,
reclassification  may be  necessary  in the  future  when  further  guidance  is
provided by the EITF.  However,  it is not currently  clear which mineral rights
might  have  to  be  reclassified  as  intangible  assets  - all  producing  and
nonproducing  leaseholds,   only  nonproducing  leaseholds  or  only  leaseholds
acquired in business  combinations  since the effective date of FAS No. 141. Any
such  reclassification  would not affect the company's total assets,  net worth,
cash flows or results of operations.  A reclassification could negatively impact
one of the company's debt  covenants and certain  contractual  obligations  that
require the company to maintain a certain  level of tangible  net worth,  absent
waiver or amendment of such  provisions.  These mineral rights would continue to
be amortized in accordance  with FAS No. 19. At December 31, 2003 and 2002,  the
company  had  total  producing   leasehold   costs  for  mineral   interests  of
approximately $1.6 billion, net of accumulated  depletion and amortization,  and
nonproducing  leasehold costs of approximately  $.5 billion,  net of accumulated
depletion  and  amortization.   Of  these  amounts,   leasehold  costs,  net  of
accumulated depletion and amortization,  acquired in business combinations since
the  effective  date of FAS No. 141 were  approximately  $1.3  billion  and $1.4
billion  of   producing   leasehold   costs  at  December  31,  2003  and  2002,
respectively,  and $.1 billion of nonproducing  leasehold costs at both December
31, 2003 and 2002.


6.   Deferred Charges

Deferred charges are as follows at year-end 2003 and 2002:

(Millions of dollars)                                      2003             2002
--------------------------------------------------------------------------------

Pension plan prepayments                                   $243             $240
Nonqualified benefit plans deposits                          35               35
Unamortized debt issue costs                                 22               27
Amounts pending recovery from third parties                   8               13
Other                                                         9               13
                                                           ----             ----

     Total                                                 $317             $328
                                                           ====             ====


7.   Accrued Liabilities

Accrued liabilities at year-end 2003 and 2002 are as follows:

(Millions of dollars)                                       2003            2002
--------------------------------------------------------------------------------

Derivatives (1)                                             $354            $135
Employee-related costs and benefits                          141             103
Interest payable                                             109             105
Current environmental reserves                                98             100
Asset retirement obligations (current portion)                20               -
Litigation reserves                                            5              43
North Sea royalties                                            -              13
Other                                                         32              21
                                                            ----            ----
     Total                                                  $759            $520
                                                            ====            ====

(1)  Balance at December 31, 2003,  includes the call option associated with the
     DECS of $155 million (See Note 18).


8.   Work Force Reduction, Restructuring Provisions and Exit Activities

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 are eligible for enhanced
benefits  under the  company's  pension  and  postretirement  plans,  along with
severance payments. The program was substantially  completed by the end of 2003,
with  certain  retiring  employees  staying  into  the  first  half of 2004  for
transition  purposes.  In connection with the work force reduction,  the company
took a pretax  charge of $56 million  during 2003,  of which $34 million was for
curtailment  and special  termination  benefits  associated  with the  company's
retirement plans and $22 million was for severance-related  costs. The provision
for  severance-related  costs is included in the  restructuring  reserve balance
below. Of the  severance-related  provision of $22 million,  $5 million has been
paid through December 31, 2003, with $17 million  remaining in the accrual to be
paid in 2004.

The company closed its synthetic  rutile plant in Mobile,  Alabama,  during June
2003. During the year, the company's  chemical - pigment operating unit provided
$24 million for costs associated with the closure of this facility.  Included in
this  amount  were $14  million  recorded  as a  cumulative  effect of change in
accounting   principle  related  to  the  recognition  of  an  asset  retirement
obligation and $10 million for the accrual of severance benefits.  The provision
for severance  benefits is included in the restructuring  reserve balance below.
See Note 1 for a discussion  of the asset  retirement  obligation.  Of the total
severance  provision of $10 million,  $8 million was paid through the end of the
year and $2 million remained in the accrual at December 31, 2003.  Approximately
135 employees  will  ultimately  be  terminated  in  connection  with this plant
closure, of which 117 had been terminated as of December 31, 2003. Additionally,
during 2003, the company  recognized $15 million in accelerated  depreciation on
the plant  assets,  $6 million for  curtailment  costs and  special  termination
benefits related to pension and postretirement plans, $8 million for cleanup and
decommissioning  costs  associated  with the  plant,  and $8  million  for other
shutdown costs.

During 2002, the company's  chemical - other operating unit provided $17 million
for costs associated with exiting its forest products business. During 2003, the
company  provided an  additional $5 million  associated  with exiting the forest
products  business.  Included in the total  provision  of $22  million  were $16
million for dismantlement and closure costs, and $6 million for severance costs.
These costs are  reflected in costs and operating  expenses in the  Consolidated
Statement of  Operations.  Of the total  provision,  $8 million was paid through
December 31, 2003, and $14 million  remained in the accrual as of year-end 2003.
Of its five remaining forest products-treating  plants, one has been closed, and
three have ceased  operations  and are in the process of being  dismantled.  The
company will continue to operate its fifth plant, a leased  facility  located in
The Dalles,  Oregon,  through the term of the lease, which runs through November
30,  2004.  In  connection  with  the  plant  closures,  252  employees  will be
terminated,  of which 163 were  terminated  as of year-end  2003.  Additionally,
during 2003, the company recognized $9 million for other shutdown related costs,
including  accelerated  depreciation  on plant  assets,  curtailment  costs  and
special termination benefits related to pension and postretirement plans.

In 2001,  the company's  chemical - pigment  operating unit provided $32 million
related to the closure of a plant in Antwerp,  Belgium.  The provision consisted
of $12 million for severance  costs,  $12 million for  dismantlement  costs,  $7
million for  contract  settlement  costs and $1 million for other plant  closure
costs.  Of this  total  accrual,  $5  million  and $9  million  remained  in the
restructuring accrual at the end of 2003 and 2002, respectively.  As a result of
this plant closure,  121 employees were  identified for termination and all have
been terminated as of December 31, 2003.

Also in 2001, the company's chemical - other operating unit provided $12 million
for  the   discontinuation  of  manganese  metal  production  at  its  Hamilton,
Mississippi,  facility.  The provision  consisted of $7 million for pond-closure
costs,  $2 million for  severance  costs and $3 million for other  plant-closure
costs.  Of this  total  accrual,  $1  million  and $2  million  remained  in the
restructuring accrual at the end of 2003 and 2002, respectively.  As a result of
this plant closure, 42 employees were terminated and all related severance costs
were paid in 2001.  Completion of the remaining  action of pond closure may take
from three to 10 years, depending on environmental constraints.

The provisions, payments, adjustments and reserve balances for 2003 and 2002 are
included in the table below.


                                               2003                                           2002
                              ---------------------------------------          --------------------------------------
                                                        Dismantlement                                   Dismantlement
                                        Personnel                 and                    Personnel                and
(Millions of dollars)         Total         Costs             Closure          Total         Costs            Closure
---------------------------------------------------------------------------------------------------------------------
                                                                                               
Beginning balance              $ 27          $  4                 $23           $ 28          $ 12               $ 16
   Provisions                    37            37                   -             17             1                 16
   Payments (1)                 (22)          (16)                 (6)           (20)          (10)               (10)
   Adjustments (2)               (3)            2                  (5)             2             1                  1
                               ----          ----                 ---           ----          ----               ----
Ending balance                 $ 39          $ 27                 $12           $ 27          $  4               $ 23
                               ====          ====                 ===           ====          ====               ====


(1)  Includes amounts in total provision that were charged directly to expense.
(2)  Includes  foreign-currency  translation  adjustments  related  to  Antwerp,
     Belgium, accrual.


9.   Debt

Lines of Credit

At year-end  2003,  the company  had  available  unused bank lines of credit and
revolving credit facilities of $1.4 billion. Of this amount, $870 million can be
used to support  commercial  paper borrowing  arrangements of Kerr-McGee  Credit
LLC,  and  $490  million  can be  used  to  support  European  commercial  paper
borrowings  of  Kerr-McGee  (G.B.) PLC,  Kerr-McGee  Chemical  GmbH,  Kerr-McGee
Pigments (Holland) B.V. and Kerr-McGee International ApS.

The company has  arrangements  to maintain  compensating  balances  with certain
banks that  provide  credit.  At year-end  2003,  the  aggregate  amount of such
compensating balances was immaterial, and the company was not legally restricted
from withdrawing all or a portion of such balances at any time during the year.

Long-Term Debt

The company's  policy is to classify  certain  borrowings under revolving credit
facilities  and  commercial  paper as  long-term  debt since the company has the
ability under certain  revolving  credit  agreements  and the intent to maintain
these  obligations  for longer than one year.  At year-end  2003 and 2002,  debt
totaling  nil  and  $68  million,  respectively,  was  classified  as  long-term
consistent with this policy.

Long-term debt consisted of the following at year-end 2003 and 2002:



(Millions of dollars)                                                                    2003                  2002
---------------------                                                                   ------                ------
                                                                                                        
Debentures -
  7.125% Debentures due October 15, 2027
    (7.01% effective rate)                                                              $  150                $  150
  7% Debentures due November 1, 2011, net of
    unamortized debt discount of $84 in 2003
    and $90 in 2002 (14.25% effective rate)                                                166                   160
  5-1/4% Convertible subordinated debentures due
    February 15, 2010 (convertible at $61.08 per
    share, subject to certain adjustments)                                                 600                   600
Notes payable -
  5-7/8% Notes due September 15, 2006 (5.89% effective rate)                               307                   325
  6-7/8% Notes due September 15, 2011,
    net of unamortized debt discount of $1
    in both 2003 and 2002 (6.90% effective rate)                                           674                   674
  7-7/8% Notes due September 15, 2031,
    net of unamortized debt discount of $2
    in both 2003 and 2002 (7.91% effective rate)                                           498                   498
  5-1/2% Exchangeable Notes (DECS) due August 2, 2004, net
    of unamortized debt discount of $4 in 2003 and
    $12 in 2002 (5.60% effective rate) (See Note 18)                                       326                   318
  6.625% Notes due October 15, 2007                                                        150                   150
  8.375% Notes due July 15, 2004                                                           145                   150
  8.125% Notes due October 15, 2005                                                        109                   150
  8% Notes due October 15, 2003                                                              -                   100
  5.375% Notes due April 15, 2005                                                          350                   350
  Floating rate notes due June 28, 2004 (1.92% average
    interest rate at December 31, 2003)                                                    100                   200
Euro Commercial paper (2.10% average effective
  interest rate at December 31, 2002)                                                        -                    68
Guaranteed Debt of Employee Stock Ownership Plan 9.61%
  Notes due in installments through January 2, 2005                                          5                    11
Gunnison Trust floating rate notes due November 8, 2006
  (1.93% average interest rate at December 31, 2003)                                        75                     -
                                                                                        ------                ------
                                                                                         3,655                 3,904
Long-term debt due within one year                                                        (574)                 (106)
                                                                                        ------                ------

     Total                                                                              $3,081                $3,798
                                                                                        ======                ======


Future maturities of long-term debt as of December 31, 2003, are as follows:



                                                                                                  There-
(Millions of dollars)           2004           2005        2006          2007         2008         after        Total
---------------------------------------------------------------------------------------------------------------------
                                                                                          

Long-term debt                  $574 (1)       $460        $382          $150         $  -        $2,089       $3,655


(1)  Of this amount,  $326 million may be a noncash  settlement of the DECS with
     distribution of the Devon stock.

The company's  long-term debt agreements do not contain subjective  acceleration
clauses  (commonly  referred to as material  adverse change  clauses);  however,
certain  of  the  company's   long-term  debt  agreements  contain   restrictive
covenants,  including a minimum  tangible  net worth  requirement  and a maximum
total debt to total  capitalization  ratio,  as defined  in the  agreements.  At
December 31, 2003, the company was in compliance with its debt covenants. Except
for the  Gunnison  Trust  floating  rate  notes  payable  discussed  below,  all
outstanding notes and debentures are unsecured.

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.  Under  the terms of the  agreement,  the
company's share of construction costs for the platform has been financed under a
five-year  synthetic  lease  credit  facility  between  the trust and  groups of
financial  institutions  for up to $157 million,  with the company  making lease
payments sufficient to pay interest at varying rates on the notes.  Construction
of the platform was  completed in December  2003,  with the  company's  share of
construction  costs totaling $149 million.  On December 31, 2003, $66 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.

Both the  Gunnison  Trust  and the new  operating  lease  trust  are  considered
variable  interest entities under the provisions of FIN 46. As such, the company
is required to analyze its relationship with each trust to determine whether the
company is the primary beneficiary, and thus required to consolidate the trusts.
Based on the analyses  performed,  the company is not the primary beneficiary of
the  operating  lease  trust;  however,  the company is  considered  the primary
beneficiary  of the  Gunnison  Trust.  Accordingly,  the  remaining  assets  and
liabilities  of the Gunnison  Trust are reflected in the company's  Consolidated
Balance  Sheet at December  31,  2003,  which  includes $83 million in property,
plant and equipment, $4 million in accrued liabilities, $75 million in long-term
debt,  and $4 million in minority  interest.  The Gunnison  Trust  floating rate
notes  payable are  secured by the  platform  assets of $83 million  included in
property and an assignment of the company's  lease  agreement  with the Gunnison
Trust. The $66 million of platform assets and related debt that was converted to
the  leveraged  lease  structure  in  December  2003  is not  recognized  in the
company's  Consolidated Balance Sheet at December 31, 2003. On January 15, 2004,
the remaining $83 million of the synthetic  lease  facility was converted to the
leveraged lease  structure,  and the related lessor trust will not be subject to
consolidation.  As a result, the related property and debt will not be reflected
in the  company's  Consolidated  Balance  Sheet in  2004.  The  operating  lease
commitment is included in the Note 17 disclosure.


10.  Asset Securitization

In December 2000, the company began an accounts receivable  monetization program
for its pigment business through the sale of selected accounts receivable with a
three-year,  credit-insurance-backed  asset securitization  program. On July 30,
2003, the company  restructured the existing  accounts  receivable  monetization
program to include the sale of receivables  originated by the company's European
chemical operations.  The maximum available funding under the amended program is
$165 million. In addition, certain other terms of the program have been modified
as  part  of  the  restructuring.  Under  the  terms  of the  program,  selected
qualifying customer accounts receivable may be sold monthly to a special-purpose
entity  (SPE),  which  in turn  sells an  undivided  ownership  interest  in the
receivables to a third-party  multi-seller commercial paper conduit sponsored by
an independent financial institution. The company sells, and retains an interest
in, excess receivables to the SPE as over-collateralization for the program. The
company's  retained  interest in the SPE's  receivables  is  classified in trade
accounts receivable in the accompanying Consolidated Balance Sheet. The retained
interest is subordinate to, and provides credit  enhancement  for, the conduit's
ownership interest in the SPE's receivables,  and is 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 termination.  However,
the company believes that the risk of credit loss is very low since its bad-debt
experience has historically  been  insignificant.  The company retains servicing
responsibilities  and receives a servicing fee of 1.07% of the receivables  sold
for the period of time  outstanding,  generally 60 to 120 days.  Servicing  fees
collected  were $2  million  in 2003 and $1  million  in both 2002 and 2001.  No
recourse  obligations were recorded since the company has no obligations for any
recourse  actions on the sold  receivables.  The company  also holds  preference
stock in the  special-purpose  entity equal to 3.5% of the receivables sold. The
preference  stock is  essentially a retained  deposit to provide  further credit
enhancements,  if needed, but otherwise recoverable by the company at the end of
the program.

During 2003, 2002 and 2001, the company sold $836 million, $609 million and $597
million, respectively, of its pigment receivables, resulting in pretax losses of
$5 million, $5 million and $8 million, respectively. 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  special-purpose  entity.  At
year-end 2003 and 2002, the outstanding  balance on receivables sold, net of the
company's  retained interest in receivables  serving as  over-collateralization,
totaled $165 million and $111 million, respectively. The outstanding balance for
receivables  serving as  over-collateralization  totaled $36 million at December
31, 2003. There were no delinquencies as of year-end 2003.


11.  Income Taxes

The  2003,  2002 and 2001  income  tax  provisions  (benefits)  from  continuing
operations are summarized below:

(Millions of dollars)                   2003             2002              2001
--------------------------------------------------------------------------------

U.S. Federal -
  Current                               $  9            $  12              $(70)
  Deferred                                19             (104)              219
                                        ----            -----              ----
                                          28              (92)              149
                                        ----            -----              ----
International -
  Current                                 58               36               130
  Deferred                               100               10                (8)
                                        ----            -----              ----
                                         158               46               122
                                        ----            -----              ----
State                                      3                -                 5
                                        ----            -----              ----

         Total                          $189            $ (46)             $276
                                        ====            =====              ====

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 Operations.

                                                      2003      2002       2001
--------------------------------------------------------------------------------

U.S. statutory rate - provision (benefit)             35.0%    (35.0)%     35.0%
  Increases (decreases) resulting from -
    Adjustment of deferred tax balances due
      to tax rate changes                                -      19.9        (.1)
    Taxation of foreign operations                     8.6      12.1        1.7
    Federal income tax credits                           -      (1.8)         -
    State income taxes                                  .5         -         .6
    Other - net                                       (1.4)     (2.2)       (.5)
                                                      ----      ----       ----

              Total                                   42.7%     (7.0)%     36.7%
                                                      ====      ====       ====


Net deferred tax  liabilities at December 31, 2003 and 2002, are composed of the
following:

(Millions of dollars)                                           2003       2002
--------------------------------------------------------------------------------

Net deferred tax liabilities -
  Accelerated depreciation                                    $1,100     $1,088
  Exploration and development                                    406        192
  Undistributed earnings of foreign subsidiaries                  28         28
  Postretirement benefits                                        (76)       (89)
  Dismantlement, remediation, restoration and
    other reserves                                              (109)       (34)
  U.S. and foreign operating loss carryforward                  (126)       (92)
  AMT credit carryforward                                        (47)       (47)
  Other                                                           83         99
                                                              ------     ------

         Total                                                $1,259     $1,145
                                                              ======     ======

The taxation of a company that has operations in several 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 (loss) from continuing  operations
before income taxes is comprised of the following:

(Millions of dollars)                      2003            2002             2001
--------------------------------------------------------------------------------

United States                              $145           $(116)            $524
International                               298            (541)             228
                                           ----           -----             ----
    Total                                  $443           $(657)            $752
                                           ====           =====             ====

On July 24, 2002,  the United  Kingdom  government  made certain  changes to its
existing tax laws.  Under one of these changes,  companies are required to pay a
supplementary corporate tax charge of 10% on profits from their U.K. oil and gas
production,  in addition to the required 30% corporate tax on these profits. The
U.K.  government also accelerated tax  depreciation  for capital  investments in
U.K.  upstream  activities and abolished North Sea royalty.  The deferred income
tax liability was adjusted to reflect these  changes,  causing a net increase in
the 2002 international deferred provision for income taxes of $132 million.

At December  31,  2003,  the company had foreign  operating  loss  carryforwards
totaling $272 million.  Of this amount,  $3 million expires in 2004, $13 million
in 2006, $1 million in 2007 and $255 million has no expiration date. Realization
of these operating loss carryforwards  depends on generating  sufficient taxable
income in future periods. A valuation  allowance of $9 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 $710
million at December 31, 2003. No provision  for deferred  U.S.  income taxes has
been made for these  earnings  because they are  considered  to be  indefinitely
invested  outside the U.S.  The  distribution  of these  earnings in the form of
dividends or otherwise,  may subject the company to U.S. income 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
1998 and is conducting an  examination of the years 1999 through 2002. The years
through  1994 have been closed.  The Oryx income tax returns have been  examined
through  1997,  and the years  through 1978 have been closed,  as have the years
1988 through 1997. The company believes that it has made adequate  provision for
income taxes that may be payable with respect to open years.


12.  Taxes, Other than Income Taxes

Taxes,  other than  income  taxes,  as shown in the  Consolidated  Statement  of
Operations for the years ended  December 31, 2003,  2002 and 2001, are comprised
of the following:

(Millions of dollars)                    2003             2002              2001
--------------------------------------------------------------------------------

Production/severance                      $46             $ 58              $ 67
Payroll                                    30               21                27
Property                                   19               20                15
Other                                       3                5                 5
                                          ---             ----              ----

    Total                                 $98             $104              $114
                                          ===             ====              ====


13.  Asset Retirement Obligations

As  discussed  in Note 1, the  company  adopted  FAS 143 on January 1, 2003.  At
December  31, 2002,  the  comparable  balance of $222  million  reflected in the
company's  Consolidated  Balance Sheet represents the non-current portion of the
company's site dismantlement reserve prior to the adoption of FAS 143. A summary
of the  changes in asset  retirement  obligations  since the date of adoption is
included in the table below.

(Millions of dollars)
--------------------------------------------------------------------------------

January 1, 2003, balance upon adoption of FAS 143                          $395
  Obligations incurred                                                       11
  Accretion expense                                                          25
  Abandonment expenditures                                                  (17)
  Abandonment obligations settled through property divestitures             (15)
  Changes in estimates, including timing                                     22
                                                                           ----
December 31, 2003                                                           421
  Less current asset retirement obligation                                  (20)
                                                                           ----
Non-current asset retirement obligation                                    $401
                                                                           ====


14.  Deferred Credits and Reserves - Other

Other  deferred  credits and reserves  consist of the following at year-end 2003
and 2002:

(Millions of dollars)                                      2003             2002
--------------------------------------------------------------------------------

Postretirement benefit obligations                         $215             $210
Reserves for remediation and restoration                    152              165
Pension plan liabilities                                     73               54
Derivatives (1)                                               2               67
Litigation reserves                                          32               30
Accrued rent expense - spar operating leases                 32                9
Ad valorem taxes                                             31               21
Other                                                        28               26
                                                           ----             ----

              Total                                        $565             $582
                                                           ====             ====

(1)  Options  associated with  exchangeable  debt of $67 million at December 31,
     2002, were reclassified from other deferred credits and reserves to accrued
     liabilities  during  2003 in  connection  with the  maturity of the DECS in
     August 2004 (see Note 18).

