****
 **UNITED
STATES**
 **SECURITIES
AND EXCHANGE COMMISSION**
 **Washington,
D. C. 20549**
 **FORM
10-K**
 
 **ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d)**
 **OF
THE SECURITIES EXCHANGE ACT OF 1934**
 
 **For
the Fiscal Year Ended December 31, 2004**
 
 **Commission
file number 1-16619**
 
 **KERR-MCGEE
CORPORATION**
 (Exact
name of registrant as specified in its charter)
 
 **DELAWARE**
    **73-1612389**(State
      or Other Jurisdiction of
    (I.R.S.
      EmployerIncorporation
      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 ONTITLE
      OF EACH CLASS
    
    WHICH
      REGISTEREDCommon
      Stock $1 Par Value
    
    New
      York Stock ExchangePreferred
      Share Purchase Right
 
 **Securities
registered pursuant to Section 12(g) of the Act:** None
 
 Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months and (2) has been subject to such filing requirements for the
past 90 days.  Yes x  No o
 
 Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [  ]
 
 Indicate
by check mark whether the registrant is an accelerated filer (as defined in Rule
12b-2 of the Act).
 Yes x  No o
 
 The
aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant was approximately $8.1 billion computed by
reference to the price at which the common equity was last sold as of June 30,
2004, the last business day of the registrant's most recently completed second
fiscal quarter.
 
 The
number of shares of common stock outstanding as of February 28, 2005, was
156,425,184. On March
2, 2005, an additional 6,798,333 shares were issued upon conversion of 5.25%
debentures.
 
  **DOCUMENTS
INCORPORATED BY REFERENCE**
 
 The
definitive Proxy Statement for the 2005 Annual Meeting of Stockholders, which
will be filed with the Securities and Exchange Commission within 120 days after
December 31, 2004, is incorporated by reference in Part III of this Form
10-K.
 
   
 
 **KERR-McGEE
CORPORATION**
  **PART
I**
 
 **Items
1. and 2. Business and Properties**
  **GENERAL
DEVELOPMENT OF BUSINESS**
  Through
its predecessors, Kerr-McGee Corporation began operations in 1929 as a privately
held company. In 1956 the company’s stock began trading publicly on the New York
Stock Exchange under the ticker symbol “KMG.” Kerr-McGee's worldwide businesses
and those of its subsidiaries are consolidated for financial reporting and
disclosure purposes. Accordingly, the terms "Kerr-McGee," "the company,” “we,”
“our” and similar terms are used interchangeably in this Form 10-K to refer to
the consolidated group or to one or more of the companies that are part of the
consolidated group.
 
 Kerr-McGee
is an energy and inorganic chemical holding company whose consolidated
subsidiaries, joint ventures and other affiliates (together, "affiliates") have
operations throughout the world. Our core businesses include:
 
 ·
    *Exploration
      and Production*- Kerr-McGee is one of the largest independent oil and gas exploration and
      production companies in the world, with major areas of operation onshore
      in the United States, in the Gulf of Mexico, the United Kingdom sector of
      the North Sea and China. In addition, we have strategic exploration
      programs in Alaska, Brazil, Morocco, Bahamas, and Benin. The company
      actively acquires leases and concessions and explores for, develops,
      produces and markets crude oil and natural gas.
 
 ·
    *Chemical*- Kerr-McGee affiliates engaged in chemical businesses produce and market
      inorganic industrial chemicals (primarily titanium dioxide pigment),
      lithium-metal-polymer batteries and heavy minerals. We are the world’s
      third-largest producer and marketer of titanium dioxide pigment in terms
      of volumes produced.
 
 The
following table provides an overview of our operating performance and the
composition of our assets and revenues by segment:
 
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002
    
    2001
    
    2000Assets
      -Exploration
      and Production
    
    **$**
    **12,246**
    
    $
    7,385
    
    $
    7,030
    
    $
    8,076
    
    $
    4,849Chemical
    
    
    **1,543**
    
    
    1,734
    
    
    1,655
    
    
    1,631
    
    
    1,638Corporate
      and other
    
    
    **729**
    
    
    1,131
    
    
    1,224
    
    
    1,369
    
    
    1,179Total
    
    **$**
    **14,518**
    
    $
    10,250
    
    $
    9,909
    
    $
    11,076
    
    $
    7,666Revenues
      -Exploration
      and Production
    
    **$**
    **3,855**
    
    $
    2,923
    
    $
    2,450
    
    $
    2,428
    
    $
    2,802Chemical
    
    
    **1,302**
    
    
    1,157
    
    
    1,065
    
    
    1,023
    
    
    1,153Total
    
    **$**
    **5,157**
    
    $
    4,080
    
    $
    3,515
    
    $
    3,451
    
    $
    3,955Income
      (Loss) from Continuing Operations
    
    **$**
    **415**
    
    $
    264
    
    $
    (590
    )
    $
    480
    
    $
    812
 
 
 
 
 
 
 Except
for information or data specifically incorporated herein by reference under
Items 10 through 14, other information and data appearing in the company’s 2005
Proxy Statement are not deemed to be filed as part of this annual report on Form
10-K.
  - 1 -
  On June
25, 2004, we completed a merger with Westport Resources Corporation (Westport),
an independent exploration and production company with operations onshore in the
Rocky Mountain, Mid-Continent and Gulf coast areas in the U.S. and in the Gulf
of Mexico. The merger added 281 million barrels of oil equivalent (boe) to our
reserves, an increase of 27% from year-end 2003. In exchange for Westport’s
common stock and options, Kerr-McGee issued stock valued at $2.4 billion,
options valued at $34 million and assumed debt of $1 billion, for a total of
$3.5 billion (net of $43 million of cash acquired). The fair value assigned to
assets acquired and goodwill totaled $4.7 billion. For a more detailed
description of the Westport merger, see Note 2 to the Consolidated Financial
Statements included in Item 8 of this annual report on Form 10-K.
 
 On
August 1, 2001, the company completed the acquisition of all the outstanding
shares of common stock of HS Resources, Inc., an independent oil and gas
exploration and production company with active projects in the Denver-Julesburg
Basin, Gulf Coast, Mid-Continent and Northern Rocky Mountain regions of the U.S.
Through this acquisition, we added approximately 217 million boe of proved
reserves, primarily consisting of natural gas reserves in the Denver, Colorado,
area, and expanded our low-risk exploitation drilling opportunities. The
acquisition price totaled $1.8 billion in cash, company stock and assumption of
debt. In connection with the HS Resources, Inc. acquisition, we completed a
holding company reorganization in which Kerr-McGee Operating Corporation,
formerly known as Kerr-McGee Corporation, changed its name and became a wholly
owned subsidiary of the company. In this Form 10-K, filings and references to
the company include business activity conducted by the current Kerr-McGee
Corporation and the former Kerr-McGee Corporation before it reorganized as a
subsidiary of the company and changed its name to Kerr-McGee Operating
Corporation. At the end of 2002, another reorganization took place, whereby
among other changes, Kerr-McGee Operating Corporation distributed its investment
in certain subsidiaries (primarily the oil and gas operating subsidiaries) to a
newly formed intermediate holding company, Kerr-McGee Worldwide Corporation.
Kerr-McGee Operating Corporation formed a new subsidiary, Kerr-McGee Chemical
Worldwide LLC, and merged into it.
 
 In
addition to a discussion of recent business developments provided below,
reference is made to Management’s Discussion and Analysis included in Item 7 of
this annual report on Form 10-K, and the Exploration and Production Operations
and Chemical Operations discussions below.
 
 **RECENT
DEVELOPMENTS**
 
 **Company
to Pursue the Separation of its Chemical Business**
 
 The
company announced on March 8, 2005, that its Board of Directors (the Board)
authorized management to proceed with its proposal to pursue alternatives for
the separation of the chemical business, including a spinoff or sale.
 
 **Share
Repurchase Program**
 
 On
March 8, 2005, the Board authorized the company to proceed with a share
repurchase program initially set at $1 billion. The Board expects to expand the
share repurchase program as the chemical business separation proceeds. The
initial $1 billion share repurchase program primarily will be financed through
the use of free cash flow generated from operations after planned capital
expenditures, which is projected to be approximately $850 million in 2005. To
ensure a portion of the projected cash flow, the company has entered into
commodity derivative instruments covering approximately 50% of its
projected oil and gas production.  The company also expects to utilize a
portion of its existing bank credit facility and may issue new securities, which
may be in the form of debt or perpetual preferred stock, to fund the remaining
repurchase program. The company still intends to retire $450 million of debt
maturities due in 2005 in addition to the conversion of subordinated debentures
discussed below. The Board and management reiterated their commitment to
maintain an investment-grade credit rating.
 
 The
timing and final number of shares to be repurchased under an expanded repurchase
program will depend on the outcome of the chemical business separation, as well
as business and market conditions, applicable securities law limitations and
other factors. Shares may be purchased from time to time in the open market or
through privately negotiated transactions at prevailing prices, and the program
may be suspended or discontinued at any time without prior notice.
 
 - 2 -
 **Recommendation
to Increase Authorized Stock**
 
 The
company’s Board of Directors in the March 8, 2005 meeting recommended for the
stockholders to approve an increase of the authorized number of shares of the
company’s common stock, par value $1.00 share, from 300 million shares to 500
million shares.
 
 **Conversion
of 5.25% Debentures**
 
 In
February 2005, the company called for redemption all of the $600 million
aggregate principal amount of its 5.25% convertible subordinated debentures due
2010 at a price of 102.625%. Prior to March 4, 2005, the redemption date, all of
the debentures were converted by the holders into approximately 9.8 million
shares of common stock. As a result of this conversion, the number of total
common shares outstanding increased to approximately 162 million as of March 11,
2005. Pro forma for the conversion, the company’s year-end 2004 total debt to
total capitalization ratio would have been 34%.
 
  **SEGMENT
AND GEOGRAPHIC INFORMATION**
  For
financial information by operating segment and geographic information, see Note
27 to the Consolidated Financial Statements included in Item 8 of this annual
report on Form 10-K.
 
  **EXPLORATION
AND PRODUCTION OPERATIONS**
  Our
exploration and production business is focused on achieving value-added growth
through exploration, exploitation and acquisitions. The company’s high-impact
deepwater exploration efforts are balanced with lower risk exploration
activities in proven world-class hydrocarbon basins in areas such as Brazil,
Alaska, and China, as well as the U.S. onshore, Gulf of Mexico shelf and the
North Sea. Through our strategic merger with Westport in 2004, we added
complementary high-quality assets in core U.S. onshore and Gulf of Mexico
regions. Combined with our existing U.S. assets, the Westport properties provide
a stable foundation of high-margin production and low-risk growth opportunities,
complementing our high-impact deepwater exploration program. The Westport
acquisition added net proved reserves of 281 million boe, approximately
two-thirds of which were natural gas reserves. Primarily as a result of this
acquisition, natural gas reserves as a percentage of total proved reserves
increased from 52% to 57% during 2004. Additionally, we increased proved
developed reserves as a percentage of total proved reserves from 50% at December
31, 2003 to 65% by the end of 2004. This increase is attributable to both the
Westport merger and to development investments made during the course of the
year.
 
 Strong
crude oil and natural gas prices combined with record production during 2004
contributed to a 25% year-over-year increase in segment operating profit, which
was $1.2 billion for 2004. The company’s 2004 average daily production was
312,200 boe, a 15% increase from 2003. Natural gas production volume averaged
921 million cubic feet per day, an increase of 27% from 2003, and crude oil
production volumes increased 6% in 2004 to 158,800 barrels per day. We ended
2004 with record fourth quarter production levels of 372,000 boe per day. The
increase in production volumes during 2004 was largely attributable to the
Westport merger. For 2005, we expect annual production to average between
352,000 and 367,000 boe per day.
 
  - 3 -
  **Oil
and Gas Sales Revenues, Volumes, Prices and Production
Costs**
 
 The
following table summarizes the company's crude oil and natural gas sales volumes
and sales revenues from continuing operations for each of the three years in the
period ended December 31, 2004. Sales revenues presented below include the
impact of the company’s hedging program. For information on the average realized
sales prices including and excluding the effect of hedging arrangements, refer
to Management’s Discussion and Analysis of Financial Condition and Results of
Operations - Segment Operations in Item 7 of this annual report on Form 10-K.
Note 30 to the Consolidated Financial Statements included in Item 8 of this
report presents the average lifting costs per boe.
 
 
 (Millions)
    
    **2004**
    
    2003
    
    2002Crude
      oil and condensate (barrels)U.S.
      Gulf of Mexico
    
    
    **21.9**
    
    
    20.7
    
    
    19.2U.S.
      onshore
    
    
    **10.3**
    
    
    7.2
    
    
    10.5North
      Sea
    
    
    **23.2**
    
    
    26.1
    
    
    37.2China
    
    
    **2.8**
    
    
    0.8
    
    
    1.2Other
      international
    
    
    **-**
    
    
    -
    
    
    1.4******58.2**
    
    
    54.8
    
    
    69.5Crude
      oil and condensate sales revenuesU.S.
      Gulf of Mexico
    
    **$**
    **644.6**
    
    $
    540.3
    
    $
    414.8U.S.
      onshore
    
    
    **293.1**
    
    
    188.1
    
    
    224.8North
      Sea
    
    
    **613.7**
    
    
    673.9
    
    
    832.8China
    
    
    **92.2**
    
    
    23.2
    
    
    29.5Other
      international
    
    
    **-**
    
    
    -
    
    
    28.9**$**
    **1,643.6**
    
    $
    1,425.5
    
    $
    1,530.8Natural
      gas (thousands of cubic feet)U.S.
      Gulf of Mexico
    
    
    **133.1**
    
    
    101.0
    
    
    99.8U.S.
      onshore
    
    
    **172.6**
    
    
    128.5
    
    
    141.0North
      Sea
    
    
    **31.2**
    
    
    35.4
    
    
    36.7**336.9**
    
    
    264.9
    
    
    277.5Natural
      gas sales revenuesU.S.
      Gulf of Mexico
    
    **$**
    **724.0**
    
    $
    493.1
    
    $
    322.2U.S.
      onshore
    
    
    **877.5**
    
    
    553.8
    
    
    410.5North
      Sea
    
    
    **127.0**
    
    
    109.3
    
    
    86.4**$**
    **1,728.5**
    
    $
    1,156.2
    
    $
    819.1
 
 **Reserves**
 
 Kerr-McGee’s
estimated crude oil, condensate, natural gas liquids and natural gas proved
reserves at December 31, 2004, and the changes in net quantities of such
reserves for the three years then ended are shown in Note 32 to the Consolidated
Financial Statements included in Item 8 of this annual report on Form 10-K.
Estimates of total proved reserves filed with or included in reports to any
other Federal authority or agency during 2004, are within 5% of amounts shown in
this filing.
 
 Estimates
of proved reserves and associated future net cash flows are made by the
company’s engineers and, for certain acquired Westport properties,
third-party reserve engineers. In 2004, we engaged the independent reserve
engineering firm of Netherland, Sewell & Associates, Inc. (NSAI) to review
methods and procedures used by our engineers to estimate December 31, 2004
reserve quantities and future revenue for certain oil and gas properties located
in the United States. For additional information with respect to NSAI’s review
and the company’s methods and procedures employed in the reserve estimation
process, see Note 32 to the Consolidated Financial Statements included in Item 8
of this annual report on Form 10-K.
 
 
  - 4 -
  **Developed
and Undeveloped Acreage**
 
 The
following table summarizes the company’s developed and undeveloped acreage held
through leases, concessions, reconnaissance permits and other interests at
December 31, 2004:
 
 **Developed
      Acreage**
    
    **Undeveloped
      Acreage**Location
    
    Gross
    
    Net
    
    Gross
    
    NetUnited
      States -Gulf
      of Mexico
    
    
    933,499
    
    
    381,632
    
    
    3,604,879
    
    
    2,097,040Alaska
    
    
    -
    
    
    -
    
    
    18,087
    
    
    12,661Onshore
    
    
    2,903,532
    
    
    1,752,601
    
    
    2,337,695
    
    
    1,256,9343,837,031
    
    
    2,134,233
    
    
    5,960,661
    
    
    3,366,635North
      Sea
    
    
    363,403
    
    
    121,378
    
    
    792,495
    
    
    392,286China(1)
    
    
    22,487
    
    
    9,015
    
    
    1,664,500
    
    
    1,469,130Other
      international -Morocco
    
    
    -
    
    
    -
    
    
    30,245,687
    
    
    13,973,805Australia
    
    
    -
    
    
    -
    
    
    10,031,824
    
    
    6,129,398Canada
    
    
    -
    
    
    -
    
    
    2,087,220
    
    
    1,310,826Benin
    
    
    -
    
    
    -
    
    
    2,459,439
    
    
    1,721,607Bahamas
    
    
    -
    
    
    -
    
    
    6,488,680
    
    
    6,488,680Brazil
    
    
    -
    
    
    -
    
    
    2,218,369
    
    
    830,424-
    
    
    -
    
    
    53,531,219
    
    
    30,454,740Total
    
    
    4,222,921
    
    
    2,264,626
    
    
    61,948,875
    
    
    35,682,791
 
 
 (1)
    Subsequent
      to December 31, 2004, Kerr-McGee signed a production sharing contract
      covering 2.4 million acres in the South China Sea with a 100% foreign
      contractor’s interest in the first phase of the exploration
      period.
 
 **Gross
and Net Productive Wells**
 
 The
number of productive oil and gas wells in which the company had an interest at
December 31, 2004, is shown in the following table. These wells include 1,888
gross or 857 net wells associated with improved recovery projects, and 2,584
gross or 2,472 net wells that have multiple completions but are included as
single wells.
 
 Location
    
    Crude
      Oil
    
    Natural
      Gas
    
    TotalUnited
      StatesGross
    
    
    4,332
    
    
    7,659
    
    
    11,991Net
    
    
    2,880
    
    
    4,495
    
    
    7,375North
      SeaGross
    
    
    274
    
    
    5
    
    
    279Net
    
    
    51
    
    
    -
    
    
    51ChinaGross
    
    
    31
    
    
    -
    
    
    31Net
    
    
    12
    
    
    -
    
    
    12TotalGross
    
    
    4,637
    
    
    7,664
    
    
    12,301Net
    
    
    2,943
    
    
    4,495
    
    
    7,438
 
 
  - 5 -
  **Net
Exploratory and Development Wells Drilled**
 
 Domestic
and international exploratory and development wells that were completed as
successful or dry holes during the three years ended December 31, 2004 are
summarized in the following tables.
 
 Net
      Exploratory(1)
    
    Net
      Development(1)Productive
    
    Dry
      Holes
    
    Total
    
    Productive
    
    Dry
      Holes
    
    Total
    
    Total2004(2)United
      States
    
    
    13.6
    
    
    9.5
    
    
    23.1
    
    
    412.7
    
    
    7.5
    
    
    420.2
    
    
    443.3North
      Sea
    
    
    -
    
    
    3.1
    
    
    3.1
    
    
    4.7
    
    
    -
    
    
    4.7
    
    
    7.8China
    
    
    -
    
    
    1.8
    
    
    1.8
    
    
    12.4
    
    
    -
    
    
    12.4
    
    
    14.2Other
      international
    
    
    -
    
    
    .9
    
    
    .9
    
    
    -
    
    
    -
    
    
    -
    
    
    .9Total
    
    
    13.6
    
    
    15.3
    
    
    28.9
    
    
    429.8
    
    
    7.5
    
    
    437.3
    
    
    466.22003United
      States
    
    
    6.7
    
    
    11.0
    
    
    17.7
    
    
    241.6
    
    
    1.0
    
    
    242.6
    
    
    260.3North
      Sea
    
    
    -
    
    
    1.0
    
    
    1.0
    
    
    2.1
    
    
    .1
    
    
    2.2
    
    
    3.2Other
      international
    
    
    -
    
    
    5.0
    
    
    5.0
    
    
    .7
    
    
    -
    
    
    .7
    
    
    5.7Total
    
    
    6.7
    
    
    17.0
    
    
    23.7
    
    
    244.4
    
    
    1.1
    
    
    245.5
    
    
    269.22002United
      States
    
    
    4.8
    
    
    11.1
    
    
    15.9
    
    
    186.9
    
    
    1.4
    
    
    188.3
    
    
    204.2North
      Sea
    
    
    -
    
    
    1.9
    
    
    1.9
    
    
    8.6
    
    
    -
    
    
    8.6
    
    
    10.5Other
      international
    
    
    -
    
    
    4.2
    
    
    4.2
    
    
    .8
    
    
    -
    
    
    .8
    
    
    5.0Total
    
    
    4.8
    
    
    17.2
    
    
    22.0
    
    
    196.3
    
    
    1.4
    
    
    197.7
    
    
    219.7
 
 
 (1)
    Net
      wells represent the company's fractional working interest in gross wells
      expressed as the equivalent number of full-interest
  wells.
 
 (2)
    The
      2004 net exploratory well count does not include 8.5 successful net wells
      drilled in the United States that are currently suspended, nor does it
      include 1.0 successful net well drilled in China, 1.6 successful net wells
      drilled in the North Sea, .3 successful net wells drilled internationally
      or 1.4 successful net wells drilled in the United States that will not be
      used for production.
 
 **Wells
in Process of Drilling**
 
 The
following table shows the number of wells in the process of drilling and the
number of wells suspended or awaiting completion as of December 31,
2004:
 
 Wells
      in Process of
    
    Wells
      Suspended orDrilling
    
    Awaiting
      CompletionExploration
    
    Development
    
    Exploration
    
    DevelopmentUnited
      StatesGross
    
    
    4.0
    
    
    19.0
    
    
    33.0
    
    
    33.0Net
    
    
    1.8
    
    
    11.5
    
    
    13.4
    
    
    14.5North
      SeaGross
    
    
    1.0
    
    
    1.0
    
    
    1.0
    
    
    2.0Net
    
    
    .3
    
    
    .1
    
    
    .4
    
    
    .2ChinaGross
    
    
    -
    
    
    1.0
    
    
    -
    
    
    -Net
    
    
    -
    
    
    .4
    
    
    -
    
    
    -TotalGross
    
    
    5.0
    
    
    21.0
    
    
    34.0
    
    
    35.0Net
    
    
    2.1
    
    
    12.0
    
    
    13.8
    
    
    14.7
 
 
  - 6 -
  
 **Product
S****ales and Marketing**
 
 Our oil
and natural gas production is sold at prevailing market prices, and the realized
revenue on the physical sale is adjusted for net realized gains or losses on
commodity derivative instruments designated to hedge sales of our oil and gas
production. For further details on such derivative instruments, see the *Market
Risks* section of Management’s Discussion and Analysis of Financial Condition and
Results of Operations in Item 7 of this annual report on Form 10-K.
 
 The
company markets all of its crude oil, located primarily in the Gulf of Mexico,
the U.K. North Sea and Bohai Bay, China, under a combination of term and spot
contracts to refiners, marketers and end users under market-reflective prices.
Our single-largest purchaser of crude oil during 2004 was BP PLC, accounting
for 23% of total crude oil sales revenues and 9% of total natural gas sales
revenues, or 17% of total crude oil and natural gas sales revenues. The
creditworthiness of each successful bidder is reviewed prior to product
delivery.
 
 Our
single-largest purchaser of domestic natural gas is Cinergy Marketing &
Trading LLC, whose purchases are guaranteed by its parent company, Cinergy
Corporation. Purchases by Cinergy represented approximately 48% of total gas
sales revenues, or 23% of total crude oil and natural gas sales revenues in
2004. Kerr-McGee manages this significant single-customer exposure through a
credit risk insurance policy.
 
 The loss of any one customer is not
expected to have a material effect on the company due to high demand
for oil and natural gas.
 
 Marketing
of the company's domestic natural gas from the Wattenberg and Greater Natural
Buttes fields, located in northeastern Colorado and northeastern Utah,
respectively, is facilitated through its subsidiary, Kerr-McGee Energy Services
Corporation (KMES). KMES is primarily engaged in the sale of the company's share
of gas production. To fulfill its direct sales obligations and to fully utilize
its contracted transportation capacity, KMES also purchases and markets natural
gas from third parties. KMES sells natural gas to a number of customers in the
Denver, Colorado, market, adjacent to the company's Wattenberg field. Natural
gas production from the Wattenberg and Uinta fields, along with other Rocky
Mountain fields acquired with the Westport merger, is sold at prevailing market
prices.
 
 North
Sea natural gas is sold both under contract and through spot market sales in the
geographic area of production.
 
 
 **Exploration
and Development Activities**
 
 The
following table shows a summary of key 2004 data for the company’s operating
areas. Production volumes are presented in thousands of barrels of oil
equivalent per day (Mboe/d). Reserve volumes are stated in thousands of barrels
of oil equivalent (Mboe). Additional information regarding oil and condensate
and natural gas production, along with average prices received in 2004, 2003,
and 2002 for the company's core geographic areas can be found in Management's
Discussion and Analysis of Financial Condition and Results of Operations in Item
7 of this annual report on Form 10-K.
 
 Estimated
      Proved
    
    
    
    Realized
      Sales PriceReserves
      at 12/31/04
    
    2004
      Production
    
    Including
      Effect of HedgesPercentage
    
    
    
    Percentage
    
    Oil
    
    GasMboe
    
    of
      Total
    
    Mboe/d
    
    of
      Total
    
    $
      per Barrel
    
    $
      per McfU.S.
      Gulf of Mexico
    
    
    325,805
    
    
    27
    %
    
    120
    
    
    38
    %
    $
    29.43
    
    $
    5.44U.S.
      onshore
    
    
    613,254
    
    
    50
    
    
    107
    
    
    34
    
    
    28.43
    
    
    5.08North
      Sea
    
    
    242,355
    
    
    20
    
    
    77
    
    
    25
    
    
    26.50
    
    
    4.06China
    
    
    36,686
    
    
    3
    
    
    8
    
    
    3
    
    
    32.37
    
    
    -Total
    
    
    1,218,100
    
    
    100
    %
    
    312
    
    
    100
    %
    $
    28.23
    
    $
    5.13
 
  - 7 -
  **U.S.
Gulf of Mexico**
 
 Kerr-McGee
has been one of the pioneering exploration and production companies in the Gulf
of Mexico since 1947, when we drilled the first successful well out of the sight
of land. This tradition has continued with the pursuit of oil and gas farther
offshore and in deeper water, where the company has developed a competitive
advantage through the use of innovative and cost-effective technologies.
Kerr-McGee was the first company to utilize floating production spar technology
in the Gulf of Mexico in 1997 for its Neptune development. We continued to
advance this technology through utilization of improved truss spar designs for
our developments at the Nansen, Boomvang and Gunnison discoveries, which were
sanctioned for development in 2000 and 2001. During 2004, first production was
achieved at the Red Hawk development, where we used new cell spar technology,
which lowers the threshold for economic development of deepwater reservoirs. The
innovative design of the cell spar reduces the cost of construction and
simplifies installation compared to other spar designs. Also in 2004, Kerr-McGee
sanctioned both the Constitution discovery, where the company’s fourth truss
spar will be utilized, and the Independence Hub, a deep draft semi-submersible
platform at a water depth of 8,000 feet. The nonoperated Independence Hub is
being constructed by a consortium including Kerr-McGee and five other companies
and is designed to process production from six fields including Kerr-McGee’s
Merganser, San Jacinto and Vortex fields.
 
 Our
merger with Westport led to increased production volumes and reserves in the
Gulf of Mexico. However, because reserves added with the merger were primarily
located in the U.S. onshore region, the weight of Gulf of Mexico proved reserves
in our portfolio declined from 35% at year-end 2003 to 27% at year-end 2004. In
2004, Gulf of Mexico production represented 38% of the company’s worldwide crude
oil and condensate production and 39% of its natural gas production, largely
unchanged from 2003. We expect that, in 2005, the Gulf of Mexico region will
represent 27% of the company’s total oil production and 39% of its natural gas
production.
 
 Kerr-McGee
is one of the largest independent exploration and production companies operating
in the Gulf of Mexico, with leases covering over 4.5 million gross acres. In
2004, the company maintained its position as one of the largest independent
leaseholders in the deepwater Gulf of Mexico with approximately 530 deepwater
blocks (deepwater locations are those in depths of more than 1,000 feet). We
believe this extensive acreage holding provides a significant competitive
advantage in our effort to maintain and develop a high-quality exploration
prospect inventory.
 
 **Exploration
Efforts**
 
 The
Gulf of Mexico was again a focus of our exploration efforts in 2004. A total of
fourteen deepwater exploratory wells were drilled or were drilling at the close
of 2004. These wells included new field wildcats, satellites to existing
infrastructure and appraisal wells to discoveries. In addition to the deepwater
program, twelve exploratory wells were spud on the shelf of the Gulf of Mexico.
Discoveries during 2004 included Ticonderoga (Green Canyon 768), Dawson Deep
(Garden Banks 625), San Jacinto (DeSoto Canyon 618) and Nile (Viosca Knoll 869).
Nile has been completed and will commence production in early 2005. Ticonderoga
and San Jacinto have been sanctioned and design and equipment procurement are
under way. Dawson Deep is anticipated to be sanctioned in 2005. Our exploration
efforts on the Gulf of Mexico shelf were more active in 2004 compared to the
prior year, which is the result of a focus on deep gas potential in a mature
area, as well as properties entering the inventory through the Westport
acquisition. The Westport inventory exposes Kerr-McGee to new trends and
complements the existing portfolio.
 
 To
further enhance the exploration program, we entered into a joint venture with
Stone Energy Corp. in the third quarter of 2004. This joint venture covers five
to seven deepwater prospects, as well as several prospects on the Gulf of Mexico
shelf. Drilling at the first of two deepwater wells in the joint venture package
was ongoing at the end of the year and reached target depth in early 2005. The
wells were declared unsuccessful in February 2005. Two additional exploration
wells are planned for 2005.
 