The company  provided for  environmental  remediation  and  restoration,  net of
authorized  reimbursements,  during  each of the years 2003,  2002 and 2001,  as
follows:

(Millions of dollars)                            2003          2002         2001
--------------------------------------------------------------------------------

Provision, net of authorized reimbursements       $62         $  80          $90
Reimbursements received                            15             9           11
Authorized reimbursements accrued                  32           113            -

The reimbursements pertain to the former facility in West Chicago, Illinois, and
the Henderson,  Nevada, facility. The West Chicago reimbursements are authorized
pursuant  to  Title  X of the  Energy  Policy  Act of  1992  and  the  Henderson
reimbursements  represent amounts  recoverable  under an environmental  cost cap
insurance policy (see Note 16).


15.  Other Income (Expense)

Other income  (expense)  included the following  during each of the years in the
three-year period ended December 31, 2003:

(Millions of dollars)                            2003         2002         2001
--------------------------------------------------------------------------------

Gain (loss) on foreign currency exchange         $(41)        $(38)        $  3
Loss from unconsolidated affiliates               (33)         (25)          (5)
Gain on sale of Devon stock                        17            -            -
Derivatives and Devon stock revaluation (1)         4           35          225
Interest income                                     5            5           10
Other                                             (11)         (12)          (9)
                                                 ----         ----         ----

         Total                                   $(59)        $(35)        $224
                                                 ====         ====         ====

(1)  See Note 18.


16.  Contingencies

West Chicago, Illinois

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

Closed  Facility  -  Pursuant  to  agreements  reached  in 1994 and  1997  among
Chemical,  the City of West  Chicago  (the  City)  and the State  regarding  the
decommissioning of the closed West Chicago facility,  Chemical has substantially
completed the excavation of contaminated soils and has shipped the bulk of those
soils to a licensed  disposal  facility.  Removal of the remaining  materials is
expected to be substantially  completed by the end of 2004, leaving  principally
surface restoration and groundwater monitoring and/or remediation for subsequent
years. Surface restoration is expected to be completed in 2004, except for areas
designated for use in connection with the Kress Creek and Sewage Treatment Plant
remediation   discussed  below.  The  long-term  scope,  duration  and  cost  of
groundwater  monitoring  and/or  remediation  are  uncertain  because  it is not
possible to reliably  predict how  groundwater  conditions have been affected by
the excavation and removal work.

Vicinity Areas - The Environmental Protection Agency (EPA) has listed four areas
in the  vicinity  of the  closed  West  Chicago  facility  on the  NPL  and  has
designated  Chemical  as a  Potentially  Responsible  Party  (PRP) in these four
areas.  Chemical has substantially  completed remedial work for two of the areas
(known as the Residential Areas and Reed-Keppler Park). The other two NPL sites,
known as Kress Creek and the Sewage  Treatment Plant, are contiguous and involve
low  levels of  insoluble  thorium  residues,  principally  in  streambanks  and
streambed  sediments,  virtually all within a floodway.  Chemical has reached an
agreement in principle 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 damage
claims.  The agreement in principle is expected to be  incorporated in a consent
decree,  which must be agreed to by the  appropriate  federal and state agencies
and local  communities  and then entered by a federal  court.  Court approval is
expected in 2004.  Chemical has already conducted an extensive  characterization
of Kress  Creek and the  Sewage  Treatment  Plant  and,  at the  request of EPA,
Chemical is conducting limited additional  characterization  that is expected to
be completed  in 2004.  The cleanup  work,  which is expected to take about four
years to complete following entry of the consent decree, 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, 2003, the company had remaining reserves
of $96 million for costs  related to West  Chicago.  This  includes  $19 million
added to the reserve in 2003 because of an increase in soil volumes  experienced
at the Closed Facility and related post-cleanup demolition,  city infrastructure
replacement,  and additional support and oversight costs.  Although actual costs
may exceed current  estimates,  the amount of any increases cannot be reasonably
estimated  at  this  time.   The  amount  of  the  reserve  is  not  reduced  by
reimbursements  expected from the federal government under Title X of the Energy
Policy Act of 1992 (Title X) (discussed below).

Government  Reimbursement  - Pursuant to Title X, the U.S.  Department of Energy
(DOE) is obligated to reimburse Chemical for certain decommissioning and cleanup
costs  incurred in connection  with the West Chicago sites in recognition of the
fact  that  about  55%  of the  facility's  production  was  dedicated  to  U.S.
government  contracts.  The amount authorized for reimbursement under Title X is
$365 million plus  inflation  adjustments.  That amount is expected to cover the
government's  full share of West Chicago  cleanup  costs.  Through  December 31,
2003, Chemical had been reimbursed  approximately $171 million under Title X. In
March  2004,  Chemical  received an  additional  reimbursement  of $44  million,
bringing the total reimbursement received to date to about $215 million.

Reimbursements  under  Title X are  provided  by  congressional  appropriations.
Historically,   congressional  appropriations  have  lagged  Chemical's  cleanup
expenditures.  As of December 31, 2003, the government's share of costs incurred
by  Chemical  but  not yet  reimbursed  by the DOE  totaled  approximately  $109
million, which was reduced to $65 million in March 2004 following receipt of the
additional  reimbursement  of $44 million.  The company  believes receipt of the
remaining   arrearage   in  due  course   following   additional   congressional
appropriations  is probable and has  reflected  the arrearage as a receivable in
the financial  statements.  The company expects to receive reimbursement for the
remainder of this receivable by the end of 2006, and will recognize  recovery of
the government's share of future remediation costs for the West Chicago sites as
Chemical incurs the costs.

Henderson, Nevada

In 1998,  Chemical decided to exit the ammonium  perchlorate  business.  At that
time,  Chemical  curtailed  operations and began preparation for the shutdown of
the  associated  production  facilities  in  Henderson,  Nevada,  that  produced
ammonium  perchlorate  and other related  products.  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 Chemical.  The ammonium  perchlorate  produced at the  Henderson
facility was used primarily in federal  government  defense and space  programs.
Perchlorate has been detected in nearby Lake Mead and the Colorado River.

Chemical  began   decommissioning   the  facility  and  remediating   associated
perchlorate  contamination,  including surface impoundments and groundwater when
it decided to exit the business in 1998. In 1999 and 2001, Chemical entered into
consent orders with the Nevada Division of Environmental Protection that require
Chemical to implement  both interim and long-term  remedial  measures to capture
and remove perchlorate from groundwater.

In 1999, Chemical initiated the interim measures required by the consent orders.
In June  2003,  construction  began on a  long-term  remediation  system.  It is
anticipated  that this system will be  operational  in early 2004. The scope and
duration of groundwater  remediation will be driven in the long term by drinking
water  standards,  which to date have not been formally  established by state or
federal  regulatory  authorities.  EPA and  other  federal  and  state  agencies
currently are  evaluating the health and  environmental  risks  associated  with
perchlorate  as part of the  process  for  ultimately  setting a drinking  water
standard.  The  resolution  of these issues could  materially  affect the scope,
duration and cost of the  long-term  groundwater  remediation  that  Chemical is
required to perform.

Financial  Reserves - In 2003, the company added $32 million to its reserves for
groundwater  remediation at Henderson for the  construction and operation of the
long-term  remediation system and the continued  operation of the interim system
during the construction and startup period for the long-term  system.  Remaining
reserves for  Henderson  totaled $23 million as of December  31, 2003.  As noted
above,  the long-term  scope,  duration and cost of groundwater  remediation are
uncertain  and,  therefore,  additional  costs may be  incurred  in the  future.
However,  the amount of any additional  costs cannot be reasonably  estimated at
this time.

Government  Litigation  - In 2000,  Chemical  initiated  litigation  against the
United States seeking  contribution for response costs. The suit is based on the
fact that the  government  owned the plant in the early years of its  operation,
exercised  significant  control  over  production  at the  plant and the sale of
products  produced  at the  plant,  and was the  largest  consumer  of  products
produced at the plant.  The litigation is in the discovery  stage.  Although the
outcome  of the  litigation  is  uncertain,  Chemical  believes  it is likely to
recover a portion of its costs from the government. The amount and timing of any
recovery cannot be estimated at this time and, accordingly,  the company has not
recorded a receivable  or otherwise  reflected in the financial  statements  any
potential recovery from the government.

Insurance - In 2001,  Chemical purchased a 10-year,  $100 million  environmental
cost cap insurance  policy for groundwater  and other  remediation at Henderson.
The  insurance  policy  provides   coverage  only  after  Chemical   exhausts  a
self-insured  retention of approximately $61 million and covers only those costs
incurred to achieve 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  Chemical  may be required to achieve a cleanup
level  more  stringent  than that  covered  by the  policy.  If so,  the  amount
recoverable  under the policy  could be  affected.  Through  December  31, 2003,
Chemical has incurred  expenditures of about $59 million that it believes can be
applied to the self-insured  retention.  The company believes that the remaining
reserve  of $23  million at  December  31,  2003,  also will  qualify  under the
insurance policy, which would exhaust the self-insured retention and leave about
$21  million  for  recovery  under  the  policy.   The  company   believes  that
reimbursement  of the $21 million  under the  insurance  policy is probable and,
accordingly,  the company has recorded a $21 million receivable in the financial
statements.  The company expects to be reimbursed for this receivable by the end
of 2007.

Milwaukee, Wisconsin

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

Groundwater   treatment   was   initiated  in  1996  to  remediate   groundwater
contamination below and in the vicinity of the former wood-treatment area. It is
not possible to reliably predict how groundwater  conditions will be affected by
the ongoing soil  remediation and groundwater  treatment;  therefore,  it is not
known how long groundwater  treatment will continue.  Soil cleanup of the former
wood-treatment area began in 2000 and was completed in 2002. Also in 2002, terms
for  addressing  the  tributary  creek were  agreed  upon with EPA,  after which
Chemical  began  the  implementation  of a remedy  to  reroute  the creek and to
remediate  associated  sediment and stream bank soils, which is expected to take
about four more years.

As of December 31, 2003,  the company had remaining  reserves of $11 million for
the costs of the  remediation  work described  above.  Although actual costs may
exceed  current  estimates,  the amount of any  increases  cannot be  reasonably
estimated at this time.

Cushing, Oklahoma

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

Subsequent  regulatory changes required more extensive  remediation at the site.
In 1990,  the  affiliate  entered  into a  consent  agreement  with the State of
Oklahoma to investigate the site and take  appropriate  remedial actions related
to  petroleum  refining  and uranium and thorium  residuals.  Investigation  and
remediation of hydrocarbon  contamination  is being  performed with oversight of
the Oklahoma  Department of Environmental  Quality.  Soil remediation to address
hydrocarbon contamination is expected to continue for about four more years. The
long-term scope, duration and cost of groundwater remediation are uncertain and,
therefore,  additional  costs may be incurred in the  future.  Additionally,  in
1993,  the  affiliate  received  a  decommissioning  license  from  the  Nuclear
Regulatory  Commission  (NRC),  the successor to AEC's licensing  authority,  to
perform certain cleanup of uranium and thorium residuals.  This work is expected
to be substantially completed in 2004.

As of December 31, 2003,  the company had remaining  reserves of $22 million for
the costs of the ongoing remediation and  decommissioning  work described above.
This  includes  $17  million  added to the  reserve  in 2003 as a result  of the
increase  in  uranium  and  thorium  residuals  experienced  at the site,  which
required  excavation,   transportation  and  disposal,  as  well  as  additional
characterization of petroleum hydrocarbons, and extended support costs. Although
actual costs may exceed current estimates, the amount of any increases cannot be
reasonably estimated at this time.

Mobile, Alabama

In June 2003,  Chemical  ceased  operations at its facility in Mobile,  Alabama,
which Chemical had used to produce  feedstock for its titanium  dioxide  plants.
Operations  prior  to  closure  had  resulted  in  minor  contamination  of  the
groundwater adjacent to surface impoundments.  A groundwater recovery system was
installed  prior to  closure  and  continues  in  operation  as  required  under
Chemical's  National  Pollutant  Discharge  Elimination  System (NPDES)  permit.
Future  remediation  work,  including  groundwater  recovery,   closure  of  the
impoundments and other minor work, is expected to be substantially  completed in
about five years.  Reserves of $11 million were provided for the  remediation in
2003 and remain  outstanding as of December 31, 2003.  Although actual costs may
exceed  current  estimates,  the amount of any  increases  cannot be  reasonably
estimated at this time.

New Jersey Wood-Treatment Site

In 1999, EPA notified Chemical and its parent company that they were potentially
responsible parties at a former  wood-treatment site in New Jersey that has been
listed by EPA as a Superfund  site. At that time,  the company knew little about
the site as neither Chemical nor its parent had ever owned or operated the site.
A predecessor of Chemical had been the sole  stockholder of a company that owned
and  operated  the  site.  The  company  that  owned the site  already  had been
dissolved  and the site had been sold to a third party  before  Chemical  became
affiliated with the former stockholder in 1964. EPA has preliminarily  estimated
that cleanup costs may reach $120 million or more.

There are substantial  uncertainties  about  Chemical's  responsibility  for the
site,  and  Chemical  is  evaluating  possible  defenses to any claim by EPA for
response costs. EPA has not articulated the factual and legal basis on which EPA
notified Chemical and its parent that they are potentially  responsible parties.
The EPA  notification  may be based on a successor  liability theory premised on
the 1964  transaction  pursuant to which  Chemical  became  affiliated  with the
former stockholder of the company that had owned and operated the site. Based on
available  historical  records,  it is uncertain  whether and, if so, under what
terms,  the former  stockholder  assumed  liabilities of the dissolved  company.
Moreover,  as noted  above,  the site had  been  sold to a third  party  and the
company  that owned and  operated the site had been  dissolved  before  Chemical
became affiliated with that company's stockholder.  In addition, there appear to
be other  potentially  responsible  parties,  though it is not known whether the
other parties have received  notification from EPA. EPA has not ordered Chemical
or its parent to perform  work at the site and is  instead  performing  the work
itself.  The  company  has not  recorded  a  reserve  for the  site as it is not
possible to reliably estimate whatever liability Chemical or its parent may have
for the cleanup because of the aforementioned uncertainties and the existence of
other potentially responsible parties.

Forest Products Litigation

Between 1999 and 2001, Kerr-McGee Chemical LLC (Chemical) and its parent company
were  named  in  22  lawsuits  in  three  states  (Mississippi,   Louisiana  and
Pennsylvania)  in connection with present and former forest products  operations
located in those states (in Columbus, Mississippi;  Bossier City, Louisiana; and
Avoca, Pennsylvania). The lawsuits sought recovery under a variety of common law
and  statutory  legal  theories  for  personal  injuries  and  property  damages
allegedly  caused by exposure to and/or release of creosote and other substances
used in the wood-treatment process.

Having  earlier  set a reserve of $70 million for  liabilities  associated  with
these matters,  Chemical executed settlement  agreements,  which are expected to
resolve   substantially  all  of  the  Louisiana,   Pennsylvania  and  Columbus,
Mississippi,  lawsuits  described  above.  About  90%  of  approximately  10,400
identified  claimants and about 2,500 class  members  pursuant to a class action
settlement have released  Chemical and its parent from liability  related to the
former forest products  operations in exchange for settlement  payments totaling
approximately  $66 million  (leaving  approximately  $4 million in the reserve).
Accordingly most of the suits have been, or are expected to be,  dismissed.  The
settlements  do not resolve two of the Columbus,  Mississippi,  lawsuits,  which
together  involve 27 plaintiffs.  The settlements also do not resolve the claims
of  plaintiffs  who did not sign  releases,  class  members who opted out of the
class  settlement,  or class  members  whose  claims may arise in the future for
currently unmanifested personal injuries.

Chemical  and its  affiliates  believe  that  lawsuits  and claims not  resolved
pursuant to the settlements  described above are without  substantial merit, and
Chemical and its  affiliates  are vigorously  defending  against them.  However,
there is no  assurance  that the  company  will not be  required  to adjust  the
reserve in the future in light of the  uncertainties of litigation.  The company
believes that the resolution of the claims that remain  outstanding with respect
to forest products operations in Columbus, Mississippi; Bossier City, Louisiana;
and Avoca, Pennsylvania, will not have a material adverse effect on the company.

Following  the  adoption  by  the   Mississippi   legislature  of  tort  reform,
plaintiffs'  lawyers filed many new lawsuits  across the state of Mississippi in
advance of the reform's effective date. On December 31, 2002,  approximately 245
lawsuits  were  filed  against   Chemical  and  its   affiliates  on  behalf  of
approximately   4,600  claimants  in  connection   with   Chemical's   Columbus,
Mississippi,  operations,  seeking  recovery  on  legal  theories  substantially
similar to those advanced in the litigation  described above.  Substantially all
of these lawsuits have been removed to the U.S.  District Court for the Northern
District  of  Mississippi,  and the  company  is seeking  to  consolidate  these
lawsuits for  pretrial  and  discovery  purposes.  Chemical  and its  affiliates
believe the lawsuits are without substantial merit and are vigorously  defending
against them. The company has not provided a reserve for the lawsuits because it
cannot  reasonably  determine the probability of a loss, and the amount of loss,
if any, cannot be reasonably estimated.

On December  31,  2002,  and June 13,  2003,  two  lawsuits  were filed  against
Chemical  in  connection   with  a  former   wood-treatment   plant  located  in
Hattiesburg, Mississippi, and the plaintiffs' lawyers also have asserted similar
claims on behalf of other  persons not named in the  lawsuits.  The lawsuits and
other  claims seek  recovery on legal  theories  substantially  similar to those
advanced in the litigation  described above.  Chemical  resolved the majority of
these claims pursuant to a settlement  reached in April 2003, which has resulted
in aggregate  payments by Chemical of approximately  $600,000.  Chemical and its
affiliates  believe  that  claims  not  resolved  pursuant  to  the  Hattiesburg
settlements are without  substantial merit and are vigorously  defending against
such claims.

The company  believes that the resolution of the claims that remain  outstanding
with respect to the follow-on litigation will not have a material adverse effect
on the company's financial condition or results of operations.

Other Matters

The  company  and/or  its  affiliates  are  parties  to a number  of  legal  and
administrative  proceedings involving environmental and/or other matters pending
in  various  courts or  agencies.  These  include  proceedings  associated  with
facilities  currently or  previously  owned,  operated or used by the  company's
affiliates and/or their predecessors,  some of which include claims for personal
injuries and property  damages.  Current and former  operations of the company's
affiliates  also involve  management  of regulated  materials and are subject to
various  environmental  laws and  regulations.  These laws and regulations  will
obligate the company's  affiliates to clean up various sites at which  petroleum
and other hydrocarbons, chemicals, low-level radioactive substances and/or other
materials have been contained, disposed of or released. Some of these sites have
been designated Superfund sites by EPA pursuant to CERCLA. Similar environmental
regulations  exist in  foreign  countries  in  which  the  company's  affiliates
operate.

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:

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

o    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;

o    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;

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

o    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;

o    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;

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

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

o    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.

As of December 31,  2003,  the company had  reserves  totaling  $259 million for
cleaning up and  remediating  environmental  sites,  reflecting  the  reasonably
estimable  costs for addressing  these sites.  This includes $96 million for the
West Chicago sites, $23 million for the Henderson,  Nevada, site and $35 million
for forest  products sites.  Additionally,  as of December 31, 2003, the company
had litigation  reserves  totaling  approximately $37 million for the reasonably
estimable  losses  associated  with  litigation.   Management  believes,   after
consultation  with  general  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.


17.  Commitments

Lease Obligations and Guarantees

Total lease rental  expense was $65 million in 2003, $61 million in 2002 and $38
million in 2001.

The  company  has  various  commitments  under  noncancelable   operating  lease
agreements,  principally for office space,  production and gathering facilities,
and drilling and other  equipment.  The company has also entered into  operating
lease  agreements  for the use of the Nansen,  Boomvang and  Gunnison  platforms
located  in the Gulf of  Mexico.  Aggregate  minimum  annual  rentals  under all
operating leases  (including the platform leases in effect at December 31, 2003,
and the Gunnison  operating  lease which closed  January 15,  2004),  total $941
million,  of which $50 million is due in 2004,  $66 million in 2005, $65 million
in 2006, $59 million in 2007, $61 million in 2008 and $640 million thereafter.

During  2001,  the company  entered  into a  synthetic  lease  arrangement  with
Kerr-McGee  Gunnison  Trust for the  construction  of the  company's  share of a
platform to be used in the  development of the Gulf of Mexico Gunnison field, in
which the company has a 50% working interest.  The construction of the company's
portion of the platform was financed with a $149 million synthetic lease between
the trust and a group of  financial  institutions.  Completion  of the  Gunnison
platform  occurred in  December  2003,  at which time a portion of the  platform
assets was acquired by a separate business trust and the company entered into an
operating lease for the use of the assets. The remaining portion of the Gunnison
synthetic  lease was  converted  to an operating  lease on January 15, 2004.  In
accordance  with the  provisions  of FIN 46, the  company has  consolidated  the
remaining  synthetic  lessor trust as of December 31, 2003, as discussed in Note
1.

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-market  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.

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 Rocky Mountain  region.  The lease  agreements were
entered into for the purpose of monetizing the related  assets.  The sales price
for the 2003  equipment was $6 million.  The sales price for the 2002  equipment
was $71  million;  however,  an $18 million  settlement  obligation  existed for
equipment  previously  covered  by the lease  agreement,  resulting  in net cash
proceeds of $53 million in 2002. 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  guarantees a
residual  value  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 conjunction with the company's sale of its Ecuadorean assets,  which included
the  company's  nonoperating  interest in the  Oleoducto de Crudos  Pesados Ltd.
(OCP) pipeline,  the company has entered into a performance  guarantee agreement
with the buyer for the  benefit of OCP.  Under the terms of the  agreement,  the
company guarantees payment of any claims from OCP against the buyer upon default
by the buyer and its parent  company.  Claims would generally be for the buyer's
proportionate  share of  construction  costs of OCP;  however,  other claims may
arise in the normal operations of the pipeline.  Accordingly,  the amount of any
such future  claims  cannot be reasonably  estimated.  In  connection  with this
guarantee,  the buyer's parent company has issued a letter of credit in favor of
the company up to a maximum of $50  million,  upon which the company can draw in
the event it is required to perform under the guarantee  agreement.  The company
will be released from this guarantee  when the buyer obtains a specified  credit
rating as stipulated under the guarantee agreement.

In connection  with certain  contracts and  agreements,  the company enters 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 $994 million,  of which
$345 million is expected to be paid in 2004, $414 million between 2005 and 2006,
$158 million between 2007 and 2008, and $77 million thereafter.

Drilling Rig Commitments

During 1999, the company entered into lease agreements to participate in the use
of  various   drilling  rigs.  The  total   commitment  with  respect  to  these
arrangements  ranges from nil to $9 million,  depending on partner  utilization.
These agreements extend through 2004.


18.  Financial Instruments and Derivative Activities

Investments in Certain Debt and Equity Securities

The company has certain  investments  that are  considered  to be available  for
sale. These financial  instruments are carried in the Consolidated Balance Sheet
at fair  value,  which is based on quoted  market  prices.  The  company  had no
securities  classified  as held to  maturity at  December  31, 2003 or 2002.  At
December 31, 2003 and 2002,  available-for-sale  securities for which fair value
can be determined are as follows:


                                                      2003                                         2002
                                       -----------------------------------         ----------------------------------
                                                                     Gross                                      Gross
                                                                Unrealized                                 Unrealized
                                        Fair                       Holding          Fair                      Holding
(Millions of dollars)                  Value          Cost           Gains         Value        Cost            Gains
---------------------------------------------------------------------------------------------------------------------
                                                                                                

Equity securities                        $27           $10              $8(1)        $70         $32              $10(1)
U.S. government obligations                4             4               -             4           4                -
                                                                        --                                        ---
          Total                                                         $8                                        $10
                                                                        ==                                        ===


(1)  This amount  includes  $9 million and $28 million at December  31, 2003 and
     2002,  respectively,  of  gross  unrealized  hedging  losses  on 15% of the
     exchangeable debt at the time of adoption of FAS 133.

The  equity  securities  represent  the  company's  investment  in Devon  Energy
Corporation  common stock.  The company also holds debt  exchangeable  for stock
(DECS) that may be repaid with the Devon stock  currently  owned by  Kerr-McGee.
Prior to the  beginning  of 2001,  the stock and the debt were  marked to market
each  month,  with the offset  recognized  in  accumulated  other  comprehensive
income. On January 1, 2001, the company adopted the provisions of FAS 133 and in
accordance  with that standard chose to reclassify 85% of the Devon shares owned
at that time to "trading" from the "available for sale" category of investments.
As a result of the  reclassification,  the company  recognized  after-tax income
totaling  $118  million  ($181   million   before  taxes)  for  the   unrealized
appreciation on 85% of the Devon shares. Additionally, with adoption of FAS 133,
the  DECS and its  embedded  option  features  were  separated.  The debt is now
recorded  in the  Consolidated  Balance  Sheet at face  value  less  unamortized
discount,  and the options associated with the exchangeable  feature of the debt
have been  recorded at fair value on the balance  sheet in accrued  liabilities.
(See further discussion on derivatives below.)

During December 2003, the company sold a portion of its Devon shares  classified
as available for sale  resulting in a pretax gain of $17 million.  The remaining
shares were sold in January 2004 for a pretax gain of $9 million.  Proceeds from
the December  sales  totaled $59 million  ($47 million  received in 2003 and $12
million  received  in 2004) and  proceeds  from the  January  sales  totaled $27
million.  The cost of the shares  sold and the  amount of the gain  reclassified
from accumulated  other  comprehensive  income were determined using the average
cost of the shares held. The Devon  securities  are carried in the  Consolidated
Balance Sheet as current  assets.  U.S.  government  obligations  are carried as
current assets or as investments - other assets, depending on their maturities.

The change in unrealized  holding gains (losses),  net of income taxes, as shown
in accumulated other comprehensive income for the years ended December 31, 2003,
2002 and 2001, is as follows:

(Millions of dollars)                                   2003     2002      2001
--------------------------------------------------------------------------------

Beginning balance                                        $ 6      $(1)    $ 139
  Net unrealized holding gains (losses)                    6        7       (22)
  Reclassification of gains included in net income        (7)       -      (118)
                                                         ---      ---     -----
Ending balance                                           $ 5      $ 6     $  (1)
                                                         ===      ===     =====

Trading Securities

As discussed  above, the company has recorded 85% of its Devon shares as trading
securities and marks this investment to market through  income.  At December 31,
2003, the market value of 8.4 million shares of Devon was $483 million,  and $96
million in unrealized  pretax gains was  recognized  during 2003 in other income
(expense) in the Consolidated  Statement of Operations.  However,  this gain was
substantially  offset by an $88 million  unrealized loss on the embedded options
associated  with the DECS. See the  discussion of these  derivatives  below.  At
year-end 2002, the market value of 8.4 million shares of Devon was $387 million,
and $61 million in unrealized  pretax gains were  recognized  during 2002.  This
gain was  partially  offset by a $34  million  unrealized  loss on the  embedded
options associated with the DECS.

Financial Instruments for Other than Trading Purposes

In addition to the financial instruments previously discussed, the company holds
or issues financial instruments for other than trading purposes. At December 31,
2003 and 2002, the carrying amount and estimated fair value of these instruments
for which fair value can be determined are as follows:


                                                                   2003                              2002
                                                         -----------------------          -------------------------
                                                         Carrying           Fair          Carrying             Fair
(Millions of dollars)                                      Amount          Value            Amount            Value
-------------------------------------------------------------------------------------------------------------------
                                                                                                 

Cash and cash equivalents                                  $  142         $  142            $   90           $   90
Long-term receivables                                          95             82                88               73
Contracts to purchase and sell foreign currencies              17             17                 2                2
Debt exchangeable for stock, excluding options                326            330               318              330
Long-term debt, except DECS                                 3,329          3,761             3,586            4,013


The  carrying  amount of cash and cash  equivalents  approximates  fair value of
those  instruments  due to their  short  maturity.  The fair value of  long-term
receivables  is based on  discounted  cash  flows.  The  fair  value of  foreign
currency forward  contracts  represents the aggregate  replacement cost based on
financial  institutions'  quotes. 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.

Derivatives

The company is exposed to market risk from fluctuations in crude oil and natural
gas prices.  To  increase  the  predictability  of its cash flows and to support
capital  projects,   the  company  initiated  a  hedging  program  in  2002  and
periodically enters into financial derivative instruments that generally fix the
commodity  prices to be received for a portion of its oil and gas  production in
the future. At December 31, 2003, the outstanding  commodity-related derivatives
accounted  for as hedges had a liability  fair value of $168  million,  which is
recorded  as  a  current  liability.  At  December  31,  2002,  the  outstanding
commodity-related  derivatives  accounted for as hedges had a net liability fair
value of $83 million,  of which $27 million was recorded as a current  asset and
$110  million  was  recorded  as a current  liability.  The fair  value of these
derivative instruments was determined based on prices actively quoted, generally
NYMEX and Dated Brent  prices.  At December 31, 2003,  the company had after-tax
deferred  losses of $106  million  in  accumulated  other  comprehensive  income
associated  with these  contracts.  The company expects to reclassify the entire
amount of these  losses  into  earnings  during the next 12 months,  assuming no
further changes in fair market value of the contracts.  During 2003, the company
realized a $71 million loss on U.S. oil hedging, a $64 million loss on North Sea
oil hedging and a $144  million loss on U.S.  natural gas hedging.  During 2002,
the company realized a $28 million loss on U.S. oil hedging,  a $50 million loss
on North Sea oil hedging and a $2 million loss on U.S. natural gas hedging.  The
losses  offset the higher oil and  natural gas prices  realized on the  physical
sale of  crude  oil and  natural  gas.  Losses  for  hedge  ineffectiveness  are
recognized as a reduction of revenue in the Consolidated Statement of Operations
and were not material for 2003 or 2002.

In addition to the company's  hedging  program,  Kerr-McGee Rocky Mountain Corp.
holds certain gas basis swaps settling  between 2004 and 2008.  Through December
2003,  the company  treated these gas basis swaps as nonhedge  derivatives,  and
changes in fair value were  recognized  in earnings.  On December 31, 2003,  the
company  designated those swaps settling in 2004 as hedges since the basis swaps
have been  coupled  with  natural gas  fixed-price  swaps,  while the  remainder
settling  between  2005  and 2008  will  continue  to be  treated  as  non-hedge
derivatives.  At December 31, 2003, these derivatives are recorded at their fair
value of $23 million, of which $8 million is recorded as a current asset and $15
million is recorded in investments - other assets.  At December 31, 2002,  these
derivatives  were  recorded at their fair value of $21 million in  investments -
other assets. The net gains associated with these non-hedge  derivatives were $2
million,  $8 million and $27 million in 2003, 2002 and 2001,  respectively,  and
are included in other income in the Consolidated Statement of Operations.

The company's  marketing  subsidiary,  Kerr-McGee  Energy  Services  Corporation
(KMES) markets natural gas (primarily  equity gas) in the Denver area.  Existing
contracts  for the  physical  delivery  of gas at  fixed  prices  have  not been
designated as hedges and are marked to market in  accordance  with FAS 133. KMES
also has  entered  into  natural  gas swaps  and basis  swaps  that  offset  its
fixed-price risk on physical contracts.  These derivative  contracts lock in the
margins  associated  with the  physical  sale.  The company  believes  that risk
associated with these derivatives is minimal due to the  creditworthiness of the
counterparties. The net asset fair value of these derivative instruments was not
material at year-end 2003 or 2002. The fair values of the outstanding derivative
instruments at December 31, 2003, were based on prices actively  quoted.  During
2003,  the net loss  associated  with these  derivative  contracts  totaled  $12
million,  of which $7 million  is  included  as a  reduction  of revenue  and $5
million is included in other income.  For 2002 and 2001, the net loss associated
with  these   derivative   contracts   totaled  $20  million  and  $24  million,
respectively,  and is  included as a  reduction  of revenue in the  Consolidated
Statement  of   Operations.   The  losses  on  the   derivative   contracts  are
substantially  offset by the fixed prices  realized on the physical  sale of the
natural gas.

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 British pound  sterling,  and sales of euro) have been  designated  and have
qualified  as cash flow  hedges of the  company's  anticipated  future cash flow
needs for a portion of its capital  expenditures,  raw  material  purchases  and
operating costs.  These forward contracts  generally have durations of less than
three years. At December 31, 2003, the outstanding  foreign exchange  derivative
contracts  accounted for as hedges had a net asset fair value of $21 million, of
which $28 million was recorded in current  assets and $7 million was recorded in
current  liabilities.  Changes in the fair value of these contracts are recorded
in accumulated other comprehensive  income and will be recognized in earnings in
the periods  during which the hedged  forecasted  transactions  affect  earnings
(i.e.,  when  hedged  assets are  depreciated  in the case of a hedge of capital
expenditures,  when  finished  inventory  is sold in the  case of a  hedged  raw
material purchase and when the forward contracts close in the case of a hedge of
operating  costs).  At  December  31, 2003 and 2002,  the company had  after-tax
deferred gains of $17 million and deferred  losses of $7 million,  respectively,
in accumulated other comprehensive income. In 2003, the company reclassified $11
million of gains on  forward  contracts  from  accumulated  other  comprehensive
income to operating  expenses in the  Consolidated  Statement of Operations.  In
2002 and 2001, the company reclassified $5 million and $9 million, respectively,
of losses on forward  contracts from accumulated other  comprehensive  income to
operating expenses in the Consolidated Statement of Operations.  Of the existing
unrealized  net gains at December  31, 2003,  approximately  $9 million in gains
will be  reclassified  into  earnings  during  the next 12 months,  assuming  no
further  changes in fair value of the  contracts.  No hedges  were  discontinued
during 2003, and no ineffectiveness was recognized.

Selected pigment receivables have been sold in an asset  securitization  program
at their equivalent U.S. dollar value at the date the receivables were sold. The
company  is  collection  agent and  retains  the risk of foreign  currency  rate
changes  between the date of sale and collection of the  receivables.  Under the
terms of the asset securitization agreement restructured in 2003, the company is
required to enter into forward  contracts for the value of the  euro-denominated
receivables  sold into the program to mitigate its foreign  currency risk. Gains
or losses on the forward contracts are recognized currently in earnings.  During
2003,  the  company  recognized  losses  of $7  million  associated  with  these
contracts.

The company has entered into other forward contracts to sell foreign currencies,
which will be  collected  as a result of pigment  sales  denominated  in foreign
currencies,  primarily in European  currencies.  These  contracts  have not been
designated  as hedges even though  they do protect the company  from  changes in
foreign  currency  rates.  The  estimated  fair  value  of these  contracts  was
immaterial at December 31, 2003 and 2002.

The company issued 5 1/2% notes  exchangeable  for common stock (DECS) in August
1999,  which  allow 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  provide the company a
floor price on Devon's  common stock of $33.19 per share (the put  option).  The
company  also has the right to retain up to 15% of the shares if  Devon's  stock
price is greater than $39.16 per share (the DECS  holders have an imbedded  call
option on 85% of the shares). If Devon's stock price at maturity is greater than
$33.19 per share but less than $39.16 per share,  the company's  right to retain
Devon  stock will be reduced  proportionately.  The  company is not  entitled to
retain any Devon  stock if the price of Devon  stock at maturity is less than or
equal to $33.19 per share. Using the Black-Scholes  valuation model, the company
recognizes  any gains or losses  resulting from changes in the fair value of the
put and call options in other  income.  At December  31, 2003 and 2002,  the net
liability  fair value of the  embedded put and call options was $155 million and
$67 million,  respectively.  The company  recorded  losses of $88  million,  $34
million and $205 million  during  2003,  2002 and 2001,  respectively,  in other
income  for the  changes  in the fair  values of the put and call  options.  The
fluctuation in the value of the put and call  derivative  financial  instruments
will  generally  offset the increase or decease in the market value of the Devon
stock classified as trading. The remaining Devon shares, which are classified as
available-for-sale  securities, were partially liquidated in December 2003, with
the   remaining   shares  sold  in  January   2004  as  discussed   above.   The
available-for-sale  Devon  shares  were in  excess of the  number of shares  the
company  believes will be required to extinguish the DECS;  however,  should the
price of the stock fall below $39.16 per share at the maturity of the DECS,  the
company would be required to either purchase  additional  Devon shares to settle
the DECS or settle a portion of the DECS with cash.  The DECS and the derivative
liability  associated  with the call  option  have been  classified  as  current
liabilities in the Consolidated Balance Sheet as of December 31, 2003.

In connection with the issuance of $350 million 5.375% notes due April 15, 2005,
the company  entered into an interest rate swap  arrangement  in April 2002. The
terms of the agreement  effectively  change the interest the company will pay on
the debt until  maturity  from the fixed  rate to a variable  rate of LIBOR plus
..875%.  The company  considers the swap to be a hedge against the change in fair
value of the debt as a result of interest rate changes. The estimated fair value
of the  interest  rate swap was $15 million and $21 million at December 31, 2003
and 2002,  respectively.  Any gain or loss on the swap is offset by a comparable
gain or loss resulting  from recording  changes in the fair value of the related
debt. The critical terms of the swap match the terms of the debt; therefore, the
swap is  considered  highly  effective  and no  hedge  ineffectiveness  has been
recorded. The company recognized an $11 million reduction in interest expense in
2003  and a $6 million reduction  in  interest  expense  in 2002  from  the swap
arrangement.


19.  Acquisition and Merger Reserves

During  2002,  the  company  recorded  an  accrual  of $3  million  representing
additional  severance  and other  acquisition-related  costs related to its 2001
acquisition  of HS Resources.  In 2001,  the company  recorded an accrual of $42
million for items associated with this acquisition,  which included  transaction
costs, severance and other  employee-related  costs, contract termination costs,
and other  acquisition-related  costs. Of the total accrual of $45 million,  $11
million  was paid in 2002 and $34  million  was paid  during  2001,  leaving  no
remaining reserve balance at December 31, 2002.


20.  Business Combination

On  August  1,  2001,  the  company  completed  the  acquisition  of  all of the
outstanding shares of common stock of HS Resources, Inc., an independent oil and
gas   exploration   and   production   company  with  active   projects  in  the
Denver-Julesburg  Basin,  Gulf Coast,  Mid-Continent and Northern Rocky Mountain
regions of the U.S. The acquisition  added  approximately 250 million cubic feet
equivalent of daily gas  production  and 1.3 trillion  cubic feet  equivalent of
proved gas reserves,  primarily in the Denver,  Colorado,  area. The addition of
these  primarily  natural gas  reserves  provided  the  company a more  balanced
portfolio,  geographic  diversity  and  production  mix,  while  also  providing
low-risk exploitation  drilling  opportunities from identified projects based on
HS Resources' seismic  inventory.  The acquisition price totaled $1.8 billion in
cash, company stock and assumption of debt. The company reflected the assets and
liabilities  acquired at fair value in its  balance  sheet  effective  August 1,
2001,  and the company's  results of operations  include HS Resources  beginning
August 1,  2001.  The  purchase  price was  allocated  to  specific  assets  and
liabilities based on their estimated fair value at the date of acquisition.  The
allocations included $348 million recorded as goodwill,  which is not deductible
for income  tax  purposes.  The cash  portion of the  acquisition  totaled  $955
million, including direct expenses, and was ultimately financed through issuance
of long-term debt. A total of 5,057,273  shares of Kerr-McGee  common stock were
issued in connection with the acquisition.  The shares were valued at $70.33 per
share,  the average price two days before and after the purchase was  announced.
Debt totaling $506 million was assumed.

The following  unaudited pro forma  condensed  information  has been prepared to
give  effect  to the HS  Resources  acquisition  as if it  had  occurred  at the
beginning of 2001, including purchase accounting adjustments.

(Millions of dollars, except per-share amounts)                             2001
--------------------------------------------------------------------------------
Revenues                                                                  $3,787
Income from continuing operations                                            490
Net income                                                                   499
Earnings per share-
  Basic                                                                     4.99
  Diluted                                                                   4.73


21.  Discontinued Operations, Asset Impairments and Asset Disposals

During  2002,  the  company  approved a plan to dispose of its  exploration  and
production  operations in Kazakhstan,  its interest in the Bayu-Undan project in
the East Timor Sea  offshore  Australia  and its interest in the Jabung block of
Sumatra,  Indonesia.  These  divestiture  decisions  were  made  as  part of the
company's  strategic plan to  rationalize  noncore oil and gas  properties.  The
results  of these  operations  have been  reported  separately  as  discontinued
operations in the  accompanying  Consolidated  Statement of  Operations  for all
years  presented.  In conjunction  with the  disposals,  the related assets were
evaluated and losses were recorded for the Kazakhstan operations,  calculated as
the difference  between the estimated sales price for the operation,  less costs
to sell, and the operations'  carrying  value.  The losses totaled $6 million in
2003  and  $35  million  in  2002  and are  reported  as  part  of  discontinued
operations.  On March 31, 2003, the company completed the sale of its Kazakhstan
operations  for $169  million.  In 2002,  the company  completed the sale of its
interest in the  Bayu-Undan  project for $132  million in cash,  resulting  in a
pretax gain of $35 million.  The company also  completed the sale of its Sumatra
operations  in 2002 for $171  million  in cash  with an $11  million  contingent
purchase price pending government approval of an LPG project.  The sale resulted
in a pretax gain of $72 million  (excluding the contingent  purchase price). The
net  proceeds  received  by the  company  from  these  sales were used to reduce
outstanding debt.

Revenues  applicable  to the  discontinued  operations  totaled $6 million,  $36
million and $72 million for 2003, 2002 and 2001, respectively. Pretax income for
the  discontinued  operations  totaled  nil  (including  the  loss on sale of $6
million), $104 million (including the gains on sale of $107 million and the loss
on sale of $35  million)  and $52  million  for the years  2003,  2002 and 2001,
respectively.

Impairment  losses on held-for-use  assets totaled $14 million in 2003, and were
primarily  related to oil and gas fields in the U.S.  onshore and Gulf of Mexico
shelf  areas  with  remaining  investments  that were no longer  expected  to be
recovered  through future cash flows.  Pretax  impairment  losses  totaling $652
million were recorded in 2002, of which $646 million  related to the exploration
and  production  operating  unit and $6 million  related to the chemical - other
operating  unit.  For  the  exploration  and  production   operating  unit,  the
impairment  charge  included $541 million for the Leadon field in the U.K. North
Sea, $82 million for certain  other North Sea fields and $23 million for several
older Gulf of Mexico shelf properties.  Negative reserve revisions stemming from
additional  performance  analysis for these  properties  during 2002 resulted in
revised  estimates of future cash flows from the properties  that were less than
the carrying  values of the related  assets.  For the chemical - other operating
unit, the $6 million  impairment  related to the company's  decision to exit the
forest products  business.  In addition,  the chemical - pigment  operating unit
recorded a $12 million  pretax  write-down  of property,  plant and equipment in
2002 related to abandoned chemical engineering  projects,  which is reflected in
depreciation and depletion in the Consolidated Statement of Operations.