 At the
close of the year, Kerr-McGee had contracted four deepwater drilling rigs for
all or part of 2005, to facilitate execution of this part of the exploration
program. Securing rig availability should allow the exploration pace to quicken
and be maintained throughout 2005.
 
  - 8 -
  **Development
Activities**
 
 Our
development activity in the deepwater Gulf of Mexico also continued at a high
level during 2004 in terms of capital outlay, wells drilled and construction
activity. Gunnison well completion activity continued throughout the year,
gradually building the field’s production rates. Installation of a cell spar was
completed at Red Hawk and production began in July 2004. The Boomvang subsea
production loop was completed, resulting in first production from the East
Breaks 598 and 599 wells in the Boomvang field area.
 
 Kerr-McGee
also sanctioned participation in a joint project to develop several gas fields
in the ultra deep waters (defined as greater than 8,000 feet) in the eastern
Gulf of Mexico. The Independence Hub development will consist of a host
processing and export facility to be located in Mississippi Canyon Block 920.
This facility will receive production from six fields in the area through subsea
tieback systems. We own an interest in three of these fields as follows:
Merganser, Atwater Valley block 37 (50% - operator), Vortex, Atwater Valley
block 261 (50%), and San Jacinto, Desoto Canyon block 618 (20%). The project is
expected to be completed by year-end 2006, with first production anticipated in
the second quarter of 2007. Kerr McGee’s anticipated net production is over 100
million cubic feet of gas
per day .
 
 At the
company's Constitution development, significant progress was made in 2004 on the
truss spar construction. Development well drilling commenced in December 2004
and is expected to be
completed in the
second quarter of 2005. This Green Canyon (GC) block 679/680 discovery, which
was approved for development in January 2004, is operated by Kerr-McGee with a
100% working interest. In addition, Kerr-McGee finalized plans for subsea
tieback development of the Ticonderoga discovery (GC 768, 50% working interest)
to the Constitution truss spar. Production from Constitution and Ticonderoga is
expected to commence in the second quarter of 2006.
 
 **Deepwater
Gulf of Mexico**
 
 ***Nansen
field, East Breaks (EB) blocks 602 and 646 (50%):*** The
Nansen field was sanctioned for development in March 2000, and first production
was achieved in January 2002. Average 2004 gross production was 29,400 barrels
of oil per day and 147 million cubic feet of gas per day. The Nansen field is
developed with a truss spar in 3,700 feet of water and has nine dry-tree
producers and three subsea wells tied back to the spar from a subsea cluster.
Planned activity for 2005 includes the sidetracking of one subsea well and
recompletion of three dry tree wells.
 
 ***Navajo
field, East Breaks block 690 area (50%):*** **** The
Navajo field cluster is located on EB 646, 689 and 690. The Navajo discovery
well, located in block 690, was drilled in September 2001. Following discovery,
the well was completed and tied back to the Nansen spar located approximately
five miles to the north. First production from Navajo was achieved in June 2002.
Two previously drilled exploratory wells were completed and began production
through the Navajo subsea system in 2003. A recompletion of one Navajo well is
planned for 2005. Gross production from Navajo, West Navajo and Northwest Navajo
wells averaged 17 million cubic feet of gas per day and 4,300 barrels of oil per
day in 2004.
 
 ***Boomvang
field, East Breaks blocks 642, 643, 688 (30%), block 598 (50%) and block 599
(33%):*** The
Boomvang field was sanctioned for development in July 2000 and first production
was achieved in June 2002. The Boomvang field is developed with a truss spar in
3,450 feet of water and has five dry-tree producers and four subsea wells tied
back to the spar from two subsea clusters. Two successful exploratory wells
drilled on Kerr-McGee leases adjacent to the Boomvang field, EB 598 #1 and EB
599 #1, were tied back to the Boomvang spar during 2004. These two wells utilize
a new subsea pipeline and cluster system. First production from both wells was
achieved in October 2004. Average 2004 gross production from the Boomvang area
was 30,500 barrels of oil per day and 127 million cubic feet of gas per day.
 
 ***Gunnison
field, Garden Banks block 668 area (50%):*** The
Gunnison field, sanctioned for development in October 2001, incorporates a truss
spar in 3,100 feet of water and has seven dry-tree wells and three subsea wells.
First production from Gunnison started in 2003 from the three subsea wells,
which produced approximately 3,600 barrels of oil per day and 125 million cubic
feet of natural gas per day. During 2004, a completion rig was installed on the
spar and completion operations began on the seven dry-tree wells. The final
completion had to be sidetracked by the spar completion rig, but was placed on
production in December 2004. Throughout 2004, oil rates were ramped up to a
maximum of approximately 18,000 barrels of oil per day as wells were completed,
and gas rates were maintained between 100 and 140 million cubic feet per day.
Average gross production from Gunnison in 2004 was approximately 11,500 barrels
of oil per day and 119 million cubic feet of gas per day.
 
 - 9 -
 ***Red
Hawk field, Garden Banks block 877 (50%):*** Development of Red Hawk, a 2001 discovery, was sanctioned in July 2002,
utilizing the world’s first cell spar designed for developing smaller reservoirs
in deepwater basins. Located in approximately 5,300 feet of water, the field has
been developed using two subsea wells tied back to the cell spar. The two wells
were completed during 2003 prior to installation of the spar. In 2004, the cell
spar and production facilities were installed. The facilities were commissioned
and first production began in July 2004. By the start of August, gross
production had reached peak projected rates of 120 million cubic feet of gas per
day. At year-end 2004, the field was producing approximately 128 million cubic
feet of gas per day.
 
 ***Neptune
field, Viosca Knoll block 826 (50%):*** Production from the Neptune field began in March 1997 from the world's first
floating production spar. Presently, there are 11 dry-tree wells producing
through the facility at a water depth of 1,950 feet. Four subsea wells also
produced to the spar in 2004, and the Nile exploratory well was drilled and
completed in late 2004, with first production expected in 2005. Average 2004
gross production from Neptune was 10,800 barrels of oil per day and 33 million
cubic feet of gas per day. Additionally, platform upgrades are being completed
to accommodate Neptune’s first third-party tieback, the Swordfish development,
operated by Mariner. First production is planned for May 2005 and, along with
Kerr-McGee’s recent subsea tiebacks, is expected to increase gross Neptune gas
production to the expanded platform capacity of 100 million cubic feet per day.
 
 ***Conger
field, Garden Banks block 215 (25%):*** Average 2004 gross production from the Conger field was 28,000 barrels of oil
per day and 87 million cubic feet of gas per day.  First production from
the Conger field began in December 2000 from the first of three subsea
wells.  The three-well subsea development is the first multi-well,
15,000-psi subsea development and is located in approximately 1,500 feet of
water.  One additional well, a sidetrack of the Garden Banks 215 No. 6
well, was completed in December 2003. The Garden Banks 215 No. 8 well is
anticipated to deplete its existing completion during 2005 and will be
recompleted into a new zone, which is expected to increase production from this
well.
 
 ***Baldpate
field, Garden Banks block 260 (50%):*** Average 2004 gross production from the Baldpate field, including the Penn State
subsea satellite wells, was 14,100 barrels of oil per day and 36 million cubic
feet of gas per day.  The field is located in 1,690 feet of water and is
producing from an articulated compliant tower.  A successful exploration
well was drilled and completed in late 2003 in Garden Banks 216 (Penn State) and
was tied back to the existing Penn State subsea system.
 
 ***Pompano
field, Viosca Knoll block 989 area (25%):*** Average 2004 gross production from the Pompano field was 15,000 barrels of oil
per day and 24 million cubic feet of gas per day.  A platform rig was
installed on Pompano during 2004 for a multi-well workover / recompletion
program. Work on at least four wells is expected to be completed in the first
half of 2005.
 
 **Gulf
of Mexico Shelf**
 
 Production
commenced in 2004 from several Gulf of Mexico shelf discoveries. Three wells
were drilled at High Island 119 (42%), with initial gross production from two
wells at 30 million cubic feet of gas. The third High Island 119 discovery began
producing in January 2005. Three development wells and one exploratory well were
drilled in the second half of 2004 at South Timbalier 41 (40%) with initial
production of 15 million cubic feet of gas per day from the first well. First
production from the remaining three wells, along with continued drilling in the
field, is expected in 2005. In the fourth quarter of 2004, Garden Banks 208
(50%) began producing from a single subsea well at a gross rate of 15 million
cubic feet of gas per day and Eugene Island 29 (45%) began producing at a gross
rate of 5 million cubic feet of gas per day.
 
 Development
drilling took place in two fields in 2004. Two successful wells drilled at Main
Pass 108 (75%) began producing at a gross rate of 15 million cubic feet of gas
per day and two wells drilled in Ship Shoal 223 (32% to 45%) began producing at
a gross rate of 5 million cubic feet of gas per day and 700 barrels of oil per
day.
 
  - 10 -
  **U.S.
Onshore**
 
 In the
U.S. onshore exploration and production activities are segregated into two
divisions, Rocky Mountain and Southern.  Rocky Mountain operations are
located in Colorado, North Dakota, Montana, Utah and Wyoming. Southern
operations are primarily focused in Texas, Louisiana, Oklahoma, New Mexico
and Kansas. In 2004, U.S. onshore production represented 51% of the company’s
worldwide gas production, 18% of its oil production and 50% of total year-end
proved reserves. The weight of U.S. onshore proved reserves in our worldwide
portfolio increased from 34% at the beginning of the year, largely as a result
of our merger with Westport. We expect that in 2005, this region will represent
approximately 55% of the company’s total natural gas production and 20% of its
oil production.
 
 **Rocky
Mountain**
 
 ***Wattenberg
field, Northeast Colorado (94%):*** Kerr-McGee obtained an interest in the Wattenberg field area as the result of
the merger with HS Resources, Inc. in 2001. The Wattenberg gas field is located
in the Denver-Julesburg (DJ) basin in northeast Colorado. Our 2004 net
production from this field was 11,300 barrels of oil per day and 171 million
cubic feet of gas per day. During 2004, the company completed more than 300
development projects in the field, including deepenings, fracture stimulations,
recompletions and an aggressive infill drilling program. The drilling activities
in 2004 were focused on the Codell Niobrara formations, with approximately half
of the wells including additional depth to allow for future completion in the J
Sand. As part of the infill drilling program, 49 5 th spot
wells (5 th well
in 160 acres) were drilled in the field to recover reserves that are not being
drained with the current field spacing. Results from this program were economic
and additional locations have been scheduled for future drilling. Codell
refracture programs, as well as the operations to add the third fracture
stimulation to existing Codell producers, continue to supply significant
low-risk development opportunities.
 
 In
support of the ongoing DJ basin exploitation program, the company continued to
successfully integrate the Wattenberg gathering system into its operating
activities. During 2004, one new compressor was purchased and installed.
Approximately 69,000 horsepower is currently being utilized to maintain system
pressures for over 1,700 miles of gathering pipeline. Operation and management
of the gathering system continues to provide improved reliability and reduced
wellhead pressures system-wide. Kerr-McGee now operates more than 3,300 wells in
the DJ basin, nearly 2,300 of which are connected to the Wattenberg gathering
system. Company-operated production represents about 70% of the total system
throughput of approximately 255 million cubic feet of natural gas per day, 30
million cubic feet of which is processed at the company’s Ft. Lupton
plant.
 
 During
2004, we participated in sixteen exploratory wells in the Rocky Mountain area.
Evaluation continued in the northeastern Colorado Niobrara play with the
drilling of three additional wells, all of which were successful. The Niobrara
prospect acreage and the eight wells drilled during 2003 and 2004 were sold in
August 2004. Production was established at the Iron Horse, Marquis and Ocla Draw
prospects in the Wind River basin. Kerr-McGee is participating in a Coalbed
Methane (CBM) pilot in the Green River basin. In 2004, we drilled a second test
well in our Gold Coast block to evaluate CBM potential. We also are
participating in the delineation of a Frontier discovery in the Big Horn basin.
Exploration drilling and evaluation of our position in the NE Red Desert will
continue in 2005.
 
 ***Greater
Natural Buttes field, Uinta County, Utah (82%):*** Kerr-McGee obtained an interest in the Greater Natural Buttes field area in 2004
as the result of the the Westport merger. Kerr-McGee operates approximately 850
wells in the greater Natural Buttes field area and has interests in an
additional 430 nonoperated wells. The combined estimated net production rates
from this area at year-end 2004 were 500 barrels of oil per day and 117 million
cubic feet of gas per day. The 2004 drilling program was primarily focused on
exploitation of the Wasatch and Mesa Verde formations. During 2004, Kerr-McGee
participated in 128 wells in our ongoing, multi-year development
program.
 
 In
support of the production operations in Natural Buttes, Kerr-McGee operates over
770 miles of gas gathering pipeline and 19 gas compressors, totaling 20,000
horsepower. The system grew by 6,000 horsepower in 2004. The system has the
capacity to deliver 230 million cubic feet of gas per day via multiple
interstate pipeline systems, giving us the ability to service multiple markets.
The gathering system will continue to grow in support of the field’s aggressive
development program, with at least 10 additional compressor installations
planned for 2005. Total gross production gathered at year-end 2004 was 195
million cubic feet of gas per day.
 
 - 11 -
 ***Moxa
Arch field, Southwest Wyoming (37%):*** Kerr-McGee obtained an interest in the Moxa Arch field area in 2004 as the
result of the Westport merger. We now operate approximately 200 wells in the
Moxa Arch field and have interests in 137 additional nonoperated wells. The
combined estimated net production rates from this area at year-end 2004 were 300
barrels of oil per day and 27 million cubic feet of gas per day. The development
program includes completions in both the Frontier and Dakota formations. During
2004, Kerr-McGee participated in 28 wells, including two wells that had initial
production rates of 5 million cubic feet of gas per day in the Dakota formation.
Development drilling is expected to continue in 2005.
 
 **Southern**
 
 The
Southern division of our U.S. onshore operations had an active drilling program
in 2004. We participated in 247 newly spud wells, of which 221 were development
wells and 26 were exploratory wells. In 2004, we drilled 220 successful wells,
and 13 wells were drilling at year-end, of which two are exploratory wells. The
exploration program had a 77% success rate with twenty discoveries resulting in
2004, many of which have development follow-on potential.
 
 ***Gulf
Coast area:*** In the
Gulf Coast area, a total of 41 wells were spud in 2004. The company plans to
continue with an active drilling program in 2005, drilling over 50 wells in the
Gulf Coast area. Kerr-McGee’s two primary Gulf Coast areas of development are
Chambers County, Texas, and Liberty County, Texas.
 
 *Chambers
County, Texas* - In Chambers
County, five of six development wells drilled in 2004 were successful. Our
share of 2004 production averaged 2,400 barrels of oil equivalent per day from
Chambers County. We plan to drill over 10 wells in this area during
2005.
 
 *Liberty
County, Texas* - In
2004, Kerr-McGee expanded its Liberty County property base by drilling five
development wells, all of which were successful, and 13 exploratory wells, 12 of
which were successful. The company’s net production rate at the end of 2004 was
approximately 7,200 barrels of oil equivalent per day. We expect to drill over
10 wells in Liberty County in 2005.
 
 ***South
Texas area:*** In the
South Texas area, a total of 56 wells were spud in 2004, including eight Wilcox,
21 Frio/Vicksburg, and 17 Lobo formation wells. Kerr-McGee plans to increase the
drilling activity in 2005 by drilling in excess of 60 wells. Two areas of focus
are:
 
 *Starr
and Hidalgo counties, Texas* -
Kerr-McGee had an active drilling program in Starr County during 2004. Eighteen
wells were spud, of which 17 resulted in new production. Average net production
in 2004 from Starr and Hidalgo counties was 9,900 barrels of oil equivalent per
day.
 
 *JC
Martin field, Texas* - The
JC Martin field in Zapata County, Texas, produces from the Lobo formation at
depths ranging from 8,500 to 10,000 feet. In 2004, we spud 11 **** development
wells in the JC Martin field, 10 successful and one still drilling. This field
produced an average of 2,300 net barrels of oil equivalent per day in
2004.
 
 ***Mid-Continent/Permian
area:*** In the
Mid-Continent/Permian area, Kerr-McGee participated in 150 newly spud wells
during 2004. At year-end, 122 of these new wells were producing, six were
drilling and 19 were in the completion phase. This area covers production in New
Mexico, west Texas, northern Louisiana, Oklahoma and Kansas. Two key locations
within the Mid-Continent/Permian area for the company are North Louisiana and
Indian Basin, New Mexico.
 
 *North
Louisiana* - The
company owns an interest in the Elm Grove field and in the North Louisiana Field
Complex, which is comprised of four adjacent fields. In 2004, Kerr-McGee
maintained an aggressive development drilling program in the area, where 87
wells were drilled, 85 of which were successful, with two drilling at year-end.
The company’s current net production for this area is approximately 5,000
barrels of oil equivalent per day. Kerr-McGee expects to drill over 70 wells in
this area in 2005.
 
 *Indian
Basin, New Mexico* - This
shallow decline area offers steady production to the Kerr-McGee portfolio. Four
wells were drilled and brought online in 2004. Net production from Indian Basin
averaged 2,300 barrels of oil equivalent per day in 2004.
 
  - 12 -
  **North
Sea**
 
 Kerr-McGee
has been active in the North Sea area since 1976. As of December 31, 2004,
Kerr-McGee had interests in 20 producing fields in the United Kingdom sector. In
2004, North Sea production represented 39% of the company’s worldwide crude oil
and condensate production and 9% of its gas production. The North Sea area
represents about 20% of Kerr-McGee's total worldwide proved reserves. In 2004,
the weight of the North Sea production and proved reserves in our worldwide
portfolio declined due to our merger with Westport, which increased our reserve
base in the U.S. We expect that in 2005 approximately 40% of the company’s total
oil production and 6% of gas production will come from the North Sea
area.
 
 During
2004, the company launched a six-well North Sea exploration and appraisal
program with the drilling of five operated wells and one nonoperated well. Of
these six wells, four wells were dry and two wells were successful. One of these
successful wells was the Dumbarton field appraisal well 15/20b-15, completed in
November, which proved the southern area of the field. The Dumbarton field,
Block 15/20, was acquired as part of the North Sea fallow block program. The
field is currently under evaluation for development options either as a subsea
tieback to existing nonoperated infrastructure or as a stand alone
facility.
 
 Business
development initiatives during 2004 to strengthen the North Sea core area
included acquiring 50% interest in license 29/20a and 11% in 30/2a shallow. In
addition, a fallow block agreement was reached resulting in the acquisition of
66% interest and operatorship of block 22/25a, 50% interest and operatorship of
blocks 23/26a (South), 30/1a and 30/1e, and 65% nonoperated interest in block
22/15. We also acquired 100% interest in block 16/21d and equalized our interest
in blocks 9/15b and 9/15a (both are now at 86.32%). Certain of these acquired
blocks contain known hydrocarbon discoveries, which the company believes may
have future appraisal or development potential.
 
 The
following is a summary of the company’s five key developments in the North Sea
area, with identification of Kerr-McGee’s working interest. These developments
contributed approximately 77% of total net North Sea production during 2004.
 
 ***Gryphon
area, blocks 9/18a, 9/18b, 9/19 and 9/23a (Maclure field 33.3%, Gryphon field
86.5%, South Gryphon field 89.9% and Tullich field
100%):*** Average 2004 gross production from the Gryphon area was 29,200 barrels of oil
per day and 10.7 million cubic feet of gas per day. The Maclure and Tullich
subsea satellites began production in August 2002. In 2003, we acquired an
additional 25% interest in the Gryphon area. This area is produced into a
floating production, storage and offloading (FPSO) vessel, with oil exported via
shuttle tanker. Gas is exported to the Leadon facility for fuel usage and/or
sold on the spot market via the St. Fergus terminal.
 
 ***Janice
area, block 30/17a (75.3%):*** Average 2004 gross production from the Janice field was 11,400 barrels of oil
per day and 1.2 million cubic feet of gas per day. During 2004, production began
from the James field, part of the Janice area. Kerr-McGee operates James and
Janice with a 75.3% interest. Oil from James is produced from a single well as a
subsea tieback to the Janice 'A' floating production facility. First oil
production from James occurred in November 2004 with sustained flow rates of
approximately 8,000 barrels of oil equivalent per day.
 
 ***Leadon
field, block 9/14a and 9/14b (100%):*** Average 2004 gross production from the Leadon field was 7,900 barrels of oil per
day. The Leadon field is being produced into an FPSO vessel, and the oil is
exported via shuttle tanker.
 
 ***Harding
field, block 9/23b (30%):*** Average 2004 gross production from the Harding field was 38,600 barrels of oil
per day. The Harding field provides Kerr-McGee with additional infrastructure in
the strategically important quadrant 9 area of the North Sea. Within the same
quadrant, Kerr-McGee also has interests in Gryphon, Leadon, Buckland, Skene,
Maclure, and Tullich.
 
 ***Skene
field, block 9/19 (33.3%):*** The
Skene field began producing in December 2001. Average 2004 gross field
production was 106 million cubic feet of gas per day and 5,100 barrels of oil
per day. The Skene field is being produced through a subsea tieback to the Beryl
Alpha platform. The oil is exported via shuttle tanker, while the gas is
exported via pipeline to the St. Fergus terminal.
 
 - 13 -
 **China**
 
  During
2004, China’s Bohai Bay became a core operating area for Kerr-McGee, with a
total of eight discoveries made since the company first became involved in the
area. In 2004, production in China represented 3% of the company’s worldwide oil
and gas production. We expect this area will contribute over 10% of the
company’s total 2005 oil production. In early 2005, we entered into a production
sharing contract with China National Offshore Oil Corp. (CNOOC) for block 43/11,
which covers 2.4 million acres in the deepwater South China Sea. We hold a 100%
foreign contractor’s interest in the first phase of the exploration period.
CNOOC has the right to participate with up to a 51% interest if Kerr-McGee
enters into the development phase.
 
 ***Bohai
Bay block 04/36 (81.8% working interest in exploration and 40.09% in development
and production phases)*** **:** Kerr-McGee commenced first production from the CFD 11-1 and 11-2 oil fields in
July 2004. Two platform topsides were installed and the FPSO was built in
China’s port city of Dalian and then mobilized to the field in May 2004.
Development drilling continued throughout the year at the CFD 11-1 field, and
the development drilling program was completed at the 11-2 field. Thirty-six
wells were completed and placed on either production or injection by the end of
2004. Gross production for 2004 was 15,100 barrels of oil equivalent per day
(annualized), with year-end rates at 41,000 barrels of oil equivalent per day.
 
 Oil in
Place (OIP) reports for the CFD 11-3/11-5 fields were approved by the Chinese
government in June 2004. CNOOC approved the Overall Development Plan for these
fields in March 2005. Government approval is expected in the second quarter of
2005. The development plan centers on a tieback to the CFD 11-1 and 11-2
facilities with full processing of the fluids at the FPSO. Export will be
commingled with similar quality crude from the CFD 11-1 and 11-2 fields. The
development plan is based on four wells initially being drilled. First
production is anticipated in the fourth quarter of 2005.
 
 The CFD
11-1N-1 exploration well was drilled in 2004 to the north of the CFD 11-1
development area, but was declared unsuccessful.
 
 ***Bohai
Bay block 05/36 (50% working interest in exploration
phase):*** Two
appraisal wells were successfully drilled in the CFD 12-1 and 12-1S fields
during 2003. The OIP reports for the CFD 12-1 and 12-1S fields in block 05/36,
along with CFD 11-6 field in block 04/36, were approved in December 2004. The
development plan for these fields is in the final stages of the approval process
with CNOOC and new prospects for block 05/36 are being evaluated for drilling in
2005. In addition, CNOOC has approved a one-year extension which would provide
for a new permit expiration date of February 28, 2006, subject to government
approval. There will be a one-well obligation resulting from this extension and
Shahejie play leads are being developed in preparation for this extension.
  ***Bohai
Bay block 09/18 (100% working interest in exploration
phase):*** Two
exploration commitment wells were drilled in this area in 2004, the CFD 14-5-1
and CFD 23-3-1. CFD 14-5-1 was an oil discovery in Eocene Shahejie sands. An
appraisal program for the area is planned for 2005. The CFD 23-3-1 was declared
unsuccessful. CNOOC has approved a one-year extension for the exploration phase,
subject to government approval, whereby all 550,000 acres will be retained until
the next election point on November 1, 2005.
 
 ***Bohai
Bay block 09/06 (100% working interest in exploration
phase):*** The
company signed an exploration contract in August 2003 for this 440,000-acre
block in Bohai Bay, adjacent to the other concessions operated by Kerr-McGee.
Since the 2004 CFD 14-5-1 discovery well was in the deep Shahejie formation, the
appraisal will extend into block 09/06. Drilling will occur in 2005. The company
purchased 3-D seismic data to help define prospectivity of the
area.
  - 14 -
  **Alaska**
 
 Kerr-McGee
signed a participation agreement with Armstrong Oil and Gas (Armstrong) on
December 24, 2003, to jointly explore areas of the prolific Alaska North Slope.
Kerr-McGee acquired a 70% working interest in and operates nine leases totaling
approximately 18,000 acres off the Alaska coast, northwest of Prudhoe Bay. The
agreement includes the right to acquire an interest in 14 additional leases in
the area, totaling 52,000 acres. In the October 2004 State of Alaska lease sale,
Kerr-McGee and Armstrong were high bidders on four adjacent tracks with 5,120
available acres. In 2004, the company drilled a successful exploration and
appraisal well on the NW Milne Point prospect (Nikaitchuq). An appraisal and
testing program of the Nikaitchuq discovery is currently under way and two
additional exploration wells are drilling.
 
 
 **Other
International**
 
 **Australia**
 
 ***WA
34-R (Formerly WA 278P) (39%):*** In
2004, a retention lease was granted by the Australian government for the areas
around Kerr-McGee's Prometheus and Rubicon wells. These wells, drilled in 2000,
successfully encountered natural gas but were considered noncommercial. We sold
our interest in October 2004 and have no further obligations.
 
 ***WA
301, 302, 303, 304 and 305 (50%):*** Kerr-McGee has an interest in 6.4 million acres in the deepwater Browse basin.
The first exploratory well, Maginnis, was drilled in early 2003 and was
unsuccessful. Kerr-McGee has entered into phase two of exploration. Geologic
studies are planned in 2005 for blocks 303, 304 and 305. We have withdrawn from
blocks 301 and 302 and have no further interest in the area.
 
 ***WA
337 (100%) and WA 339 (50%):*** In
early 2003, Kerr-McGee acquired an interest in 2.3 million acres in the
deepwater Perth basin. Seismic data was acquired in late 2003, and processing is
now complete. The remaining obligation for these blocks includes geologic
studies, which are planned for 2005.
 
 ***EPP
33 (100%):*** In
late 2003, Kerr-McGee was awarded an interest in 1.3 million acres in the
deepwater Otway basin. A new 2-D seismic survey over the block was acquired in
the fourth quarter of 2004. Processing of the seismic data is currently under
way.
 
 **Bahamas**
 
 On June
25, 2003, Kerr-McGee signed an exploration contract (100%) on 6.5 million acres
in northern Bahamian waters, 90 miles east of the Florida coast. Water depths
range from 650 feet to 7,000 feet. Kerr-McGee completed a speculative seismic
acquisition program in 2004. Activity planned for 2005 includes seismic
processing and interpretation.
 
 **Benin**
 
 ***Block
4 (70%):*** Kerr-McGee owns a 70% working interest in 2.5 million acres offshore Benin.
Water depths on this block range from 300 feet to 10,000 feet. A two-well
drilling program was initiated in 2002, and both wells found noncommercial
amounts of hydrocarbons. In late 2002, Kerr-McGee and Petronas Carigali Overseas
Sdn Bhd. entered into a partnership on the block. The joint venture entered the
next three-year phase of exploration in August 2003. Acquisition of additional
2-D seismic data was completed in 2003 to evaluate areas not covered by the
existing 3-D seismic data. Kerr-McGee is renegotiating a farmout agreement to
reduce its interest in the block to 40%, pending government approval. The
company has an obligation to drill one well during the current phase of
exploration.
 
 **Brazil**
 
 ***BM-ES-9
(50%):*** This
offshore block was acquired in 2001 and extends over 535,000 acres in the
Espirito Santo basin in water depths ranging from 4,400 feet to 9,600 feet.
During 2002, 3-D seismic data was acquired. An exploratory well at the Tartaruga
Verde prospect was drilled in 2004 and was unsuccessful. The company has elected
to withdraw from this block and has no further obligations.
 
 - 15 -
 ***BM-C-7
(33 1/3%):*** In
December 2003, Kerr-McGee acquired an interest in 161,000 acres in the Campos
basin. Water depth on this block ranges from 300 to 400 feet. In 2004,
Kerr-McGee participated in an exploratory well at the Dragon prospect. The well
encountered hydrocarbons and oil samples were taken. Kerr-McGee also drilled one
vertical appraisal well in late 2004, which was unsuccessful. Additional
appraisal drilling and a potential flow test are scheduled for 2005. EnCanBrasil
operates the block with 66 2/3% interest.
 