During  2003,  the company  selectively  marketed its 100% owned Leadon field to
third parties. Although no divestiture negotiations are currently under way, the
company  continues  to  review  its  options  with  respect  to the  field  and,
particularly,  the associated floating production, storage and offloading (FPSO)
facility.  Management  presently intends to continue operating and producing the
field until such time as the operating cash flow generated by the field does not
support continued production or until a higher value option is identified. Given
the  significant  value  associated  with the FPSO  relative  to the size of the
entire  project,  the company will continue to pursue a long-term  solution that
achieves  maximum  value for Leadon - which may include  disposing of the field,
monetizing  the FPSO by selling  it as a  development  option for a  third-party
discovery, or redeployment in other company operations. As of December 31, 2003,
the carrying  value of the Leadon field assets  totaled $374 million.  Given the
uncertainty  concerning  possible outcomes,  it is reasonably  possible that the
company's  estimate  of future cash flows from the Leadon  field and  associated
fair  value  could  change  in the near term due to,  among  other  things,  (i)
unfavorable  changes in commodity prices or operating  costs,  (ii) a production
profile that  declines  more rapidly than  currently  anticipated,  and/or (iii)
unsuccessful  results of continued  marketing  activities or failure to locate a
strategic buyer (or suitable redeployment opportunity).  Accordingly, management
anticipates that the Leadon field will be subject to periodic  impairment review
until such time as the field is abandoned or sold.  If future cash flows or fair
value decrease from that presently  estimated,  an additional  write-down of the
Leadon field could occur in the future.

Impairment losses in 2001 were comprised of a $47 million write-down  associated
with the  shut-down  of the North Sea Hutton  field and $29  million for certain
chemical  facilities in Belgium and the U.S. In 2001, the company's  exploration
and production  operating unit suspended production from the Hutton field in the
North Sea due to concerns about the amount of corrosion present in the pipeline,
which would have ultimately required  replacement of the pipeline for production
to resume. Due to the small amount of remaining field reserves,  the company, as
operator,  and the other partners entered into a plan to decommission the field,
which was completed during 2003.

At the end of 2001,  the  company's  chemical - pigment  operating  unit  ceased
production at its titanium dioxide pigment plant in Antwerp, Belgium, as part of
its strategy to improve efficiencies and enhance margins by rationalizing assets
within the  chemical  unit.  A $14 million  impairment  loss was  recognized  in
connection with the Antwerp shutdown. Also during 2001, the company's chemical -
other operating unit ceased  production at its manganese metal  production plant
in Hamilton,  Mississippi,  due to low-priced  imports and softening prices that
made the  product  no  longer  profitable.  A $13  million  impairment  loss was
recognized in connection with the Hamilton shutdown.  Additionally,  the loss of
its only major customer led to a $2 million  impairment  charge for the shutdown
of a wood-preserving plant in Indianapolis, Indiana.

In connection with the company's  divestiture program initiated in 2002, certain
oil  and  gas  properties   were  identified  for  disposal  and  classified  as
held-for-sale  properties.  Upon  classification as held-for-sale,  the carrying
value of the related  properties is analyzed in relation to the  estimated  fair
value less costs to sell, and losses are recognized if necessary.  Upon ultimate
disposal of the  properties,  any gain or additional loss on sale is recognized.
Losses of $23  million  and gains of $68 million  were  recognized  in 2003 upon
conclusion  of the  divestiture  program in the U.S.  and North Sea, and for the
sale of the company's  interest in the South China Sea (Liuhua  field) and other
noncore U.S.  properties  (onshore and Gulf of Mexico shelf areas).  The company
recognized losses of $176 million in 2002 associated with oil and gas properties
held for sale in the U.S.  (onshore  and Gulf of Mexico shelf  areas),  the U.K.
North Sea and  Ecuador.  Proceeds  realized  from these  disposals  totaled $119
million in 2003 and $374 million in 2002.  The  proceeds  from the sale of these
properties have been used to reduce long-term debt.

The  chemical  -  pigment   operating  unit  began  production   through  a  new
high-productivity  oxidation  line at the Savannah,  Georgia,  chloride  process
pigment  plant  in  January  2004.  This new  technology  results  in  low-cost,
incremental   capacity  increases  through  modification  of  existing  chloride
oxidation  lines  and  allows  for  improved  operating   efficiencies   through
simplification of hardware configurations and reduced maintenance  requirements.
Based on the future outcome of these technological advancements, the company may
need to review its existing  configuration at the Savannah plant to optimize the
plant's  resources  in  relation  to capacity  requirements.  The  company  will
evaluate  the  performance  of  the  new  high-productivity  line,  analyze  the
implications   on  the  capacity  of  existing   assets  and  have  a  plan  for
reconfiguration,   if  any,   by  the   latter   part  of   2004.   If  the  new
high-productivity  line  performs  as  expected,  the outcome of this review may
result in the  deployment of certain assets to alternate uses and/or the need to
idle certain other assets. If this occurs, the future useful life of such assets
may be adjusted, resulting in the acceleration of depreciation expense.

The assets and liabilities of discontinued  operations and other assets held for
sale have been  reclassified  as  Assets/Liabilities  Associated with Properties
Held for Disposal in the Consolidated  Balance Sheet.  The company  recognized a
net gain on disposal of property,  excluding discontinued  operations and assets
held for sale,  of $1  million in 2003,  $1  million in 2002 and $12  million in
2001,  which is  reflected  in Other  Income in the  Consolidated  Statement  of
Operations.


22.  Common Stock

Changes in common stock issued and treasury  stock held for 2003,  2002 and 2001
are as follows:

                                                               Common   Treasury
(Thousands of shares)                                           Stock      Stock
--------------------------------------------------------------------------------

Balance December 31, 2000                                     101,417     6,933
  Exercise of stock options and stock appreciation rights         533         -
  Cancellation of outstanding shares of Kerr-McGee
    Operating Corporation (formerly Kerr-McGee
    Corporation)                                              (95,118)        -
  Issuance of stock by Kerr-McGee Corporation
    (new holding company)                                      95,118         -
  Shares issued to purchase HS Resources                        5,057         -
  Cancellation of treasury stock                               (6,838)   (6,838)
  Issuance of restricted stock                                     16      (102)
  Forfeiture of restricted stock                                    -         8
  Issuance of shares for achievement awards                         1         -
                                                              -------    ------
Balance December 31, 2001                                     100,186         1
  Exercise of stock options                                       112         -
  Issuance of restricted stock                                     94        (5)
  Forfeiture of restricted stock                                   (2)       11
  Issuance of shares for achievement awards                         1         -
                                                              -------    ------
Balance December 31, 2002                                     100,391         7
  Exercise of stock options                                        18         -
  Issuance of restricted stock                                    483         -
  Forfeiture of restricted stock                                    -        25
                                                              -------    ------
Balance December 31, 2003                                     100,892        32
                                                              =======    ======


The  company  has 40  million  shares  of  preferred  stock  without  par  value
authorized, and none is issued.

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.

Under the 2002 Long-Term  Incentive Plan (Plan), the company may grant incentive
opportunities to key employees.  The Plan includes  provisions for stock,  stock
options and performance-related  awards. A maximum of 7,000,000 shares of common
stock was  authorized  for  issuance  under the Plan in  connection  with  stock
options, stock appreciation rights,  restricted stock and performance awards. Of
the total 7,000,000  shares,  a maximum of 1,750,000  shares of common stock are
authorized for issuance  under the Plan in connection  with awards of restricted
stock and  performance  awards.  Restricted  stock is awarded in the name of the
employee and, except for the right of disposal,  holders have full shareholders'
rights during the period of restriction,  including  voting rights and the right
to  receive  dividends.  Under the Plan,  certain  key  employees  in Europe and
Australia have received stock opportunity  grants giving them the opportunity to
earn unrestricted  stock in the future provided that certain conditions are met.
These stock opportunity grants do not carry voting privileges or dividend rights
since the related shares are not issued until vested. Restricted stock and stock
opportunity  grants  generally  vest between three and five years.  Compensation
expense is recognized  over the vesting  period and was $10 million,  $6 million
and $4  million  in 2003,  2002 and  2001,  respectively.  The  company  granted
483,000,  99,000 and 118,000 shares of restricted common stock in 2003, 2002 and
2001,  respectively,  for which the  weighted  average fair value at the date of
grant was $20  million,  $4 million  and $7 million,  respectively.  The company
granted 9,000 stock  opportunity  shares in 2003 for which the weighted  average
fair value at the date of grant was $.4 million. There were no stock opportunity
grants issued in 2002 or 2001.

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.


23.  Employee Stock Option Plans

The 2002 Long-Term  Incentive Plan (2002 Plan) authorizes the issuance of shares
of the  company's  common stock any time prior to May 13,  2012,  in the form of
stock  options,  restricted  stock or  performance  awards.  The  options may be
accompanied by stock  appreciation  rights.  A total of 7,000,000  shares of the
company's common stock is authorized to be issued under the 2002 Plan.

In January 1998, the Board of Directors approved a broad-based stock option plan
(BSOP) that  provides  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 is  authorized to be issued under the
BSOP.

The  1987  Long-Term  Incentive  Program  (1987  Program),  the  1998  Long-Term
Incentive  Plan (1998 Plan) and the 2000  Long-Term  Incentive  Plan (2000 Plan)
authorized  the issuance of shares of the  company's  stock in the form of stock
options,  restricted stock or long-term performance awards. The 1987 Program was
terminated  when the  stockholders  approved  the 1998  Plan,  the 1998 Plan was
terminated  with the approval of the 2000 Plan, and the 2000 Plan was terminated
with the approval of the 2002 Plan.  No options  could be granted under the 1987
Program, the 1998 Plan or the 2000 Plan after each plan's respective termination
date,   although  options  and  any  accompanying  stock   appreciation   rights
outstanding may be exercised prior to their expiration dates.

The company's employee stock options are fixed-price options granted at the fair
market value of the underlying common stock on the date of the grant. Generally,
one-third of each grant vests and becomes  exercisable over a three-year  period
immediately following the grant date and expires 10 years after the grant date.

The following table summarizes the stock option transactions under the plans
described above.


                                                       2003                     2002                     2001
                                             ----------------------    ---------------------    ---------------------
                                                          Weighted-                Weighted-                Weighted-
                                                            Average                  Average                  Average
                                                           Exercise                 Exercise                 Exercise
                                                          Price per                Price per                Price per
                                               Options       Option      Options      Option       Options     Option
---------------------------------------------------------------------------------------------------------------------
                                                                                             
Outstanding, beginning of year               5,406,424       $59.27    3,433,745      $61.18    3,036,605      $59.66
  Options granted                            1,353,100        42.93    2,544,562       57.08    1,024,530       65.19
  Options exercised                            (18,500)       44.55     (111,411)      46.78     (532,260)      59.55
  Options surrendered upon exercise
     of stock appreciation rights                    -           -             -           -       (1,900)      42.63
  Options forfeited                           (189,638)       55.35     (141,116)      58.42      (62,539)      62.78
  Options expired                             (132,667)       57.78     (319,356)      67.09      (30,691)      63.74
                                             ---------                 ---------                ---------
Outstanding, end of year                     6,418,719        56.02    5,406,424       59.27    3,433,745       61.18
                                             =========                 =========                =========
Exercisable, end of year                     3,382,550        59.81    2,179,960       59.60    1,935,880       59.32
                                             =========                 =========                =========


The following table summarizes  information about stock options issued under the
plans described above that are outstanding and exercisable at December 31, 2003:


                              Options Outstanding                                       Options Exercisable
   --------------------------------------------------------------------           ------------------------------
                                          Weighted-           Weighted-                                Weighted-
                                            Average             Average                                  Average
                Range of Exercise         Remaining            Exercise                                 Exercise
                       Prices per       Contractual           Price per                                Price per
  Options                  Option      Life (years)             Option              Options               Option
----------------------------------------------------------------------------------------------------------------
                                                                                           
    9,457         $30.00 - $39.99               1.5              $34.19               9,457               $34.19
1,587,178          40.00 -  49.99               7.9               42.88             278,603                42.63
1,950,998          50.00 -  59.99               6.4               55.10           1,105,917                55.82
2,751,442          60.00 -  69.99               6.5               63.57           1,868,929                63.98
  119,644          70.00 -  79.99               2.2               73.41             119,644                73.41
---------                                                                         ---------
6,418,719          30.00 -  79.99               6.7               56.02           3,382,550                59.81
----------------------------------------------------------------------------------------------------------------



24.  Employee Benefit Plans

The company has both noncontributory and contributory defined-benefit retirement
plans and  company-sponsored  contributory  postretirement plans for health care
and life  insurance.  Most employees are covered under the company's  retirement
plans,  and  substantially  all  U.S.  employees  may  become  eligible  for the
postretirement  benefits  if they reach  retirement  age while  working  for the
company.  Kerr-McGee uses a December 31 measurement date for its plans. In 2003,
the  company   recognized  a  curtailment  loss  with  respect  to  pension  and
postretirement  benefits in connection with its work-force reduction program and
other plant closures and recognized special termination benefits associated with
its  work-force  reduction  program.  These  losses have been  reflected  in the
disclosures below.

In  December  2003,  the  FASB  issued  FAS  132  (revised  2003),   "Employers'
Disclosures  about Pensions and Other  Postretirement  Benefits," (FAS 132). FAS
132 does not change the  measurement  or  recognition  of those plans;  however,
certain additional disclosures are required by the new standard and are included
herein.  Additional  disclosures for the company's foreign plans will be delayed
for one year as permitted by the new standard.

Following are the changes in the benefit obligations during the past two years:


                                                                                                 Postretirement
                                                             Retirement Plans                Health and Life Plans
                                                          -----------------------            ---------------------
(Millions of dollars)                                       2003             2002            2003            2002
------------------------------------------------------------------------------------------------------------------
                                                                                     
Benefit obligation, beginning of year                     $1,147           $1,075            $327             $271
    Service cost                                              25               24               3                3
    Interest cost                                             74               76              17               19
    Plan amendments                                           (3)               -              10                -
    Net actuarial loss (gain)                                 84               60             (28)              53
    Foreign exchange rate changes                             17               12               -                -
    Contributions by plan participants                         -                -               9                6
    Special termination benefits and
        curtailment losses                                    28                -               9                -
    Benefits paid                                           (122)            (100)            (33)             (25)
                                                          ------           ------            ----             ----

Benefit obligation, end of year                           $1,250           $1,147            $314             $327
                                                          ======           ======            ====             ====


The benefit  amount  that can be covered by the  retirement  plans that  qualify
under the Employee  Retirement Income Security Act of 1974 (ERISA) is limited by
both ERISA and the Internal  Revenue Code.  Therefore,  the company has unfunded
supplemental  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.  The projected benefit
obligation and  accumulated  benefit  obligation for the U.S and certain foreign
unfunded retirement plans, excluding the under-funded U.K. plan discussed below,
were $60 million and $51 million,  respectively,  at December 31, 2003,  and $58
million and $47  million,  respectively,  at December  31,  2002.  Although  not
considered plan assets,  a grantor trust was established from which payments for
certain of these U.S.  supplemental  plans are made.  The trust had a balance of
$37 million at year-end 2003 and at year-end 2002. The postretirement  plans are
also unfunded. In addition, the company has an under-funded foreign pension plan
covering  employees in the United Kingdom.  The projected benefit obligation and
accumulated  benefit  obligation for that plan at year-end 2003 were $75 million
and  $63  million,   respectively,   and  were  $50  million  and  $45  million,
respectively,  at year-end  2002.  The market  value of plan assets for the U.K.
plan was $44 million at December 31, 2003,  resulting in an under-funded  status
for the plan of $31 million.

Following  are the changes in the fair value of plan assets  during the past two
years  and  the  reconciliation  of the  plans'  funded  status  to the  amounts
recognized in the financial statements at December 31, 2003 and 2002:


                                                                                                 Postretirement
                                                            Retirement Plans                 Health and Life Plans
                                                       -------------------------            -----------------------
(Millions of dollars)                                     2003              2002             2003              2002
-------------------------------------------------------------------------------------------------------------------
                                                                                                  
Fair value of plan assets, beginning of year           $ 1,190           $ 1,364            $   -             $   -
   Actual return on plan assets                            198               (90)               -                 -
   Employer contributions (1)                                5                 6               24                18
   Participant contributions                                 -                 -                9                 7
   Foreign exchange rate changes                            12                10                -                 -
   Benefits paid                                          (122)             (100)             (33)              (25)
                                                       -------           -------            -----             -----

Fair value of plan assets, end of year (2)               1,283             1,190                -                 -
Benefit obligation                                      (1,250)           (1,147)            (314)             (327)
                                                       -------           -------            -----             -----
Funded status of plans - over (under)                       33                43             (314)             (327)
    Amounts not recognized in the
        Consolidated Balance Sheet -
           Prior service costs                              58                79               12                 3
           Net actuarial loss                              106                83               68                96
                                                       -------           -------            -----             -----
Prepaid expense (accrued liability)                    $   197           $   205            $(234)            $(228)
                                                       =======           =======            =====             =====

Accumulated benefit obligation                         $(1,147)          $(1,046)
                                                       =======           =======


(1)  No  contributions  are expected in 2004 for the U.S.  qualified  retirement
     plan.  Kerr-McGee  Corporation expects to contribute $2 million to its U.S.
     nonqualified retirement plans in 2004.

(2)  The fair value of plan assets for the U.S.  qualified  retirement  plan was
     $1.188 billion at December 31, 2003.

Following is the  classification  of the amounts  recognized in the Consolidated
Balance Sheet at December 31, 2003 and 2002:


                                                                                                Postretirement
                                                            Retirement Plans                 Health and Life Plans
                                                          ----------------------            -----------------------
(Millions of dollars)                                     2003              2002             2003              2002
-------------------------------------------------------------------------------------------------------------------
                                                                                                  
Prepaid benefits expense                                  $230              $240            $   -             $   -
Accrued benefit liability                                  (72)              (62)            (234)             (228)
Additional minimum liability -
   intangible asset                                          1                 1                -                 -
Accumulated other comprehensive
   income (before tax)                                      38                26                -                 -
                                                          ----              ----            -----             -----
      Total                                               $197              $205            $(234)            $(228)
                                                          ====              ====            =====             =====


For 2003,  2002 and 2001,  the company had after-tax  losses of $7 million,  $14
million and $2 million,  respectively,  included in other  comprehensive  income
resulting from changes in the additional minimum pension liability.

Total costs recognized for employee retirement and postretirement  benefit plans
for each of the years ended December 31, 2003, 2002 and 2001, were as follows:


                                                                                            Postretirement
                                                   Retirement Plans                      Health and Life Plans
                                            -------------------------------         -------------------------------
(Millions of dollars)                        2003         2002         2001         2003         2002          2001
-------------------------------------------------------------------------------------------------------------------
                                                                                       

Net periodic cost -
   Service cost                             $  25        $  24        $  22          $ 3          $ 3           $ 2
   Interest cost                               73           76           73           17           19            17
   Expected return on plan assets            (122)        (130)        (124)           -            -             -
   Special termination benefits,
     curtailment loss                          38            -            -           10            -             -
   Net amortization -
     Transition asset                           -            -           (1)           -            -             -
     Prior service cost                         9           10            9            -            1             1
     Net actuarial (gain) loss                 (9)         (16)         (23)           -            1             -
                                            -----        -----        -----          ---          ---           ---
         Total                              $  14        $ (36)       $ (44)         $30          $24           $20
                                            =====        =====        =====          ===          ===           ===


The following assumptions were used in estimating the net periodic expense:


                                           2003                           2002                               2001
                                --------------------------       ---------------------------       -----------------------
                                United                           United                            United
                                States       International       States        International       States    International
--------------------------------------------------------------------------------------------------------------------------
                                                                                               
Discount rate                     6.75%         5.5 - 5.75%        7.25%                5.75%        7.75%       5.5 - 6.5%

Expected return on                 8.5         5.25 - 7.25          9.0           5.75 - 7.0          9.0              7.0
   plan assets

Rate of compensation               4.5           2.5 - 6.5          5.0            2.5 - 7.5          5.0        3.0 - 5.0
  increases



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


                                            2003                            2002                            2001
                               ---------------------------       ---------------------------      ------------------------
                                United                           United                            United
                                States       International       States        International       States    International
--------------------------------------------------------------------------------------------------------------------------
                                                                              
Discount rate                     6.25%         5.25 - 5.5%        6.75%          5.5 - 5.75%        7.25%            5.75%

Rate of compensation               4.5          2.75 - 5.0          4.5            2.5 - 6.5          5.0        2.5 - 7.5
  increases


The  health  care  cost  trend  rates  used  to  determine   the  year-end  2003
postretirement benefit obligation were 10% in 2004, gradually declining to 5% in
the year 2009 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, 2003,  by $15 million and increase the  aggregate of
the service and interest cost components of net periodic  postretirement expense
for 2003 by $1  million.  A 1%  decrease  in the trend rate for each future year
would reduce the benefit obligation at year-end 2003 by $15 million and decrease
the  aggregate of the service and interest  cost  components of the net periodic
postretirement expense for 2003 by $1 million.