 ***BM-C-32
(33%), BM-C-30 (25%), BM-C-29 (100%), BM-ES-M-24 (30%), BM-ES-25
(40%):*** In
November 2004, Kerr-McGee acquired an interest in seven blocks, which have since
been redesignated as five permit areas located offshore in the prolific Campos
and Espírito Santo basins. The blocks are in shallow to deep water (water depths
of 200 to 6,600 feet). In the Campos Basin, we operate C-M-101BM-C-30 and
C-M-202BM-C29. In the Espirito Santo basin, Devon Energy Corporation operates
block C-M-61BM-C-32 and Petrobras operates blocks BM-ES-M-24 and BM-ES-25. To
comply with governmental requirements, we expect to increase our interest in
C-M-101BM-C-30 to 30%. Work obligations for the contract area include the
acquisition of 3-D seismic, as well as an eight-well drilling commitment over a
four-year period.
 
 **Morocco**
 
 ***Cap
Draa block (11.25%):*** Kerr-McGee and partners had an exploration contract covering approximately 3
million acres along the deepwater shelf edge offshore Morocco, in water depths
ranging from 650 feet to 6,500 feet. A 3-D seismic acquisition was completed in
2002. In February 2004, the company executed a farm-out agreement with Shell Oil
Company, reducing its interest in this block to 11.25%. In mid-2004, Kerr-McGee
participated in the drilling of one exploratory well which was unsuccessful. We
have withdrawn from this block and have no further obligations.
 
 ***Boujdour
block (50%):*** In
October 2001, Kerr-McGee acquired a reconnaissance permit covering approximately
27 million acres offshore Morocco from the shoreline to a water depth of more
than 10,000 feet. A reconnaissance permit allows Kerr-McGee to perform seismic
and related activities for evaluation purposes. In early 2003, we acquired a
large 2-D seismic grid. A new seismic and drop core survey was acquired in 2004
and evaluation of the data is currently under way. In 2004, Kerr-McGee, Kosmos
Energy Morocco HC and Pioneer Natural Resources Morocco Limited entered into a
partnership on the block. Kerr-McGee is involved in discussions with the
Moroccan government on future actions .
 
 **Gabon**
 
 In the
Olonga Marin block, Kerr-McGee and partners conducted seismic operations in
2003. The company relinquished its acreage at the end of the exploration period
in the first quarter of 2004.
 
 **Nova
Scotia, Canada**
 
 ***EL2383,
EL2386, EL2393 and EL2396 (50%):*** Kerr-McGee was operator of four deepwater blocks covering approximately 1.5
million acres offshore Nova Scotia, Canada, in water depths ranging from 500
feet to 9,200 feet. The agreements expired in 2004.
 
 ***EL2398
(66 2/3%), EL2399 (100%) and EL2404 (50%):*** These
Kerr-McGee operated blocks, covering more than 1.5 million acres, are in water
depths ranging from 350 feet to 10,000 feet. A regional 2-D seismic program was
interpreted in 2001, and additional 2-D seismic data was acquired in 2003. Norsk
Hydro has taken a working interest in EL2404 and EL2398 and is providing
technical evaluation.
 
 **Yemen**
 
 ***Block
50 (47.5%):*** Kerr-McGee relinquished its interest in block 50 in April 2004.
 
 
  - 16 -
   **CHEMICAL
OPERATIONS**
  Kerr-McGee
chemical operations consist of two segments (pigment and other chemical
products) that produce and market inorganic industrial chemicals and heavy
minerals through its affiliates, Kerr-McGee Chemical LLC, KMCC Western
Australia Pty. Ltd., Kerr-McGee Pigments GmbH, Kerr-McGee Pigments International
GmbH, Kerr-McGee Pigments Ltd., Kerr-McGee Pigments (Holland) B.V. and
Kerr-McGee Pigments (Savannah) Inc. Many of the pigment products are
manufactured using proprietary chloride technology developed by the company.
Industrial chemicals include titanium dioxide, synthetic rutile, manganese
dioxide, boron and sodium chlorate. Heavy minerals produced are ilmenite,
natural rutile, leucoxene and zircon.  Additionally, Kerr-McGee owns a 50%
interest in a joint venture that produces lithium-metal-polymer (LMP)
batteries.  As discussed under Recent Developments above, Kerr-McGee is
pursuing alternatives for the separation of its chemical business.
 
 **Exit
Activities**
 
 In
2004, the company shut down its titanium dioxide pigment sulfate production at
its Savannah, Georgia, facility and recognized a pretax charge of $105 million
for costs associated with the shutdown. Demand and prices for sulfate anatase
pigments, particularly in the paper market, had declined in North America
consistently during the past several years. The decreasing volumes, along with
unanticipated environmental and infrastructure issues discovered after
Kerr-McGee acquired the facility in 2000, created unacceptable financial returns
for the facility and contributed to the decision. The company also ended
production at its Savannah gypsum plant that used by-product from the sulfate
process to manufacture gypsum. The Savannah facility’s work force of 410 was
reduced by approximately 100 positions. The company expects this decision to
result in an improvement in segment operating profit of approximately $15
million annually.
 
 On
December 16, 2002, the company announced plans to exit the forest products
business due to the strategic focus on the growth of the core businesses, oil
and gas exploration and production and the production and marketing of titanium
dioxide pigment. Four of the company’s five wood-treatment facilities were
closed during 2003. The fifth plant, which was a leased facility, ceased all
significant operations by the end of 2004 and the assets were sold in early
2005. Results of operations for the forest products business are reflected in
the Consolidated Statement of Operations in income (loss) from discontinued
operations for all periods presented.
 
  **Titanium
Dioxide Pigment**
  The
company’s primary chemical product is titanium dioxide pigment (TiO 2 ), a
white pigment used in a wide range of products, including paint, coatings,
plastics, paper and specialty applications. TiO 2 is
used in these products for its unique ability to impart whiteness, brightness
and opacity.
  Titanium
dioxide pigment is produced in two crystalline forms - rutile and anatase. The
rutile form has a higher refractive index than anatase titanium dioxide,
providing better opacity and tinting strength. Rutile titanium dioxide products
also provide a higher level of durability (resistance to weathering). In
general, the rutile form of titanium dioxide is preferred for use in paint,
coatings, plastics and inks. Anatase titanium dioxide is less abrasive than
rutile and is preferred for use in fibers, rubber, ceramics and some paper
applications.
  Titanium
dioxide is produced using one of two different technologies, the chloride
process and the sulfate process, both of which are used by Kerr-McGee. Because
of market considerations, chloride-process capacity has increased to a
substantially higher level than sulfate-process capacity during the past 20
years. The chloride process currently makes up about 60% of total industry
capacity and accounts for approximately 83% of the company’s gross production
capacity.
  The
company produces TiO 2 pigment at five production facilities. Two are located in the United States, the
others are in Australia, Germany and the Netherlands. The following table
outlines the company’s production capacity by location and process.
   - 17 -
  **TiO** **2** **Capacity**
 As of
January 1, 2005
 (Gross
tonnes per year)
 
 Facility
    
    Capacity
    
    ProcessHamilton,
      Mississippi
    
    
    225,000
    
    
    ChlorideSavannah,
      Georgia
    
    
    110,000
    
    
    ChlorideKwinana,
      Western Australia(1)
    
    
    110,000
    
    
    ChlorideBotlek,
      Netherlands
    
    
    72,000
    
    
    ChlorideUerdingen,
      Germany
    
    
    107,000
    
    
    SulfateTotal
    
    
    624,000
 
  (1) 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 TiO 2 project in Western Australia (the Tiwest Joint Venture). The venture consists of
a heavy-minerals mine, a minerals separation facility, a synthetic rutile plant
and a titanium dioxide plant.
 
 Heavy
minerals are mined from 8,513 hectares (21,027 acres) leased by the Tiwest Joint
Venture. The company’s 50% interest in the properties’ remaining in-place proven
and probable reserves is 6 million tonnes of heavy minerals contained in 214
million tonnes of sand averaging 2.8% heavy minerals. The valuable heavy
minerals are composed of 61% ilmenite, 4.5% natural rutile, 3.4% leucoxene and
10% zircon, with the remaining 21.1% of heavy minerals having no significant
value.
 
 Heavy-mineral
concentrate from the mine is processed at a 750,000 tonne-per-year dry
separation plant. Some of the recovered ilmenite is upgraded at a nearby
synthetic rutile facility, which has a capacity of 225,000 tonnes per year.
Synthetic rutile is a high-grade titanium dioxide feedstock. The Tiwest Joint
Venture provides synthetic rutile feedstock to its 110,000 tonne-per-year
titanium dioxide plant located at Kwinana, Western Australia. Production of
ilmenite, synthetic rutile, natural rutile and leucoxene in excess of the Tiwest
Joint Venture’s requirements is sold to third parties, as well as to Kerr-McGee
as part of its feedstock requirement for TiO 2 manufacturing under a long-term agreement executed in September
2000.
 
 Information
regarding the company’s 50% interest in heavy-mineral reserves, production and
average prices for the three years ended December 31, 2004, is presented in the
following table. Mineral reserves in this table represent the estimated
quantities of proven and probable ore that, under presently anticipated
conditions, may be profitably recovered and processed for the extraction of
their mineral content. Future production of these resources depends on many
factors, including market conditions and government regulations.
  Heavy-Mineral
Reserves, Production and Prices
  (Thousands
      of tonnes)
    
    **2004**
    
    2003
    
    2002Proven
      and probable reserves
    
    
    **5,570**
    
    
    5,970
    
    
    5,700Production
    
    
    **302**
    
    
    294
    
    
    289Average
      market price (per tonne)
    
    **$**
    **161**
    
    $
    152
    
    $
    150
 
 Titanium-bearing
ores used for the production of TiO 2 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 TiO 2 business
from a variety of suppliers in the United States, Australia, Canada, South
Africa, Norway, India and Ukraine. Ores are generally purchased under multi-year
agreements.
 
 The
global market in which the company’s titanium dioxide business operates is
highly competitive. The company actively markets its TiO 2 utilizing primarily direct sales but also through a network of agents and
distributors. In general, products produced in a given market region will be
sold there to minimize logistical costs. However, the company actively exports
products, as required, from its facilities in the United States, Europe and
Australia to other market regions.
 
 - 18 -
 Titanium
dioxide applications are technically demanding, and the company utilizes a
strong technical sales and services organization to carry out its marketing
efforts. Technical sales and service laboratories are strategically located in
major market areas, including the United States, Europe and the Asia-Pacific
region. The company’s products compete on the basis of price and product
quality, as well as technical and customer service.
 
 **Other
Chemical Products**
 
 The
other segment within the chemical operations consisted of the company's
electrolytic operations and forest products business.  As discussed above,
the company sold its remaining assets of the forest products business in
January 2005.
 
 ***Electrolytic
Products:*** Plants
at the company’s Hamilton, Mississippi, complex include a 135,000 tonne-per-year
sodium chlorate facility. Sodium chlorate is used in the environmentally
preferred chlorine dioxide process for bleaching pulp. The conversion by the
pulp and paper industry to chlorine dioxide technology from chlorine is
essentially complete. Over 95% of sodium chlorate is consumed by the pulp and
paper industry. Sodium chlorate demand in the United States is expected to
increase approximately 2% to 3% per year in the near term as the pulp and paper
industry recovers.
 
 The
company operates facilities at Henderson, Nevada, producing electrolytic
manganese dioxide (EMD) and boron trichloride. Annual production capacity is
29,500 tonnes for EMD and 340,000 kilograms for boron trichloride. Boron
trichloride is used in the production of pharmaceuticals and in the manufacture
of semiconductors. EMD is a major component of alkaline batteries. The company’s
share of the North American EMD market is approximately one-third. Demand is
being driven by the need for alkaline batteries for portable electronic devices.
 
 In July
2003, the company filed an anti-dumping action against low-priced EMD illegally
imported into the U.S. and temporarily idled the Henderson, Nevada, EMD
manufacturing facility due to the impact of these imports on market conditions.
Partly as a result of the anti-dumping petition, demand for U.S. EMD products
increased and the plant resumed operations in December 2003. While the company
withdrew the anti-dumping petition in February 2004, we are continuing to
monitor market conditions.
 
 As part
of the company’s strategic decision to focus on the titanium dioxide pigment
business, the company continues to investigate divestiture options for the
electrolytic business.
  ***Forest
Products:*** The
principal product of the forest products business was treated railroad
crossties. Other products included railroad crossing materials, bridge timbers
and utility poles. As previously discussed, the company ceased significant
operations at its remaining wood-treatment plant in December 2004.
  
 **Stored
Power**
 
 The
company owns a 50% interest in Avestor, a joint venture formed in 2001 to
produce and commercialize a solid-state LMP battery. Compared with
traditional lead-acid batteries, Avestor’s no-maintenance battery offers
superior performance at one-third the size, one-fifth the weight and two to four
times the life. The batteries also provide an environmentally preferred
alternative since they contain no acid or liquid that may spill or leak. The
Avestor joint venture began battery sales in late 2003 from its plant near
Montreal, Canada, and started increasing production and sales rates in
2004. Initial battery sales and customer feedback indicate strong demand in
the North American telecommunications industry, the initial target market. The
European telecommunications market will be the most likely target in 2006.
Battery quality and performance are being carefully monitored and evaluated as
production rates increase. Development of AVESTOR batteries for industrial and
electric utility markets is currently under way, with field trials planned in
2006. With market demand growing, Avestor expects to achieve a breakeven
operating cash position in 2006 and anticipates sales matching plant
capacity in 2009.
 
 **OTHER**
 
 **Research
and Development**
 
 The
company’s Technical Center in Oklahoma City performs research and development in
support of existing businesses and for the development of new and improved
products and processes. The primary focus of the company’s research and
development efforts is on the titanium dioxide business. A separate dedicated
group at the Technical Center performs research and development in support of
the company’s battery materials business.
 
 - 19 -
 **Employees**
 
 On
December 31, 2004, the company and its affiliates had 4,084 employees.
Approximately 888, or 22%, of these employees were represented by chemical
industry collective bargaining agreements in the United States and
Europe.
 
 **Competitive
Conditions**
 
 The oil
and gas exploration and production industry is highly competitive, and
competition exists from the initial process of bidding for leases to the sale of
crude oil and natural gas. Competitive factors include the ability to find,
develop and produce crude oil and natural gas efficiently, as well as the
development of successful marketing strategies. Many of the company's
competitors, including integrated multinational oil and gas companies, have
access to substantially greater financial resources, facilities and staffs than
Kerr-McGee.
 
 The
titanium dioxide pigment business is highly competitive and some of our
competitors have greater financial resources, staffs and facilities. The number
of competitors in the industry has declined due to recent consolidations, and
this trend is expected to continue. Our competitors' resources may give them
various advantages when responding to market conditions. Significant
consolidation among the consumers of titanium dioxide has also taken place
during the past five years and is expected to continue. Worldwide, Kerr-McGee is
one of only five producers that own proprietary chloride-process technology to
produce titanium dioxide pigment. Cost efficiency and product quality as well as
technical and customer service are key competitive factors in the titanium
dioxide business.
 
 It is
not possible to predict the effect of future competition on Kerr-McGee's
operating and financial results.
  
 **GOVERNMENT
REGULATIONS AND ENVIRONMENTAL MATTERS**
  **General**
 
 The
company’s affiliates are subject to extensive regulation by federal, state,
local and foreign governments. The production and sale of crude oil and natural
gas are subject to special taxation by federal, state, local and foreign
authorities and regulation with respect to allowable rates of production,
exploration and production operations, calculations and disbursements of royalty
payments, and environmental matters. Additionally, governmental authorities
regulate the generation and treatment of waste and air emissions at the
operations and facilities of the company’s affiliates. At certain operations,
the company’s affiliates also comply with certain worldwide, voluntary standards
such as ISO 9002 for quality management and ISO 14001 for environmental
management, which are standards developed by the International Organization for
Standardization, a nongovernmental organization that promotes the development of
standards and serves as an external oversight for quality and environmental
issues.
 
 **Environmental
Matters**
 
 Federal,
state and local laws and regulations relating to environmental protection affect
almost all company operations. Under these laws, the company’s affiliates are or
may be required to obtain or maintain permits and/or licenses in connection with
their operations. In addition, these laws require the company’s affiliates to
remove or mitigate the effects on the environment of the disposal or release of
certain chemical, petroleum, low-level radioactive and other substances at
various sites. Operation of pollution-control equipment usually entails
additional expense. Some expenditures to reduce the occurrence of releases into
the environment may result in increased efficiency; however, most of these
expenditures produce no significant increase in production capacity, efficiency
or revenue.
 
 During
2004, direct capital and operating expenditures related to environmental
protection and cleanup of operating sites totaled $32 million. Additional
expenditures totaling $99 million were charged against reserves for
environmental remediation and restoration. While it is difficult to estimate the
total direct and indirect costs to the company of government environmental
regulations, the company presently estimates that in 2005 it will incur $11
million in direct capital expenditures, $11 million in operating expenditures
and $96 million in expenditures charged to reserves. Additionally, the company
estimates that in 2006 it will incur $6 million in direct capital expenditures,
$11 million in operating expenditures and $64 million in expenditures charged to
reserves.
 
 - 20 -
 The
company and its affiliates are parties to a number of legal and administrative
proceedings involving environmental matters and/or other matters pending in
various courts or agencies. These include proceedings associated with businesses
and facilities currently or previously owned, operated or used by the company’s
affiliates and/or their predecessors, and include claims for personal injuries,
property damages, breach of contract, injury to the environment, including
natural resource damages, and non-compliance with permits. The current and
former operations of the company’s affiliates also involve management of
regulated materials and are subject to various environmental laws and
regulations. These laws and regulations obligate the company’s affiliates to
clean up various sites at which petroleum and other hydrocarbons, chemicals,
low-level radioactive substances and/or other materials have been contained,
disposed of or released. Some of these sites have been designated Superfund
sites by the U.S. Environmental Protection Agency (EPA) pursuant to the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
(CERCLA) and are listed on the National Priority List (NPL).
 
 The
company provides for costs related to environmental contingencies when a loss is
probable and the amount is reasonably estimable. It is not possible for the
company to reliably estimate the amount and timing of all future expenditures
related to environmental matters because, among other reasons:
 
 ·
    some
      sites are in the early stages of investigation, and other sites may be
      identified in the future;
  ·
    remediation
      activities vary significantly in duration, scope and cost from site to
      site depending on the mix of unique site characteristics, applicable
      technologies and regulatory agencies
involved;
  ·
    cleanup
      requirements are difficult to predict at sites where remedial
      investigations have not been completed or final decisions have not been
      made regarding cleanup requirements, technologies or other factors that
      bear on cleanup costs;
  ·
    environmental
      laws frequently impose joint and several liability on all potentially
      responsible parties, and it can be difficult to determine the number and
      financial condition of other potentially responsible parties and their
      respective shares of responsibility for cleanup costs;
  ·
    environmental
      laws and regulations, as well as enforcement policies, are continually
      changing, and the outcome of court proceedings and discussions with
      regulatory agencies are inherently
uncertain;
  ·
    unanticipated
      construction problems and weather conditions can hinder the completion of
      environmental remediation;
  ·
    the
      inability to implement a planned engineering design or use planned
      technologies and excavation methods may require revisions to the design of
      remediation measures, which delay remediation and increase its costs;
      and
  ·
    the
      identification of additional areas or volumes of contamination and changes
      in costs of labor, equipment and technology generate corresponding changes
      in environmental remediation costs.
  
 The
company believes that currently it has reserved adequately for the reasonably
estimable costs of contingencies. However, additions to the reserves may be
required as additional information is obtained that enables the company to
better estimate its liabilities, including any liabilities at sites now under
review. The company cannot reliably estimate the amount of future additions to
the reserves at this time. Additionally, there may be other sites where the
company has potential liability for environmental-related matters but for which
the company does not have sufficient information to determine that the liability
is probable and/or reasonably estimable. We have not established reserves for
such sites.
 
 For
additional discussion of environmental matters, see Legal Proceedings included
in Item 3, *Environmental
Matters* section of Management’s Discussion and Analysis of Financial Condition and
Results of Operations included in Item 7, and Note 19 to the Consolidated
Financial Statements in Item 8 of this annual report on Form 10-K.
 
 
  - 21 -
  **RISK
FACTORS**
 
 In
addition to the risks identified in Management’s Discussion and Analysis
included in Item 7 of this annual report on Form 10-K, investors should consider
carefully the following risks.
 
 **Volatile
product prices and markets could adversely affect results of operations and cash
flows of the company.**
 
 The
company's results of operations and cash flows are highly dependent upon the
prices of and demand for oil and gas. Historically, the markets for oil and gas
have been volatile and are likely to continue to be volatile in the future, and
the prices received by the company for its oil and gas production are dependent
upon numerous factors that are beyond its control. These factors include, but
are not limited to:
 
 ·
    worldwide
      supply and consumer product demand;
  
 ·
    governmental
      regulations and taxes;
  
 ·
    the
      price and availability of alternative
fuels;
  
 ·
    the
      level of imports and exports of oil and
gas;
  
 ·
    actions
      of the Organization of Petroleum Exporting
Countries;
  
 ·
    the
      political and economic uncertainty of foreign
  governments;
  
 ·
    international
      conflicts and civil disturbances; and
  
 ·
    the
      overall economic environment.
  
 The
company uses commodity derivative instruments as a means of balancing price
uncertainty and volatility with the company’s financial and investment
requirements. Nevertheless, a sustained period of sharply lower commodity prices
could have material adverse effects on the company, including:
 
 ·
    curtailment
      or deferral of exploration and development
projects;
  
 ·
    reduction
      in the level of economically viable proved
reserves;
  
 ·
    reduction
      of the discounted future net cash flows relating to the company’s proved
      oil and gas reserves;
  
 ·
    reduced
      ability of the company to maintain or grow its future production through
      future investment in exploration, exploitation and acquisition activities;
      and
  
 ·
    reduced
      ability of the company to borrow funds.
  
 The
commodity derivative instruments also may prevent the company from realizing the
benefit of price increases above the levels reflected in such contracts. In
addition, the commodity derivative instruments may expose the company to the
risk of financial loss in certain circumstances, including, but not limited to,
instances in which:
 
 ·
    production
      is less than the volumes covered by the derivative
      instruments;
  
 ·
    basis
      differentials tighten substantially from the prices established by these
      arrangements; or
  
 ·
    the
      counter-parties to commodity price and basis differential risk management
      contracts fail to perform as required by the
contracts.
  
 - 22 -
 **The
company's debt may limit its financial flexibility.**
  The
company uses both short and long-term debt to finance its operations. The level
of the company's debt could affect the company in important ways,
including:
 
 ·
    a
      portion of the company's cash flow from operations will be applied to the
      payment of principal and interest and will not be available for other
      purposes;
 
 ·
    ratings
      of the company’s debt and other obligations vary from time to time and
      impact the costs, terms, conditions and availability of
      financing;
 
 ·
    covenants
      associated with debt arrangements require the company to meet financial
      and other tests that can affect its flexibility in planning for and
      reacting to changes in its business, including possible acquisition
      opportunities;
 
 ·
    the
      company's ability to obtain additional financing for working capital,
      capital expenditures, acquisitions, general corporate and other purposes
      may be limited; and
 
 ·
    the
      company may be at a competitive disadvantage to similar companies that
      have less debt.
  
 **Failure
to fund continued capital expenditures and to replace oil and gas reserves could
adversely affect results of operations of the company.**
 
 The
future success of the company's oil and gas business depends upon its ability to
find, develop or acquire additional oil and gas reserves that are economically
recoverable. The company will be required to expend capital to replace its
reserves and to maintain or increase production levels. The company believes
that, after considering the amount of its debt, it will have sufficient cash
flow from operations, available drawings under its credit facilities and other
debt financings to fund capital expenditures. However, if these sources are not
sufficient to enable the company to fund necessary capital expenditures, its
ability to find and develop oil and gas reserves may be adversely affected and
its interests in some of its oil and gas properties may be reduced or forfeited.
Further, if oil and gas prices increase, finding costs for additional reserves
could also increase, making it more difficult to replace reserves on an economic
basis.
 
 **Oil
and gas exploration, development and production operations involve substantial
capital costs and are subject to various economic risks.**
 
 The
company's oil and gas operations are subject to the economic risks typically
associated with exploration, development and production activities. In
conducting exploration activities, unanticipated pressure or irregularities in
formations, miscalculations or accidents may cause exploration activities to be
unsuccessful, and even where oil and gas are discovered it may not be possible
to produce or market the hydrocarbons on an economically viable basis. Drilling
operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which may be beyond the company's control, including unexpected
drilling conditions, weather conditions, compliance with environmental and other
governmental requirements and shortages or delays in the delivery of equipment
and services. The occurrence of any of these or similar events could result in a
partial or total loss of investment in a particular property.
 
 **The
company operates in foreign countries and is subject to political, economic and
other uncertainties.**
 
 The
company conducts significant operations in foreign countries and may expand its
foreign operations in the future. Operations in foreign countries are subject to
political, economic and other uncertainties, including, but not limited
to:
 
 ·
    the
      risk of war, acts of terrorism, revolution, border disputes,
      expropriation, renegotiation or modification of existing contracts,
      import, export and transportation regulations and
  tariffs;
 
 ·
    taxation
      policies, including royalty and tax increases and retroactive tax
      claims;
 
 - 23 -
 ·
    exchange
      controls, currency fluctuations and other uncertainties arising out of
      foreign government sovereignty over the company's international
      operations;
 
 ·
    exposure
      to movements in foreign currency exchange rates, because the U.S. dollar
      is the functional currency for the company's international operations,
      except for the company's European chemical operations, for which the euro
      is the functional currency;
 
 ·
    laws
      and policies of the United States affecting foreign trade, taxation and
      investment; and
 
 ·
    the
      possibility of being subject to the exclusive jurisdiction of foreign
      courts in connection with legal disputes and the possible inability to
      subject foreign persons to the jurisdiction of courts in the United
      States.
 
 Foreign
countries have occasionally asserted rights to land, including oil and gas
properties, through border disputes. If a country claims superior rights to oil
and gas leases or concessions granted to the company by another country, the
company's interests could be lost or could decrease in value. Various regions of
the world have a history of political and economic instability. This instability
could result in new governments or the adoption of new policies that might
assume a substantially more hostile attitude toward foreign investment. In an
extreme case, such a change could result in termination of contract rights and
expropriation of foreign-owned assets. The company seeks to manage these risks
by, among other things, focusing much of its international exploration efforts
in areas where it believes the existing government is stable and favorably
disposed towards United States exploration and production
companies.
 
 **Competition
is intense, and companies with greater financial, technological and other
resources may be better able to compete.**
 
 The oil
and gas exploration and production business and the titanium dioxide pigment
business are each highly competitive. In addition to competing with other
independent oil and gas producers (i.e., companies not engaged in petroleum
refining and marketing operations), the company competes with large, integrated,
multinational oil and gas and chemical companies. These
companies may have greater resources, which may give them various advantages
when responding to market conditions.
 
 **The
company's business involves many operating risks that may result in substantial
losses. Insurance may not be adequate to protect the company against these
risks.**
 
 The
company's operations are subject to hazards and risks inherent in drilling for,
producing and transporting oil and gas, as well as in producing chemicals,
including, but not limited to: fires; natural disasters; explosions; formations with abnormal pressures; marine risks
such as currents, capsizing, collisions and hurricanes; adverse weather
conditions; casing collapses, separations or other failures, including cement
failure; uncontrollable flows of underground gas, oil and formation water;
surface cratering; failure of chemical plant equipment; and environmental
hazards such as gas leaks, chemical leaks, oil spills and discharges of toxic
gases.
 
 Any of
these risks can cause substantial losses in connection with the: injury or loss
of life; damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage; regulatory investigations and
penalties; suspension of operations; and repair and remediation
costs.
 
 To help
protect against these and other risks, the company maintains insurance coverage
against some, but not all, potential losses. Losses could occur for uninsurable
or uninsured risks, or in amounts in excess of existing insurance coverage. The
occurrence of an event that is not fully covered by insurance could harm the
company's financial condition and results of operations.
 
 **Oil
and gas reserve information is estimated.**
 
 The
company’s estimates of proved oil and gas reserves are based on internal reserve
data prepared by the company’s engineers. Petroleum reserve estimation is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in a direct or exact manner. Estimates of economically
recoverable oil and gas reserves and of future net cash flows necessarily depend
on a number of variable factors and assumptions, including:
 
 - 24 -
 ·
    historical
      production trends from a particular area are representative of future
      performance;
  
 ·
    data
      gathered for purposes of reserve estimation, such as well logs and cores,
      are representative of average reservoir
properties;
  
 ·
    assumed
      effects of regulation by governmental
agencies;
  
 ·
    assumptions
      concerning future oil and gas prices, future development, operating and
      abandonment costs and capital expenditures;
and
  
 ·
    estimates
      of future severance and excise taxes and workover and remedial
      costs.
  
 Estimates
of reserves prepared or audited by different engineers using the same data, or
by the same engineers at different times, may vary substantially. Actual
production, revenues and expenditures with respect to the company's reserves
will likely vary from estimates, and the variance may be material. The company
mitigates the risks inherent to reserve estimation through a comprehensive
reserve administration process, which includes review by independent reserve
engineers, Netherland, Sewell & Associates, Inc. (NSAI), of the company’s
procedures and methods for estimating reserves, internal peer review and
third-party assessment of significant reserve additions and annual internal
review of about 80% of the company’s total proved reserves.  At December
31, 2004, approximately 43% of the company's proved reserves had been subjected
to third-party procedures and methods reviews.
 