Asset  categories for the company's U.S.  funded  retirement plan (the Plan) and
the  weighted-average  asset allocations at December 31, 2003 and 2002, by asset
category are as follows:

                                                                Plan Assets
                                                              at December 31,
                                                       -------------------------
                                                          2003              2002
--------------------------------------------------------------------------------
Equity securities                                           55%              42%
Debt securities                                             41%              56%
Cash                                                         4%               2%
                                                           ----             ----
  Total                                                    100%             100%
                                                           ====             ====

The Plan is administered  by a board  appointed  committee that maintains a well
developed  investment  policy  stating the guidelines  for the  performance  and
allocation of plan assets,  performance review  procedures,  and updating of the
policy  itself.  The committee  adheres to  traditional  capital  market pricing
theory, recognizing that over the long term the risk of owning equity securities
is generally  rewarded with a greater return than  available  from  fixed-income
investments.  However, the committee also recognizes that the avoidance of large
risks is desirable and may forego certain higher return  opportunities  in order
to preserve a lower-risk investment profile. At least annually, the 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  at its  discretion;  however,
throughout  2002 and 2003,  the committee has maintained an allocation of assets
in the range of  40-60%  equity  securities  and  40-60%  debt  securities.  The
long-term  return  forecasting  methodology  for both  equity  and  fixed-income
securities  is based on a capital asset  pricing  model using  historical  data.
Based on the asset allocation at the end of 2003, the expected long-term rate of
return of plan assets is forecasted to be 8.5%.

Substantially  all of the plan's  assets are invested  with eight select  equity
fund managers and six  fixed-income  fund  managers.  At year-end 2003 and 2002,
equity  securities held by the plan included $2 million of Kerr-McGee  stock, or
50,737  shares.  Dividends  paid on these shares were less than $100,000 in 2003
and 2002. To control risk, equity fund managers are prohibited from investing in
commodities,  including all futures  contracts,  purchasing letter stock,  short
selling, option trading, margin and Kerr-McGee securities,  but are 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 foreign debt  securities,  direct real estate
mortgages or  commingled  real estate  funds,  private  placements,  purchase of
guaranteed investment contracts, and Kerr-McGee securities, but are permitted to
invest  in debt  securities  issued  by the U.S.  government,  its  agencies  or
instrumentalities, corporate bonds, debentures and other forms of corporate debt
obligations,  commercial  paper rated A1/P1,  certificates of deposit or bankers
acceptances  in amounts of $100,000 or less of U.S.  banks  insured by the FDIC,
and financial futures contracts on U.S. Treasury obligations and options on such
contracts  where these  investments  are for the sole  purpose of hedging.  Some
exceptions to the plan's investment restrictions are granted to equity and fixed
income mutual funds. As long as a mutual fund remains in compliance with its own
prospectus  with  regard  to  investment  restrictions  it  is  deemed  to be in
compliance with plan policy.  All securities  held in fixed-income  fund manager
accounts  must be rated  no less  than  Baa3 or its  equivalent  and  each  fund
manager's portfolio should have an average credit rating that is A or better.

On  December  8,  2003,  the  Medicare   Prescription   Drug,   Improvement  and
Modernization  Act of 2003 ("the  Act") was signed  into law.  The Act  expanded
Medicare  to include,  for the first  time,  coverage  for  prescription  drugs.
Kerr-McGee  expects  that  this  legislation  will  eventually  reduce  the cost
associated  with  its  retiree  medical  programs.   However,   at  this  point,
Kerr-McGee's  investigation  into its options in response to the  legislation is
preliminary  and guidance  from various  governmental  and  regulatory  agencies
concerning the requirements that must be met to obtain these cost reductions, as
well as the manner in which such savings  should be  measured,  has not yet been
issued.

Because of  various  uncertainties  surrounding  Kerr-McGee's  response  to this
legislation  and the  appropriate  accounting  methodology  for this event,  the
company  has  elected  to defer  financial  recognition  of the  impact  of this
legislation until the FASB issues final accounting  guidance.  When issued,  the
final  guidance  could  require  the  company  to  change  previously   reported
information.  This  one-time  deferral  election is  permitted  under FASB Staff
Position No.  106-1,  "Accounting  and  Disclosure  Requirements  Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003."


25.  Employee Stock Ownership Plan

In 1989, the company's  Board of Directors  approved a leveraged  Employee Stock
Ownership Plan (ESOP) into which is paid the company's matching contribution for
the employees'  contributions to the Kerr-McGee  Corporation  Savings Investment
Plan (SIP). The ESOP was amended in 2001 to provide matching  contributions  for
the employees'  contributions made to the Kerr-McGee  Pigments  (Savannah) Inc.,
Employees' Savings Plan, a savings plan for the bargaining-unit employees at the
company's  Savannah,  Georgia,  pigment  plant  (Savannah  Plan).  Most  of  the
company's  employees are eligible to participate in both the ESOP and the SIP or
Savannah  Plan.  Although the ESOP,  SIP and Savannah  Plan are separate  plans,
matching   contributions   to  the  ESOP  are  contingent   upon   participants'
contributions  to the SIP or Savannah  Plan.  Additionally,  HS Resources  had a
savings  plan at the time of  acquisition,  which  had only  discretionary  cash
contributions  by the  employer.  Kerr-McGee  paid $1 million  into this plan in
December 2001.  Beginning January 1, 2002, the remaining HS Resources  employees
became eligible to participate in the Kerr-McGee ESOP and SIP.

In  1989,  the  ESOP  trust  borrowed  $125  million  from a  group  of  lending
institutions  and used the  proceeds to  purchase  approximately  three  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  are
guaranteed by the company and are reflected in the Consolidated Balance Sheet as
Long-Term Debt (see Note 9).

The Oryx  Capital  Accumulation  Plan  (CAP)  was a  combined  stock  bonus  and
leveraged  employee stock  ownership plan  available to  substantially  all U.S.
employees of the former Oryx  operations.  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.  This  loan  was  sponsor  financing  and  does  not  appear  in the
accompanying  balance sheet. The remaining  balance of the sponsor  financing is
$33 million at year-end 2003.  During 1999, the company merged the Oryx CAP into
the ESOP and SIP.

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  contribution and
dividends  on the shares held by the ESOP trust are used to repay the loan,  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 SIP.
Long-term  debt is reduced as payments  are made on the  third-party  financing.
Dividends paid on the common stock held in participants'  accounts are also used
to repay  the  loans,  and  stock  with a market  value  equal to the  amount of
dividends is allocated to participants' accounts.

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

(Thousands of shares)                                     2003              2002
--------------------------------------------------------------------------------

Participants' accounts                                   1,496             1,448
Loan suspense account                                      315               630

The  shares  in the  loan  suspense  account  at  December  31,  2003,  included
approximately  5,000  released  shares  that  were  allocated  to  participants'
accounts in January 2004. At December 31, 2002,  the shares in the loan suspense
account  included  approximately  6,000  released  shares that were allocated to
participants' accounts in January 2003.

All  ESOP  shares  are   considered   outstanding   for  net  income   per-share
calculations. Dividends on ESOP shares are charged to retained earnings.

Compensation  expense  related to the plan was $33 million,  $19 million and $12
million in 2003, 2002 and 2001,  respectively.  These amounts  include  interest
expense  incurred on the third-party ESOP debt, which was not material for 2003,
2002 or 2001. The company  contributed $42 million,  $27 million and $22 million
to the ESOP in 2003,  2002 and 2001,  respectively.  Included in the  respective
contributions  were $37 million,  $19 million and $12 million for  principal and
interest payments on the sponsor  financings.  The cash contributions are net of
$4  million,  $5 million and $4 million  for the  dividends  paid on the company
stock held by the ESOP trust in 2003, 2002 and 2001, respectively.


26.  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 for the years ended December 31, 2003, 2002 and 2001.


                                           2003                              2002                             2001
                               ----------------------------      ----------------------------    ------------------------------
(Millions of dollars,              Income                              Loss                          Income
except                               from              Per-            from              Per-          from                Per-
per-share amounts and          Continuing             share      Continuing             share    Continuing               share
thousands of shares)           Operations   Shares   Income      Operations    Shares    Loss    Operations     Shares   Income
-------------------------------------------------------------------------------------------------------------------------------
                                                                                               
Basic earnings per share             $254  100,145    $2.52           $(611)  100,330  $(6.09)         $476     97,106    $4.91
  Effect of dilutive securities:
    5-1/4% convertible
      debentures                       21    9,824                        -         -                    22      9,824
    Restricted stock                    -      697                        -         -                     -          -
    Employee stock options              -       17                        -         -                     -        181
                                     ----  -------    -----           -----   -------  ------          ----    -------    -----
Diluted earnings per share           $275  110,683    $2.48           $(611)  100,330  $(6.09)         $498    107,111    $4.65
                                     ====  =======    =====           =====   =======  ======          ====    =======    =====


Not included in the  calculation  of the  denominator  for diluted  earnings per
share were 4,866,144, 4,688,853 and 2,219,858 employee stock options outstanding
at year-end 2003,  2002 and 2001,  respectively.  The inclusion of these options
would  have been  antidilutive  since they were not "in the money" at the end of
the  respective  years.  Since  the  company  incurred  a loss  from  continuing
operations  for 2002,  no dilution  of the loss per share  would  result from an
additional  330,003  stock  options that were "in the money" at year-end 2002 or
the assumed conversion of the convertible debentures, discussed below.

The company has  reserved  9,823,778  shares of common stock for issuance to the
owners  of its  5-1/4%  Convertible  Subordinated  Debentures  due  2010.  These
debentures are convertible  into the company's common stock at any time prior to
maturity at $61.08 per share of common stock.


27.  Condensed Consolidating Financial Information

In connection  with the  acquisition of HS Resources in 2001, a holding  company
structure was implemented.  The company formed a new holding company, Kerr-McGee
Holdco,  which  then  changed  its name to  Kerr-McGee  Corporation.  The former
Kerr-McGee  Corporation's name was changed to Kerr-McGee Operating  Corporation.
At the end of 2002,  another  reorganization  took  place  whereby  among  other
changes,  Kerr-McGee Operating Corporation distributed its investment in certain
subsidiaries  (primarily  the  oil and gas  operating  subsidiaries)  to a newly
formed  intermediate   holding  company,   Kerr-McGee   Worldwide   Corporation.
Kerr-McGee  Operating  Corporation formed a new subsidiary,  Kerr-McGee Chemical
Worldwide LLC, and merged into it.

On October 3, 2001,  Kerr-McGee  Corporation  issued $1.5  billion of  long-term
notes in a public offering. The notes are general,  unsecured obligations of the
company  and  rank in  parity  with all of the  company's  other  unsecured  and
unsubordinated   indebtedness.   Kerr-McGee  Chemical  Worldwide  LLC  (formerly
Kerr-McGee Operating  Corporation,  which was previously the original Kerr-McGee
Corporation)  and Kerr-McGee  Rocky  Mountain  Corporation  have  guaranteed the
notes.  Additionally  Kerr-McGee  Corporation has guaranteed all indebtedness of
its  subsidiaries,  including  the  indebtedness  assumed in the  purchase of HS
Resources. As a result of these guarantee arrangements,  the company is required
to  present  condensed  consolidating  financial  information.  The top  holding
company is Kerr-McGee Corporation. The guarantor subsidiaries include Kerr-McGee
Chemical Worldwide LLC in 2003 and 2002, its predecessor,  Kerr-McGee  Operating
Corporation in 2001, along with Kerr-McGee  Rocky Mountain  Corporation in 2003,
2002 and 2001.

The following tables present condensed  consolidating  financial information for
(a) Kerr-McGee Corporation,  the parent company, (b) the guarantor subsidiaries,
and (c) the non-guarantor subsidiaries on a consolidated basis.



Condensed  Consolidating Statement of Operations for the Year Ended December 31, 2003
----------------------------------------------------------------------------------------------------------------------
                                             Kerr-McGee      Guarantor   Non-Guarantor
(Millions of dollars)                       Corporation   Subsidiaries    Subsidiaries    Eliminations    Consolidated
----------------------------------------------------------------------------------------------------------------------
                                                                                                 
Revenues                                          $   -           $694          $3,491           $   -          $4,185
                                                  -----           ----          ------           -----          ------
Costs and Expenses
  Costs and operating expenses                        -            351           1,319              (2)          1,668
  Selling, general and administrative
    expenses                                          -             14             357               -             371
  Shipping and handling expenses                      -              9             131               -             140
  Depreciation and depletion                          -            122             623               -             745
  Accretion expense                                   -              2              23               -              25
  Impairments on assets held for use                  -              -              14               -              14
  Loss (gain) associated with assets
    held for sale                                     -              1             (46)              -             (45)
  Exploration, including dry holes and
    amortization of undeveloped leases                -             15             339               -             354
  Taxes, other than income taxes                      -             25              73               -              98
  Provision for environmental remediation
    and restoration, net of reimbursements            -             31              31               -              62
  Interest and debt expense                         116             36             277            (178)            251
                                                  -----           ----          ------           -----          ------
        Total Costs and Expenses                    116            606           3,141            (180)          3,683
                                                  -----           ----          ------           -----          ------
                                                   (116)            88             350             180             502
Other Income (Expense)                              506             (9)             65            (621)            (59)
                                                  -----           ----          ------           -----          ------
Income from Continuing Operations
  before Income Taxes                               390             79             415            (441)            443
Benefit (Provision) for Income Taxes               (189)            23            (171)            148            (189)
                                                  -----           ----          ------           -----          ------
Income from Continuing Operations                   201            102             244            (293)            254
Income (Loss) from Discontinued Operations,
  net of taxes                                        -             12             (10)             (2)              -
Cumulative Effect of Change in Accounting
  Principle, net of taxes                             -             (1)            (34)              -             (35)
                                                  -----           ----          ------           -----          ------
Net Income                                        $ 201           $113          $  200           $(295)         $  219
                                                  =====           ====          ======           =====          ======





Condensed  Consolidating Statement of Operations for the Year Ended December 31, 2002
----------------------------------------------------------------------------------------------------------------------
                                             Kerr-McGee      Guarantor   Non-Guarantor
(Millions of dollars)                       Corporation   Subsidiaries    Subsidiaries    Eliminations    Consolidated
----------------------------------------------------------------------------------------------------------------------
                                                                                                 
Revenues                                          $   -           $351          $3,554           $(259)         $3,646
                                                  -----           ----          ------           -----          ------
Costs and Expenses
  Costs and operating expenses                        -            105           1,611            (260)          1,456
  Selling, general and administrative
    expenses                                          -              4             309               -             313
  Shipping and handling expenses                      -              9             116               -             125
  Depreciation and depletion                          -            121             693               -             814
  Impairments on assets held for use                  -              3             649               -             652
  Loss (gain) associated with assets
    held for sale                                     -              -             176               -             176
  Exploration, including dry holes and
    amortization of undeveloped leases                -             12             261               -             273
  Taxes, other than income taxes                      -             16              88               -             104
  Provision for environmental remediation
    and restoration, net of reimbursements            -              -              80               -              80
  Interest and debt expense                         115             36             323            (199)            275
                                                  -----           ----          ------           -----          ------
         Total Costs and Expenses                   115            306           4,306            (459)          4,268
                                                  -----           ----          ------           -----          ------
                                                   (115)            45            (752)            200            (622)
Other Income (Expense)                             (438)           484            (127)             46             (35)
                                                  -----           ----          ------           -----          ------
Income (Loss) from Continuing Operations
  before Income Taxes                              (553)           529            (879)            246            (657)
Benefit (Provision) for Income Taxes                 68            (26)             44             (40)             46
                                                  -----           ----          ------           -----          ------
Income (Loss) from Continuing Operations           (485)           503            (835)            206            (611)
Income from Discontinued Operations,
  net of taxes                                        -              -             126               -             126
                                                  -----           ----          ------           -----          ------
Net Income (Loss)                                 $(485)          $503          $ (709)          $ 206          $ (485)
                                                  =====           ====          ======           =====          ======



Condensed Consolidating Statement of Operations for the Year Ended December 31, 2001
----------------------------------------------------------------------------------------------------------------------
                                             Kerr-McGee      Guarantor   Non-Guarantor
 (Millions of dollars)                      Corporation   Subsidiaries    Subsidiaries    Eliminations    Consolidated
----------------------------------------------------------------------------------------------------------------------
                                                                                                 
Revenues                                          $   -         $  122          $3,790         $  (357)         $3,555
                                                  -----         ------          ------         -------          ------
Costs and Expenses
  Costs and operating expenses                        -             47           1,574            (357)          1,264
  Selling, general and administrative
    expenses                                          -             69             159               -             228
  Shipping and handling expenses                      -              2             109               -             111
  Depreciation and depletion                          -             57             690               -             747
  Impairments on assets held for use                  -              -              76               -              76
  Exploration, including dry holes and
    amortization of undeveloped leases                -             15             195               -             210
  Taxes, other than income taxes                      -             13             101               -             114
  Provision for environmental remediation
    and restoration, net of reimbursements            -             82               -               -              82
  Interest and debt expense                          36            202             121            (164)            195
                                                  -----         ------          ------         -------          ------
         Total Costs and Expenses                    36            487           3,025            (521)          3,027
                                                  -----         ------          ------         -------          ------
                                                    (36)          (365)            765             164             528
Other Income                                        809          1,205             150          (1,940)            224
                                                  -----         ------          ------         -------          ------
Income from Continuing Operations
  before Income Taxes                               773            840             915          (1,776)            752
Provision for Income Taxes                         (287)          (209)           (362)            582            (276)
                                                  -----         ------          ------         -------          ------
Income from Continuing Operations                   486            631             553          (1,194)            476
Income from Discontinued Operations,
  net of taxes                                        -              -              30               -              30
Cumulative Effect of Change in Accounting
  Principle, net of taxes                             -            (21)              1               -             (20)
                                                  -----         ------          ------         -------          ------
Net Income                                        $ 486         $  610          $  584         $(1,194)         $  486
                                                  =====         ======          ======         =======          ======






Condensed Consolidating Balance Sheet as of December 31, 2003
-------------------------------------------------------------------------------------------------------------------------
                                                   Kerr-McGee      Guarantor  Non-Guarantor
 (Millions of dollars)                            Corporation   Subsidiaries   Subsidiaries   Eliminations   Consolidated
-------------------------------------------------------------------------------------------------------------------------
                                                                                                   
ASSETS
Current Assets
  Cash                                                 $    2         $    -         $  140        $     -        $   142
  Accounts receivable                                       -            125            458              -            583
  Intercompany receivables                                795            (26)         2,110         (2,879)             -
  Inventories                                               -              6            388              -            394
  Deposits, prepaid expenses and other assets               -             18            619              -            637
  Current assets associated with properties
    held for disposal                                       -              -              1              -              1
                                                       ------         ------         ------        -------        -------
       Total Current Assets                               797            123          3,716         (2,879)         1,757
Investments in and Advances to Subsidiaries             3,949            519            (20)        (4,448)             -
Investments and Other Assets                               10             96            538            (79)           565
Property, Plant and Equipment - Net                         -          1,975          5,492              -          7,467
Goodwill                                                    -            346             11              -            357
Long-Term Assets Associated with Properties
  Held for Disposal                                         -              -             28              -             28
                                                       ------         ------         ------        -------        -------
       Total Assets                                    $4,756         $3,059         $9,765        $(7,406)       $10,174
                                                       ======         ======         ======        =======        =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
  Accounts payable                                     $   45         $   81         $  609        $     -        $   735
  Intercompany borrowings                                  69            563          2,183         (2,815)             -
  Long-term debt due within one year                        -              -            574              -            574
  Other current liabilities                                37            132            754              -            923
                                                       ------         ------         ------        -------        -------
       Total Current Liabilities                          151            776          4,120         (2,815)         2,232
Investments by and Advances from Parent                     -              -            598           (598)             -
Long-Term Debt                                          1,829              -          1,252              -          3,081
Deferred Credits and Reserves                              (6)           678          1,555             (2)         2,225
Stockholders' Equity                                    2,782          1,605          2,240         (3,991)         2,636
                                                       ------         ------         ------        -------        -------
       Total Liabilities and Stockholders' Equity      $4,756         $3,059         $9,765        $(7,406)       $10,174
                                                       ======         ======         ======        =======        =======







Condensed Consolidating Balance Sheet as of December 31, 2002
-------------------------------------------------------------------------------------------------------------------------
                                                   Kerr-McGee      Guarantor  Non-Guarantor
(Millions of dollars)                             Corporation   Subsidiaries   Subsidiaries   Eliminations   Consolidated
-------------------------------------------------------------------------------------------------------------------------
                                                                                                    
ASSETS
Current Assets
  Cash                                                 $    3         $    -         $   87        $     -         $   90
  Accounts receivable                                       -             73            535              -            608
  Intercompany receivables                                956             46          1,641         (2,643)             -
  Inventories                                               -              6            396              -            402
  Deposits, prepaid expenses and other assets               -             60             75             (2)           133
  Current assets associated with properties
    held for disposal                                       -              -             57              -             57
                                                       ------         ------         ------        -------         ------
       Total Current Assets                               959            185          2,791         (2,645)         1,290
Investments in and Advances to Subsidiaries             3,673            695             80         (4,448)             -
Investments and Other Assets                               12            118            986            (81)         1,035
Property, Plant and Equipment - Net                         -          1,956          5,080              -          7,036
Goodwill                                                    -            347              9              -            356
Long-Term Assets Associated with Properties
  Held for Disposal                                         -              -            187              5            192
                                                       ------         ------         ------        -------         ------
       Total Assets                                    $4,644         $3,301         $9,133        $(7,169)        $9,909
                                                       ======         ======         ======        =======         ======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
  Accounts payable                                     $   45         $   78         $  649        $     -         $  772
  Intercompany borrowings                                  68            842          1,732         (2,642)             -
  Long-term debt due within one year                        -              -            106              -            106
  Other current liabilities                                18            195            491             26            730
  Current liabilities associated with properties
    held for disposal                                       -              -              2              -              2
                                                       ------         ------         ------        -------         ------
       Total Current Liabilities                          131          1,115          2,980         (2,616)         1,610
Long-Term Debt                                          1,847              -          1,951              -          3,798
Investments by and Advances from Parent                     -              -            729           (729)             -
Deferred Credits and Reserves                               -            675          1,298            (24)         1,949
Long-Term Liabilities Associated with Properties
  Held for Disposal                                         -              -             16              -             16
Stockholders' Equity                                    2,666          1,511          2,159         (3,800)         2,536
                                                       ------         ------         ------        -------         ------
       Total Liabilities and Stockholders' Equity      $4,644         $3,301         $9,133        $(7,169)        $9,909
                                                       ======         ======         ======        =======         ======






Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2003
--------------------------------------------------------------------------------------------------------------------------------
                                                          Kerr-McGee      Guarantor  Non-Guarantor
(Millions of dollars)                                    Corporation   Subsidiaries   Subsidiaries   Eliminations   Consolidated
--------------------------------------------------------------------------------------------------------------------------------
                                                                                                           
Cash Flow from Operating Activities
  Net income                                                   $ 201          $ 113         $  200          $(295)        $  219
  Adjustments to reconcile to net cash provided
    by operating activities -
      Depreciation, depletion and amortization                     -            127            687              -            814
      Accretion expense                                            -              2             23              -             25
      Deferred income taxes                                       (6)            (8)           170              -            156
      Dry hole costs                                               -              -            181              -            181
      Impairments on assets held for use                           -              -             14              -             14
      Gain associated with assets held for sale                    -              -            (39)             -            (39)
      Cumulative effect of change in accounting principle          -              1             34              -             35
      Equity in loss (earnings) of subsidiaries                 (227)            65              -            162              -
      Provision for environmental remediation and
        restoration, net of reimbursements                         -             31             31              -             62
      (Gains) losses on asset retirements and sales                -            (12)            11              -             (1)
      Noncash items affecting net income                           1             34            109              -            144
      Other net cash provided by (used in) operating
        activities                                                 3           (157)            62              -            (92)
                                                               -----          -----         ------          -----         ------
          Net cash provided by (used in) operating
            activities                                           (28)           196          1,483           (133)         1,518
                                                               -----          -----         ------          -----         ------
Cash Flow from Investing Activities
  Capital expenditures                                             -           (129)          (852)             -           (981)
  Dry hole costs                                                   -              -           (181)             -           (181)
  Acquisitions                                                     -              -           (110)             -           (110)
  Proceeds from sales of assets                                    -              8            296              -            304
  Other investing activities                                       -              -             17              -             17
                                                               -----          -----         ------          -----         ------
          Net cash used in investing
            activities                                             -           (121)          (830)             -           (951)
                                                               -----          -----         ------          -----         ------
Cash Flow from Financing Activities
  Issuance of long-term debt                                       -              -             31              -             31
  Increase (decrease) in intercompany notes payable              226            (75)          (152)             1              -
  Repayment of long-term debt                                    (18)             -           (351)             -           (369)
  Dividends paid                                                (181)             -           (134)           134           (181)
  Other financing activities                                       -              -              1             (2)            (1)
                                                               -----          -----         ------          -----         ------
          Net cash provided by (used in) financing
            activities                                            27            (75)          (605)           133           (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
                                                               =====          =====         ======          =====         ======







Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2002
--------------------------------------------------------------------------------------------------------------------------------
                                                          Kerr-McGee      Guarantor  Non-Guarantor
(Millions of dollars)                                    Corporation   Subsidiaries   Subsidiaries   Eliminations   Consolidated
--------------------------------------------------------------------------------------------------------------------------------
                                                                                                           
Cash Flow from Operating Activities
  Net income (loss)                                            $(485)         $ 503         $ (709)         $ 206         $ (485)
  Adjustments to reconcile to net cash provided by
    operating activities -
      Depreciation, depletion and amortization                     -            124            760              -            884
      Deferred income taxes                                        -              9           (121)             -           (112)
      Dry hole costs                                               -              -            113              -            113
      Impairments on assets held for use                           -              3            649              -            652
      Loss associated with assets held for sale                    -              -            210              -            210
      Equity in loss (earnings) of subsidiaries                  465            (25)             -           (440)             -
      Provision for environmental remediation and
        restoration, net of reimbursements                         -              -             89              -             89
      Gains on asset retirements and sales                         -              -           (110)             -           (110)
      Noncash items affecting net income                           -            (13)           113              -            100
      Other net cash provided by (used in) operating
        activities                                               (16)           328           (205)             -            107
                                                               -----          -----         ------          -----         ------
          Net cash provided by (used in) operating
            activities                                           (36)           929            789           (234)         1,448
                                                               -----          -----         ------          -----         ------
Cash Flow from Investing Activities
  Capital expenditures                                             -           (179)          (980)             -         (1,159)
  Dry hole costs                                                   -              -           (113)             -           (113)
  Acquisitions                                                     -              -            (24)             -            (24)
  Other investing activities                                       -           (639)         1,342              -            703
                                                               -----          -----         ------          -----         ------
          Net cash provided by (used in) investing
             activities                                            -           (818)           225              -           (593)
                                                               -----          -----         ------          -----         ------
Cash Flow from Financing Activities
  Issuance of long-term debt                                     350              -             68              -            418
  Issuance of common stock                                         5              -              -              -              5
  Increase (decrease) in intercompany notes payable             (135)          (112)           248             (1)             -
  Decrease in short-term borrowings                                -              -             (8)             -             (8)
  Repayment of long-term debt                                      -              -         (1,093)             -         (1,093)
  Dividends paid                                                (181)             -           (235)           235           (181)
                                                               -----          -----         ------          -----         ------
          Net cash provided by (used in) financing
            activities                                            39           (112)        (1,020)           234           (859)
                                                               -----          -----         ------          -----         ------
Effects of Exchange Rate Changes on Cash and Cash
  Equivalents                                                      -              -              3              -              3
                                                               -----          -----         ------          -----         ------
Net Increase (Decrease) in Cash and Cash Equivalents               3             (1)            (3)             -             (1)
Cash and Cash Equivalents at Beginning of Year                     -              1             90              -             91
                                                               -----          -----         ------          -----         ------
Cash and Cash Equivalents at End of Year                       $   3          $   -         $   87          $   -         $   90
                                                               =====          =====         ======          =====         ======







Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2001
--------------------------------------------------------------------------------------------------------------------------------
                                                          Kerr-McGee      Guarantor  Non-Guarantor
(Millions of dollars)                                    Corporation   Subsidiaries   Subsidiaries   Eliminations   Consolidated
--------------------------------------------------------------------------------------------------------------------------------
                                                                                                          
Cash Flow from Operating Activities
  Net income                                                  $  486        $   610        $   584        $(1,194)       $   486
  Adjustments to reconcile to net cash provided by
    operating activities -
      Depreciation, depletion and amortization                     -             60            753              -            813
      Deferred income taxes                                        -            166             39              -            205
      Dry hole costs                                               -              -             72              -             72
      Impairments on assets held for use                           -              -             76              -             76
      Cumulative effect of change in accounting principle          -             21             (1)             -             20
      Equity in earnings of subsidiaries                        (520)          (586)             -          1,106              -
      Provision for environmental remediation and
        restoration, net of reimbursements                         -             82              -              -             82
      Gains on asset retirements and sales                         -             (3)            (9)             -            (12)
      Noncash items affecting net income                           -           (222)            33              -           (189)
      Other net cash provided by (used in) operating
        activities                                              (463)           656           (700)            97           (410)
                                                              ------        -------        -------        -------        -------
           Net cash provided by (used in) operating
             activities                                         (497)           784            847              9          1,143
                                                              ------        -------        -------        -------        -------
Cash Flow from Investing Activities
  Capital expenditures                                             -            (95)        (1,697)             -         (1,792)
  Dry hole costs                                                   -              -            (72)             -            (72)
  Acquisitions                                                  (955)             -            (23)             -           (978)
  Other investing activities                                       -              6            (61)             -            (55)
                                                              ------        -------        -------        -------        -------
          Net cash used in investing activities                 (955)           (89)        (1,853)             -         (2,897)
                                                              ------        -------        -------        -------        -------
Cash Flow from Financing Activities
  Issuance of long-term debt                                   1,497            (10)         1,026              -          2,513
  Issuance of common stock                                         -             32              -              -             32
  Increase (decrease) in intercompany notes payable                -          1,009              -         (1,009)             -
  Increase (decrease) in short-term borrowings                     -            (11)             2              -             (9)
  Repayment of long-term debt                                      -           (586)           (75)             -           (661)
  Dividends paid                                                 (45)        (1,128)             -          1,000           (173)
                                                              ------        -------        -------        -------        -------
          Net cash provided by (used in) financing
            activities                                         1,452           (694)           953             (9)         1,702
                                                              ------        -------        -------        -------        -------
Effects of Exchange Rate Changes on Cash and Cash
  Equivalents                                                      -              -             (1)             -             (1)
                                                              ------        -------        -------        -------        -------
Net Increase (Decrease) in Cash and Cash Equivalents               -              1            (54)             -            (53)
Cash and Cash Equivalents at Beginning of Year                     -              3            141              -            144
                                                              ------        -------        -------        -------        -------
Cash and Cash Equivalents at End of Year                      $    -        $     4        $    87        $     -        $    91
                                                              ======        =======        =======        =======        =======





28.  Reporting by Business Segments and Geographic Locations

The  company  has  three  reportable  segments:  oil  and  gas  exploration  and
production, production and marketing of titanium dioxide pigment, and production
and marketing of other  chemicals.  The exploration and production unit explores
for and produces oil and gas in the United States,  the United Kingdom sector of
the North Sea and China.  Exploration  efforts also extend to Australia,  Benin,
Bahamas,  Brazil, Gabon, Morocco,  Western Sahara,  Canada, Yemen and the Danish
and Norwegian sectors of the North Sea. The chemical unit primarily produces and
markets  titanium  dioxide  pigment and has production  facilities in the United
States,  Australia,  Germany and the  Netherlands.  Other chemicals  include the
company's  electrolytic   manufacturing  and  marketing  operations  and  forest
products treatment business. All of these operations are in the United States.

Crude oil sales to individually significant customers totaled $446 million to BP
PLC and  subsidiaries  (BP) in 2003; $408 million to Texon L.P. and $450 million
to BP in 2002; and $408 million to Texon L.P. and $401 million to BP in 2001. In
addition,  natural  gas sales  totaled  $103  million to BP and $782  million to
Cinergy  Marketing & Trading LP  (Cinergy)  in 2003;  $72 million to BP and $496
million  to  Cinergy in 2002;  and $682  million  to  Cinergy in 2001.  Sales to
subsidiary companies are eliminated as described in Note 1.

(Millions of dollars)                             2003        2002        2001
--------------------------------------------------------------------------------
Revenues -
  Exploration and production                     $2,923      $2,450      $2,428
                                                 ------      ------      ------
  Chemicals -
    Pigment                                       1,079         995         931
    Other                                           183         201         196
                                                 ------      ------      ------
      Total Chemicals                             1,262       1,196       1,127
                                                 ------      ------      ------
        Total                                    $4,185      $3,646      $3,555
                                                 ======      ======      ======

Operating profit (loss) -
  Exploration and production                     $1,002      $ (140)     $  922
                                                 ------      ------      ------
  Chemicals -
    Pigment                                         (13)         24         (22)
    Other                                           (35)        (23)        (17)
                                                 ------      ------      ------
      Total Chemicals                               (48)          1         (39)
                                                 ------      ------      ------
        Total                                       954        (139)        883
                                                 ------      ------      ------

Net interest expense                               (246)       (270)       (185)
Net nonoperating income (expense)                  (265)       (248)         54
Benefit (provision) for income taxes               (189)         46        (276)
Discontinued operations, net of taxes                 -         126          30
Cumulative effect of change in accounting
  principle, net of taxes                           (35)          -         (20)
                                                 ------      ------      ------
Net income (loss)                                $  219      $ (485)     $  486
                                                 ======      ======      ======

Depreciation, depletion and amortization -
  Exploration and production (1)                 $  678      $  758      $  675
                                                 ------      ------      ------
  Chemicals -
    Pigment                                         110          97         103
    Other                                            18          20          17
                                                 ------      ------      ------
      Total Chemicals                               128         117         120
                                                 ------      ------      ------
  Other                                               8           6           8
  Discontinued operations                             -           3          10
                                                 ------      ------      ------
        Total                                    $  814      $  884      $  813
                                                 ======      ======      ======

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


(Millions of dollars)                             2003        2002        2001
--------------------------------------------------------------------------------
Capital expenditures -
  Exploration and production
    (excludes Gunnison lease of $83)            $   869      $  988     $ 1,557
                                                -------      ------     -------
  Chemicals -
    Pigment                                          90          78         139
    Other                                             7           8          14
                                                -------      ------     -------
      Total Chemicals                                97          86         153
                                                -------      ------     -------
  Other                                              15          58          15
  Discontinued operations                             -          27          67
                                                -------      ------     -------
        Total                                       981       1,159       1,792
                                                -------      ------     -------

Exploration expenses -
  Exploration and production -
    Dry hole costs                                  181         113          72
    Amortization of undeveloped leases               69          67          56
    Other                                           104          93          82
                                                -------      ------     -------
      Total                                         354         273         210
                                                -------      ------     -------
        Total capital expenditures
          and exploration expenses              $ 1,335      $1,432     $ 2,002
                                                =======      ======     =======

Total assets -
  Exploration and production                    $ 7,324      $7,030     $ 8,076
                                                -------      ------     -------
  Chemicals -
    Pigment                                       1,521       1,413       1,391
    Other                                           212         247         245
                                                -------      ------     -------
      Total Chemicals                             1,733       1,660       1,636
                                                -------      ------     -------
        Total                                     9,057       8,690       9,712

  Corporate and other assets                      1,117       1,038       1,010
  Discontinued operations                             -         181         354
                                                -------      ------     -------
        Total                                   $10,174      $9,909     $11,076
                                                =======      ======     =======

Revenues -
  U.S. operations                               $ 2,860      $2,190     $ 2,125
                                                -------      ------     -------
  International operations -
    North Sea - exploration and production          791         936         935
    China - exploration and production               23          30          31
    Other - exploration and production                -          28          39
    Europe - pigment                                313         294         258
    Australia - pigment                             198         168         167
                                                -------      ------     -------
                                                  1,325       1,456       1,430
                                                -------      ------     -------
        Total                                   $ 4,185      $3,646     $ 3,555
                                                =======      ======     =======

Operating profit (loss) -
  U.S. operations                               $   622      $  322     $   647
                                                -------      ------     -------
  International operations -
    North Sea - exploration and production          353        (412)        318
    China - exploration and production                1           7           6
    Other - exploration and production              (66)        (59)        (66)
    Europe - pigment                                 14         (21)        (53)
    Australia - pigment                              30          24          31
                                                -------      ------     -------
                                                    332        (461)        236
                                                -------      ------     -------
        Total                                   $   954      $ (139)    $   883
                                                =======      ======     =======

Net property, plant and equipment -
  U.S. operations                               $ 5,021      $4,631     $ 4,483
                                                -------      ------     -------
  International operations -
    North Sea - exploration and production        1,874       1,912       2,427
    China - exploration and production              165         115          93
    Other - exploration and production                4          13          27
    Europe - pigment                                301         255         226
    Australia - pigment                             102         110         122
                                                -------      ------     -------
                                                  2,446       2,405       2,895
                                                -------      ------     -------
        Total                                   $ 7,467      $7,036     $ 7,378
                                                =======      ======     =======



29.  Costs Incurred in Crude Oil and Natural Gas Activities

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, 2003, are reflected in the following table:





                                                      Property
                                                   Acquisition       Exploration       Development
(Millions of dollars)                                 Costs(1)          Costs(2)          Costs(3)            Total
-------------------------------------------------------------------------------------------------------------------
                                                                                                 
2003 -
  United States                                         $  121              $357            $  473           $  951
  North Sea                                                 46                43                55              144
  China                                                      1                31                45               77
  Other international                                        1                49                 -               50
                                                        ------              ----            ------           ------
    Total finding, development and
      acquisition costs incurred                           169               480               573            1,222
  Asset retirement costs (4)                                 9                 -                 2               11
                                                        ------              ----            ------           ------
        Total costs incurred                            $  178              $480            $  575           $1,233
                                                        ======              ====            ======           ======

2002 -
  United States                                         $   89              $206            $  426           $  721
  North Sea                                                 55                14               296              365
  China                                                      -                14                16               30
  Other international                                        2                44                 -               46
                                                        ------              ----            ------           ------
    Total continuing operations                            146               278               738            1,162
  Discontinued operations                                    2                 1                 5                8
                                                        ------              ----            ------           ------
        Total costs incurred                            $  148              $279            $  743           $1,170
                                                        ======              ====            ======           ======

2001 -
  United States                                         $1,420              $225            $  457           $2,102
  North Sea                                                  -                71               695              766
  China                                                      -                45                 4               49
  Other international                                        3                54                17               74
                                                        ------              ----            ------           ------
    Total continuing operations                          1,423               395             1,173            2,991
  Discontinued operations                                    -                 4                64               68
                                                        ------              ----            ------           ------
        Total costs incurred                            $1,423              $399            $1,237           $3,059
                                                        ======              ====            ======           ======



(1)  Includes  $95  million,  $69  million  and  $1.128  billion  applicable  to
     purchases of reserves in place in 2003, 2002 and 2001, respectively.

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

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

(4)  Asset retirement  costs 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.  See
     further discussion in Note 1 regarding the 2003 adoption of FAS 143.


30.  Results of Operations from Crude Oil and Natural Gas Activities

The results of  operations  from crude oil and natural  gas  activities  for the
three years ended December 31, 2003, consist of the following:


                                                                                          Loss (Gain) on
                                                                                           Held for Sale      Income      Results of
                                       Production                         Depreciation,       Properties         Tax     Operations,
                                        (Lifting)   Other   Exploration   Depletion and        and Asset     Expense       Producing
 (Millions of dollars)      Revenues        Costs   Costs      Expenses       Accretion      Impairments   (Benefit)      Activities
------------------------------------------------------------------------------------------------------------------------------------
                                                                                                      
2003 -
  United States               $1,775         $235    $149          $249            $400             $ (4)       $255          $ 491
  North Sea                      783          146      60            27             220              (15)        147            198
  China                           23            5       8            19               2              (12)          1              -
  Other international              -            -       6            59               1                -         (22)           (44)
                              ------         ----    ----          ----            ----             ----        ----          -----
    Total crude oil and
      natural gas activities   2,581          386     223 (1)       354             623              (31)        381            645
  Other (2)                      342            -     355             -              11                -          (8)           (16)
                              ------         ----    ----          ----            ----             ----        ----          -----
    Total from continuing
      operations               2,923          386     578           354             634              (31)        373            629
  Discontinued operations          6            1       2             -               -                6           -             (3)
                              ------         ----    ----          ----            ----             ----        ----          -----
        Total                 $2,929         $387    $580          $354            $634             $(25)       $373          $ 626
                              ======         ====    ====          ====            ====             ====        ====          =====

2002 -
  United States               $1,367         $254    $106          $159            $389             $111        $116          $ 232
  North Sea                      920          244      60            48             288              706          33           (459)
  China                           30           10       5             5               3                -           2              5
  Other international             29            7      14            61               -                5         (17)           (41)
                              ------         ----    ----          ----            ----             ----        ----          -----
    Total crude oil and
      natural gas activities   2,346          515     185 (1)       273             680              822         134           (263)
  Other (2)                      104            -     105             -              10                -          (4)            (7)
                              ------         ----    ----          ----            ----             ----        ----          -----
    Total from continuing
      operations               2,450          515     290           273             690              822         130           (270)
  Discontinued operations         36            4      14             1               3               35           -            (21)
                              ------         ----    ----          ----            ----             ----        ----          -----
        Total                 $2,486         $519    $304          $274            $693             $857        $130          $(291)
                              ======         ====    ====          ====            ====             ====        ====          =====
2001 -
  United States               $1,402         $217    $ 69          $100            $331             $  -        $248          $ 437
  North Sea                      922          207      61            29             273               47         120            185
  China                           30           10       5             6               4                -           2              3
  Other international             39            8      14            74               7                -         (21)           (43)
                              ------         ----    ----          ----            ----             ----        ----          -----
    Total crude oil and
      natural gas activities   2,393          442     149 (1)       209             615               47         349            582
  Other (2)                       35            -      39             1               4                -          (7)            (2)
                              ------         ----    ----         -----            ----             ----        ----          -----
    Total from continuing      2,428          442     188           210             619               47         342            580
      operations
  Discontinued operations         72            7      17             1              10                -          17             20
                              ------         ----    ----          ----            ----             ----        ----          -----
        Total                 $2,500         $449    $205          $211            $629             $ 47        $359          $ 600
                              ======         ====    ====          ====            ====             ====        ====          =====


(1)  Includes  transportation,  general and  administrative  expense,  and taxes
     other than income taxes associated with oil and 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 taxes)
per barrel of oil  equivalent  from  continuing  operations for each of the past
three  years.  Natural  gas  production  has been  converted  to a barrel of oil
equivalent based on approximate relative heating value (6 Mcf equals 1 barrel).