 **The
company is subject to complex laws and regulations, including environmental and
safety regulations, that can adversely affect the cost, manner or feasibility of
doing business.**
 
 The
company's operations and facilities are subject to certain federal, state,
tribal and local laws and regulations relating to the exploration for, and the
development, production and transportation of, oil and gas, and the production
of chemicals, as well as environmental and safety matters. Future laws or
regulations, any adverse change in the interpretation of existing laws and
regulations, inability to obtain necessary regulatory approvals, or a failure to
comply with existing legal requirements may harm the company's business, results
of operations and financial condition. The company may be required to make large
and unanticipated capital expenditures to comply with environmental and other
governmental regulations, such as: land use restrictions; drilling bonds,
performance bonds and other financial responsibility requirements; spacing of
wells; unitization and pooling of properties; habitat and endangered species
protection, reclamation and remediation, and other environmental protection;
protection and preservation of historic, archaeological and cultural resources;
safety precautions; regulations governing the operation of chemical
manufacturing facilities; regulation
of discharges, emissions, disposal and waste-related permits; operational
reporting; and taxation.
 
 Under
these laws and regulations, the company could be liable for: personal injuries;
property and natural resource damages; oil spills and releases or discharges of
hazardous materials; well reclamation costs; remediation and clean-up costs and
other governmental sanctions, such as fines and penalties; and other
environmental damages.
 
 The
company's operations could be significantly delayed or curtailed and its costs
of operations could significantly increase beyond those anticipated as a result
of regulatory requirements or restrictions. We are not able to predict the
ultimate cost of compliance with these requirements or their effect on our
operations.
 
  - 25 -
  **Costs
of environmental liabilities and regulation could exceed
estimates.**
 
 The
company and its affiliates are parties to a number of legal and administrative
proceedings involving environmental and/or other matters pending in various
courts or agencies. These include proceedings associated with facilities
currently or previously owned, operated or used by the company’s affiliates
and/or their predecessors, and include claims for personal injuries, property
damages, injury to the environment, including natural resource damages, and
non-compliance with permits. The current and former operations of the company’s
affiliates also involve management of regulated materials that are subject to
various environmental laws and regulations. These laws and regulations obligate
the company’s affiliates to clean up various sites at which petroleum and other
hydrocarbons, chemicals, low-level radioactive substances and/or other materials
have been disposed of or released. Some of these sites have been designated
Superfund sites by the Environmental Protection Agency pursuant to the
Comprehensive Environmental Response, Compensation and Liability
Act.
 
 The
company provides for costs related to environmental matters when a loss is
probable and the amount is reasonably estimable. It is not possible for the
company to estimate reliably the amount and timing of all future expenditures
related to environmental matters for the reasons described above in Items 1 and
2 under Government Regulations and Environmental Matters.
 
  Although
management believes that it has established appropriate reserves for cleanup
costs, costs may be higher than anticipated and the company could be required to
record additional reserves in the future.
 
 **The
company's oil and gas marketing activities may expose it to claims from royalty
owners.**
 
 In
addition to marketing its oil and gas production, the company's marketing
activities generally include marketing oil and gas production for royalty
owners. Over the past several years, royalty owners have commenced litigation
against a number of companies in the oil and gas production business claiming
that amounts paid for production attributable to the royalty owners' interest
violated the terms of the applicable leases and laws in various respects,
including the value of production sold, permissibility of deductions taken and
accuracy of quantities measured. The company could be required to make payments
as a result of such litigation, and the company's costs relating to the
marketing of oil and gas may increase as new cases are decided and the law in
this area continues to develop.
 
 **The
company is subject to lawsuits and claims.**
 
 A
number of lawsuits and claims are pending against the company and its
affiliates, some of which seek large amounts of damages. Although management
believes that none of the lawsuits or claims will have a material adverse effect
on the company's financial condition or liquidity, litigation is inherently
uncertain, and the lawsuits and claims could have a material adverse effect on
the company's results of operations for the accounting period or periods in
which one or more of them might be resolved adversely.
 
 
 **AVAILABILITY
OF REPORTS AND GOVERNANCE DOCUMENTS**
 
 Kerr-McGee
makes available at no cost on its Internet website, www.kerr-mcgee.com, its
Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on
Form 8-K and any amendments to those reports as soon as reasonably practicable
after the company electronically files or furnishes such reports to the SEC.
Interested parties should refer to the Investor Relations link on the company's
website. In addition, the company’s Code of Business Conduct and Ethics, Code of
Ethics for The Chief Executive Officer and Principal Financial Officers,
Corporate Governance Guidelines and the charters for the Board of Directors’
Audit Committee, Executive Compensation Committee, and Corporate Governance and
Nominating Committee, all of which were adopted by the company’s Board of
Directors, can be found on the company’s website under the Corporate Governance
link. The company will provide these governance documents in print to any
stockholder who requests them. Any amendment to, or waiver of, any provision of
the Code of Ethics for the Chief Executive Officer and Principal Financial
Officers and any waiver of the Code of Business Conduct and Ethics for directors
or executive officers will be disclosed on the company’s website under the
Corporate Governance link.
 
 On June
1, 2004, Luke R. Corbett, Chairman and Chief Executive Officer of the company,
certified to the New York Stock Exchange that he was not aware of any violation
by the company of the New York Stock Exchange’s corporate governance listing
standards. In addition, the company filed as exhibits to the company’s Form 10-K
for the year ended December 31, 2003, the certifications required under section
302 of the Sarbanes-Oxley Act of 2002.
 
 - 26 -
 
 **Item
3.**  **Legal
Proceedings**
 
 A.  In
2001, the company’s chemical affiliate (Chemical) received a Notice of Violation
(NOV) from EPA, Region 9. The NOV claims that Chemical has been in continuous
violation of the Clean Air Act new source review requirements applicable to the
construction in 1994 and continued operation of an open-hearth furnace at its
Henderson, Nevada, facility. Chemical operated the open-hearth furnace in
compliance with state-issued permits and believes that the NOV is without
substantial merit. During the fourth quarter of 2004, the parties reached an
agreement in principle on a settlement that is expected to resolve the NOV.
Under the settlement, the government would waive its claim, and Chemical would
pay penalties totaling approximately $50,000.
 
 B.  In
2002, Tiwest Pty Ltd, an Australian joint venture that produces titanium dioxide
and in which Chemical indirectly has a 50% interest, received a complaint and
notice of violation from the Department of Environmental Waters and Catchment
Protection in Western Australia (the Department) alleging violations of the
Environmental Protection Act (1986). This matter concerned an alleged chlorine
release at the facility. Tiwest defended the proceeding in the Court of Petty
Sessions, Perth, Western Australia, and on March 26, 2004, the Court found in
favor of Tiwest. The Department has appealed the Court’s decision. Tiwest is
vigorously defending against the appeal, and the company believes that, should
the Court’s ruling be overturned, any fines or penalties related to the matter
will not have a material adverse effect on the company.
 
 C.  On
January 7, 2004, the United States filed a civil lawsuit in the U.S. District
Court for the District of Oregon against Kerr-McGee Chemical Worldwide LLC and
two other private parties in connection with the remediation of contaminated
materials at the White King/Lucky Lass uranium mines in Lakeview, Oregon. The
mines were owned and operated by a predecessor of Kerr-McGee Chemical Worldwide
LLC and are currently designated as a Superfund site. The lawsuit seeks
reimbursement of Forest Service response costs, an injunction requiring
compliance with an Administrative Order issued to the private parties regarding
cleanup of the site, and civil penalties for alleged noncompliance with the
Administrative Order. All legal proceedings have been stayed pending discussions
to resolve outstanding issues. The company believes that the litigation will not
have a material adverse effect on the company.
 
 D.  On
September 8, 2003, the Environmental Protection Division of the Georgia
Department of Natural Resources (EPD) issued a unilateral Administrative Order
to Kerr-McGee Pigments (Savannah) Inc., claiming that the Savannah plant
exceeded emission allowances provided for in the facility's Title V air
permit. The EPD is seeking monetary penalties of approximately $173,000.
The company is vigorously defending against the claims made in the order and, in
that connection, the order was appealed, and its effectiveness stayed, on
October 8, 2003. The company believes that any penalties related to the Order
will not have a material adverse effect on the company.
 
 E.  On
September 15, 2004, the Missouri Attorney General issued to Kerr-McGee Chemical
LLC (Chemical) a Notice of Violations (NOV) of the Missouri Clean Water Act. The
NOV alleges the discharge of untreated contaminants from Chemical’s plant in
Springfield, Missouri to the City of Springfield sanitation system and the
Little Sac River. The Attorney General is requesting a civil penalty of
$375,000, the performance of an environmental assessment and natural resource
damages, which the Missouri Department of Natural Resources currently estimates
to be $500,000. The contractor performing the decommissioning work at the plant
at the time of the alleged discharge has acknowledged its contractual obligation
to indemnify Chemical for costs, damages or fines resulting from its actions.
The company believes that the claims made in the NOV are without substantial
merit and that any penalties and damages related to the NOV will not have a
material adverse effect on the company.
 
 F.  For a
discussion of other legal proceedings and contingencies, reference is made to
the Environmental Matters section of Management’s Discussion and Analysis of
Financial Condition and Results of Operations included in Item 7 and Note 19 to
the Consolidated Financial Statements included in Item 8 of this annual report
on Form 10-K, both of which are incorporated herein by
reference.
  - 27 -
  **Item
4.**  **Submission
of Matters to a Vote of Security Holders**
 
 None
submitted during the fourth quarter of 2004.
 
 **Executive
Officers of the Registrant**
 
 The
following is a list of executive officers, their ages, and their positions and
offices as of March 1, 2005:
  Name
    
    Age
    
    OfficeLuke
      R. Corbett
    
    58
    
    Chief
      Executive Officer since 1997. Chairman of the Board since May 1999 and
      from 1997 to February 1999. President and Chief Operating Officer from
      1995 until 1997.Kenneth
      W. Crouch
    
    61
    
    Executive
      Vice President since March 2003. Senior Vice President from 1996 to 2003.
      Senior Vice President, Exploration and Production Operations, from 1998 to
      2003. Senior Vice President, Exploration, from 1996 to
    1998.David
      A. Hager
    
    48
    
    Senior
      Vice President (oil and gas exploration and production), since March 2003.
      Vice President of Exploration and Production, 2002 to 2003. Vice President
      of Gulf of Mexico and Worldwide Deepwater Exploration and Production, 2001
      to 2002; Vice President of Worldwide Deepwater Exploration and Production,
      2000 to 2001; Vice President of International Operations, 2000; previously
      Vice President of Gulf of Mexico operations. Joined Sun Oil Co.,
      predecessor of Oryx Energy Company, in 1981. Oryx and Kerr-McGee merged in
      1999.Gregory
      F. Pilcher
    
    44
    
    Senior
      Vice President, General Counsel and Corporate Secretary since July 2000.
      Vice President, General Counsel and Corporate Secretary from 1999 to 2000.
      Deputy General Counsel for Business Transactions from 1998 to 1999.
      Associate/Assistant General Counsel for Litigation and Civil Proceedings
      from 1996 to 1998.Robert
      M. Wohleber
    
    54
    
    Senior
      Vice President and Chief Financial Officer since December 1999. Prior to
      joining the company in 1999, served as Executive Vice President and Chief
      Financial Officer of Freeport-McMoRan Exploration Company,President
      and Chief Executive Officer of Freeport-McMoRan Sulfur and Senior Vice
      President of Freeport-McMoRan Gold and Copper Corporation, each of which
      is a natural resources company.Thomas
      W. Adams
    
    44
    
    Vice
      President of Chemical since September 2004. Vice President and General
      Manager of the Pigment Division from May to September 2004. Vice President
      of Strategic Planning and Business Development from 2003 to 2004. Vice
      President of Acquisitions from March 2003 to September 2003. Vice
      President of Information Management and Technology from 2002 to 2003.
      Joined Sun Oil Co., predecessor of Oryx Energy Company, in 1982. Oryx and
      Kerr-McGee merged in 1999.George
      D. Christiansen
    
    60
    
    Vice
      President, Safety and Environmental Affairs, since 1998. Vice President,
      Environmental Assessment and Remediation, from 1996 to
    1998.
  - 28 -
 
 Fran
      G. Heartwell
    
    58
    
    Vice
      President of Human Resources since March 2003; Director of Human
      Resources, Kerr-McGee Oil & Gas, from September 2002 to January 2003;
      Vice President of Human Resources and Administration, Oryx Energy Company,
      from 1995 until the 1999 merger of Oryx and Kerr-McGee.Christina
      M. Poos
    
    35
    
    Vice
      President and Treasurer since November 2004; Vice President and Treasurer
      for Kerr-McGee Worldwide Corporation from September to November 2004;
      Assistant Corporate Controller from February 2004 to September 2004;
      Manager of Financial Reporting from November 2002 to February 2004.
      Previously Director of Accounting, Foodbrands America Incorporated (a
      division of IBP, Inc., a food products company) from June 2000 to
      September 2002.J.
      Michael Rauh
    
    55
    
    Vice
      President since 1987. Controller from 1987 to 1996 and from January 2002
      to present. Treasurer from 1996 to 2002.John
      F. Reichenberger
    
    52
    
    Vice
      President, Deputy General Counsel and Assistant Secretary since July 2000.
      Assistant Secretary and Deputy General Counsel from 1999 to 2000. Deputy
      General Counsel from 1998 to 1999. Associate General Counsel from 1996 to
      1999.
 There
is no family relationship between any of the executive officers.
 
 
 **CAUTIONARY
STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS**
 
  The
company makes certain forward-looking statements in this annual report on Form
10-K that are subject to risks and uncertainties. These statements regarding the
company's or management's intentions, beliefs or expectations, or that otherwise
speak to future events, are based on the information currently available to
management. These forward-looking statements include those statements preceded
by, followed by or that otherwise include the words "believes," "expects,"
"anticipates," "intends," "estimates," "projects," "target," “budget,” "goal,"
"plans," "objective," “outlook,” "should," or similar words. In addition, any
statements regarding possible commerciality, development plans, capacity
expansions, drilling of new wells, ultimate recoverability of reserves, future
production rates, future cash flows and changes in any of the foregoing are
forward-looking statements. Future results and developments discussed in these
statements may be affected by numerous factors and risks, such as the accuracy
of the assumptions that underlie the statements, the success of the oil and gas
exploration and production program, drilling risks, the market value of
Kerr-McGee’s products, uncertainties in interpreting engineering data, demand
for consumer products for which Kerr-McGee’s businesses supply raw materials,
the financial resources of competitors, changes in laws and regulations, the
ability to respond to challenges in international markets, including changes in
currency exchange rates, political or economic conditions in areas where
Kerr-McGee operates, trade and regulatory matters, general economic conditions,
and other factors and risks discussed herein and in the company’s other SEC
filings, and many such factors and
risks are beyond Kerr-McGee’s ability to control or predict. Forward-looking
statements are not guarantees of performance. Actual results and developments
may differ materially from those expressed or implied in this annual report on
Form 10-K. Readers are cautioned not to place any undue reliance on any
forward-looking statements. Forward-looking statements speak only as of the date
of this annual report on Form 10-K. Kerr-McGee undertakes no obligation to
update publicly any forward-looking statements, whether as a result of new
information, future events or otherwise. For such statements, Kerr-McGee claims
the protection of the safe harbor for "forward-looking statements" set forth in
the Private Securities Litigation Reform Act of 1995.
   - 29 -
  **PART
II**
 
 **Item
5.**  **Market
for the Registrant's Common Equity and Related Stockholder
Matters**
 
 Information
relating to the market in which the company's common stock is traded, the high
and low sales prices of the common stock by quarters for the past two years, and
the approximate number of holders of common stock is furnished in Note 34 to the
Consolidated Financial Statements included in Item 8 of this annual report on
Form 10-K.
 
 Quarterly
dividends declared totaled $1.80 per share for each of the years 2004, 2003 and
2002. Cash dividends have been paid continuously since 1941 and totaled $205
million in 2004, $181 million in 2003 and $181 million in 2002.
 
 Information
required under Item 201(d) of Regulation S-K relating to the company's
securities authorized for issuance under equity compensation plans is included
in Item 12 of this annual report on Form 10-K.
 
 
 **Item
6.**  **Selected
Financial Data**
 
 Information
regarding selected financial data required in this item is presented in the
schedule captioned "Ten-Year Financial Summary" included in Item 8 of this
annual report on Form 10-K.
 
 
 **Item
      7.**
    **Management's
      Discussion and Analysis of Financial Condition and Results of
      Operations**
 
 ****
 **Management’s
Discussion and Analysis**
  
 **Overview**
 
 Kerr-McGee
Corporation is one of the largest U.S.-based independent oil and gas exploration
and production companies and the world's third-largest producer and marketer of
titanium dioxide pigment in terms of volumes produced. Kerr-McGee has three
reportable business segments, oil and gas exploration and production, production
and marketing of titanium dioxide pigment (chemical - pigment), and production
and marketing of other chemical products (chemical - other). Discussion of
business developments and results of operations for each of our reportable
segments is provided below. The company announced on March 8, 2005, that its
Board of Directors authorized management to proceed with its proposal to pursue
alternatives for the separation of the chemical business, including a spinoff or
sale.
 
 In
2004, we merged with Westport Resources Corporation (Westport), an independent
exploration and production company with operations onshore in the United States
and in the Gulf of Mexico. The merger, which was completed on June 25, 2004,
increased our year-end 2003 proved oil and gas reserves by approximately 30% on
a pro forma basis, with year-end 2004 reserves reaching 1.2 billion barrels of
oil equivalent. In exchange for Westport’s common stock and options, Kerr-McGee
issued stock valued at $2.4 billion, options valued at $34 million and
assumed debt of $1 billion, for a total of $3.5 billion (net of $43 million of
cash acquired). The fair value assigned to assets acquired and goodwill totaled
$4.7 billion. The Westport merger added properties to our oil and gas business
that are complementary to existing operations. We believe this merger improves
the risk profile of our assets by adding low-risk exploitation opportunities and
increasing the weight of U.S. onshore natural gas reserves in our portfolio.
U.S. onshore reserves increased from 34% of total proved reserves at the
beginning of the year to 50% at year-end, largely as a result of our merger with
Westport. Additionally, the merger contributed to an increase in proved
developed reserves from 50% of total proved reserves at December 31, 2003, to
65% by the end of 2004. Because the percentage of our reserves located onshore
in the U.S. increased, we expect that this area will represent a higher
proportion of our worldwide production volumes and a larger share of our total
capital spending in the future. Based on our current budget, we expect that U.S.
onshore production will represent approximately 40% of our total production in
2005 on a barrel of oil equivalent basis, an increase from 34% during 2004, and
our capital expenditures in this region are anticipated to increase from 17% of
total capital expenditures in 2004 to 32% in 2005.
 
 - 30 -
 Strategically,
Kerr-McGee focuses on growing its exploration and production operations and
improving profitability of its titanium dioxide pigment business through
technological advancements and optimization of assets. Additionally, we continue
to concentrate on reducing the company’s total debt burden to remain competitive
and to increase financial flexibility. As a result of certain investing and
financing activities, including the Westport merger, the ratio of total debt to
total capitalization improved from 58% at year-end 2003 to 41% by the end of
2004 (capitalization is determined as total debt plus stockholders’ equity). In
February 2005, the company called for redemption all of the $600 million
aggregate principal amount of its 5.25% convertible subordinated debentures due
2010 at a price of 102.625%. Prior to March 4, 2005, the redemption date, all of
the debentures were converted by the holders into approximately 9.8 million
shares of common stock. Pro forma for the conversion, the company’s year-end
2004 total debt to total capitalization ratio would have been 34%. On March 8,
2005, the Board of Directors authorized the company to proceed with a share
repurchase program initially set at $1 billion. Expanded discussion of the
company’s cash flows, liquidity and capital resources is included in the *Financial
Condition* section
below.
 
 We
continue to manage risks associated with our environmental remediation
responsibilities. Because of the nature of Kerr-McGee’s current and historical
operations, the company has significant environmental remediation
responsibilities and provides reserves for these remediation projects. During
2004, the company provided $92 million (net of reimbursements) for environmental
remediation and restoration costs, of which $6 million related to discontinued
operations, and funded $49 million of expenditures associated with its
environmental projects, net of $50 million in reimbursements received from other
parties. A discussion of the status and circumstances surrounding these projects
is included in the *Environmental
Matters* section below.
 
 The
following table summarizes segment operating profit (loss), with a
reconciliation to consolidated net income (loss) for each of the last three
years:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Segment
      operating profit (loss) (1) -Exploration
      and production
    
    **$**
    **1,249**
    
    $
    1,002
    
    $
    (140
    )Chemical
      -Pigment
    
    
    **(80**
    **)**
    
    (13
    )
    
    24Other
    
    
    **(1******
    ******)**
    
    (23
    )
    
    (13
    )Total
      Chemical
    
    
    **(81******
    ******)**
    
    (36
    )
    
    11Total
      segment operating profit (loss)
    
    
    **1,168**
    
    
    966
    
    
    (129
    )Unallocated
      expenses -Interest
      and debt expense
    
    
    **(245**
    **)**
    
    (251
    )
    
    (275
    )Corporate
      expenses
    
    
    **(130**
    **)**
    
    (152
    )
    
    (158
    )Environmental
      provisions, net of reimbursements
    
    
    **(82**
    **)**
    
    (47
    )
    
    (32
    )Other
      income (expense)
    
    
    **(40**
    **)**
    
    (57
    )
    
    (31
    )Benefit
      (provision) for income taxes
    
    
    **(256******
    ******)**
    
    (195
    )
    
    35Total
      unallocated expenses
    
    
    **(753******
    ******)**
    
    (702
    )
    
    (461
    )Income
      (Loss) from continuing operations
    
    
    **415**
    
    
    264
    
    
    (590
    )Discontinued
      operations, net of taxes
    
    
    **(11**
    **)**
    
    (10
    )
    
    105Cumulative
      effect of change in accounting principle, net of taxes
    
    
    **-**
    
    
    (35
    )
    
    -Net
      Income (Loss)
    
    **$**
    **404**
    
    $
    219
    
    $
    (485
    )Net
      Income (loss) per Common Share:Basic
    
    **$**
    **3.20**
    
    $
    2.18
    
    $
    (4.84
    )Diluted
    
    
    **3.11**
    
    
    2.17
    
    
    (4.84
    )
 
 (1)
    Segment
      operating profit (loss) represents results of operations before
      considering general corporate expenses, interest and debt expense,
      environmental provisions related to businesses in which the company’s
      affiliates are no longer engaged, other income (expense) and income
      taxes.
  - 31 -
  Our
results of operations for all periods presented included certain items affecting
comparability between periods. Because of their nature and amount, these items
are identified separately to help explain the changes in segment operating
profit and income (loss) from continuing operations before income
taxes between periods, as well as to help distinguish the underlying trends
for the company’s core businesses. These items are listed in the following table
and, to the extent material, are discussed in the *Results
of Operations - Consolidated* and *Results of Operations*  *by
Segment* sections below.
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002*Included
      in Total Segment Operating Profit:*Plant shutdown costs and accelerated depreciation
    
    **$**
    **(122**
    **)**
    $
    (45
    )
    $
    (12
    )Environmental provisions
    
    
    **(4**
    **)**
    
    (13
    )
    
    (21
    )Asset impairments
    
    
    **(36**
    **)**
    
    (14
    )
    
    (646
    )Gain (loss) associated with assets held for sale
    
    
    **(29**
    **)**
    
    45
    
    
    (176
    )Nonhedge derivative loss
    
    
    **(23**
    **)**
    
    -
    
    
    -Insurance premium adjustment
    
    
    **(16**
    **)**
    
    -
    
    
    -Costs associated with the 2003 work force reduction
program
    
    
    **(2**
    **)**
    
    (35
    )
    
    -Compensation expense for allocated ESOP shares
    
    
    **-**
    
    
    (15
    )
    
    -Other
    
    
    **-**
    
    
    (4
    )
    
    (4
    )*Included
      in Unallocated Expenses:*Environmental provisions, net of reimbursements
    
    
    **(82**
    **)**
    
    (47
    )
    
    (32
    )Foreign currency losses
    
    
    **(21**
    **)**
    
    (41
    )
    
    (38
    )Litigation costs
    
    
    **(6**
    **)**
    
    (9
    )
    
    (72
    )Gain on sale of Devon stock
    
    
    **9**
    
    
    17
    
    
    -Costs associated with the 2003 work force reduction
program
    
    
    **-**
    
    
    (18
    )
    
    -Compensation expense for allocated ESOP shares
    
    
    **-**
    
    
    (6
    )
    
    -Other
    
    
    **(4******
    ******)**
    
    (6
    )
    
    6Total
      items affecting comparability
    
    **$**
    **(336**
    **)**
    $
    (191
    )
    $
    (995
    )
 
 An
overview of each segment is included below to provide background information for
the various discussions that follow in Management’s Discussion and Analysis of
Financial Condition and Results of Operations. A detailed discussion of each
segment’s business and properties is included in Items 1 and 2 of this annual
report on Form 10-K.
 
 **Exploration
and Production -** The
company's oil and gas business is principally focused on exploration,
development and production of crude oil and natural gas. Our core areas of
operation are in the Gulf of Mexico, onshore in the United States, the United
Kingdom sector of the North Sea and China. In addition, we are actively engaged
in exploration efforts within the core areas listed above, as well as in Alaska,
Brazil, Morocco, Bahamas, Benin and other areas.
 
 Our
exploration and production business is focused on creating shareholder value and
profitable growth through exploration, core area exploitation and tactical
acquisitions. The first component of our strategy is deepwater-focused
exploration in both the Gulf of Mexico and key international basins,
complemented by lower risk exploration activities onshore in the U.S., Gulf of
Mexico shelf, the North Sea and China. Over the past year, Kerr-McGee has
refined its international/new ventures exploration strategy to focus primarily
on opportunities in areas with proven world-class hydrocarbon basins such as
Brazil and Alaska. We believe this refined strategy will yield more predictable
results from exploration and better year-over-year growth performance from the
drill-bit.
 
 Cost-efficient
core area exploitation is a second key component of the company’s strategy.
Exploitation and development opportunities within our core areas of operation
provide the base cash generation capability of our business and ultimately fund
exploration growth opportunities. The company supplements its exploration and
exploitation programs with tactical acquisitions in its core producing areas. We
only pursue acquisition opportunities where we can add incremental value through
unique geological knowledge, utilization of existing infrastructure in the areas
acquired or our ability to lower costs.
 
 - 32 -
 Commodity
prices were relatively high throughout 2004. This price strength, coupled with a
15% increase in average daily production volume, enabled us to fund a $1.2
billion capital expenditure program and still generate significant excess free
cash flow. Significant financial and operating milestones achieved by the
exploration and production business in 2004 included:
 
 ·
    Successful
      completion of the Westport merger.
 
 ·
    Operating
      profit increased 25% over 2003, reaching a record $1.2
      billion.
 
 ·
    Average
      daily production volumes were 312,200 barrels of oil equivalent in 2004,
      an increase of 15% over 2003, largely due to the Westport merger. We
      anticipate that 2005 average daily production will range between 352,000
      and 367,000 barrels of oil equivalent.
 
 ·
    Replaced
      280% of 2004 production largely as a result of the Westport
      merger.
 
 ·
    Achieved
      first production from the Red Hawk development in the deepwater Gulf of
      Mexico. The project was completed on time and within
    budget.
 
 ·
    Achieved
      first production from the CFD 11-1 and CFD 11-2 development in Bohai Bay,
      China. First production was achieved nearly five months ahead of schedule
      and within budget.
 
 Although
the company achieved a number of significant exploration successes in 2004, most
were not well enough defined to recognize proved reserves, but may offer
potential for future proved reserves additions. 2004 discoveries
included:
 
 ·
    Ticonderoga
      (50% working interest) in the deepwater Gulf of Mexico, which will be
      developed as a subsea tieback to our Constitution
    development.
 
 ·
    Nikaitchuq
      (70%) in Alaska where we drilled two successful wells in 2004. An
      appraisal and testing program designed to delineate the discovery is
      currently under way.
 
 ·
    BMC-7
      (33%) in the Campos Basin of Brazil. Appraisal of this discovery is
      ongoing.
 
 ·
    CFD-14-5-1
      (100%) in the 09/18 block in Bohai Bay, China. Appraisal planning for this
      discovery is under way, and we expect to spud the first appraisal well in
      the first quarter of 2005.
 
 Despite
these successes and other successful exploratory wells onshore in the U.S. and
in the Gulf of Mexico, the exploration program was unable to deliver an
acceptable level of proved reserve additions in 2004, with an exploration-based
production replacement of only 34%. To improve the consistency of its
exploration performance, the company has refocused its core exploration program
in areas with proven world-class hydrocarbon basins. Concentrating our
exploration in areas where working hydrocarbon systems are known to exist
reduces the geologic risk profile for the company, increasing our chances of
discovering economically recoverable accumulations of oil and gas. We believe
this shift in focus moves us to a more appropriate overall risk profile. The
merger with Westport also is anticipated to provide an important source of
future low-risk proved reserve additions. The company believes its refined
exploration strategy, supplemented by low- to moderate-risk offshore satellite
opportunities and an active U.S. onshore program focused on contributing to our
proved reserves, will improve the consistency of results from exploration and
deliver better year-over-year performance.
 
 The
merger with Westport added substantial depth, breadth and balance to the
company’s oil and gas operations. Specifically, the merger expanded the
company’s base of low-risk exploitation projects in the Rocky Mountains, U.S.
Gulf Coast and the Mid-Continent/Permian Basin areas. In addition, the merger
changed the composition of the company’s reserve base, increasing U.S. reserves
from 69% at year-end 2003 to 77% at year-end 2004. A significant portion of the
acquired U.S. reserves are long-lived natural gas reservoirs. The Westport
merger accelerated the company’s growth profile, contributing to a 15% increase
in production over 2003. Since the completion of the merger, we have moved
rapidly to capitalize on new exploitation opportunities, with much of our effort
focused in two key fields, the Greater Natural Buttes in Utah and Moxa Arch in
Wyoming. This exploitation focus is already generating strong results, with
production from Westport’s Rocky Mountain properties up by over 15% since the
merger.
 
 - 33 -
 Our
refined exploration strategy has been designed to put the company on track to
deliver improved exploration performance in 2005 and beyond. The company has a
large portfolio of low-risk exploitation projects, and we intend to capitalize
on those opportunities in 2005. For 2005, we have planned the largest
exploration and development program in the company’s history, including some 900
exploration and development wells, $1.7 billion in capital expenditures and $380
million in exploration costs. We are committing the resources necessary to
effectively execute this program with a goal of delivering growth in both
reserves and production.
 
 **Chemical
-** Our
chemical business has focused its strategy on its titanium dioxide pigment
operations. As part of this strategic decision, we continue to investigate
divestiture options for the electrolytic business and finalized our exit of the
forest products business in early 2005. Results of operations for the forest
products business are reflected in the Consolidated Statement of Operations in
income (loss) from discontinued operations for all periods
presented.
 
 Titanium
dioxide pigment is produced using one of two different technologies, the
chloride process and the sulfate process. The chloride process produces a
pigment with superior brightness and durability preferred by many manufactures
of paint, coatings and plastics. In early 2005, chloride-process capacity
accounted for 83% of our gross pigment production capacity. The remaining
capacity is sulfate-process production, which produces pigment used in paper and
specialty products. In the
global titanium dioxide pigment industry, Kerr-McGee is the third-largest
producer and marketer and one of five companies that own chloride technology.
 
 The
profitability and cash flows of the company’s pigment operations is directly
tied to the global demand, consumption and pricing of titanium dioxide pigment,
which tends to follow global economic trends (discussed in the *Operating
Environment and Outlook* section below). While the general business environment and pigment pricing play
a major role in profitability, execution of asset optimization plans, operations
excellence, supply chain management principles, technological innovation and
market segmentation further affect performance.
 
 To
optimize our assets and improve profitability, the company shut down its
Savannah, Georgia, titanium dioxide pigment sulfate facility in 2004. This
facility contributed approximately 4% of our total worldwide pigment production
in the first half of 2004. Demand and prices for sulfate anatase pigments,
particularly in the paper market, had consistently declined in North America
during the past several years. The decreasing volumes, along with unanticipated
environmental and infrastructure issues discovered after Kerr-McGee acquired the
facility in 2000, created unacceptable financial returns for the facility and
contributed to the decision. In conjunction with this decision, the company also
ended production at its Savannah gypsum plant that used by-product from the
sulfate process to manufacture gypsum. In connection with the shutdown, the
company recognized a pretax charge of $105 million during 2004.
 
 As part
of the company's efforts in the area of technological innovation, low-cost
capacity expansions were added to take advantage of future market growth. As a
result of these efforts, production began through a new high-productivity
oxidation line at the Savannah, Georgia, chloride process pigment plant in early
2004. This new technology is expected to result in low-cost, incremental
capacity increases through modification of existing chloride oxidation lines and
should allow for improved operating efficiencies through simplification of
hardware configurations and reduced maintenance requirements.
 
 The
company continues to evaluate the performance of this new oxidation line and
expects to have a better understanding of how the Savannah site might be
reconfigured to exploit its capabilities in 2005. The possible reconfiguration
of the Savannah site, if any, could include redeployment of certain assets,
idling of certain assets and reduction of the future useful life of certain
assets, resulting in the acceleration of depreciation expense and the
recognition of other charges.
 
 The
Avestor joint venture was created by Kerr-McGee and Hydro-Quebec, one of North
America’s largest utilities, to commercialize and produce a
lithium-metal-polymer battery. Commercial battery production and sales
commenced in late 2003 to the North American telecommunications industry.
Production and sales rates increased during 2004 and are expected to continue
increasing during 2005. Avestor’s unique technical and product offering
capability is expected to create additional high-market-value opportunities in
the electric utility and industrial battery back-up energy markets. With
market demand growing, Avestor expects to achieve a breakeven operating cash
position in 2006 and anticipates sales matching plant capacity in
2009.
 
 - 34 -
  
 
 **Operating
Environment and Outlook**
  **Oil and Gas
Exploration and Production**
  ***Commodity
Markets*** - The
oil and gas industry enjoyed strong commodity prices throughout 2004. Supply and
geopolitical uncertainties, combined with strong demand, resulted in
historically high prices for the industry. Prices for West Texas Intermediate
(WTI) crude oil averaged $41.40 per barrel for the year, with a low price of
about $32.50 per barrel occurring in the first quarter and a high price point in
excess of $55.00 per barrel in late October. Crude oil prices were driven
largely by geopolitical instabilities in various producing regions, including
the Middle East, Nigeria and Venezuela, as well as concerns that world oil
production may be challenged to meet overall market demand. These concerns,
coupled with rapidly growing demand, particularly in Asian markets, contributed
to strong pricing and market volatility. The year ended with WTI crude oil
prices at about $43.50 per barrel. U.S. natural gas pricing was also strong
throughout the year, with New York Mercantile Exchange (NYMEX) futures prices
never falling below $5.00 per million British thermal units (MMBtu). The gas
market continues to be driven by fundamental uncertainties regarding the
industry’s ability to maintain supply in line with increasing demand. In spite
of high gas storage inventories, pricing peaked during the fourth quarter of
2004 at around $8.00 per MMBtu. Late in the fourth quarter, prices moderated in
response to continued high inventory levels and mild winter conditions for much
of the country. For the year, NYMEX natural gas prices averaged about $6.15 per
MMBtu and ended the year at about $6.40 per MMBtu. The outlook for the commodity
markets in 2005 calls for continued volatility. Most experts see prices for both
oil and gas moderating, but remaining above historical levels.
  To
mitigate uncertainties related to oil and gas price fluctuations, the company
enters into derivatives to hedge prices expected to be realized upon the sale of
future oil and gas production. Details of the company’s commodity derivatives
are provided in the Market
Risks section below.
  ***Industry
Environment*** -
Competition in the oil and gas industry for attractive exploration, exploitation
and development opportunities is intense. To meet this competition, Kerr-McGee
employs a balanced portfolio of attractive exploration opportunities,
supplemented by lower-risk satellite and onshore exploration prospects and a
strong exploitation project inventory. In addition, the company pursues tactical
acquisitions, property exchanges and other business development activity to
augment its exploration, exploitation and development programs.
  The
company’s exploration portfolio is anchored by a large acreage and prospect
inventory. The company makes extensive use of technology and highly trained
geoscientists to effectively evaluate prospects, reducing pre-drill risk to an
acceptable level. The company maintains a dedicated exploration technology group
which focuses on 3-D visualization technology, seismic data processing and
interpretation, and application of new and emerging technologies to more
effectively evaluate exploration prospects. Over the past year, our exploration
efforts have been refocused on proven world-class hydrocarbon basins to lower
the overall risk profile. The company maintains a core group of highly
experienced development personnel to quickly and efficiently exploit attractive
new offshore oil and gas discoveries using new technologies. We currently
operate five facilities in the deepwater Gulf of Mexico. This infrastructure
provides Kerr-McGee with a competitive advantage, enabling the company to
efficiently employ a hub-and-spoke concept of satellite exploration and
exploitation of nearby opportunities. One of the company’s key strengths is its
ability to profitably develop smaller offshore oil and gas discoveries that
previously might have been considered uneconomical.
  The
company’s acquisition of HS Resources in 2001 and Westport in mid-2004 greatly
enhanced its inventory of low-risk natural gas exploitation opportunities in the
Rocky Mountain region. These gas resources are long life reservoirs, which work
to stabilize the company’s production base. The relatively low risk nature of
these opportunities provides balance to the company’s exploration program. In
the U.K. the company also employs a hub and spoke development philosophy
utilizing Kerr-McGee’s operated infrastructure as a base for satellite
exploration and exploitation of nearby opportunities.
  - 35 -
 The
company utilizes regional business development teams to evaluate tactical
acquisition and trade opportunities to supplement its exploration and
exploitation efforts. A good example is the recently announced trade of our U.S.
onshore Arkoma Basin properties for British Petroleum’s interest in the Blind
Faith discovery in the Gulf of Mexico. The transaction provided the company with
a 37.5% interest in a new offshore discovery which Kerr-McGee plans to quickly
develop into new proved reserves and production.
  In
2005, with higher commodity prices, the company expects competition for
high-quality exploration and exploitation opportunities to remain strong. The
company will continue to refine the exploration, exploitation and business
development approach described above to gain competitive advantage among its
peers.
  
 **Chemical**
 
 Titanium
dioxide is a quality-of-life product, and its consumption follows general
economic trends. Coming off a challenging year in 2003, business conditions for
the company's chemical operations improved in 2004 due to general strengthening
of the global economy. These economic forces created increases in demand,
pushing capacity utilization higher and reduced overall inventory levels,
thereby creating an environment favorable for product price gains. Partially
offsetting the general economic robustness, were the impacts of higher energy
prices on our operations and the weakening of the U.S. dollar, which weakened
local pricing dynamics in various global markets. While overall global economic
growth was strong throughout 2004, the last quarter of 2004 did begin to show
signs of a leveling off in the leading U.S. economic indicators and Euro-zone
gross domestic product. Moving into 2005, general economic conditions are
expected to resemble more normal growth patterns, particularly in North America
and Europe, while Asian markets are expected to lead the way, as they did in
2004.
 
 The
strategy for Kerr-McGee's chemical unit focuses on continued improvement in
asset productivity, process and product capability, cost reductions and
providing superior products for market-segment growth. Multiple initiatives are
being pursued to capture new market growth through segmentation strategies that
align products with customer needs, low-cost plant modifications to increase
production capacity, continuous improvement programs to increase efficiency and
lower operating costs, and technology-based programs to improve product quality
and lower costs.
 
  - 36 -
   
 **Results
of Operations - Consolidated**
 
 The
following discussion presents results of consolidated operations, with
additional analysis of segment operations included in *Results
of Operations by Segment.*
 
 ***Revenues*** - The
increase in 2004 revenues was primarily due to higher average realized sales
prices and higher sales volumes for crude oil, natural gas and titanium dioxide
pigment. Approximately 87% of the 2004 growth in consolidated revenues was
generated by our oil and gas exploration and production segment. Oil and gas
sales volumes on a barrel of oil equivalent basis increased 15% over 2003
volumes as a result of the Westport merger completed in June 2004. Oil and gas
sales volumes declined in 2003 compared to 2002 primarily due to property
divestitures. Average prices realized from sales of oil and gas, including the
effect of realized losses on our hedging contracts, increased by 13% in 2004 and
29% in 2003 as a result of stronger commodity prices. Gas marketing sales
revenues increased by $121 million in 2004 and $228 million in 2003 largely as a
result of higher natural gas marketing volumes and prices. These increases were
offset by higher gas purchase costs. Improvement in the general economic
conditions favorably affected pigment sales volumes in 2004 and 2003,
contributing to growth in our consolidated revenues. A summary of components of
changes in consolidated revenues over the three-year period ended December 31,
2004, is presented below. Additional analysis of factors contributing to these
changes is included in Results
of Operations by Segment.
 
 (Millions
      of dollars)
    
    **2004**
    
    **2004
      vs. 2003**
    
    **2003**
    
    **2003
      vs. 2002**
    
    **2002*****Revenues***
    
    $
    5,157
    
    $
    1,077
    
    $
    4,080
    
    $
    565
    
    $
    3,515Increase
      (decrease) in:Oil
      and gas sales revenues due to volume changes
    
    
    
    
    $
    405
    
    
    
    
    $
    (362
    )Oil
      and gas sales revenues due to changes in realized prices
    
    
    
    
    
    385
    
    
    
    
    
    594Gas
      marketing sales revenues
    
    
    
    
    
    121
    
    
    
    
    
    228Other
      exploration and production segment revenues
    
    
    
    
    
    21
    
    
    
    
    
    13Pigment
      sales revenues due to volume changes
    
    
    
    
    
    114
    
    
    
    
    
    (10
    )Pigment
      sales revenues due to changes in realized prices
    
    
    
    
    
    16
    
    
    
    
    
    94Other
      chemical segment revenues
    
    
    
    
    
    15
    
    
    
    
    
    8**Total
      change in revenues**
    
    
    
    
    $
    1,077
    
    
    
    
    $
    565
 
 
 ***Costs
and Operating Expenses -*** Costs
and operating expenses during 2004 increased by $390 million, or 25%, over 2003,
largely due to higher lease operating expenses, gas purchase costs and pigment
production costs. The increase in lease operating expenses is primarily
attributable to the Westport merger. Cost of natural gas marketed and associated
transportation expenses increased by $127 million, more than offsetting the
increase in gas marketing sales revenues discussed above. Additionally, higher
pigment sales volume and average cost contributed to the 2004 increase. Costs
and operating expenses for 2003 increased $220 million over 2002, primarily due
to higher gas marketing costs of $233 million (which offset higher gas marketing
sales revenues), higher pigment production costs of $35 million and 2003 plant
shutdown provisions associated with the closure of the synthetic rutile facility
in Mobile, Alabama. These increases were partially offset by lower lease
operating expense of $114 million, mainly due to oil and gas property
divestitures.
 
 (Millions
      of dollars)
    
    **2004**
    
    **2004
      vs. 2003**
    
    **2003**
    
    **2003
      vs. 2002**
    
    **2002*****Costs
      and Operating Expenses***
    
    $
    1,953
    
    $
    390
    
    $
    1,563
    
    $
    220
    
    $
    1,343Increase
      (decrease) in:Lease
      operating expense
    
    
    
    
    $
    118
    
    
    
    
    $
    (114
    )Gas
      purchase costs
    
    
    
    
    
    127
    
    
    
    
    
    233Costs
      associated with plant shutdowns
    
    
    
    
    
    16
    
    
    
    
    
    28Pigment
      production costs
    
    
    
    
    
    108
    
    
    
    
    
    35Other
      costs and operating expenses
    
    
    
    
    
    21
    
    
    
    
    
    38**Total
      change in costs and operating expenses**
    
    
    
    
    $
    390
    
    
    
    
    $
    220
 
 - 37 -
 ***Selling,
General and Administrative Expenses*** - The
decrease of $28 million from 2003 to 2004 was mainly due to certain 2003
expenses that did not reoccur, partially offset by higher compensation costs. In
2003, we initiated a work force reduction program and recorded a total charge of
$53 million, of which $48 million was included as a component of selling,
general and administrative expenses and $5 million was included in other
categories of operating expenses. An additional $1 million of costs associated
with the 2003 work force reduction program was incurred in 2004. Recurring
employee-related costs, primarily incentive compensation, increased by $32
million in 2004. During 2003, selling, general and administrative expenses
increased 19% over 2002, primarily due to provisions associated with the 2003
work force reduction program and additional compensation expense resulting from
loan prepayments required to release shares from the company’s employee stock
ownership plan. Additionally, higher expense associated with incentive
compensation awards and pension and postretirement benefits contributed to the
2003 increase. These increases were partially offset by a decrease in litigation
provisions. In 2002, we recognized a charge of $72 million mainly related to
certain forest products litigation in Mississippi, Louisiana and Pennsylvania.
This litigation is discussed in Note 19 to the Consolidated Financial Statements
included in Item 8 of this annual report on Form 10-K.
 
 (Millions
      of dollars)
    
    **2004**
    
    **2004
      vs. 2003**
    
    **2003**
    
    **2003
      vs. 2002**
    
    **2002*****Selling,
      general and administrative expenses***
    
    $
    337
    
    $
    (28
    )
    $
    365
    
    $
    57
    
    $
    308Increase
      (decrease) in:Cost of the 2003 work force reduction program
    
    
    
    
    $
    (47
    )
    
    
    
    $
    48Compensation expense for allocated ESOP shares
    
    
    
    
    
    (16
    )
    
    
    
    
    16Other compensation, including incentive compensation
    
    
    
    
    
    32
    
    
    
    
    
    21Litigation provisions
    
    
    
    
    
    3
    
    
    
    
    
    (63
    )Other selling, general and administrative expenses
    
    
    
    
    
    -
    
    
    
    
    
    35**Total
      change in selling, general and administrative****expenses**
    
    
    
    
    $
    (28
    )
    
    
    
    $
    57
 
 
 ***Depreciation
and Depletion*** - The
2004 increase reflects the impact of the Westport merger, changes in reserve
estimates for certain oil and gas properties and accelerated depreciation
associated with chemical plants. The decrease in 2003 is due to divested or
held-for-sale oil and gas properties and lower depletion on the Leadon field,
the value of which was written down in 2002, partially offset by higher
depletion expense in the Gulf of Mexico region, mainly due to increased oil and
gas production volumes.
 
 (Millions
      of dollars)
    
    **2004**
    
    **2004
      vs. 2003**
    
    **2003**
    
    **2003
      vs. 2002**
    
    **2002*****Depreciation
      and depletion***
    
    $
    1,060
    
    $
    318
    
    $
    742
    
    $
    (67
    )
    $
    809Increase
      (decrease) in:Oil
      and gas depletion due to change in depletion rates
    
    
    
    
    $
    150
    
    
    
    
    $
    19Oil
      and gas depletion due to change in sales volumes
    
    
    
    
    
    95
    
    
    
    
    
    (100
    )Chemical
      segment accelerated depreciation
    
    
    
    
    
    71
    
    
    
    
    
    3Other
      depreciation
    
    
    
    
    
    2
    
    
    
    
    
    11**Total
      change in depreciation and depletion**
    
    
    
    
    $
    318
    
    
    
    
    $
    (67
    )
 
 ***Exploration
Expense*** - Total
exploration expense of $356 million in 2004 remained substantially unchanged
from 2003. Exploration expense in 2003 was higher than in 2002 by $81 million.
Components of exploration expense are further analyzed in *Results
of Operations by Segment - Exploration and Production.*
 
 -
38 -
 ***Interest
and Debt Expense*** -
Interest and debt expense for 2004, 2003 and 2002 was $245 million, $251 million
and $275 million, respectively. The 2004 decrease of $6 million was due to an
increase in capitalized interest and higher realized gains on interest rate
swaps designated to hedge the fair value of our debt.  For additional
information regarding these instruments, refer to the *Market
Risks* section below. The decrease from 2002 to 2003 was attributable to lower average
borrowings under revolving credit facilities and commercial paper of
approximately $570 million and slightly lower average interest rates on the
company’s long-term debt.
 
 ***Shipping
and Handling Expenses*** -
Shipping and handling expenses for 2004, 2003 and 2002 were $166 million, $139
million and $124 million, respectively. An analysis of transportation and
shipping and handling expenses is provided in *Results
of Operations by Segment* below.
 
 ***Accretion
Expense*** -
Accretion expense for 2004 and 2003 was $30 million and $25 million,
respectively. The increase during 2004 resulted primarily from an increase in
our asset retirement obligations associated with Westport
properties.
 
 ***Asset
Impairments*** -
Asset impairment charges totaled $36 million in 2004, $14 million in 2003 and
$646 million in 2002. Our chemical - pigment segment incurred an asset
impairment of $8 million in 2004 (related to the shutdown of the
sulfate-process titanium dioxide pigment production at the Savannah, Georgia,
plant). The remaining asset impairment charges were related to our exploration
and production segment and are discussed in more detail in *Results
of Operations by Segment - Exploration and Production* .
 
 ***Gains
(Losses) Associated with Assets Held for Sale*** - Net
gains (losses) associated with assets held for sale in 2004, 2003 and 2002 were
$(29) million, $45 million and $(176) million, respectively, all of which
related to our oil and gas exploration and production segment. Additional
discussion of these gains and losses is provided in *Results
of Operations by Segment - Exploration and Production* .
 
 ***Taxes,
Other than Income Taxes*** -
Taxes, other than income taxes totaled $148 million, $96 million and $102
million in 2004, 2003 and 2002, respectively, and includes $104 million,
$52 million and $67 million, respectively, of oil and gas production and ad
valorem taxes. Because oil and gas production taxes are generally determined as
a percentage of oil and gas sales revenues, they fluctuate with
changes in oil and gas sales volumes and realized prices. Oil and gas production
and ad valorem taxes increased $52 million in 2004 compared to 2003 due to
higher sales volumes primarily as a result of the Westport merger and higher
realized prices. The decrease from 2002 to 2003 was caused by elimination
of royalty payments in the U.K. North Sea and lower sales volumes due to
property divestitures.  Taxes, other than income taxes also includes
payroll and ad valorem taxes, which did not change significantly over the
three-year period ended December 31, 2004.
 
 ***Provision
for Environmental Remediation and Restoration*** -
Provision for environmental remediation and restoration, net of reimbursements,
totaled $86 million, $60 million and $53 million in 2004, 2003 and 2002,
respectively. Our environmental obligations are discussed in detail under *Environmental
Matters* below.
 
 ***Other
Income (Expense)*** -
Other income (expense) totaled $(40) million, $(57) million and $(31) million,
which included $(21) million, $(41) million and $(38) million in 2004, 2003 and
2002, respectively, of net foreign currency losses. The majority of the foreign
currency losses resulted from the company's U.K. operations due to unfavorable
changes in the U.S. dollar/British pound sterling exchange rates. Additionally,
equity in net losses of equity method investees, net of gains, totaled $26
million, $33 million and $25 million in 2004, 2003 and 2002, respectively, and
were primarily the result of the investment in the Avestor joint venture formed
in 2001 to develop lithium-metal-polymer batteries. These losses were partially
offset in 2004 and 2003 by gains on sales of Devon common stock. In December
2003, we sold a portion of our investment in Devon shares classified as
available for sale, resulting in a pretax gain of $17 million. The remaining
shares classified as available for sale were sold in January 2004 for a pretax
gain of $9 million. Through August 2, 2004, we also held 8.4 million shares of
Devon common stock classified as trading. On August 2, 2004, these shares were
distributed to the holders of our debt exchangeable for common stock to repay
the debt at maturity. During 2002, 2003 and through August 2, 2004, other income
(expense) included net gains of $27 million, $8 million and $2
million representing changes in the fair value of Devon common stock
classified as trading and changes in the estimated fair value of options
embedded in the debt exchangeable for common stock.
 
  - 39 -
  ***Provision
(Benefit) for Income Taxes*** - The
effective tax rate for 2004 was 38.2%, compared with 42.5% in 2003 and (5.6)% in
2002. The effective tax rate declined in 2004 because of decreased proportion of
income from continuing operations attributable to foreign operations. The 2002
tax benefit was reduced from the U.S. statutory rate due to deferred tax expense
of $132 million associated with a 33% increase in the U.K. corporate tax rate
for oil and gas companies, together with the impact of taxation on foreign
operations.
 
 ***Income
(Loss) from Discontinued Operations*** - The
company recognized a loss from discontinued operations as a result
of its decision to dispose of the forest products business of $11
million, $10 million and $21 million, net of tax benefit, for the years 2004,
2003 and 2002, respectively. Prior to its disposition, the forest product
business reqresented a componet of our chemical - other segment.  The 2002
income from discontinued operations also includes income of $126 million
(including tax benefit of $22 million) resulting from the company’s decision in
early 2002 to dispose of its exploration and production interests in Indonesia
and Kazakhstan and its interest in the Bayu-Undan project in the East Timor Sea
offshore Australia. The $126 million income included a net pretax gain on sale
of $72 million associated with the divestitures. These divestiture decisions
were made as part of the company’s strategic plan to rationalize noncore
chemical and oil and gas assets.
 
 ***Cumulative
Effect of Change in Accounting Principle*** - We
recognized a loss of $35 million (net of income tax benefit of $18 million) in
2003 upon adoption, as of January 1, 2003, of Financial Accounting Standards
Board Statement No. 143 (FAS No. 143), “Accounting for Asset Retirement
Obligations.” Adoption of this standard also resulted in an increase in net
property of $108 million, an increase in abandonment liabilities of $161 million
and a decrease in deferred income tax liabilities of $18
million.
  - 40 -
   
 **Results
of Operations by Segment**
 
 **EXPLORATION
AND PRODUCTION**
 
 **Segment
Operating Profit**
 
 Revenues,
operating costs and expenses relating to the production, sale and marketing of
crude oil, condensate and natural gas are shown in the following
table.
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Revenues,
      excluding marketing revenues
    
    **$**
    **3,436**
    
    $
    2,625
    
    $
    2,380Operating
      costs and expenses:Lifting
      costs:Lease
      operating expense
    
    
    **452**
    
    
    334
    
    
    448Production
      and ad valorem taxes
    
    
    **104**
    
    
    52
    
    
    67Total
      lifting costs
    
    
    **556**
    
    
    386
    
    
    515Depreciation,
      depletion and amortization
    
    
    **854**
    
    
    609
    
    
    690Accretion
      expense (abandonment obligations)
    
    
    **30**
    
    
    25
    
    
    -Asset
      impairments
    
    
    **28**
    
    
    14
    
    
    646Loss
      (gain) associated with assets held for sale
    
    
    **29**
    
    
    (45
    )
    
    176General
      and administrative expense
    
    
    **135**
    
    
    127
    
    
    87Transportation
      expense
    
    
    **111**
    
    
    94
    
    
    84Gas
      gathering, pipeline and other expenses
    
    
    **89**
    
    
    66
    
    
    61Exploration
      expense
    
    
    **356**
    
    
    354
    
    
    273Total
      operating cost and expenses
    
    
    **2,188**
    
    
    1,630
    
    
    2,532Operating
      profit (loss), excluding net marketing margin
    
    
    **1,248**
    
    
    995
    
    
    (152
    )Marketing
      - Gas sales revenues
    
    
    **419**
    
    
    298
    
    
    70Marketing
      - Gas purchase cost (including transportation)
    
    
    **(418******
    ******)**
    
    (291
    )
    
    (58
    )Net
      marketing margin
    
    
    **1**
    
    
    7
    
    
    12Total
      Operating Profit (Loss)
    
    **$**
    **1,249**
    
    $
    1,002
    
    $
    (140
    )
 
 
 Operating
profit (loss) for all periods presented included certain items affecting
comparability between periods. Because of their nature and amount, these items
are identified separately to help explain the changes in operating profit (loss)
between periods, as well as to help distinguish the underlying trends for the
segment’s core business. These items are listed in the following table and, to
the extent material, are discussed in the analysis of operating profit
components that follows:
 
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Asset
      impairments
    
    **$**
    **(28**
    **)**
    $
    (14
    )
    $
    (646
    )Gain
      (loss) associated with assets held for sale
    
    
    **(29**
    **)**
    
    45
    
    
    (176
    )Nonhedge
      derivative loss
    
    
    **(23**
    **)**
    
    -
    
    
    -Insurance
      premium adjustment
    
    
    **(12**
    **)**
    
    -
    
    
    -Costs
      associated with the 2003 work force reduction program
    
    
    **(1**
    **)**
    
    (14
    )
    
    -Environmental
      provisions
    
    
    **-**
    
    
    -
    
    
    (11
    )Compensation
      expense for allocated ESOP shares
    
    
    **-**
    
    
    (9
    )
    
    -Other
    
    
    **(4******
    ******)**
    
    (5
    )
    
    (2
    )Total
      items affecting comparability
    
    **$******
    **(97******
    ******)**
    $
    3
    
    $
    (835
    )
 
 
  - 41 -
  **Revenues**
 
 Revenues,
production statistics and average prices received from sales of crude oil,
condensate and natural gas are shown in the following table (exclusive of
discontinued operations):
 
 (Millions
      of dollars, except per-unit amounts)
    
    **2004**
    
    2003
    
    2002Revenues
      -Crude
      oil and condensate sales
    
    **$**
    **1,644**
    
    $
    1,426
    
    $
    1,531Natural
      gas sales
    
    
    **1,728**
    
    
    1,156
    
    
    819Gas
      marketing activities
    
    
    **419**
    
    
    298
    
    
    70Other
      revenues
    
    
    **87**
    
    
    43
    
    
    30Nonhedge
      derivative losses
    
    
    **(23******
    ******)**
    
    -
    
    
    -Total
    
    **$**
    **3,855**
    
    $
    2,923
    
    $
    2,450Production
      -Crude
      oil and condensate (thousands of barrels per day):U.S.
      Gulf of Mexico
    
    
    **59.9**
    
    
    56.8
    
    
    52.7U.S.
      onshore
    
    
    **28.2**
    
    
    19.7
    
    
    28.6North
      Sea
    
    
    **62.3**
    
    
    71.6
    
    
    102.8China
    
    
    **8.4**
    
    
    2.1
    
    
    3.3Other
      International
    
    
    **-**
    
    
    -
    
    
    3.9Total
    
    
    **158.8**
    
    
    150.2
    
    
    191.3Natural
      gas (MMcf per day):U.S.
      Gulf of Mexico
    
    
    **364**
    
    
    277
    
    
    273U.S.
      onshore
    
    
    **472**
    
    
    352
    
    
    386North
      Sea
    
    
    **85**
    
    
    97
    
    
    101Total
    
    
    **921**
    
    
    726
    
    
    760Total
      equivalent barrels of oil (thousands of barrels per day)
    
    
    **312**
    
    
    271
    
    
    318Average
      sales prices (excluding hedges) (1)
      -Crude
      oil and condensate (per barrel):U.S.
      Gulf of Mexico
    
    **$**
    **37.97**
    
    $
    29.14
    
    $
    22.73U.S.
      onshore
    
    
    **37.63**
    
    
    27.42
    
    
    22.12North
      Sea
    
    
    **35.77**
    
    
    28.26
    
    
    23.75China
    
    
    **32.37**
    
    
    29.66
    
    
    24.84Other
      International
    
    
    **-**
    
    
    -
    
    
    20.28Average
    
    
    **36.76**
    
    
    28.50
    
    
    23.17Natural
      gas (per Mcf):U.S.
      Gulf of Mexico
    
    **$**
    **6.25**
    
    $
    5.60
    
    $
    3.39U.S.
      onshore
    
    
    **5.92**
    
    
    4.87
    
    
    2.81North
      Sea
    
    
    **4.06**
    
    
    3.09
    
    
    2.35Average
    
    
    **5.88**
    
    
    4.92
    
    
    2.96Average
      realized sales prices (including hedges) (1)
      -Crude
      oil and condensate (per barrel):U.S.
      Gulf of Mexico
    
    **$**
    **29.43**
    
    $
    26.12
    
    $
    21.58U.S.
      onshore
    
    
    **28.43**
    
    
    26.23
    
    
    21.50North
      Sea
    
    
    **26.50**
    
    
    25.82
    
    
    22.41China
    
    
    **32.37**
    
    
    29.66
    
    
    24.84Other
      International
    
    
    **-**
    
    
    -
    
    
    20.28Total
    
    
    **28.23**
    
    
    26.04
    
    
    22.04Natural
      gas (per Mcf):U.S.
      Gulf of Mexico
    
    **$**
    **5.44**
    
    $
    4.88
    
    $
    3.23U.S.
      onshore
    
    
    **5.08**
    
    
    4.31
    
    
    2.91North
      Sea
    
    
    **4.06**
    
    
    3.09
    
    
    2.35Total
    
    
    **5.13**
    
    
    4.37
    
    
    2.95
 
 (1)Prices
are shown both with and without the impact of the company's oil and gas hedging
program which began in 2002.
 