                                                       2003       2002      2001
--------------------------------------------------------------------------------
Average price of crude oil sold (per barrel) -
    United States                                    $26.14     $21.56    $22.05
    North Sea                                         25.82      22.41     23.23
    China                                             29.66      24.84     21.94
    Other international                                   -      20.28     19.14
       Average(1)                                     26.04      22.04     22.60

Average price of natural gas sold (per Mcf) -
    United States                                     $4.56      $3.04     $3.99
    North Sea                                          3.09       2.35      2.46
       Average(1)                                      4.37       2.95      3.83

Lifting costs (per barrel of oil equivalent) -
    United States                                     $3.57      $3.64     $3.56
    North Sea                                          4.52       5.64      5.03
    China                                              6.02       8.08      7.15
    Other international                                   -       5.05      4.54
       Average                                         3.90       4.45      4.20

(1)  Includes the results of the company's 2003 and 2002 hedging program,  which
     reduced the average  price of crude oil sold by $2.46 and $1.13 per barrel,
     respectively, and natural gas sold by $.55 and $.01 per Mcf, respectively.


31.  Capitalized Costs of Crude Oil and Natural Gas Activities

Capitalized  costs of crude  oil and  natural  gas  activities  and the  related
reserves for  depreciation,  depletion and  amortization  at the end of 2003 and
2002 are set forth in the table below.

(Millions of dollars)                                        2003           2002
--------------------------------------------------------------------------------
Capitalized costs -
    Proved properties                                     $10,875        $10,442
    Unproved properties                                       837            782
    Other                                                     375            361
                                                          -------        -------
        Total                                              12,087         11,585
    Assets held for disposal                                  467            782
    Discontinued operations                                     -             63
                                                          -------        -------
        Total                                              12,554         12,430
                                                          -------        -------

Reserves for depreciation, depletion and amortization -
    Proved properties                                       5,403          5,384
    Unproved properties                                       206            155
    Other                                                     110             93
                                                          -------        -------
        Total                                               5,719          5,632
    Assets held for disposal                                  439            746
    Discontinued operations                                     -             17
                                                          -------        -------
        Total                                               6,158          6,395
                                                          -------        -------

Net capitalized costs                                     $ 6,396        $ 6,035
                                                          =======        =======


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

The estimates of proved reserves have been prepared by the company's  geologists
and  engineers  in  accordance  with  the  Securities  and  Exchange  Commission
definitions.  Such estimates  include  reserves on certain  properties  that are
partially  undeveloped  and  reserves  that may be  obtained  in the  future  by
improved-recovery  operations now in operation or for which  successful  testing
has been  demonstrated.  The  company  has no proved  reserves  attributable  to
long-term  supply  agreements with  governments or consolidated  subsidiaries in
which there are significant minority interests.  Natural gas liquids and natural
gas volumes are determined using a gas pressure base of 14.73 psia.

The following  table  summarizes the changes in the estimated  quantities of the
company's  crude oil,  condensate,  natural  gas  liquids and natural gas proved
reserves for the three years ended December 31, 2003.


                                                               Continuing Operations
                                                ---------------------------------------------------
                                                                                              Total
Crude Oil, Condensate and Natural Gas Liquids   United   North                   Other   Continuing   Discontinued
(Millions of barrels)                           States     Sea   China   International   Operations     Operations     Total
----------------------------------------------------------------------------------------------------------------------------
                                                                                                  
Proved developed and undeveloped reserves -
  Balance December 31, 2000                        228     355      12              40          635             65       700
    Revisions of previous estimates                 27      (4)      -               1           24              -        24
    Purchases of reserves in place                  45       -       -               -           45              -        45
    Sales of reserves in place                      (4)      -       -               -           (4)             -        (4)
    Extensions, discoveries and other
      additions                                     49      74      25               -          148              -       148
    Production                                     (28)    (37)     (2)             (2)         (69)            (3)      (72)
                                                 -----    ----      --             ---        -----           ----     -----
  Balance December 31, 2001                        317     388      35              39          779             62       841
    Revisions of previous estimates                  8    (101)      1               -          (92)             -       (92)
    Purchases of reserves in place                   1      13       -               -           14              -        14
    Sales of reserves in place                     (62)    (61)      -             (37)        (160)           (51)     (211)
    Extensions, discoveries and other
      additions                                      6       1       -               -            7              -         7
    Production                                     (29)    (38)     (1)             (2)         (70)            (2)      (72)
                                                 -----    ----      --             ---        -----           ----     -----
  Balance December 31, 2002                        241     202      35               -          478              9       487
    Revisions of previous estimates                  7      (7)      2               -            2              -         2
    Purchases of reserves in place                   3      12       -               -           15              -        15
    Sales of reserves in place                     (16)      -      (3)              -          (19)            (9)      (28)
    Extensions, discoveries and other
      additions                                     55      14       6               -           75              -        75
    Production                                     (28)    (26)     (1)              -          (55)             -       (55)
                                                 -----    ----      --             ---        -----           ----     -----
  Balance December 31, 2003                        262     195      39               -          496              -       496
                                                 =====    ====      ==             ===        =====           ====     =====

  Natural Gas (Billions of cubic feet)
  --------------------------------------------------------------------------------------------------------------------------
  Proved developed and undeveloped reserves -
  Balance December 31, 2000                      1,325     467       -               -        1,792            535     2,327
    Revisions of previous estimates                 35       2       -               -           37              -        37
    Purchases of reserves in place               1,050       5       -               -        1,055              -     1,055
    Sales of reserves in place                      (7)      -       -               -           (7)             -        (7)
    Extensions, discoveries and other
      additions                                    737      76       -               -          813              -       813
    Production                                    (195)    (23)      -               -         (218)             -      (218)
                                                 -----    ----      --             ---        -----           ----     -----
  Balance December 31, 2001                      2,945     527       -               -        3,472            535     4,007
    Revisions of previous estimates                (70)     (7)      -               -          (77)             -       (77)
    Purchases of reserves in place                  17      16       -               -           33              -        33
    Sales of reserves in place                     (76)     (9)      -               -          (85)          (535)     (620)
    Extensions, discoveries and other
      additions                                    204       6       -               -          210              -       210
    Production                                    (241)    (37)      -               -         (278)             -      (278)
                                                 -----    ----      --             ---        -----           ----     -----
  Balance December 31, 2002                      2,779     496       -               -        3,275              -     3,275
    Revisions of previous estimates                (10)     11       -               -            1              -         1
    Purchases of reserves in place                  57      30       -               -           87              -        87
    Sales of reserves in place                     (77)      -       -               -          (77)             -       (77)
    Extensions, discoveries and other
      additions                                    152       8       -               -          160              -       160
    Production                                    (230)    (35)      -               -         (265)             -      (265)
                                                 -----    ----      --             ---        -----           ----     -----
  Balance December 31, 2003                      2,671     510       -               -        3,181              -     3,181
                                                 =====    ====      ==             ===        =====           ====     =====




                                                               Continuing Operations
                                                ---------------------------------------------------
                                                                                              Total
Crude Oil, Condensate and Natural Gas Liquids   United   North                   Other   Continuing   Discontinued
(Millions of barrels)                           States     Sea   China   International   Operations     Operations     Total
----------------------------------------------------------------------------------------------------------------------------
                                                                                                  
Proved developed reserves -

     December 31, 2001                             206     248       2              11          467             11       478
     December 31, 2002                             147     130       2               -          279              5       284
     December 31, 2003                             122     125       -               -          247              -       247

Natural Gas (Billions of cubic feet)
----------------------------------------------------------------------------------------------------------------------------
Proved developed reserves -

     December 31, 2001                           1,741     208       -               -        1,949             13     1,962
     December 31, 2002                           1,658     168       -               -        1,826              -     1,826
     December 31, 2003                           1,502     113       -               -        1,615              -     1,615


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
                                                ---------------------------------------------------
                                                                                              Total
Barrels of Oil Equivalent                       United   North                   Other   Continuing   Discontinued
(Millions of barrels)                           States     Sea   China   International   Operations     Operations     Total
----------------------------------------------------------------------------------------------------------------------------
                                                                                                  
Proved developed and undeveloped reserves -
  Balance December 31, 2000                        449     433      12              40          934            154     1,088
    Revisions of previous estimates                 33      (4)      -               1           30              -        30
    Purchases of reserves in place                 219       1       -               -          220              -       220
    Sales of reserves in place                      (5)      -       -               -           (5)             -        (5)
    Extensions, discoveries and other additions    172      87      25               -          284              -       284
    Production                                     (60)    (41)     (2)             (2)        (105)            (3)     (108)
                                                 -----    ----      --             ---        -----           ----     -----
  Balance December 31, 2001                        808     476      35              39        1,358            151     1,509
    Revisions of previous estimates                 (4)   (102)      1               -         (105)             -      (105)
    Purchases of reserves in place                   3      16       -               -           19              -        19
    Sales of reserves in place                     (74)    (63)      -             (37)        (174)          (140)     (314)
    Extensions, discoveries and other additions     40       2       -               -           42              -        42
    Production                                     (69)    (44)     (1)             (2)        (116)            (2)     (118)
                                                 -----    ----      --             ---        -----           ----     -----
  Balance December 31, 2002                        704     285      35               -        1,024              9     1,033
    Revisions of previous estimates                  5      (5)      2               -            2              -         2
    Purchases of reserves in place                  12      17       -               -           29              -        29
    Sales of reserves in place                     (29)      -      (3)              -          (32)            (9)      (41)
    Extensions, discoveries and other additions     81      15       6               -          102              -       102
    Production                                     (66)    (32)     (1)              -          (99)             -       (99)
                                                 -----    ----      --             ---        -----           ----     -----
  Balance December 31, 2003                        707     280      39               -        1,026              -     1,026
                                                 =====    ====      ==             ===        =====           ====     =====




                                                              Continuing Operations
                                                ---------------------------------------------------
                                                                                              Total
                                                United   North                   Other   Continuing   Discontinued
(Millions of equivalent barrels)                States     Sea   China   International   Operations     Operations     Total
----------------------------------------------------------------------------------------------------------------------------
                                                                                                    
Proved developed reserves -

     December 31, 2001                             496     283       2              11          792             13       805
     December 31, 2002                             423     158       2               -          583              5       588
     December 31, 2003                             372     144       -               -          516              -       516




33.  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 properties  involved.
However,  the  company  cautions  that  actual  future  net cash  flows may vary
considerably  from these  estimates.  Although the company's  estimates of total
reserves,  development  costs  and  production  rates  were  based  on the  best
information  available,  the  development  and  production  of the  oil  and gas
reserves may not occur in the periods  assumed.  Actual prices  realized,  costs
incurred  and  production  quantities  may vary  significantly  from those used.
Therefore,  such  estimated  future  net cash flow  computations  should  not be
considered to represent the company's  estimate of the expected  revenues or the
current value of existing proved reserves.



                                                                                                         Standardized
                                                                                     Future                Measure of
                                 Future        Future         Future      Future        Net        10%     Discounted
                                   Cash    Production    Development      Income       Cash     Annual     Future Net
(Millions of dollars)           Inflows(1)      Costs          Costs(2)    Taxes      Flows   Discount     Cash Flows
---------------------------------------------------------------------------------------------------------------------
                                                                                          
2003
  United States                 $23,850        $5,002         $2,067      $5,467    $11,314     $4,721         $6,593
  North Sea                       7,770         2,437            790       1,552      2,991        970          2,021
  China                           1,114           306            130         178        500        208            292
                                -------        ------         ------      ------    -------     ------         ------
        Total                   $32,734        $7,745         $2,987      $7,197    $14,805     $5,899         $8,906(3)
                                =======        ======         ======      ======    =======     ======         ======

2002
  United States                 $17,195        $4,909         $1,642      $3,372     $7,272     $2,951         $4,321
  North Sea                       7,332         1,484            602       1,887      3,359        923          2,436
  China                           1,052           280            154         162        456        214            242
                                -------        ------         ------      ------    -------     ------         ------
    Total continuing
      operations                 25,579         6,673          2,398       5,421     11,087      4,088          6,999(3)
  Discontinued
    operations                      224            84             11          34         95         32             63
                                -------        ------         ------      ------    -------     ------         ------
      Total                     $25,803        $6,757         $2,409      $5,455    $11,182     $4,120         $7,062
                                =======        ======         ======      ======    =======     ======         ======

2001
  United States                 $12,126        $3,952         $1,851      $2,007     $4,316     $1,937         $2,379
  North Sea                       8,348         2,950            855       1,155      3,388      1,216          2,172
  China                             541           255            143          40        103         62             41
  Other international               535           236            104          58        137         67             70
                                -------        ------         ------      ------    -------     ------         ------
    Total continuing
      operations                 21,550         7,393          2,953       3,260      7,944      3,282          4,662(3)
  Discontinued
    operations                    2,440           748            326         497        869        543            326
                                -------        ------         ------      ------    -------     ------         ------
      Total                     $23,990        $8,141         $3,279      $3,757     $8,813     $3,825         $4,988
                                =======        ======         ======      ======    =======     ======         ======


(1)  Future  cash  inflows  from sales of crude oil and natural gas are based on
     average year-end prices of $29.05,  $28.61 and $17.52 per barrel of oil and
     $5.77,  $3.63  and $2.31 per Mcf of  natural  gas for 2003,  2002 and 2001,
     respectively.

(2)  Future abandonment  costs, net of anticipated  salvage values, for 2002 and
     2001  have  been  classified  in  future  development  costs  (rather  than
     production costs) to conform with the current year presentation.

(3)  Estimated  future net cash flows before  income tax expense,  discounted at
     10%, totaled  approximately $13.2 billion,  $10.3 billion and $6.5 billion,
     for 2003, 2002 and 2001, respectively.

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

(Millions of dollars)                                 2003      2002       2001
--------------------------------------------------------------------------------
Net change in sales prices and production costs    $ 3,308   $ 6,870    $(5,879)
Sales revenues less production costs                (2,383)   (1,795)    (1,904)
Purchases of reserves in place                         344       243      1,117
Extensions, discoveries and other additions          1,183       347      1,232
Revisions in quantity estimates                         63    (1,433)       168
Sales of reserves in place                            (255)   (1,920)       (87)
Current-period development costs incurred              573       743      1,237
Changes in estimated future development costs         (472)     (209)      (639)
Accretion of discount                                1,033       701      1,093
Change in income taxes                                (978)   (1,336)     1,689
Timing and other                                      (572)     (137)      (265)
                                                   -------   -------    -------
         Net change                                  1,844     2,074     (2,238)
Total at beginning of year                           7,062     4,988      7,226
                                                   -------   -------    -------
Total at end of year                                $8,906    $7,062    $ 4,988
                                                   =======   =======    =======


34.  Quarterly Financial Information (Unaudited)

A summary  of  quarterly  consolidated  results  for 2003 and 2002 is  presented
below. 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 (Loss) from
                                                                   Income             Continuing Operations
                                                              (Loss) from      Net      per Common Share
(Millions of dollars,                             Operating    Continuing   Income    ---------------------
except per-share amounts)          Revenues   Profit (Loss)    Operations   (Loss)       Basic      Diluted
-----------------------------------------------------------------------------------------------------------
                                                                                   
2003 Quarter Ended -
   March 31                          $1,100           $ 270         $ 104    $  70       $ 1.04      $  .99
   June 30                            1,052             250            70       70          .70         .68
   September 30                       1,006             226            29       29          .29         .29
   December 31                        1,027             208            51       50          .50         .50
                                     ------           -----         -----    -----       ------      ------
      Total                          $4,185           $ 954         $ 254    $ 219       $ 2.52      $ 2.48
                                     ======           =====         =====    =====       ======      ======
2002 Quarter Ended -
   March 31                           $ 791           $ 111         $  (2)   $   6       $ (.02)     $ (.02)
   June 30                              926              56          (178)     (58)       (1.77)      (1.77)
   September 30                         965             182           (87)     (87)        (.86)       (.86)
   December 31                          964            (488)         (344)    (346)       (3.43)      (3.43)
                                     ------           -----         -----    -----       ------      ------
      Total                          $3,646           $(139)        $(611)   $(485)      $(6.09)     $(6.09)
                                     ======           =====         =====    =====       ======      ======


The company's  common stock is listed for trading on the New York Stock Exchange
and at year-end 2003 was held by approximately 24,500 Kerr-McGee stockholders of
record and Oryx and HS Resources  owners who have not yet exchanged their stock.
The ranges of market prices and dividends declared during the last two years for
Kerr-McGee Corporation are as follows:



                                                 Market Prices
                          -----------------------------------------------------------                 Dividends
                                    2003                               2002                           per Share
                          ------------------------           ------------------------            ------------------
                            High               Low             High               Low              2003        2002
-------------------------------------------------------------------------------------------------------------------
                                                                                          
Quarter Ended -
     March 31             $44.90            $37.82           $63.29            $50.72             $.45         $.45
     June 30               48.59             39.90            63.58             52.80              .45          .45
     September 30          45.50             41.08            53.90             39.10              .45          .45
     December 31           47.20             40.10            47.51             38.02              .45          .45







Ten-Year Financial Summary
------------------------------------------------------------------------------------------------------------------------------------
(Millions of dollars, except
  per-share amounts)                   2003       2002       2001      2000      1999      1998     1997     1996     1995     1994
------------------------------------------------------------------------------------------------------------------------------------
                                                                                              
Summary of Net Income (Loss)
Revenues                            $ 4,185    $ 3,646    $ 3,555    $4,063    $2,712    $2,233   $2,651   $2,779   $2,462  $ 2,389
                                    ------------------------------------------------------------------------------------------------
Costs and operating expenses          3,432      3,993      2,832     2,651     2,314     2,626    2,059    2,162    2,343    2,203
Interest and debt expense               251        275        195       208       191       159      141      145      194      210
                                    ------------------------------------------------------------------------------------------------
Total costs and expenses              3,683      4,268      3,027     2,859     2,505     2,785    2,200    2,307    2,537    2,413
                                    ------------------------------------------------------------------------------------------------
                                        502       (622)       528     1,204       207      (552)     451      472      (75)     (24)
Other income (expense)                  (59)       (35)       224        50        36        40       81      109      146       15
Benefit (provision) for income taxes   (189)        46       (276)     (437)     (105)      173     (183)    (224)      41      (14)
                                    ------------------------------------------------------------------------------------------------
Income (loss) from continuing
   operations                           254       (611)       476       817       138      (339)     349      357      112      (23)
Income from discontinued
   operations                             -        126         30        25         8       271       35       57       25       47
Extraordinary charge                      -          -          -         -         -         -       (2)       -      (23)     (12)
Cumulative effect of change in
   accounting principle                 (35)         -        (20)        -        (4)        -        -        -        -     (948)
                                    ------------------------------------------------------------------------------------------------
Net income (loss)                   $   219    $  (485)   $   486    $  842    $  142    $  (68)  $  382   $  414   $  114  $  (936)
                                    ================================================================================================
Effective Income Tax Rate              42.7%     (7.0)%      36.7%     34.8%     43.2%    (33.8)%   34.4%    38.6%    57.7%      NM
Common Stock Information, per
   Share
Diluted net income (loss) -
   Continuing operations            $  2.48    $ (6.09)   $  4.65    $ 8.13    $ 1.60    $(3.91)  $ 4.00   $ 4.03   $ 1.25  $  (.26)
   Discontinued operations                -       1.25        .28       .24       .09      3.13      .40      .65      .28      .53
   Extraordinary charge                   -          -          -         -         -         -     (.02)       -     (.26)    (.14)
   Cumulative effect of accounting
     change                            (.31)         -       (.19)        -      (.05)        -        -        -        -   (10.82)
                                    ------------------------------------------------------------------------------------------------
         Net income (loss)          $  2.17    $ (4.84)   $  4.74    $ 8.37    $ 1.64    $ (.78)  $ 4.38   $ 4.68   $ 1.27  $(10.69)
                                    ================================================================================================
Dividends declared                  $  1.80    $  1.80    $  1.80    $ 1.80    $ 1.80    $ 1.80   $ 1.80   $ 1.64   $ 1.55  $  1.52
Stockholders' equity                  23.79      23.01      28.83     25.01     17.19     15.58    17.88    14.59    12.47    12.33
Market high for the year              48.59      63.58      74.10     71.19     62.00     73.19    75.00    74.13    64.00    51.00
Market low for the year               37.82      38.02      46.94     39.88     28.50     36.19    55.50    55.75    44.00    40.00
Market price at year-end            $ 46.49    $ 44.30    $ 54.80    $66.94    $62.00    $38.25   $63.31   $72.00   $63.50  $ 46.25
Shares outstanding at year-end
   (thousands)                      100,860    100,384    100,185    94,485    86,483    86,367   86,794   87,032   89,613   90,143

Balance Sheet Information
Working capital                     $  (475)   $  (320)   $   193    $  (34)   $  321    $ (173)  $    -   $  161   $ (106) $  (254)
Property, plant and equipment - net   7,467      7,036      7,378     5,240     3,972     4,044    3,844    3,658    3,789    4,493
Total assets                         10,174      9,909     11,076     7,666     5,899     5,451    5,339    5,194    5,006    5,918
Long-term debt                        3,081      3,798      4,540     2,244     2,496     1,978    1,736    1,809    1,683    2,219
Total debt                            3,655      3,904      4,574     2,425     2,525     2,250    1,766    1,849    1,938    2,704
Total debt less cash                  3,513      3,814      4,483     2,281     2,258     2,129    1,574    1,719    1,831    2,612
Stockholders' equity                  2,636      2,536      3,174     2,633     1,492     1,346    1,558    1,279    1,124    1,112

Cash Flow Information
Net cash provided by operating
   activities                         1,518      1,448      1,143     1,840       708       418    1,114    1,144      732      693
Capital expenditures                    981      1,159      1,792       842       528     1,006      851      829      749      622
Dividends paid                          181        181        173       166       138        86       85       83       79       79
Treasury stock purchased            $     -    $     -    $     -    $    -    $    -    $   25   $   60   $  195   $   45  $     -