 - 42 -
 ***Crude
Oil Sales Revenues and Production*** - Oil
sales revenues increased $218 million or 15% in 2004 compared with 2003 due to a
combination of higher production and higher realized commodity prices. Oil
production of 159 thousand barrels per day (Mbbls/d) in 2004 represented an
increase of almost 6% over 2003 levels, primarily due to the contribution of
Westport assets acquired in late June 2004 (14 Mbbls/d). In addition, China's
CFD 11-1/11-2 fields started producing in July 2004 and the Gulf of Mexico's
Gunnison field, which began production in the fourth quarter of 2003,
contributed to the increase. Production volume increases in the U.S. and China
were partially offset by a 13% decline in North Sea production. The North Sea
production decrease was primarily due to declines at Tullich, Harding and
Leadon, partially offset by strong 2004 development drilling results at the
Gryphon field. Average oil prices, including the effect of hedging activity,
increased $2.19 per barrel in 2004, resulting in a $128 million increase in
sales revenues.
 
 Oil
production in 2003 was 150 Mbbls/d, down 21% compared to 2002, 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 area,
Gulf of Mexico shelf and the 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 decreased $105 million in 2003 compared with 2002, primarily as a
result of lower production due to the property divestitures in 2002 and 2003.
The effect of the 41 Mbbl/d decrease in oil production on sales revenues was
partially offset by the effect of higher realized prices. The average realized
price, including the effect of hedging activity increased $4 per barrel, adding
$220 million to oil sales revenues, while lower oil production reduced revenues
by $325 million.
 
 ***Natural
Gas Sales Revenues and Production*** **-** Natural
gas sales revenues increased $572 million in 2004 compared to 2003 as a result
of a 27% increase in gas production, combined with a $.76 per Mcf increase in
the average realized price. Gas production in 2004 was 921 MMcf per day, 195
MMcf per day above 2003 annual production, contributing an additional $315
million in gas sales revenues. Gas production increased as a result of
additional production from Westport assets, which contributed approximately 197
MMcf per day in 2004. In addition, new production from deepwater Gulf of Mexico
fields, primarily Red Hawk and Gunnison, offset declines that occurred in the
U.S. onshore area, as well as the North Sea Tullich field. The Red Hawk field
began production in July 2004. Higher realized gas prices provided an additional
$257 million in gas sales revenues, averaging $5.13 per Mcf, including the
impact of hedging activity.
 
 Natural
gas sales revenues in 2003 were $337 million higher than in 2002, 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. Higher realized prices in
2003 increased revenue by $374 million, while lower gas production reduced
revenues by $37 million. Production declines resulted primarily from property
divestitures concentrated 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.
 
 ***Other
Revenues*** **-** Other
revenues include gas processing plant and gathering system revenues in the U.S.
onshore area, along with oil tariffs and non-equity oil and gas sales in the
U.K. Gas marketing activities in the Rocky Mountain area are discussed
below.
 
 Other
revenues totaled $87 million in 2004, an increase of $44 million over 2003. The
increase is primarily the result of higher U.S. commodity prices impacting sales
generated from the company's ownership interest in gas plants and gathering
systems located in Louisiana and Colorado ($21 million). In addition, the North
Sea generated higher revenues from resale of nonequity gas, an increase of $10
million in 2004 compared with 2003.
 
 Other
revenues increased by $13 million in 2003 from $30 million reported in 2002. The
increase is primarily due to higher U.S. natural gas prices favorably impacting
gas processing plant and gas gathering revenues in the U.S. onshore
area.
 
 - 43 -
 ***Nonhedge
Derivative Losses*** -
Nonhedge derivative losses represent net realized and unrealized gains and
losses related to crude oil and natural gas derivative instruments that have not
been designated as hedges or that do not qualify for hedge accounting treatment.
In the second quarter of 2004, we entered into financial derivative instruments
in the form of fixed-price swaps and costless collars relating to specified
quantities of projected 2004-2006 production that was not already hedged,
including unhedged production from the Westport properties. Certain crude oil
and natural gas swaps covering the period from August to December 2004 were
characterized initially as nonhedge derivatives since either our U.S. production
(excluding Westport volumes) was already hedged or, in the case of Rocky
Mountain production, we did not have sufficient basis swaps in place to ensure
that the hedges would be highly effective. Consequently, we recognized
mark-to-market losses of $10 million in earnings during the second quarter
associated with these derivatives. After the Westport merger closed and with
sufficient oil and gas production available, these swaps were designated as
hedges and, as such, realized gains and losses thereafter were recognized in
earnings when the hedged production was sold.
 
 In
connection with the Westport merger, we recognized a $196 million net liability
associated with Westport’s existing commodity derivatives at the merger date
(June 25, 2004). Some of these derivative instruments were designated as hedges
in July 2004 in connection with the redesignation of acquisition-related
derivatives described above, while others do not qualify for hedge accounting
treatment. In the second quarter of 2004, we recognized a mark-to-market gain of
$15 million in earnings since the value of the net derivative liability had
decreased to $181 million by June 30, 2004.
 
 Westport’s
derivatives in place at the merger date consisted of fixed-price oil and gas
swaps, natural gas basis swaps, and costless and three-way collars. The swaps
qualify for hedge accounting and were designated as hedges after the merger
date. Accordingly, future realized gains and losses on those derivative
instruments are reflected in earnings when the hedged production is sold.
However, the costless and three-way collars - each of which was in a liability
position - do not qualify for hedge accounting treatment under existing
accounting standards because they represent “net written options” at the merger
date. As a result, even though these collars effectively reduce commodity price
risk, we will continue to recognize mark-to-market gains and losses in earnings
until the collars mature, rather than defer such amounts in accumulated other
comprehensive income (loss). In the second half of 2004, we recognized losses of
$28 million associated with Westport’s collars. The net derivative liability
associated with these derivatives at year-end 2004 was $69 million.
 
 For
further discussion of the company's derivative activities, see Note 11 to the
Consolidated Financial Statements included in Item 8 of this annual report on
Form 10-K. A full description of open derivative positions, both for hedge and
nonhedge derivatives, is included in the Market Risks section
below.
 
 **Lease
Operating Expense** ****
 
 During
2004, lease operating expense increased 35% or $118 million compared with 2003.
On a per-unit basis, 2004 lease operating expense increased $.58 per barrel of
oil equivalent (boe) to $3.95 per boe compared to $3.37 per boe for 2003. The
increase was primarily due to additional operating expenses associated with
Westport assets ($66 million), start-up production costs at China's CFD
11-1/11-2 fields, and higher expense in the Gulf of Mexico deepwater related to
an operating lease for platform infrastructure at the Gunnison field. Also
contributing to the increase were higher pension and contract labor costs for
nonoperated properties in the North Sea. A charge of $12 million in 2004, or
$.11 per boe, for a property insurance premium adjustment primarily associated
with higher industry losses due to Hurricane Ivan, also contributed to the
year-over-year increase.
 
 Lease
operating expense in 2003 was $114 million lower than 2002, a decrease of 25%.
On a per-unit basis, lease operating expense decreased by about 13% to $3.37 per
boe in 2003 from $3.87 per boe in 2002. Lower operating expenses were primarily
related to the divestment of noncore, high-operating-cost properties in 2002 and
early 2003.
 
 **Production
and Ad Valorem Taxes**
 
 Production
and ad valorem taxes are comprised primarily of severance taxes associated with
properties located onshore and in state waters in the U.S. These taxes, which
usually are based on a percentage of oil and gas sales revenues, increased $52
million in 2004 as a result of higher commodity prices and higher sales volumes.
The addition of Westport's properties resulted in higher production taxes as a
percentage of sales revenues by increasing the proportion of U.S. onshore
properties subject to production taxes in our portfolio.
 
 - 44 -
 Production
taxes of $52 million in 2003 were $15 million lower than 2002 primarily due to
the elimination of royalty payments in the U.K. North Sea and lower production
volumes. These factors were partially offset by the impact of higher commodity
prices on production taxes.
 
 **Depreciation,
Depletion and Amortization (DD&A)**
 
 DD&A
expense of $854 million for 2004 increased $245 million over the prior year,
primarily caused by additional DD&A expense for the recently acquired
Westport properties ($206 million). On a per-unit basis, DD&A increased from
$6.16 per boe in 2003 to $7.47 per boe in 2004, reflecting the impact of the
Westport merger which had a higher acquisition cost per boe than our historical
asset base. In addition, DD&A unit costs increased in the North Sea area due
to a reduction in the expected life and field facility salvage values on certain
fields, combined with the impact of changes in reserve estimates.  We
expect 2005 per-unit DD&A costs to average between $8.60 per boe and $8.75
per boe.
 
 DD&A
expense in 2003 was $609 million, representing a 12% decline compared with 2002.
The decrease was primarily the result of reduced production due to 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
expense increased 3% to $6.16 per boe in 2003 from $5.97 per boe in 2002.
Although total DD&A expense was lower, per unit costs increased, reflecting
the company's divestiture activity and a change in the overall mix of producing
properties between 2003 and 2002. In accordance with accounting standards,
depletion expense was not recorded for various assets that were designated as
held-for-sale in 2002, although production quantities for these properties
continued to be included in the calculation of overall per-unit
DD&A.
 
 **Accretion
Expense**
 
 Accretion
expense increased by $5 million in 2004 compared to 2003, reflecting an increase
in our asset retirement obligations associated with the Westport properties.
Accretion expense of $25 million in 2003 resulted from the initial
implementation of FAS No. 143. Prior to 2003, abandonment costs were recorded as
DD&A expense on a per-unit basis (undiscounted) as oil and gas was
produced.
 
 **Asset
Impairments and Gain (Loss) associated with Assets Held for
Sale**
 
 Kerr-McGee
records impairment losses when performance analysis and other factors indicate
that future net cash flows from production will not be sufficient to recover the
carrying amounts of the related assets. In general, such write-downs often occur
on mature properties that are nearing the end of their productive lives or cease
production sooner than anticipated. Asset impairment losses recorded in 2004 and
2003 totaled $28 million and $14 million, respectively. Asset impairment losses
in 2004 related in large part ($17 million) to two U.S. Gulf of Mexico fields
that experienced premature water breakthrough and ceased production sooner than
expected. In addition, an $8 million impairment loss was recognized for a North
Sea field that is no longer certain to be developed and a $3 million impairment
loss was recognized for other minor U.S. onshore properties.
 
 The
2003 impairments of $14 million related to mature oil and gas producing assets
in the U.S. onshore and Gulf of Mexico shelf areas. The impairment charges of
$646 million in 2002 included $541 million for the Leadon field in the U.K.
North Sea, $82 million for certain nonoperated North Sea fields and $23 million
for several older Gulf of Mexico shelf properties. Negative reserve revisions
stemming from additional performance analysis of 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 additional information
regarding the Leadon field, see Note 25 to the Consolidated Financial Statements
included in Item 8 of this annual report on Form 10-K.
 
 The
company recognized a net loss on sale of assets of $29 million in 2004. The loss
was associated primarily with the conveyance of the company’s interest in a
nonproducing Gulf of Mexico field to another participating partner ($25
million), as well as losses of $6 million and gains of $2 million on sales of
noncore properties in the Gulf of Mexico shelf and U.S. onshore areas. At
December 31, 2004, the company had oil and gas properties with a carrying amount
of $5 million classified as held-for-sale and, from time to time, may identify
other oil and gas properties to be disposed of that are considered noncore or
nearing the end of their productive lives.
 
 - 45 -
 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
interests 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 were
used to reduce long-term debt.
 
 **Transportation
Expense** ****
 
 Transportation
expense, representing the costs paid to third-party providers to transport oil
and gas  production,
increased by $17 million during 2004, to $111 million. The increase was due to
additional transportation costs associated with the Westport assets ($11
million) and the new deepwater Gulf of Mexico Red Hawk and Gunnison fields. The
increase was partially offset by lower costs in the North Sea due to lower sales
volumes in 2004. On a per-unit basis, 2004 transportation expense was $.97 per
boe compared to $.95 per boe in 2003.
 
 Transportation
costs in 2003 of $94 million were $10 million, or 12%, higher than 2002 as a
result of higher costs associated with new deepwater Gulf of Mexico producing
fields, partially offset by lower expense in the North Sea
area.
 
 **General
and Administrative Expense**
 
 General
and administrative expense was $1.18 per boe for 2004, a decrease of $.11 per
boe compared to 2003.  Total 2004 general and administrative expense of
$135 million was $8 million higher than 2003.  Contributing to the increase
was higher incentive compensation and pension costs, as well as additional
administrative and personnel costs associated with the Westport merger ($8
million).  The increase in 2004 was offset partially by lower costs as
compared to 2003 associated with the workforce reduction program and the
employee stock ownership plan.
 
 General
and administrative expense in 2003 was $40 million higher than in 2002.  Of
this increase, $23 million was due to employee severance and related costs
attributed to the company's 2003 workforce reduction program and additional
compensation expense associated with the employee stock purchase plan. 
Additionally, the company incurred higher costs in 2003 associated with pension
and other employee benefits. These cost increases were offset partially by lower
costs for direct labor and contract services
 **Exploration
Expense**
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Exploration
      costs (1)
    
    **$**
    **54**
    
    $
    45
    
    $
    36Geological
      and geophysical costs
    
    
    **86**
    
    
    59
    
    
    57Dry
      hole expense
    
    
    **161**
    
    
    181
    
    
    113Amortization
      of undeveloped leases
    
    
    **63**
    
    
    69
    
    
    67Sales
      of unproved properties
    
    
    **(8******
    ******)**
    
    -
    
    
    -Total
      exploration expense
    
    **$**
    **356**
    
    $
    354
    
    $
    273
 
 (1)
    Exploration
      costs include delay rentals, cost of retaining and carrying unproved
      properties and exploration department
overhead.
 
 In
2004, total exploration expense was $356 million, an increase of $2 million.
Exploration activity associated with Westport assets contributed $36 million to
exploration expense in 2004. Additionally, geological and geophysical data
acquisition and processing costs increased in 2004 due to activity in the
company’s international areas, such as Brazil, Morocco and the Bahamas, as well
as other new venture areas. Partially offsetting these increases were lower dry
hole costs, lower amortization of undeveloped leases and a gain on sale of
unproved properties. The gain on sale of unproved properties related primarily
to reimbursement of past exploration costs by new partners purchasing an
interest in our Morocco activities.
 
 - 46 -
 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.
 
 Capitalized
costs in our Consolidated Balance Sheet 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, 2004, the
company had capitalized costs of approximately $136 million associated with such
ongoing exploration activities, primarily in the deepwater Gulf of Mexico,
Brazil, Alaska and China. Additional information regarding deferred exploratory
drilling costs is included in Note 31 to the Consolidated Financial Statements
included in Item 8 of this annual report on Form 10-K.
 
 **Gas
Marketing Activities**
 
 Kerr-McGee
purchases third-party natural gas for aggregation and sale with the company's
own production in the Rocky Mountain area. In addition, we have transportation
capacity to markets in the Midwest to facilitate sale of natural gas outside the
immediate vicinity of our production. This activity began with the company's
acquisition of HS Resources in August 2001 and has increased since that time.
 
 Marketing
revenue was $419 million in 2004 and $298 million in 2003, an increase of $121
million and $228 million, respectively, as compared to the prior years. The
increase in both 2004 and 2003 was the result of higher purchase and resale of
third-party natural gas in the Rocky Mountain area and higher natural gas
prices. Increased gas purchase costs of $127 million and $233 million in 2004
and 2003, respectively, more than offset the increase in revenues. Marketing
volumes (thousand MMBtu/day) were 210 in 2004, 178 in 2003 and 77 in
2002.
 
 **CHEMICAL**
 
 Chemical
segment revenues, operating profit (loss) and pigment production volumes are
shown in the following table:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Revenues
      -Pigment
    
    **$**
    **1,209**
    
    $
    1,079
    
    $
    995Other
    
    
    **93**
    
    
    78
    
    
    70Total
    
    **$**
    **1,302**
    
    $
    1,157
    
    $
    1,065Operating
      profit (loss)(1)
      -Pigment
    
    **$**
    **(80**
    **)**
    $
    (13
    )
    $
    24Other
    
    
    **(1******
    ******)**
    
    (23
    )
    
    (13
    )Total
    
    **$******
    **(81******
    ******)**
    $
    (36
    )
    $
    11Titanium
      dioxide pigment production(thousands
      of tonnes)
    
    
    **549**
    
    
    532
    
    
    508
 
 (1)
    Operating
      profit (loss) does not include litigation provisions and environmental
      provisions, net of reimbursements, related to various businesses in which
      the company’s affiliates are no longer engaged, such as the mining and
      processing of uranium and thorium and other
businesses.
  - 47 -
  Operating
profit (loss) for all periods presented included certain items affecting
comparability between periods. Because of their nature and amount, these items
are identified separately to help explain the changes in operating profit (loss)
between periods, as well as to help distinguish the underlying trends for the
segment’s core businesses. These items are listed in the following table and, to
the extent material, are discussed in the analysis of operating profit that
follows:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002*Included
      in Chemical - Pigment Operating Profit (Loss):*Plant
      shutdown costs and accelerated depreciation
    
    **$**
    **(122**
    **)**
    $
    (44
    )
    $
    (12
    )Asset
      impairments
    
    
    **(8**
    **)**
    
    -
    
    
    -Insurance
      premium adjustment
    
    
    **(4**
    **)**
    
    -
    
    
    -Environmental
      provisions
    
    
    **(1**
    **)**
    
    (1
    )
    
    5Cost
      associated with the 2003 work force reduction program
    
    
    **(1**
    **)**
    
    (18
    )
    
    -Compensation
      expense for allocated ESOP shares
    
    
    **-**
    
    
    (5
    )
    
    -Other
    
    
    **4**
    
    
    1
    
    
    (2
    )*Included
      in Chemical - Other Operating Loss:*Plant
      shutdown costs and accelerated depreciation
    
    
    **-**
    
    
    (1
    )
    
    -Environmental
      provisions
    
    
    **(3**
    **)**
    
    (12
    )
    
    (15
    )Cost
      associated with the 2003 work force reduction program
    
    
    **-**
    
    
    (3
    )
    
    -Compensation
      expense for allocated ESOP shares
    
    
    **-**
    
    
    (1
    )
    
    -Total
      items affecting comparability
    
    **$******
    **(135******
    ******)**
    $
    (84
    )
    $
    (24
    )
 
 **Chemical
- Pigment** -
Revenues increased $130 million, or 12%, in 2004 to $1.209 billion from $1.079
billion in 2003. Of the total increase, $114 million was due to increased sales
volumes and $16 million resulted from an increase in average sales prices. Sales
volumes for 2004 were approximately 9% higher than in the prior year due
primarily to strong market conditions. Approximately half of the increase in
average sales prices in 2004 was due to the effect of foreign currency exchange
rates and the remainder due to price increases resulting from improved market
conditions.
 
 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.
 
 The
chemical - pigment operating unit recorded an operating loss of $80 million in
2004, compared with an operating loss of $13 million in 2003. The 2004 operating
loss was primarily the result of shutdown provisions totaling $105 million
(including an $8 million charge for asset impairment) for the sulfate-process
titanium dioxide pigment production at the Savannah, Georgia, facility and
additional charges at that facility of $18 million for accelerated depreciation
of other plant assets that are no longer in service. In addition, operating
results for 2004 were negatively impacted by $7 million of costs incurred in
connection with the continued efforts to close the synthetic rutile plant in
Mobile, Alabama, compared to a $47 million plant closure provision recognized in
2003 for this facility. Additionally, operating results in 2003 were negatively
impacted by a $23 million charge for work force reduction and other compensation
costs. These charges had the effect of reducing operating profit by $130 million
in 2004 and $70 million in 2003. The $130 million increase in revenues in 2004
resulting from higher volume and sales prices was offset by an increase of $125
million in production costs due to higher volume ($73 million) and costs ($52
million including the effects of foreign currency exchange rate changes) and an
increase in shipping and handling costs and selling, general and administrative
expenses of $13 million over 2003. Additional information related to the
shutdowns of the Savannah and Mobile facilities is included in Note 13 to the
Consolidated Financial Statements included in item 8 of this annual report on
Form 10-K.
 
 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.
 
 - 48 -
 During
2004, the company continued to operate its new high-productivity oxidation line
for chloride-process titanium dioxide pigment production at the Savannah
facility. This project, if successful, will substantially increase chloride
production capability at a reduced asset intensity level. The company continues
to evaluate the performance of this new oxidation line and expects to have a
better understanding of how the Savannah site might be reconfigured to exploit
its capabilities in 2005. The possible reconfiguration of the Savannah site, if
any, could include redeployment of certain assets, idling of certain assets and
reduction of the future useful life of certain assets, resulting in the
acceleration of depreciation expense and the recognition of other charges.
 
 **Chemical
- Other** -
Operating loss for 2004 was $1 million on revenues of $93 million, compared with
operating loss of $23 million on revenues of $78 million in 2003. The increase
in revenues of $15 million was primarily due to an increase in electrolytic
sales due primarily to the full year of operations at the company's electrolytic
manganese dioxide (EMD) manufacturing operation in Henderson, Nevada (see
further discussion below). Improved operating performance was primarily due to
the full year of operations at the EMD facility, lower environmental costs in
2004 of $9 million compared to 2003 and the work force reduction and other
compensation charges recognized in 2003 that did not reoccur in
2004.
 
 Operating
loss for 2003 was $23 million on revenues of $78 million, compared with
operating loss of $13 million on revenues of $70 million in 2002. The increase
in sales was due to higher electrolytic operations sales volumes. The increased
volumes were predominantly achieved in sodium chlorate and boron products, 17%
and 37%, respectively. The $10 million increase in operating loss for 2003 was
primarily due to 2003 work force reduction costs and other compensation charges
of $4 million and higher electrolytic product costs of $8 million, partially
offset by lower environmental costs of $3 million. Environmental provisions in
both 2003 and 2002 related primarily to ammonium perchlorate remediation
associated with the company’s Henderson, Nevada, operations (see Note 19 to the
Consolidated Financial Statements included in Item 8 of this annual report on
form 10-K).
 
 In
2002, the company announced plans to exit the forest products business and four
of the company’s five wood-treatment facilities were closed during 2003. The
fifth plant, which was a leased facility, ceased all significant operations by
the end of 2004 and the assets were sold in January 2005.
 
 During
the third quarter of 2003, Kerr-McGee Chemical LLC placed its EMD manufacturing
operation in Henderson, Nevada, on standby to reduce inventory levels because of
the harmful effect of low-priced imports on the company's EMD business. In
response to the pricing activities of importing companies, 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 continues to monitor market
conditions.
 
  - 49 -
   
 **Financial
Condition**
 
 The
following table provides certain information useful in analysis of the company's
financial condition at December 31, 2004, 2003 and 2002.
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Current
      ratio(1)
    
    
    **0.8
      to 1**
    
    
    0.8
      to 1
    
    
    0.8
      to 1Total
      debt
    
    **$**
    **3,699**
    
    $
    3,655
    
    $
    3,904Total
      debt less DECS(2)
    
    
    **3,699**
    
    
    3,329
    
    
    3,586Stockholders’
      equity
    
    **$**
    **5,318**
    
    $
    2,636
    
    $
    2,536Debt
      to total capitalization(3)
    
    
    **41**
    **%**
    
    58
    %
    
    61
    %Total
      debt less DECS to total capitalization(2)
      (3)
    
    
    **41**
    **%**
    
    56
    %
    
    59
    %Floating-rate
      debt to total debt (fixed-rate debt with interest rateswaps
      to variable rate is treated as floating rate debt)
    
    
    **25**
    **%**
    
    14
    %
    
    16
    %
 
 (1)
    Represents a
      ratio of current assets to current liabilities.
  (2)
    Under
      the terms of the company’s debt exchangeable for stock (DECS) which
      matured on August 2, 2004, we had an option to redeem our debt obligation
      by distributing shares of Devon Energy Corporation (Devon) common
      stock to the debt holders. The DECS were redeemed at maturity through
      the distribution of Devon stock. Certain ratios and measures are provided
      excluding the effect of DECS balances at December 31, 2003 and 2002
      to demonstrate the effect on our financial condition of debt
      obligations that require the use of cash. Additional information regarding
      the DECS and their redemption is included in Note 7 to the Consolidated
      Financial Statements included in item 8 of this annual report on Form
      10-K.
  (3)
    Capitalization
      is determined as total debt or total debt less DECS, as applicable, plus
      total stockholders' equity.
  
 
 During
2004, we reduced the percentage of total debt to total capitalization from 58%
to 41%, despite the assumption of approximately $1.0 billion of debt in the
Westport merger. Activities contributing to this change in the leverage ratio
are outlined below.
 
 ·
    Westport
      debt assumed in the merger was repaid shortly after completing the merger
      with net proceeds from the issuance of $650 million principal amount of
      6.95% notes due 2024 and borrowings under our revolving credit
      facility.
  ·
    In
      connection with the merger, we issued 48.9 million shares of common stock
      to former Westport shareholders, increasing stockholders’ equity by $2.4
      billion.
  ·
    Net
      income exceeded dividends declared, increasing equity by $176
      million.
  ·
    In
      addition to repaying Westport debt, we reduced total debt by $577 million,
      including the redemption of $330 million principal amount of DECS through
      distribution of Devon shares.
 
 Kerr-McGee
operates with the philosophy that over a five-year plan period the company's
capital expenditures and dividends should be funded by cash generated from
operations. On a cumulative basis, the cash generated from operations for the
past five years has exceeded the company’s capital expenditures (excluding cash
spent for acquisitions) and dividend payments. Debt and equity transactions are
utilized for acquisition opportunities and short-term needs due to timing of
cash flow.
 
 The
company’s future debt level depends on our future results of operations, our
capital expenditure program, and requirements for and sources of cash associated
with asset acquisitions and dispositions. Discussion on the company’s borrowing
capacity available to meet unanticipated cash requirements is included in
the *Liquidity* section below.
  - 50 -
  In
February 2005, we called for redemption all of the $600 million aggregate
principal amount of our 5.25% convertible subordinated debentures due 2010 at a
price of 102.625%. Prior to March 4, 2005, the redemption date, all of the
debentures were converted by the holders into approximately 9.8 million shares
of common stock. As a result of this conversion, the number of total common
shares outstanding increased to approximately 162 million. Pro forma for the
conversion, our year-end 2004 total debt to total capitalization ratio would
have been 34%.
 
 On
March 8, 2005, the company's Board of Directors (the Board) authorized the
company to proceed with a share repurchase program initially set at $1 billion.
The Board expects to expand the share repurchase program as the chemical
business separation proceeds. The initial $1 billion share repurchase program
primarily will be financed through the use of free cash flow generated from
operations after planned capital expenditures, which is projected to be
approximately $850 million in 2005. The company also expects to utilize a
portion of its existing bank credit facility and may issue new securities, which
may be in the form of debt or perpetual preferred stock, to fund the remaining
repurchase program. The company still intends to retire $450 million of debt
maturities due in 2005 in addition to the conversion of subordinated debentures
discussed above. The Board and management reiterated their commitment to
maintain an investment-grade credit rating.
 
 The
timing and final number of shares to be repurchased under an expanded repurchase
program will depend on the outcome of the chemical business separation, as well
as business and market conditions, applicable securities law limitations and
other factors. Shares may be purchased from time to time in the open market or
through privately negotiated transactions at prevailing prices, and the program
may be suspended or discontinued at any time without prior notice.
 
 **Cash
Flows**
 
 We rely
on cash flows from operating activities as a primary source of liquidity. As
necessary, this source has been supplemented by accessing credit lines and
commercial paper markets and issuing equity and debt securities.
 
 
  ***Cash
Flow*** ***s
from Operating Activities*** - Cash
flows from operating activities increased by $532 million, from $1.5 billion in
2003 to $2.1 billion in 2004. Our merger with Westport in June 2004 contributed
to an increase in oil and gas production on a barrel of oil equivalent basis of
15% over 2003. Average prices realized upon the sale of oil and gas, including
hedging activities, increased by 13%. The combined effect of these factors
contributed significantly to the 2004 increase in cash flows from operating
activities. Additionally, in 2004, our environmental cash expenditures, net of
reimbursements received, were lower compared to the prior year. These positive
effects on cash flows from operating activities were partially offset by higher
contributions made to postretirement and pension plans and higher expenditures
for operating costs primarily due to the Westport merger.
 
 ***Cash
Used in Investing Activities*** -
Including dry hole costs, we invested $1.3 billion, $1.2 billion and $1.3
billion in our capital program in 2004, 2003 and 2002, respectively. The $178
million increase in capital expenditures and dry hole costs in 2004 was
primarily related to higher spending onshore in the U.S., where our drilling
program was expanded following the Westport merger. The capital program for 2003
was $110 million lower than in the prior year, resulting primarily from lower
capital expenditures in the North Sea and U.S. onshore regions, partially offset
by higher capital expenditures in the Gulf of Mexico and China and higher dry
hole costs.
 
 - 51 -
 Our
merger with Westport was financed by issuing common stock and assuming
Westport’s debt obligations and, therefore, did not affect investing cash flows,
except for Westport cash balances of $43 million acquired in the merger. During
2003, we invested $110 million in selected oil and gas property acquisitions for
an additional interest in the U.K. Gryphon and South Gryphon fields and an
onshore property acquisition in South Texas. Additionally, in 2003, we 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.
Cash outlays for investing activities during 2004, 2003 and 2002 include
investment by the chemical unit in Avestor, its lithium-metal-polymer battery
joint venture in Canada, of $25 million, $34 million and $47 million,
respectively. Other investing cash inflows included $39 million in 2004 and $47
million in 2003 in proceeds related to the sale of Devon stock. By the end of
2004, all of the shares of Devon common stock were disposed of either through
sale or in settlement of our DECS obligation discussed in the *Financial
Condition* section above.
 
 ***Cash
Used in Financing Activities*** - In
2004, we repaid $1.3 billion of debt, including debt assumed in the Westport
merger. The $245 million balance outstanding under the Westport revolving credit
facility at the date of the merger was repaid upon completion of the merger and
the facility was terminated on July 13, 2004. We also redeemed the 8.25%
Westport notes assumed in the merger for $786 million (including a make-whole
premium of $100 million) and repaid $247 million in 2004 for scheduled
repayments and maturities of our debt. On July 1, 2004, we issued 6.95% notes
due 2024 for net proceeds of $636 million. Proceeds from the notes issuance were
used to redeem the 8.25% Westport notes discussed above. In 2004, we also paid
$101 million to settle derivative liabilities assumed from Westport. Dividends
paid in 2004 were $205 million, an increase of $24 million compared to 2003.
This increase primarily resulted from the issuance of 48.9 million shares of our
common stock in the Westport merger. We received proceeds from employee stock
option exercises of $55 million in 2004 with more stock option exercises
compared to prior years as a result of the Westport merger and the increasing
price of our common stock.
 
 **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 cash flows from
operating activities, borrowing capacity and ability to raise capital. The
company’s primary source of funds has been from operating cash flows, which
could be adversely affected by declines in oil, natural gas and pigment prices,
all of which can be volatile, as discussed under *Operating
Environment and Outlook* . Our
hedging program is intended to partially mitigate variability in operating cash
flows caused by fluctuations in oil and natural gas prices. At December 31,
2004, commodity derivatives covered approximately 50% of our projected 2005 oil
and gas production. The portion of our projected production subject to
commodity derivative instruments is determined by management and may change in
future periods in response to market conditions and our operational needs. If
operating cash flows decline, the company may reduce its capital expenditures
program, borrow under its commercial paper program, draw upon its revolving
credit facility and/or consider selective long-term borrowings or equity
issuances. Our commercial paper programs are backed by the revolving credit
facility currently in place.
 
 In
November 2004, the company entered into a $1.5 billion unsecured revolving
credit agreement with a term of five years. Concurrent with this transaction, we
terminated two revolving credit facilities with an aggregate maximum
availability of $1.35 billion. A portion of the $1.5 billion revolving credit
facility can be used to support commercial paper borrowings in the U.S. and
Europe by certain wholly-owned subsidiaries and are guaranteed by the parent
company. Borrowings under the credit agreement can be made in U.S. dollars,
British pound sterling and euros. Interest on borrowings under the new revolving
credit facility may be based, at the company’s option, on LIBOR, EURIBOR or on
the JPMorgan prime rate. The interest rate margin varies based on facility
utilization and the company’s debt rating, utilizing the two highest of the
company’s senior unsecured debt ratings by Moody’s, Standard and Poors
(S&P), and Fitch in determining the spread above the applicable interest
rate index. At year-end 2004, the company had a maximum available capacity under
the revolving credit facility and bank lines of credit of $1.55 billion and $41
million outstanding in commercial paper borrowings.
 
 At
December 31, 2004, the company classified its $41 million of short-term
commercial paper borrowings as long-term debt based on its ability and intent,
as evidenced by committed credit agreements, to refinance this 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. Additional information on the company’s debt
is included in Note 14 to the Consolidated Financial Statements included in Item
8 of this annual report on Form 10-K.
 
 - 52 -
 The
company has available, to issue and sell, a total of $1 billion of debt
securities, common or preferred stock, or warrants under its shelf registration
with the Securities and Exchange Commission, which was last updated in February
2002.
 
 Additionally,
the company maintains an accounts receivable monetization program, which
provides an additional source of liquidity up to a maximum of $165 million. This
program is discussed in detail in the *Off-Balance
Sheet Arrangements* section that follows.
 
 The
company had negative working capital at the end of 2004; however, that is not
indicative of a lack of liquidity as the company maintains sufficient current
assets to settle current liabilities when due. Cash balances are minimized as
one way to finance capital expenditures and lower borrowing costs. Additionally,
our working capital position is affected by current assets and liabilities
associated with our financial derivatives. At December 31, 2004, the
company had recorded approximately $300 million of net current derivative
liabilities for contracts that will effectively adjust the cash flows to be
realized upon the sale of our future oil and gas production and chemical
products. Because those sales have not yet occurred, the associated accounts
receivable are not yet reflected in our Consolidated Balance Sheet, while
derivative assets and liabilities are carried on the Consolidated Balance Sheet
at their estimated fair value. Because of the high degree of volatility in oil
and natural gas commodity markets, our working capital position will be
continually affected by changes in the fair value of derivative instruments.
 
 Certain
of our derivative financial instruments require margin deposits if unrealized
losses exceed limits established with individual counterparty institutions. From
time to time, we may be required to advance cash to our counterparties to
satisfy margin deposit requirements. No margin deposits were outstanding at
December 31, 2004.
 
 Our
long-term debt agreements do not contain subjective acceleration clauses
(commonly referred to as material adverse change clauses); however, certain of
our long-term debt agreements contain restrictive covenants, including a maximum
total debt to total capitalization ratio, as defined in the agreements, of 65%.
At December 31, 2004, the company had a total debt to capitalization ratio of
41% and was in compliance with its other debt covenants. As discussed under *Financial
Condition* above,
$600 million of our 5.25% convertible subordinated debentures were converted to
common stock in March 2005. Pro forma for the conversion, our year-end 2004
total debt to total capitalization ratio would have been 34%.
 
 As of
December 31, 2004, the company’s senior unsecured debt was rated BBB by S&P
and Fitch and Baa3 by Moody’s. In March 2005, Moody's, S&P and Fitch each
issued a press release indicating the company was under review for a possible
downgrade.  The rating agency announcements were primarily in response to a
recent shareholder proposal to execute a large share repurchase program using
proceeds from a volumetric production payment (VPP).  The Board rejected
the VPP proposal as irresponsible and not in the best interests of stockholders,
creditors and the company.  The Board of Directors did, however, approve a
$1 billion share repurchase program on March 8, 2005, as discussed in Financial
Condition above.  Following the company's announcement of the share
repurchase program,  S&P lowered the company's credit rating from BBB
to BBB-.  The downgrade by S&P will result in a 15 basis-point increase
in borrowing costs under our revolving credit facility.  In rating the
company’s debt, the agencies consider our financial and operating risk profile
by analyzing our debt levels, growth profile, cost structure, oil and gas
reserve replacement ratios, capital expenditure requirements, contingencies,
dividend policy and any other factors they deem relevant that could potentially
impact our ability to service our debt. Should
the company’s commercial paper or debt ratings be further downgraded, borrowing
costs will increase, and the company may experience a 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.  If two of the three rating
agencies lowered the company’s debt rating to BB+ or Ba1, the company’s
borrowing costs would increase 55 basis points from year-end levels.  As
discussed in the Off-Balance
Sheet Arrangements section that follows, ratings downgrade
below specified levels would result in modifications to or termination of
our accounts receivable monetization program.  In connection with the March
8, 2005 share repurchase program announcement, the company's Board and
management reiterated their commitment to maintain an investment-grade credit
rating.
 
  - 53 -
  **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.
 
 ***Spar
Platform Leases*** -
During 2001, the company entered into a leasing arrangement for its interest in
the production platform and related equipment for the Gunnison field in the
Garden Banks area of the Gulf of Mexico. This leasing arrangement is similar to
two arrangements entered into in 2000 for the Nansen and Boomvang fields in the
East Breaks area of the Gulf of Mexico. In each of these three arrangements, 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 platforms 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 December 31, 2003, the remaining assets
and liabilities of the synthetic lessor trust were included in the company’s
Consolidated Balance Sheet at December 31, 2003. Since the remaining portion of
the Gunnison synthetic lease was converted to an operating lease structure in
January 2004, the platform assets and related debt are not included in our
Consolidated Balance Sheet at December 31, 2004. For additional information
regarding Gunnison trust consolidation see Note 14 to the Consolidated Financial
Statements included in Item 8 of this annual report on Form 10-K.
 
 In
conjunction with the operating lease agreements, the company has guaranteed that
the residual values of the Nansen, Boomvang and Gunnison platforms at the end of
the operating leases shall be equal to at least 10% of their fair market value
at the inception of the lease. For Nansen and Boomvang, the guaranteed values
are $14 million and $8 million, respectively, in 2022, and for Gunnison the
guaranteed value is $15 million in 2024. Estimated future minimum annual rentals
under these leases and the residual value guarantees are shown in the table of
contractual obligations below.
 
 ***Accounts
Receivable Monetization Program*** - 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. During the third quarter of 2004, the company completed its
renewal of the program, extending the term through July 27, 2005. The maximum
availability under the program is $165 million. Under the terms of the program,
selected qualifying customer accounts receivable are 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. 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 SPE, which
essentially represents a retained deposit to provide further credit
enhancements, if needed, but otherwise is recoverable by the company at the end
of the program. The carrying value of our investment in the preference stock was
$4 million at December 31, 2004 and 2003.
 
 - 54 -
 The
program includes a ratings downgrade trigger in the event Kerr-McGee's corporate
senior unsecured debt rating falls below BBB- by S&P or Baa3 by Moody's, or
in the event such rating has been suspended or withdrawn by S&P or Moody's.
The result of the downgrade trigger is an increase in the cost of the program,
along with other program modifications. In addition, the program includes a
ratings downgrade termination event, upon which the program effectively
liquidates over time and the third-party multi-seller commercial paper conduit
is repaid by the collections on accounts receivable sold by the SPE. The ratings
downgrade termination event is triggered if Kerr-McGee's corporate senior
unsecured debt (i) is rated less than BBB- by S&P and Baa3 by Moody's, (ii)
is rated less than BB+ by S&P or Ba1 by Moody's or (iii) is withdrawn or
suspended by S&P or Moody's. At year-end 2004 and 2003, the outstanding
balance on receivables sold under the program totaled $165 million.
 
 ***Sale-Leaseback
Transactions*** -
During 2003 and 2002, the company entered into sale-leaseback arrangements with
General Electric Capital Corporation (GECC) covering assets associated with a
gas-gathering system in the Wattenberg field. The lease agreements were entered
into for the purpose of monetizing certain of the gathering system 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.
 
 ***Other
Arrangements*** - 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 entered into a performance guarantee agreement
with the buyer for the benefit of OCP. Execution of the guarantee by Kerr-McGee
was required to obtain the necessary cooperation and consents from OCP to close
the company’s sale of its Ecuadorean assets. 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 has entered into certain indemnification agreements related to
title claims, environmental matters, litigation and other claims. The company
has recorded no material obligations in connection with its indemnification
agreements. At December 31, 2004, the company had outstanding letters of credit
in the amount of approximately $106 million. Most of these letters of credit
have been granted by financial institutions to support our international
drilling commitments.
 
  - 55 -
  **Obligations
and Commitments**
 
 In the
normal course of business, the company enters into purchase obligations,
contracts, leases and borrowing arrangements. The company has no debt guarantees
for third parties. As part of the company’s project-oriented exploration and
production business, we routinely enter into contracts for certain aspects of a
project, such as engineering, drilling, subsea work, etc. These contracts 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, 2004, are summarized in the
following table:
 
 (Millions
      of dollars)
    
    Payments
      due by period2006
    
    2008
    
    AfterType
      of Obligation
    
    Total
    
    2005
    
    -2007
    
    -2009
    
    2009Long-term
      debt, including current portion (1)
    
    $
    3,783
    
    $
    460
    
    $
    457
    
    $
    41
    
    $
    2,825Operating
      leases for Nansen,Boomvang
      and Gunnison
    
    
    582
    
    
    23
    
    
    54
    
    
    55
    
    
    450All
      other operating leases
    
    
    241
    
    
    46
    
    
    72
    
    
    54
    
    
    69Drilling
      rig commitments
    
    
    117
    
    
    117
    
    
    -
    
    
    -
    
    
    -Purchase
      obligations -Ore
      contracts
    
    
    387
    
    
    156
    
    
    191
    
    
    40
    
    
    -Gas
      purchase and transportation contracts
    
    
    222
    
    
    32
    
    
    55
    
    
    46
    
    
    89Other
      purchase obligations
    
    
    511
    
    
    221
    
    
    219
    
    
    38
    
    
    33Leased
      equipment residual value guarantees
    
    
    72
    
    
    -
    
    
    -
    
    
    35
    
    
    37Total
    
    $
    5,915
    
    $
    1,055
    
    $
    1,048
    
    $
    309
    
    $
    3,503
 (1)
    Principal
      amounts represent future payments and exclude the unamortized discount on
      issuance of $85 million and the net fair value hedge adjustments of $(1)
      million.
 
  
 **Capital
Spending**
 
 Capital
expenditures are summarized as follows:
 
 (Millions
      of dollars)
    
    Est.
      2005
    
    2004
    
    2003
    
    2002Exploration
      and production, includingdry
      hole costs
    
    $
    1,919
    
    $
    1,230
    
    $
    1,050
    
    $
    1,101Chemical
    
    
    100
    
    
    92
    
    
    97
    
    
    85Other,
      including discontinued operations
    
    
    25
    
    
    18
    
    
    15
    
    
    86Total
    
    $
    2,044
    
    $
    1,340
    
    $
    1,162
    
    $
    1,272
 
 Capital
spending, excluding acquisitions, totaled $3.8 billion in the three-year period
ended December 31, 2004, and dividends paid totaled $567 million in the same
three-year period, which compares with $5 billion of net cash provided by
operating activities during the same period.
 
 Kerr-McGee
has budgeted approximately $2 billion for its capital program in 2005. Management anticipates that the 2005
capital program, dividends and debt reduction can be provided for through
internally generated funds. Available borrowing capacity 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 particular year.
 
 **Exploration
and Production**
 
 Our
merger with Westport during 2004 provided a substantial inventory of low-risk
onshore exploitation opportunities, particularly in the Rocky Mountain area. The
company plans to capitalize on these opportunities in 2005 with a $430 million
development drilling program in the Rocky Mountain area, focusing primarily
on the Greater Natural Buttes and Wattenberg fields. In the Southern area of the
U.S. onshore region, the Westport merger also resulted in a significant increase
in the company’s inventory of attractive investment opportunities. As a
result, we plan to invest about $230 million in the Southern area primarily
for development drilling in South Texas, the Mid-Continent/Permian Basin and
Gulf Coast regions. Capital expenditures onshore in the U.S. will total
about $660 million in 2005.
 
 - 56 -
 In the
Gulf of Mexico, the company plans to invest $645 million in 2005. About
one-third of our planned Gulf of Mexico capital expenditures will be investment
at the Constitution/Ticonderoga development on Green Canyon 680/768
where first production is expected in mid-2006. Other Gulf of Mexico
investments will focus on subsea development of our Atwater Valley discoveries
at Merganser, Vortex and San Jacinto, as well as other satellite exploitation,
infill drilling and recompletion investments around existing
infrastructure.
 
 In the
North Sea region, we plan capital expenditures of about $270 million for 2005.
The 2005 program for the North Sea will focus primarily on infill drilling at
the company-operated Gryphon and Janice fields, as well
as other non-operated fields. In the international and new ventures
areas, we plan to invest about $160 million in 2005. This investment will
be focused primarily on the completion of the initial development drilling
program at the CFD 11-1/2 fields in Bohai Bay, China, as well as expected
development costs at the CFD 11-3/5, CFD 11-6 and CFD 12-1/12-1S fields.
 
 Including
about $9 million for investment in information systems technology, the company’s
2005 capital budget for its exploration and production business totals about
$1.7 billion. In addition, the company has budgeted expenditures of
approximately $305 million (excluding noncash amortization of nonproducing
leasehold costs) for exploration expense in 2005, including $175 million
for dry hole costs. The company’s exploration program is expected to fund
approximately 100 exploratory and appraisal wells, with emphasis on balancing
risks and potential rewards in both shallow and deep waters and onshore in the
U.S.
 
 **Chemical**
 
 Capital
expenditures for chemical operations are budgeted at $100 million for 2005.
Process and technology improvements that increase productivity and enhance
product quality will account for approximately 43% of the 2005 capital
budget. This includes changes to the front-end process at the Uergingen,
Germany pigment facility to convert waste to a saleable product and reduce raw
material costs and upgrading the oxidation line at the Botlek, Netherlands,
pigment facility to improve throughput. Chemical has also budgeted $45 million
of additional investment in Avestor for 2005.
 
  - 57 -
   
 **Market
Risks**
 
 The
company is exposed to a variety of market risks, including credit risk, changes
in oil and gas commodity prices, foreign currency exchange rates and interest
rates. We address these risks through a controlled program of risk management
that includes the use of insurance and derivative financial instruments. In
addition to information included in this section, see Notes 1 and 11 to the
Consolidated Financial Statements included in Item 8 of this annual report on
Form 10-K for discussions of the company’s derivatives and hedging
activities.
 
 **Commodity
Price Risk**
  Our oil
and natural gas production is generally sold at prevailing market prices, thus
exposing us to the risk of variability of our revenues and operating cash flows.
To reduce the impact of these risks on earnings and to increase the
predictability of its cash flows, the company enters into certain derivative
instruments that generally fix the commodity prices to be received for a portion
of its future oil and gas production. The
company utilizes derivative instruments as a means of balancing cash flow
requirements for debt repayment and its capital programs. At
December 31, 2004, commodity derivatives covered approximately 50% of our
projected 2005 oil and gas production, a decline from approximately 75% for
2004. A lower hedge ratio allows us to benefit from increases in market prices
for oil and natural gas, if they occur, but also exposes us to a greater
possibility of lower realized prices, should commodity prices decline.
A risk
management committee consisting of senior executives, including the CEO,
develops the company’s hedging strategy. In setting hedge targets, the committee
evaluates various factors, including debt management targets, liquidity,
exploration and development opportunities, cash flow modeling under various
price scenarios and the overall growth strategy for the company. These and other
factors are used to formulate specific hedge targets on an ongoing basis.
 At
December 31, 2004, outstanding commodity-related derivatives had a net liability
fair value of $494 million. The fair value of these derivative instruments was
determined based on prices actively quoted, generally NYMEX and Dated Brent
prices. For derivative instruments designated as cash flow hedges, gains and
losses are deferred in accumulated other comprehensive income (loss) and
reclassified into earnings when the associated hedged production is sold, except
for gains or losses resulting from hedge ineffectiveness, which are recognized
as incurred. Realized and unrealized gains and losses arising from derivative
instruments not designated as hedges or that do not qualify for hedge accounting
(nonhedge derivatives) are recognized in earnings currently. At December 31,
2004, the company had after-tax deferred losses of $174 million in accumulated
other comprehensive income (loss) associated with oil and gas cash flow hedges.
We expect to reclassify $52 million of these losses into earnings during the
next 12 months, assuming no further changes in fair value of the contracts. Net
realized oil and gas hedging losses totaled $748 million, $279 million and $81
million in 2004, 2003 and 2002, respectively. The losses offset the higher oil
and natural gas prices realized on the physical sale of crude oil and natural
gas. Average realized oil and gas sales prices excluding and including the
effect of our hedging program are presented above under *Results
of Operations by Segment - Exploration and Production* . Gains
and losses for hedge ineffectiveness for all periods presented were not
material.
 
  - 58 -
  The
following summary provides information about outstanding commodity-related
derivative contracts that have been designated as hedges at December 31,
2004:
 
 Average
    
    AverageContract
      Type(1)
    
    Period
    
    Daily
      Volume
    
    Contract
      Price**Natural
      Gas Hedges******
    
    
    
    **MMBtu**
    
    **$/MMBtu**Fixed-price
      swaps (NYMEX)
    
    
    2005
    
    
    55,000
    
    $
    4.42Q2,
      Q3 - 2005
    
    
    75,000
    
    $
    6.48Q4
      - 2005
    
    
    25,272
    
    $
    6.48Costless
      collars (NYMEX)
    
    
    Q1
      - 2005
    
    
    225,000
    
    $
    6.50
      - $10.31Q2,
      Q3 - 2005
    
    
    75,000
    
    $
    6.00
      - $ 7.86Q4
      - 2005
    
    
    25,272
    
    $
    6.00
      - $ 7.862005
    
    
    280,000
    
    $
    5.00
      - $ 6.252006
    
    
    340,000
    
    $
    4.75
      - $ 5.50Basis
      swaps (CIG)(2)
    
    
    2005
    
    
    20,000
    
    $
    0.39Basis
      swaps (NWPRM)(3)
    
    
    2005
    
    
    25,000
    
    $
    0.43**Crude
      Oil Hedges**
    
    
    
    
    
    **Barrel**
    
    ****
    **$/Barrel**Fixed-price
      swaps (WTI)
    
    
    2005
    
    
    3,000
    
    $
    29.23Fixed-price
      swaps (Brent)
    
    
    2005
    
    
    16,000
    
    $
    41.03Costless
      collars (WTI)
    
    
    2005
    
    
    5,500
    
    $
    40.00
      - $49.802005
    
    
    14,000
    
    $
    28.50
      - $31.892006
    
    
    19,000
    
    $
    27.00
      - $30.58Costless
      collars (Brent)
    
    
    2005
    
    
    10,500
    
    $
    38.00
      - $48.12
 
 (1)  These
contracts may be subject to margin calls above certain limits established with
individual counterparty institutions.
 
 (2)  Colorado
Interstate Gas pipeline.
 
 (3)  Northwest
Pipeline Rocky Mountain index.
 
 The
company holds certain gas basis swaps settling between 2005 and 2008 that were
acquired in the 2001 merger with HS Resources. The company initially treated
these gas basis swaps as nonhedge derivatives, with changes in fair value
recognized in earnings. In 2004, the company designated those swaps settling in
2005 as hedges, since the basis swaps have been coupled with natural gas
fixed-price swaps, while the remainder settling between 2006 and 2008 will
continue to be treated as nonhedge derivatives. From time to time, the company
also enters into basis swaps to help mitigate its exposure to localized natural
gas indices by, in effect, converting that exposure to NYMEX-based pricing. To
the extent such basis swaps are coupled with NYMEX natural gas fixed-price
swaps, they are accounted for as hedges; otherwise, any mark-to-market gains or
losses are recognized currently in earnings.
 
  - 59 -
  At
December 31, 2004, the following commodity-related derivatives were outstanding
and represent those contracts that have not been designated as hedges or that do
not qualify for hedge accounting treatment in the case of the costless and
three-way collars acquired in the Westport merger.
 
 
 Average
    
    AverageContract
      Type(1)
    
    Period
    
    Daily
      Volume
    
    Contract
      Price**Natural
      Gas (Nonhedge)**
    
    
    
    **MMBtu**
    
    **$/MMBtu**Costless
      collars (NYMEX)
    
    
    2005
    
    
    60,000
    
    $
    4.09
      - $5.57Three-way
      collars (NYMEX)(5)
    
    
    2006
    
    
    20,000
    
    $
    4.00
      - $6.00Three-way average floor
    
    
    
    
    
    
    
    $
    3.04Basis
      swaps (CIG)(2)
    
    
    Q1
      - 2005
    
    
    175,000
    
    $
    0.712006
    
    
    20,000
    
    $
    0.392007
    
    
    20,000
    
    $
    0.392008
    
    
    4,973
    
    $
    0.39Basis
      swaps (NWPRM)(3)
    
    
    Q1
      - 2005
    
    
    70,000
    
    $
    0.712006
    
    
    15,000
    
    $
    0.202007
    
    
    15,000
    
    $
    0.202008
    
    
    15,000
    
    $
    0.20Basis
      swaps (HSC)(4)
    
    
    Q1
      - 2005
    
    
    6,556
    
    $
    0.36**Crude
      Oil (Nonhedge)**
    
    
    
    
    
    **Barrel**
    
    ****
    **$/Barrel**Three-way
      collars (WTI)
    
    
    2005
    
    
    5,000
    
    $
    25.00
      - $28.23Three-way average floor
    
    
    
    
    
    
    
    $
    20.932006
    
    
    2,000
    
    $
    25.00
      - $28.65$
    20.88
 
 (1)
    These
      contracts may be subject to margin calls above certain limits established
      with individual counterparty institutions.
 
 (2)
    ColoradoInterstateGas pipeline.
 
 (3)
    Northwest
      Pipeline Rocky Mountain index.
 
 (4)
    Houston
      Ship Channel.
 
 (5)
    These
      derivatives function similar to a costless collar with the exception that
      if the NYMEX or WTI price, as applicable, falls below the three-way floor,
      the company loses price protection. For example, the company only has
      $.96/MMBtu of price protection if the NYMEX price falls below $3.04/MMBtu
      in the case of its 2006 natural gas three-way collars ($4.00 -
      $3.04).
 
  - 60 -
  The
following hedge and nonhedge derivative contracts were entered into from January
1, 2005 through February 28, 2005.
 
 Average
    
    AverageContract
      Type(1)
    
    Period
    
    Daily
      Volume
    
    Contract
      Price**Natural
      Gas Hedges******
    
    
    
    **MMBtu**
    
    **$/MMBtu**Fixed-priced
      swaps (NYMEX)
    
    
    Q2,
      Q3 - 2005
    
    
    75,000
    
    $
    6.09Q4
      - 2005
    
    
    25,272
    
    $
    6.09Costless
      collars (NYMEX)
    
    
    Q2,
      Q3 - 2005
    
    
    120,000
    
    $
    6.00
      - $7.00Q4
      - 2005
    
    
    40,435
    
    $
    6.00
      - $7.00Basis swaps
      (CIG)(2)
    
    
    Q2,
      Q3 - 2005
    
    
    35,000
    
    $
    0.75Q4
      - 2005
    
    
    11,793
    
    $
    0.75Basis swaps
      (NWPRM)(3)
    
    
    Q2,
      Q3 - 2005
    
    
    52,500
    
    $
    0.73Q4
      - 2005
    
    
    17,690
    
    $
    0.73Basis swaps
      (HSC)(4)
    
    
    Q2,
      Q3 - 2005
    
    
    70,000
    
    $
    0.13Q4
      - 2005
    
    
    23,587
    
    $
    0.13**Crude
      Oil Hedges**
    
    
    
    
    
    **Barrel**
    
    ****
    **$/Barrel**Fixed-price
      swaps (WTI)
    
    
    Q1
      - 2005
    
    
    4,589
    
    $
    43.78Q2,
      Q3, Q4 - 2005
    
    
    7,000
    
    $
    43.78Costless
      collars (WTI)
    
    
    Q1
      - 2005
    
    
    4,589
    
    $
    40.00
      - $48.46Q2,
      Q3, Q4 - 2005
    
    
    7,000
    
    $
    40.00
      - $48.46Costless
      collars (Brent)
    
    
    Q1
      - 2005
    
    
    3,278
    
    $
    38.00
      - $49.24Q2,
      Q3, Q4 - 2005
    
    
    5,000
    
    $
    38.00
      - $49.24**Natural
      Gas (Nonhedge)******Basis swaps
      (CIG)(2)
    
    
    Q2,
      Q3 - 2005
    
    
    35,000
    
    $
    0.75Q4
      - 2005
    
    
    11,793
    
    $
    0.75Basis swaps
      (HSC)(4)
    
    
    Q1
      - 2005
    
    
    49,667
    
    $
    0.36Q2,
      Q3 - 2005
    
    
    30,000
    
    $
    0.13Q4
      - 2005
    
    
    23,370
    
    $
    0.24
 
 (1)  These
contracts may be subject to margin calls above certain limits established with
individual counterparty institutions.
 
 (2)  Colorado
Interstate Gas pipeline index.
 
 (3)  Northwest
pipeline Rocky Mountain index.
 
 (4)  Houston
Ship Channel.
 