Ratios and Percentage
Current ratio                            .8         .8        1.2       1.0       1.4        .8      1.0      1.2       .9       .8
Average price/earnings ratio           19.9         NM       12.8       6.6      27.6        NM     14.9     13.9     42.5       NM
Total debt less cash to total
     capitalization                      57%        60%        59%       46%       60%       61%      50%      57%      62%      70%

Employees
Total wages and benefits            $   541    $   412    $   369    $  333    $  327    $  359   $  367   $  367   $  402  $   422
Number of employees at year-end       3,915      4,470      4,638     4,426     3,653     4,400    4,792    4,827    5,176    6,724
------------------------------------------------------------------------------------------------------------------------------------






 Ten-Year Operating Summary
------------------------------------------------------------------------------------------------------------------------------------
                                                  2003     2002     2001     2000     1999     1998     1997    1996    1995   1994
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                                
Exploration and Production
Net production of crude oil and condensate -
  (thousands of barrels per day)
     United States                                76.5     81.3     77.7     73.7     79.3     66.2     70.6    73.8    74.8    73.4
     North Sea                                    71.6    102.8    101.9    117.7    102.9     87.4     83.3    86.5    91.9    88.7
     China                                         2.1      3.3      3.8      4.5      5.2      7.6      8.7     3.7       -       -
     Other international                             -      3.9      5.5      4.5      4.3      5.7      7.0    11.2    16.4    26.4
                                                ------------------------------------------------------------------------------------
       Total                                     150.2    191.3    188.9    200.4    191.7    166.9    169.6   175.2   183.1   188.5
                                                ------------------------------------------------------------------------------------
Average price of crude oil sold (per barrel) -
     United States                              $26.14   $21.56   $22.05   $27.50   $16.90   $12.78   $18.45  $19.56  $15.78  $14.25
     North Sea                                   25.82    22.41    23.23    27.92    17.88    12.93    18.93   19.60   16.56   15.33
     China                                       29.66    24.84    21.94    27.54    15.23    11.79    17.71   19.53       -       -
     Other international                             -    20.28    19.14    24.55    12.99     7.23    12.60   14.53   14.91   14.58
       Average                                  $26.04   $22.04   $22.60   $27.69   $17.30   $12.63   $18.40  $19.26  $16.10  $14.80
Natural gas sales (MMcf per day)                   726      760      596      531      580      584      685     781     809     872
Average price of natural gas sold (per Mcf)     $ 4.37   $ 2.95   $ 3.83   $ 3.87   $ 2.38   $ 2.13   $ 2.44  $ 2.11  $ 1.63  $ 1.82
Net exploratory wells drilled(1)-
     Productive                                    6.7      4.8      2.4      1.3      1.7      4.4      7.7     6.9     4.7    11.6
     Dry                                          17.0     17.2     11.4     10.5      3.8     14.4      7.4     5.5    11.2    13.5
                                                ------------------------------------------------------------------------------------
       Total                                      23.7     22.0     13.8     11.8      5.5     18.8     15.1    12.4    15.9    25.1
                                                ------------------------------------------------------------------------------------
 Net development wells drilled(1)-
     Productive                                  244.4    196.3    128.6     47.8     46.2     62.3     95.8   143.3   135.9    69.3
     Dry                                           1.1      1.4      6.6      5.4      5.9      9.0      7.0    13.1    11.9     9.6
                                                ------------------------------------------------------------------------------------
       Total                                     245.5    197.7    135.2     53.2     52.1     71.3    102.8   156.4   147.8    78.9
                                                ------------------------------------------------------------------------------------
Undeveloped net acreage (thousands)(1)-
     United States                               2,884    2,399    2,382    2,020    1,560    1,487    1,353   1,099   1,280   1,415
     North Sea                                     369      871      932      923      861      908      523     560     570     629
     China                                       1,488    1,046      917      961      346    1,481    2,183     925     341     282
     Other international                        47,178   41,514   50,450   25,117   18,693   13,235   12,447   3,631   3,690   7,212
                                                ------------------------------------------------------------------------------------
       Total                                    51,919   45,830   54,681   29,021   21,460   17,111   16,506   6,215   5,881   9,538
                                                ------------------------------------------------------------------------------------
Developed net acreage (thousands)(1)-
     United States                               1,352    1,266    1,192      729      796      810      830     871   1,190   1,270
     North Sea                                     136      109      149      115      105      115       70      79      58      68
     China                                           -       17       17       17       19       19       19      19      19      19
     Other international                             -        1      639      639      766      593      182     179     188     996
                                                ------------------------------------------------------------------------------------
       Total                                     1,488    1,393    1,997    1,500    1,686    1,537    1,101   1,148   1,455   2,353
                                                ------------------------------------------------------------------------------------
Estimated proved reserves(1)-
   (millions of equivalent barrels)              1,026    1,033    1,509    1,088      920      901      892     849     864   1,059
Chemicals
Titanium dioxide pigment
   production (thousands of tonnes)                532      508      483      480      320      284      168     155     154     148
------------------------------------------------------------------------------------------------------------------------------------


(1)  Includes discontinued operations.



Item 9. Change 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 design and operation 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  were no  significant  changes  in the
company's internal controls or in other factors that could significantly  affect
these controls subsequent to the date of their evaluation.

                                    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 11,
         2004.

(b)  Identification of executive officers -

         The information required under this section is set forth in the caption
         "Executive  Officers of the Registrant" on pages 23 and 24 of this 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 11, 2004.

(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 Item 2. of
         this  Form  10-K  under   "Availability   of  Reports  and   Governance
         Documents."

(e)  Audit committee financial expert -

         For information  required under this section,  reference is made to the
         "Information  About the Board" section of the company's proxy statement
         made in connection with its Annual Stockholders'  Meeting to be held on
         May 11, 2004.


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 11, 2004.


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, 2003, is included in the
following table:


                                                   Number of shares of                               Number of shares
                                                    common stock to be      Weighted-average      remaining available
                                                  issued upon exercise     exercise price of      for future issuance
                                                        of outstanding           outstanding             under equity
                                                     options, warrants     options, warrants             compensation
                                                            and rights            and rights                    plans (1)
---------------------------------------------------------------------------------------------------------------------
                                                                                                   
Equity compensation plans approved
  by security holders                                        5,591,602                $55.68                4,232,453
Equity compensation plans not
  approved by security holders                                 827,117                 58.32                  531,133
                                                             ---------                                      ---------
      Total                                                  6,418,719                 56.02                4,763,586
                                                             =========                                      =========


(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.
This plan is a  broad-based  stock option plan that provides 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 10.14 to the  company's  December 31, 2003
Form 10-K.

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 11,
2004.


Item 13. Certain Relationships and Related Transactions

None.


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 11, 2004.


                                     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 Form 10-K.

(a)     2.    Financial Statement  Schedules - See the  Index to  the  Financial
              Statement Schedules included in Item 8. of this Form 10-K.

(a)     3.    Exhibits - The following documents are filed under 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
                    company's  Registration Statement on Form S-4 dated June 28,
                    2001, and incorporated herein by reference.

            3.2     Amended and restated By Laws of Kerr-McGee Corporation.

            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
                    company's  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  company's  Registration  Statement on
                    Form 8-A/A filed on August 1, 2001, and incorporated  herein
                    by reference.

            4.3     Indenture dated as of November 1, 1981,  between the company
                    and United  States  Trust  Company of New York,  as trustee,
                    relating to the  company's  7%  Debentures  due  November 1,
                    2011,  filed as Exhibit 4 to Form S-16,  effective  November
                    16, 1981, Registration No. 2-772987, and incorporated herein
                    by reference.

            4.4     Indenture dated as of August 1, 1982,  filed as Exhibit 4 to
                    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.

            4.5     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 company:  the Note Agreement  dated as
                    of  November  29,  1989,  among the  Kerr-McGee  Corporation
                    Employee Stock  Ownership Plan Trust (the Trust) and several
                    lenders,  providing for a loan  guaranteed by the company of
                    $125  million to the Trust;  the $150  million,  8.375% Note
                    Agreement  entered  into by Oryx dated as of July 17,  1996,
                    and due  July  15,  2004;  the  $150  million,  8-1/8%  Note
                    Agreement entered into by Oryx dated as of October 20, 1995,
                    and due October 15, 2005; the amended and restated Revolving
                    Credit  Agreement dated as of January 11, 2002,  between the
                    company or certain  subsidiary  borrowers  and various banks
                    providing  for revolving  credit up to $650 million  through
                    January 12, 2006; the $700 million Credit Agreement dated as
                    of  November  14,  2003,  between  the  company  or  certain
                    subsidiary  borrowers  and  various  banks  providing  for a
                    364-day  revolving  credit  facility;  and the $200  million
                    variable-interest  rate Note Agreement  dated June 26, 2001,
                    and due  June 28,  2004.  The  total  amount  of  securities
                    authorized  under each of such  instruments  does not exceed
                    10% of the total assets of the company and its  subsidiaries
                    on a consolidated basis.

            4.6     Kerr-McGee   Corporation   Direct   Purchase   and  Dividend
                    Reinvestment  Plan filed on September  9, 2001,  pursuant to
                    Rule  424(b)(2)  of  the  Securities  Act  of  1933  as  the
                    Prospectus  Supplement  to the  Prospectus  dated August 31,
                    2001, and incorporated herein by reference.

            4.7     Second Supplement to the August 1, 1982,  Indenture dated as
                    of August 2, 1999,  between the company and Citibank,  N.A.,
                    as trustee,  relating to the company's  5-1/2%  exchangeable
                    notes  due  August 2,  2004,  filed as  Exhibit  4.11 to the
                    report on Form 10-K for the year ended  December  31,  1999,
                    and incorporated herein by reference.

            4.8     Fifth  Supplement to the August 1, 1982,  Indenture dated as
                    of February  11,  2000,  between  the company and  Citibank,
                    N.A.,  as  trustee,   relating  to  the   company's   5-1/4%
                    Convertible  Subordinated  Debentures due February 15, 2010,
                    filed as Exhibit 4.1 to Form 8-K filed February 4, 2000, and
                    incorporated herein by reference.

            4.9     Indenture  dated as of August 1, 2001,  between  the company
                    and Citibank,  N.A.,  as trustee,  relating to the company's
                    $350 million, 5-3/8% notes due April 15, 2005; $325 million,
                    5-7/8% notes due  September 15, 2006;  $675 million,  6-7/8%
                    notes due September 15, 2011;  and $500 million 7-7/8% notes
                    due  September  15,  2031,  filed as Exhibit 4.1 to Form S-3
                    Registration Statement No. 333-68136 Pre-effective Amendment
                    No. 1, and incorporated herein by reference.

           10.1*    Kerr-McGee   Corporation  Deferred   Compensation  Plan  for
                    Non-Employee  Directors  as amended and  restated  effective
                    January 1, 2003,  filed as Exhibit 10.1 to the Form 10-K for
                    the year ended December 31, 2002, and incorporated herein by
                    reference.

           10.2*    Kerr-McGee  Corporation Executive Deferred Compensation Plan
                    as amended and restated  effective January 1, 2003, filed as
                    Exhibit  10.4 to the Form 10-K for the year  ended  December
                    31, 2002, and incorporated herein by reference.

           10.3*    Benefits  Restoration Plan as amended and restated effective
                    May 1, 1999.

           10.4*    First Supplement to Benefits Restoration Plan as amended and
                    restated effective January 1, 2000.

           10.5*    Second  Supplement to Benefits  Restoration  Plan as amended
                    and restated effective January 1, 2001.

           10.6*    Kerr-McGee  Corporation  Supplemental  Executive  Retirement
                    Plan as amended and  restated  effective  February 26, 1999,
                    filed as  exhibit  10.6 to the  report  on Form 10-K for the
                    year ended  December 31, 2001,  and  incorporated  herein by
                    reference.

           10.7*    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 report on
                    Form  10-K  for  the  year  ended  December  31,  2001,  and
                    incorporated herein by reference.

           10.8*    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 report on
                    Form  10-K  for  the  year  ended  December  31,  2001,  and
                    incorporated herein by reference.

           10.9*    The Long Term  Incentive  Program  as amended  and  restated
                    effective  May 9, 1995,  filed as Exhibit  10.5 on Form 10-Q
                    for the  quarter  ended  March 31,  1995,  and  incorporated
                    herein by reference.

           10.10*   The  Kerr-McGee  Corporation  1998 Long Term  Incentive Plan
                    effective  January  1, 1998,  filed as Exhibit  10.4 on Form
                    10-Q for the quarter ended March 31, 1998, and  incorporated
                    herein by reference.

           10.11*   The  Kerr-McGee  Corporation  2000 Long Term  Incentive Plan
                    effective  May 1, 2000,  filed as Exhibit  10.4 on Form 10-Q
                    for the  quarter  ended  March 31,  2000,  and  incorporated
                    herein by reference.

           10.12*   The 2002 Long Term  Incentive  Plan  effective May 14, 2002,
                    filed as  Exhibit  10.1 on Form 10-Q for the  quarter  ended
                    June 30, 2002, and incorporated herein by reference.

           10.13*   The 2002 Annual  Incentive  Compensation  Plan effective May
                    14, 2002, filed as Exhibit 10.1 on Form 10-Q for the quarter
                    ended June 30, 2002, and incorporated herein by reference.

           10.14*   Kerr-McGee  Corporation  Performance  Share  Plan  effective
                    January 1, 1998, filed as Exhibit 10.19 to the Form 10-K for
                    the year ended December 31, 2002, and incorporated herein by
                    reference.

           10.15*   Oryx  Energy  Company  1992  Long-Term  Incentive  Plan,  as
                    amended and restated May 1, 1997.

           10.16*   Oryx  Energy  Company  1997  Long-Term  Incentive  Plan,  as
                    amended and restated May 1, 1997.

           10.17*   Amended and restated  Agreement,  restated as of January 11,
                    2000,  between  the  company  and Luke R.  Corbett  filed as
                    Exhibit  10.10 on Form 10-K for the year ended  December 31,
                    2000, and incorporated herein by reference.

           10.18*   Amended and restated  Agreement,  restated as of January 11,
                    2000,  between the  company  and Kenneth W. Crouch  filed as
                    Exhibit  10.11 on Form 10-K for the year ended  December 31,
                    2000, and incorporated herein by reference.

           10.19*   Amended and restated  Agreement,  restated as of January 11,
                    2000,  between the company and Robert M.  Wohleber  filed as
                    Exhibit  10.12 on Form 10-K for the year ended  December 31,
                    2000, and incorporated herein by reference.

           10.20*   Amended and restated  Agreement,  restated as of January 11,
                    2000,  between the company and William P. Woodward  filed as
                    Exhibit  10.13 on Form 10-K for the year ended  December 31,
                    2000, and incorporated herein by reference.

           10.21*   Amended and restated  Agreement,  restated as of January 11,
                    2000,  between the company and Gregory F.  Pilcher  filed as
                    Exhibit  10.14 on Form 10-K for the year ended  December 31,
                    2000, and incorporated herein by reference.

           10.22*   Form of  agreement,  amended and  restated as of January 11,
                    2000, between the company and certain executive officers not
                    named in the Summary  Compensation  Table  contained  in the
                    company's  definitive  Proxy  Statement  for the 2001 Annual
                    Meeting of Stockholders  filed as Exhibit 10.15 on Form 10-K
                    for the year  ended  December  31,  2000,  and  incorporated
                    herein by reference.

            12      Computation of ratio of earnings to fixed charges.

            14      Code of Ethics.

            21      Subsidiaries of the Registrant.

            23      Consent of Ernst & Young LLP.

            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.


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


(b)  Reports on Form 8-K -

     The following  Current Reports on Form 8-K were filed by the company during
     the quarter ended December 31, 2003:

     o Current  Report dated October 22, 2003,  announcing a conference  call to
       discuss  the  company's   third-quarter   2003  financial  and  operating
       activities, and expectations for the future.

     o Current  Report  dated  October 29, 2003,  announcing a security  analyst
       meeting to discuss the company's financial and operating outlook for 2003
       and certain  expectations for oil and natural gas production  volumes for
       the year 2003.

     o Current Report dated October 29, 2003,  announcing the company had posted
       on its website a table  containing  hedge  guidance for 2003 and 2004 oil
       and gas derivative instruments.

     o Current Report dated October 29, 2003,  announcing the company had posted
       on its website a table  containing a  reconciliation  of GAAP to Adjusted
       Net  Income for the  year-to-date  and  quarterly  fiscal  periods  ended
       September 30, 2003.

     o Current   Report  dated  October  29,  2003,   announcing  the  company's
       third-quarter 2003 earnings.

     o Current Report dated November 3, 2003,  announcing that the company would
       present at the Merrill  Lynch  Global  Energy  Conference  on November 5,
       2003.

     o Current Report dated November 13, 2003,  announcing certain  expectations
       for oil and natural gas production volumes for the year 2004.

     o Current Report dated November 14, 2003, announcing that the company would
       present at the Banc of America  Securities 2003 Energy & Power Conference
       on November 18, 2003.

     o Current Report dated November 20, 2003,  announcing a conference  call to
       discuss the company's interim fourth-quarter 2003 financial and operating
       activities, and expectations for the future.

     o Current Report dated November 25, 2003, announcing the company had posted
       on its website a table  containing  hedge  guidance for 2003 and 2004 oil
       and gas derivative instruments.

     o Current Report dated November 25, 2003,  announcing certain  expectations
       for oil and natural gas production volumes for the year 2003.

     o Current Report dated December 1, 2003,  announcing that the company would
       present at the Friedman, Billings, Ramsey 10th Annual Investor Conference
       on December 3, 2003.

     o Current Report dated December 9, 2003, announcing certain updates to 2004
       oil and gas hedge positions.

     o Current Report dated December 17, 2003,  announcing a conference  call to
       discuss the company's interim fourth-quarter 2003 financial and operating
       activities, and expectations for the future.

     o Current  Report dated  December 23, 2003,  announcing a security  analyst
       meeting to discuss the company's financial and operating outlook for 2003
       and certain  expectations for oil and natural gas production  volumes for
       the year 2003.

     o Current  Report dated  December 23, 2003,  announcing a security  analyst
       meeting to discuss the company's financial and operating outlook for 2003
       and certain  expectations for oil and natural gas production  volumes for
       the year 2004.



                                                                     SCHEDULE II


                 KERR-McGEE CORPORATION AND SUBSIDIARY COMPANIES
                         VALUATION ACCOUNTS AND RESERVES


                                                                         Additions
                                                                 --------------------------
                                                  Balance at     Charged to      Charged to     Deductions     Balance at
                                                   Beginning     Profit and           Other           from         End of
(Millions of dollars)                                of Year           Loss        Accounts       Reserves           Year
---------------------                             ----------     ----------      ----------     ----------     ----------
                                                                                                     
Year Ended December 31, 2003
Deducted from asset accounts
    Allowance for doubtful notes
        and accounts receivable                        $  19           $  1           $   -           $  1          $  19
    Warehouse inventory obsolescence                       4              6               -              2              8
                                                       -----           ----           -----           ----          -----
           Total                                       $  23           $  7           $   -           $  3          $  27
                                                       =====           ====           =====           ====          =====

Year Ended December 31, 2002
Deducted from asset accounts
    Allowance for doubtful notes
        and accounts receivable                        $  21           $  -           $   -           $  2          $  19
    Warehouse inventory obsolescence                       5              1               -              2              4
                                                       -----           ----           -----           ----          -----
           Total                                       $  26           $  1           $   -           $  4          $  23
                                                       =====           ====           =====           ====          =====

Year Ended December 31, 2001
Deducted from asset accounts
    Allowance for doubtful notes
        and accounts receivable                        $  20           $  1           $   2           $  2          $  21
    Warehouse inventory obsolescence                       5              1               -              1              5
                                                       -----           ----           -----           ----          -----
           Total                                       $  25           $  2           $   2           $  3          $  26
                                                       =====           ====           =====           ====          =====





                                   SIGNATURES

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



                                                     KERR-McGEE CORPORATION




                                          By:      Luke R. Corbett*
                                                   -----------------------------
                                                   Luke R. Corbett,
                                                   Chief Executive Officer




March 11, 2004                            By:      (Robert M. Wohleber)
--------------                                     -----------------------------
       Date                                        Robert M. Wohleber
                                                   Senior Vice President and
                                                   Chief Financial Officer




                                          By:      (John M. Rauh)
                                                   -----------------------------
                                                   John M. Rauh
                                                   Vice President and Controller
                                                   and Chief Accounting Officer



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



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







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


                                     By:      Luke R. Corbett*
                                              ----------------------------------
                                              Luke R. Corbett, Director

                                     By:      William E. Bradford*
                                              ----------------------------------
                                              William E. Bradford, Director

                                     By:      Sylvia A. Earle*
                                              ----------------------------------
                                              Sylvia A. Earle, Director

                                     By:      David C. Genever-Watling*
                                              ----------------------------------
                                              David C. Genever-Watling, Director

March 11, 2004                       By:      Martin C. Jischke*
--------------                                ----------------------------------
       Date                                   Martin C. Jischke, Director

                                     By:      Leroy C. Richie*
                                              ----------------------------------
                                              Leroy C. Richie, Director

                                     By:      Matthew R. Simmons*
                                              ----------------------------------
                                              Matthew R. Simmons, Director

                                     By:      Farah M. Walters*
                                              ----------------------------------
                                              Farah M. Walters, Director

                                     By:      Ian L. White-Thomson*
                                              ----------------------------------
                                              Ian L. White-Thomson, Director


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


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