 The
company’s marketing subsidiary, Kerr-McGee Energy Services (KMES) purchases
third-party natural gas for aggregation and sale with the company’s own
production in the Rocky Mountain area. Under some of its marketing arrangements,
KMES receives fixed prices for the sale of natural gas. Existing contracts for
the physical delivery of gas at fixed prices have not been designated as hedges
and are marked-to-market through earnings in accordance with FAS No. 133. KMES
has entered into natural gas swaps and basis swaps that largely offset its
fixed-price risk on physical contracts and lock in margins associated with
the physical sales. The gains and losses on the swaps, which also are
marked-to-market through earnings, substantially offset the gains and losses
from the fixed-price physical delivery contracts.
  - 61 -
  **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 flows related to pigment sales, capital expenditures, raw material
purchases and operating costs. These contracts generally have durations of less
than three years. Changes in the fair value of these contracts are recorded in
accumulated other comprehensive income (loss) and are recognized in earnings in
the periods during which the hedged forecasted transactions affect
earnings.
 
 As
discussed above, under Off-Balance Sheet Arrangements, the company sells
selected receivables in an accounts receivable monetization program for its
pigment business. Receivables, including those denominated in foreign currency,
are sold at their equivalent U.S. dollar value at the date of monetization. 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 accounts receivable monetization 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. These
contracts to sell foreign currency are considered nonhedge derivatives.
Therefore, gains or losses on such contracts are recognized as a component of
other income (expense) as incurred.
 
 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. Accordingly, gains or losses on such contracts are
recognized in earnings as incurred.
 
 The
following table presents the notional amounts at the contract exchange rates and
the weighted-average contractual exchange rates for contracts to purchase (sell)
foreign currencies outstanding at year-end 2004 and 2003. All amounts are U.S.
dollar equivalents. The estimated fair value of our foreign currency forward
contracts is based on the year-end forward exchange rates quoted by financial
institutions. At December 31, 2004 and 2003, the fair value of our foreign
currency forward contracts was a net asset of $14 million and $17 million,
respectively.
 
 (Millions
      of dollars,
    
    Notional
    
    Weighted-Averageexcept
      average contract rates)
    
    Amount
    
    Contract
      RateOpen
      contracts at December 31, 2004 -Maturing
      in 2005 -British
      pound sterling
    
    $
    186
    
    $
    1.7104Euro
    
    
    151
    
    
    1.3170Euro
    
    
    (292
    )
    
    1.2977British
      pound sterling
    
    
    (1
    )
    
    1.8043Japanese
      yen
    
    
    (1
    )
    
    .0095New
      Zealand dollar
    
    
    (1
    )
    
    .6873Open
      contracts at December 31, 2003 -Maturing
      in 2004 -British
      pound sterling
    
    $
    139
    
    $
    1.6372Australian
      dollar
    
    
    38
    
    
    .5366Euro
    
    
    (113
    )
    
    1.1358British
      pound sterling
    
    
    (1
    )
    
    1.6876Japanese
      yen
    
    
    (2
    )
    
    .0092New
      Zealand dollar
    
    
    (1
    )
    
    .6121Maturing
      in 2005 -British
      pound sterling
    
    $
    77
    
    $
    1.5995
 
 
 - 62 -
 
 **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 2004. All borrowings are in U.S.
dollars.
 
 FairThere-
    
    
    
    Value(Millions
      of dollars)
    
    2005
    
    2006
    
    2007
    
    2008
    
    2009
    
    after
    
    Total(2)
    
    12/31/04Fixed-rate
      debt -Principal
      amount
    
    $
    1
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    2,825
    
    $
    2,826
    
    $
    3,082Weighted-averageinterest
      rate
    
    
    9.61
    %
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    6.75
    %
    
    6.75
    %Variable-rate
      debt(1)
      -Principal
      amount
    
    $
    459
    
    $
    307
    
    $
    150
    
    $
    -
    
    $
    41
    
    $
    -
    
    $
    957
    
    $
    957Weighted-averageinterest
      rate
    
    
    4.16
    %
    
    5.30
    %
    
    5.55
    %
    
    -
    
    
    2.70
    %
    
    -
    
    
    4.68
    %
 
 (1)
    Includes
      fixed-rate debt with interest rate swaps to variable
  rate.
 (2)
    Principal
      amounts represent future payments and exclude the unamortized discount on
      issuance of $85 million and the net fair value hedge adjustments of $(1)
      million.
 
 **Interest
Rate Derivatives** - In
connection with the issuance of $350 million of 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%. 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, were
converted to pay a variable rate of LIBOR plus 3.35%; $109 million of
8.125% notes due October 15, 2005, were converted to pay a variable rate of
LIBOR plus 5.86%; and $307 million of 5.875% notes due September 15, 2006, were
converted to pay a variable rate of LIBOR plus 3.1%. The company considers
these swaps to be hedges against the change in fair value of the related debt as
a result of interest rate changes. The swaps are carried in the Consolidated
Balance Sheet at their estimated fair value. Any unrealized gain or loss on
the swaps is offset by a comparable gain or loss resulting from recording
changes in the fair value of the related debt.  Gains and losses on
interest rate swaps, along with the changes in the fair value of the related
debt, are reflected in interest and debt expense in the Consolidated Statement
of Operations.  The critical terms of the swaps match the terms of the
debt; therefore, the swaps are considered highly effective and no hedge
ineffectiveness has been recognized. At December 31, 2004 and 2003, the fair
value of our interest rate swaps was a net asset of $1 million and $15 million,
respectively.
 
  
 **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. Even so, 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 exploratory drilling costs, crude oil and natural gas proved
reserve estimation, recoverability of long-lived assets, accounting for business
combinations, accounting for derivative instruments, environmental remediation,
tax accruals and benefit plans. Management's judgments and estimates in these
areas are based on information available from both internal and external
sources, including engineers, legal counsel, actuaries, environmental studies
and historical experience in similar matters. Actual results could differ
materially from those estimates as additional information becomes
known.
 
 - 63 -
 **Exploratory
Drilling Costs**
 
 The
company follows the successful efforts method of accounting for its oil and gas
exploration and development activities. Exploration expenses, including
geological and geophysical costs and exploratory dry holes, are charged against
earnings. Costs of successful exploratory wells and related production equipment
are capitalized and amortized using the unit-of-production method on a
field-by-field basis as oil and gas is produced. The successful efforts method
reflects the inherent unpredictability of exploring for oil and gas. This
accounting method may yield significantly different operating results than the
full-cost method.
 
 Under
the successful efforts method, the cost of drilling an exploratory well is
capitalized pending determination of whether proved reserves can be attributed
to the discovery. In the case of onshore wells and offshore wells in relatively
shallow water, that determination usually can be made upon or shortly after
cessation of exploratory drilling operations. However, such determination may
take longer in other areas (particularly deepwater exploration and international
locations) depending upon, among other things, the amount of hydrocarbons
discovered, the outcome of planned geological and engineering studies, the need
for additional future appraisal drilling to determine whether the discovery is
sufficient to support an economic development plan, and the requirement for
government sanctioning in certain international locations. As a consequence, the
company has capitalized costs associated with exploratory wells on its
Consolidated Balance Sheet at any point in time that may be charged to earnings
in a future period if management determines that commercial quantities of
hydrocarbons have not been discovered. At December 31, 2004, the company had
capitalized exploratory drilling costs of approximately $136 million associated
with ongoing exploration and/or appraisal activities, primarily in the deepwater
Gulf of Mexico, Brazil, Alaska and China. Additional information regarding the
amount of capitalized exploratory drilling costs and changes during the
last three yeas is presented in Note 31 to the Consolidated Financial Statements
included in Item 8 of this annual report on Form 10-K.
 
 **Proved
Oil and Gas Reserves**
 
 The
company’s estimates of proved of oil and gas reserves are prepared by the
company’s engineers using available geological and reservoir data, as well as
production performance data. The U.S. Securities and Exchange Commission has
defined proved reserves as the estimated quantities of crude oil and natural
gas  which
geological and engineering data demonstrate with “reasonable certainty” to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Even though the company’s engineers are knowledgeable and
follow authoritative guidelines for estimating proved reserves, they must make a
number of subjective determinations based on professional judgments in
developing the company’s reserve estimates. Such estimates are reviewed annually
and revised, either upward or downward, as warranted by additional data.
Revisions of previous estimates can occur due to, among other things, changes in
reservoir performance, commodity prices, economic conditions and governmental
regulations. The company mitigates the inherent risks associated with reserve
estimation through a comprehensive reserves administration process. See Note 32,
"Crude Oil, Condensate, Natural Gas Liquids and Natural Gas Net Reserves
(Unaudited)" to the Consolidated Financial Statements included
in Item 8 of this annual report on Form 10-K for
additional information concerning the reserve administration process and
revisions to reserve estimates in each of the last three years, including the
use of independent third-party engineers.
 
 Oil and gas reserve
estimates impact our financial statements in two important ways. First, proved
reserves are used to calculate depreciation and depletion rates for capitalized
costs associated with our proved oil and gas properties (i.e., depreciation and
depletion expense is based on the percentage of proved reserves depleted in
the current year). If previously estimated reserves for a particular oil and gas
field are revised downward, depreciation and depletion expense will increase in
the future. Conversely, increased reserve estimates will cause depreciation and
depletion rates to decline. Second, proved reserves are used as a component of
the basis for calculating expected future cash flows for impairment test
purposes under FAS No. 144 whenever events or changes in circumstances indicate
that an impairment loss may have occurred. We monitor our oil and gas properties
for impairment based on current period operating results and reserve
revisions which may indicate that the carrying amount of a particular oil and
gas field is not recoverable. All else being equal, downward revisions of
previous reserve estimates increase the likelihood that an impairment loss may
be recognized. The periodic impairment losses shown in the company’s
Consolidated Financial Statements, in general terms, result from either downward
reserve revisions due to changes in reservoir performance or fields that ceased
production sooner than anticipated.  Factors contributing to impairment
losses on oil and gas properties recognized during each of the last three
years are discussed above under Results
of Operation by Segment - Exploration and Production.
  - 64 -
  **Impairment
of Assets**
 
 A
long-lived asset is evaluated for potential impairment whenever events or
changes in circumstances indicate that its carrying amount may be greater
than its future net cash flows. Such evaluations involve a significant amount of
judgment since the results are based on estimated future events, such
as sales prices for oil, gas or chemicals; costs to produce these
products; estimates of future oil and gas production; development costs and the
timing thereof; the economic and regulatory climates; and other factors. The
need to test an asset for impairment may result from significant declines in
sales prices, downward revisions to previous oil and gas reserve estimates,
increases in operating costs, and changes in environmental or abandonment
regulations. Assets held for sale are reviewed for potential loss on sale when
the company commits to a plan to sell and thereafter while the asset is held for
sale. Losses are measured as the difference between fair value less costs to
sell and the asset's carrying value. Estimates of anticipated sales prices are
judgmental and subject to revision in future periods, although initial estimates
usually are based on sales prices for similar assets and other valuation data.
The company cannot predict when or if future impairment charges will be required
for held-for-use assets or intangibles, or whether losses associated with
held-for-sale properties will be recognized.
 
 **Business
Combinations**
 
 *Purchase
Price Allocation* - In
connection with a business combination, the company is required to assign
the cost of the acquisition to assets acquired and liabilities assumed and
record deferred taxes for any differences between the assigned values and tax
bases of assets and liabilities. Any excess of purchase price over the
amounts assigned to assets and liabilities is recorded as goodwill.  Most
assets and liabilities are recorded in the opening balance sheet at their
estimated fair values. The company uses all available information to make these
fair value determinations, including information commonly considered by the
company’s engineers in valuing individual oil and gas properties and sales
prices for similar assets. Estimated deferred taxes are based on available
information concerning the tax basis of the acquired company’s assets and
liabilities and loss carryforwards at the merger date, although such estimates
may change in the future as additional information becomes known. Any change in
deferred tax assets and liabilities as of the merger date based on information
that becomes available later is recorded as an increase or decrease in
goodwill.  The amount of goodwill recorded in any particular business
combination can vary significantly depending upon the value attributed to assets
acquired and liabilities assumed.
 
 *Goodwill* - In
connection with our acquisition of HS Resources in 2001 and our merger with
Westport in 2004, we recorded a total of $1.2 billion of goodwill for the excess
of the purchase price over the value assigned to individual assets acquired and
liabilities assumed. The company is required to assess goodwill for impairment
annually, or more often as circumstances warrant. The first step of that process
is to compare the fair value of the reporting unit to which goodwill has been
assigned to the carrying amount of the associated net assets and goodwill. If
the estimated fair value is greater than the carrying amount of the reporting
unit, then no impairment loss is required. The company completed its annual
impairment test associated with the goodwill recognized in the HS Resources
merger as of June 30, 2004 and no impairment was indicated. The goodwill
associated with the Westport merger will not be tested for impairment until
2005. Although the company cannot predict when or if goodwill will be impaired
in the future, impairment charges may occur if the company is unable to
replace the value of its depleting asset base or if other adverse events (for
example, lower sustained oil and gas prices) reduce the fair value of the
associated reporting unit.
 
 **Derivative
Instruments**
 
 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 increase the predictability of its cash flows, 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, in accordance with FAS No. 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. We have elected, under the
provisions of FAS No. 133, to apply hedge accounting to the vast majority of our
oil and gas commodity derivatives which has the effect of deferring unrealized
gains and losses on these instruments in equity, as a component of accumulated
other comprehensive income (loss), until such time as the hedged production is
sold. Alternatively, we could have elected to recognize the unrealized gains and
losses in current-period earnings, which would have resulted in significant
earnings volatility in periods preceding the actual physical sale of oil and
gas. If we had elected to apply this alternative treatment, an additional
after-tax unrealized loss of $174 million would have been recognized in earnings
prior to December 31, 2004. Our chosen accounting method has no bearing on the
company’s liquidity or our total debt to total capitalization ratio because, in
either case, stockholder’s equity is reduced by the unrealized
loss.
 
 - 65 -
 **Environmental
Remediation 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. Estimates
of environmental liabilities, which include the cost of investigation and
remediation, are based on a variety of matters, including, but not limited to,
the stage of investigation, the stage of the remedial design, evaluation of
existing remediation technologies, and presently enacted laws and regulations.
In future periods, a number of factors could significantly change the company’s
estimate of environmental remediation costs, such as changes in laws and
regulations, revisions to the remedial design, unanticipated construction
problems, identification of additional areas or volumes of contamination, and
changes in costs of labor, equipment and technology. Consequently, it is not possible for management to reliably estimate the amount
and timing of all future expenditures related to environmental or other
contingent matters and actual costs may vary significantly from the company's
estimates. Before considering reimbursements of the company’s environmental
costs discussed below, the company provided $106 million, $94 million and $202
million for environmental remediation and restoration costs in 2004, 2003 and
2002, respectively, including provisions related to the company’s forest
products business reflected as a component of income (loss) from discontinued
operations.
  To the
extent costs of investigation and remediation are recoverable from the U.S.
government under Title X and under certain insurance policies and such
recoveries are deemed probable, the company records a receivable. In considering
the probability of receipt, the company evaluates its historical experience with
receipts, as well as its claim submission experience. At December 31, 2004,
estimated recoveries of environmental costs recorded in the Consolidated Balance
Sheet totaled $94 million, of which $49 million was received in early 2005.
Provisions for environmental remediation and restoration in the
Consolidated Statement of Operations were reduced by $14 million, $32 million
and nil in 2004, 2003 and 2002, respectively, for estimated
recoveries.
 For
additional information about contingencies, refer to the *Environmental
Matters* section
that follows and Note 19 to the Consolidated Financial Statements in Item 8 of
this annual report on Form 10-K.
 
 **Tax
Accruals**
 
 The
company has operations in several countries around the world and is subject to
income and 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 No. 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. The company
also provides certain postretirement health care and life insurance benefits and
accounts for the related plans in accordance with FAS No. 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.
 
  - 66 -
  The
following are considered significant assumptions related to the company’s U.S.
and foreign retirement plans and the U.S. postretirement plan:
 
 ·
    Long-term
      rate of return (applies to funded plans
only)
 ·
    Discount
      rate
 ·
    Rate
      of compensation increases
 ·
    Health
      care cost trend rate (applies to postretirement plan
  only)
 
 Other
factors considered in developing actuarial valuations include inflation rates,
retirement rates, mortality rates and other factors. Assumed inflation rates are
based on an evaluation of external market indicators. Retirement rates are based
primarily on actual plan experience. The discussion that follows provides
additional information about the assumptions made and their effect on the
financial statements. Advice of independent actuaries is taken into account when
forming assumptions.
 
 ***U.S.
Benefit Plans***
 
 *Long-term
rate of return -* In
forming the assumption of the U.S. long-term rate of return, the company takes
into account the expected earnings on funds already invested, earnings on
contributions expected to be received in the current year, and earnings on
reinvested returns. The long-term rate of return estimation methodology for U.S.
plans is based on a capital asset pricing model using historical data. The
modeling is performed and updated semi-annually by a third-party consultant and
incorporates current portfolio allocation, historical asset-class returns and an
assessment of expected future performance using asset-class risk factors. Based
on this information, the company selected a long-term rate of return assumption
of 8.5% as of year-end 2003 and 8.25% as of year-end 2004 for the U.S. pension
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, 2005, the amount of unrecognized losses on U.S. pension assets was
$90 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 $7 million in 2006 through 2009.
 
 A 25
basis point increase/decrease in the company’s expected long-term rate of return
assumption as of the beginning of 2005 would decrease/increase net periodic
pension cost for U.S. pension plans for 2005 by $3 million. The change would not
affect expected contributions to fund the company’s U.S. pension
plans.
 
 The net
effect of the U.S. pension plans on 2004 results of operations was expense of $1
million. This consisted of $14 million expense attributable to a curtailment
loss and special termination benefits and $13 million reduction of expense due
to the expected return on assets exceeding other components of 2004 net periodic
pension cost. The total expected return on assets of the U.S. pension plans for
2004 was $110 million, compared with an actual return of $100 million. During
2004, the company’s contributions to the retirement plans totaled $39 million
for certain U.S. nonqualified plans.
 
 *Discount
rate -* The
company selects a discount rate assumption as of December 31 each year based on
the average current yields on high quality long-term fixed income instruments.
For U.S. plans, the average Moody’s Long-Term AA Corporate Bond Yield and the
Citigroup Pension Liability Index are used as a guide in the selection of the
discount rate. The discount rates selected for year-end 2003 and 2004 were 6.25%
and 5.75%, respectively. The decrease in the discount rate effective December
31, 2004 is expected to increase 2005 net periodic pension cost by approximately
$2 million, but is not expected to affect future contributions made to the
plans.
 
 *Rate
of compensation increases -* The
company determines this assumption based on its long-term plans for compensation
increases specific to employee groups covered and expected economic conditions.
The assumed rate of salary increases includes the effects of merit increases,
promotions and general inflation. The rate of 4.5% was selected for both
year-end 2003 and 2004.
 
 -
67 -
 *Health
care cost trend rate -* The
health care cost trend assumptions are developed based on historical cost data,
the near-term outlook and an assessment of likely long-term trends. The company
chooses an initial medical trend rate and an ultimate medical trend rate, as
well as the number of years it will take to move between the two rates. The
initial and the ultimate medical trend rates chosen for both 2003 and 2004
year-ends were 10% and 5%. In both cases, the number of years that it will take
to move to the ultimate trend rate was six.  A 1% increase in the assumed
health care cost trend rate for each future year would increase the year-end
2004 postretirement benefit obligation by $14 million and increase the aggregate
of the service and interest cost components of the 2004 net periodic
postretirement expense by $1 million.
 
 ***Foreign
Benefit Plans***
 
 *Long-term
rate of return -* Our
assumption of the long-term rate of return for the U.K. and the Netherlands
plans is based on the advice of the third-party consultants, considering
portfolio mix and the rates of return on local government and corporate bonds.
The long-term rates of return chosen as of year-end 2003 and 2004 were 7.25% and
7.0%, respectively, for the U.K. plan. For the Netherlands plan, the long-term
rate of return assumption was 5.75% at year-end 2003 and 5.5% at year-end
2004.
 
 *Discount
rate -* For
foreign plans, the company bases the estimates on local corporate bond index
rates. The discount rates selected for the foreign plans at December 31, 2003
ranged from 5.25% to 5.5%. The respective rates for year-end 2004 ranged from
4.75% to 5.25%.
 
 *Rate
of compensation increases -* Consistent
with the U.S. plans, the company determines this assumption based on its
long-term plans for compensation increases specific to employee groups covered.
The assumed rate of salary increases includes the effects of merit increases,
promotions and general inflation. The rates of compensation increases for the
foreign retirement plans ranged from 2.75% - 5.0% at year-end 2003 and from 3.0%
- 4.75% at year-end 2004.
 
 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 the foreign countries in which they operate. Under
these laws, the company’s affiliates are or may be required to obtain or
maintain permits and/or licenses in connection with their operations. In
addition, under these laws, the company’s affiliates are or may be required to
remove or mitigate the effects on the environment of the disposal or release of
certain chemical, petroleum, low-level radioactive and other substances at
various sites. Environmental laws and regulations are becoming increasingly
stringent, and compliance costs are significant and will continue to be
significant in the foreseeable future. There can be no assurance that such laws
and regulations or any environmental law or regulation enacted in the future
will not have a material effect on the company'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, 2004, 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.
 
  - 68 -
  **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, the treatment of forest products and other activities.
Although the company’s affiliates are no longer engaged in certain businesses,
residual obligations may still exist, including obligations related to
compliance with environmental laws and regulations, including the Clean Water
Act, the Clean Air Act, CERCLA and RCRA. These laws and regulations require
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 and at sites where they were
involved in the production and sale of ammonium perchlorate. Additionally, the
company’s chemical affiliate is decommissioning and remediating its
wood-treatment facilities as part of its exit from 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, 2004, are as follows:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002
    
    TotalCharges
      to environmental reserves
    
    **$**
    **99**
    
    $
    104
    
    $
    128
    
    $
    331Recurring
      expenses
    
    
    **17**
    
    
    19
    
    
    37
    
    
    73Capital
      expenditures
    
    
    **15**
    
    
    18
    
    
    22
    
    
    55Total
    
    **$**
    **131**
    
    $
    141
    
    $
    187
    
    $
    459
 
 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.
 
  - 69 -
  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, 2004, the company's financial reserves for all active and inactive
sites totaled $255 million. This includes $106 million added in 2004 for active
and inactive sites. In the Consolidated Balance Sheet, $158 million of the total
reserve is classified as noncurrent liabilities-other, and the remaining $97
million is included in accrued liabilities. Management believes that currently
the company has reserved adequately for the reasonably estimable costs of known
environmental contingencies. However, additional reserves may be required in the
future due to the previously noted uncertainties. Additionally, there may be
other sites where the company has potential liability for environmental-related
matters but for which the company does not have sufficient information to
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
financial reserves recorded at year-end 2004. In the table, aggregated
information is presented for certain sites that are individually not significant
(each has a remaining reserve balance of less than $10 million). Amounts
reported in the table for the West Chicago sites are not reduced for actual or
expected reimbursement from the U.S. government under Title X of the Energy
Policy Act of 1992 (Title X), described in Note 19 to the Consolidated Financial
Statements included in Item 8 of this annual report on Form 10-K.
 
 
 - 70 -
   RemainingTotal
      Expenditures Through 2004
    Reserve
      Balance at December 31, 2004
    TotalLocation
      of Site
    Stage
      of Investigation/Remediation
    (Millions
      of dollars)**EPA
      Superfund sites on**
      **National
      Priority List (NPL)**West
      Chicago, Ill.
      Vicinity
      areas
    Remediation
      of thorium tailings at Residential Areas and Reed-Keppler Park is
      substantially complete. 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 2005.
    $
      118
    $
      86
    $
      204Milwaukee,
      Wis.
    Completed
      soil cleanup at former wood-treatment facility and began cleanup of
      offsite tributary creek. Groundwater remediation and cleanup of tributary
      creek is continuing.
    39
    6
    45Other
      sites
    Sites
      where the company has been named a PRP, including landfills, wood-treating
      sites, a mine site and an oil recycling refinery. These sites are in
      various stages of investigation/remediation.
    32
    16
    48189
    108
    297**Sites
      under consent order, license or agreement, not on EPA Superfund
      NPL**West
      Chicago, Ill.
      Former
      manufacturing
      facility
    Excavation,
      removal and disposal of contaminated soils at former thorium mill is
      substantially complete. The site will be used for moving material from the
      Kress Creek and Sewage Treatment Plan remediation sites. Surface
      restoration and groundwater monitoring and remediation will
      continue.
    444
    14
    458Los
      Angeles County, Cal.
    Excavation,
      removal and disposal of soils contaminated with wastes from oil and gas
      production is ongoing.
    14
    25
    39Cushing,
      Okla.
    Excavation,
      removal and disposal of thorium and uranium residuals was substantially
      completed in 2004. Investigation of and remediation addressing hydrocarbon
      contamination is continuing.
    141
    21
    162Henderson,
      Nev.
    Groundwater
      treatment to address perchlorate contamination is being conducted under
      consent decree with Nevada Department of Environmental
      Protection.
    119
    10
    129Other
      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.
    311
    77
    3881,029
    147
    1,176Total
    $1,218
    $255
    $1,473
 
 
  - 71 -
  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 19 to the
Consolidated Financial Statements which financial statements are included in
Item 8 of this annual report on Form 10-K. Discussion in Note 19 of the West
Chicago, Illinois; Henderson, Nevada; Los Angeles County, California; Milwaukee,
Wisconsin; and Cushing, Oklahoma sites is incorporated herein by reference and
made fully a part hereof.
 
  
 **New/Revised
Accounting Standards**
 
 The
Financial Accounting Standards Board (FASB) has proposed an amendment to
Statement No. 19, “Financial Accounting and Reporting by Oil and Gas Producing
Companies” (FAS No. 19) that may change the way oil and gas producers account
for deferred exploratory drilling costs. Under the current rules, there is a
presumption that all exploratory drilling costs will be expensed within one year
following completion of drilling if proved reserves have not been recorded,
except for costs related to areas where additional exploration wells are
necessary to justify development plans *and* such
additional wells are under way or firmly planned for the near future.
Application of FAS No. 19 to the facts and circumstances commonly faced by oil
and gas producers in today’s exploration and development environment
(particularly in deepwater and international areas) has become a concern for the
industry and there are diverse views in practice. For example, in the case of
deepwater discoveries, additional appraisal wells are almost never under way or
firmly planned when the drilling rig is released due to the time required to
assess the initial discovery well, update geologic models, and plan appraisal
well locations in an extremely high-cost drilling environment.
 
 The new
standard would relax the one-year limitation, so long as oil and gas reserves
have been discovered and an enterprise “is making sufficient progress assessing
the reserves and the economic and operating viability of the project.” The FASB
staff has developed indicators to help determine whether sufficient progress is
being made. The company believes the adoption of the proposed amendment (once
finalized) will have no impact on its consolidated financial statements.
Additional information related to exploratory drilling costs is included in Note
31 to the Consolidated Financial Statements included in Item 8 of this annual
report on Form 10-K.
 
 In
December 2004, the FASB issued FASB Staff Position No. FAS 109-2 (FSP No.
109-2), “Accounting and Disclosure Guidance for the Foreign Earnings
Repatriation Provisions within the American Jobs Creation Act of 2004” (the Jobs
Act). FSP No. 109-2 provides guidance with respect to reporting the potential
impact of the repatriation provisions of the Jobs Act on an enterprise’s income
tax expense and deferred tax liability. The Jobs Act was enacted on October 22,
2004, and provides for a temporary 85% dividends received deduction on certain
foreign earnings repatriated during a one-year period. The deduction would
result in an approximate 5.25% federal tax rate on the repatriated earnings. To
qualify for the deduction, the earnings must be reinvested in the United States
pursuant to a domestic reinvestment plan established by a company’s chief
executive officer and approved by a company’s board of directors. Certain other
criteria in the Jobs Act must be satisfied as well. FSP No. 109-2 states that an
enterprise is allowed time beyond the financial reporting period to evaluate the
effect of the Jobs Act on its plan for reinvestment or repatriation of foreign
earnings. The company has not yet completed its evaluation of the impact of the
repatriation provisions of the Jobs Act. Accordingly, as provided for in FSP No.
109-2, the company has not adjusted its tax expense or deferred tax liability to
reflect the repatriation provisions of the Jobs Act. Additional disclosures
related to the status of our evaluation of the Jobs Act repatriation provisions
are included in Note 15 to the Consolidated Financial Statements included in
Item 8 of this annual report on Form 10-K.
 
  - 72 -
  In
December 2004, the FASB issued FASB Staff Position No. FAS 109-1,
"Application of FASB Statement No. 109, Accounting for Income Taxes, to the
Tax Deduction on Qualified Production Activities Provided by the American Jobs
Creation Act of 2004," indicating that this deduction, which will be available
to the company in 2005, should be accounted for as a special deduction in
accordance with the provisions of FAS No. 109, as opposed to a tax-rate
reduction. Beginning in 2005, the company will recognize the allowable
deductions as qualifying activity occurs.
 
 In
December 2004, the FASB issued Statement No. 123 (revised 2004), “Share-Based
Payment” (FAS No. 123R), which replaces FAS No. 123 and supersedes APB Opinion
No. 25, “Accounting for Stock Issued to Employees. ”FAS No. 123R requires all
share-based payments to employees, including grants of employee stock options,
to be recognized in the financial statements based on their fair values
beginning with the first interim period after June 15, 2005, with early adoption
encouraged. The pro forma disclosures previously permitted under FAS No. 123 no
longer will be an alternative to financial statement recognition. The company is
required to adopt FAS No. 123R in the third quarter of 2005. Under FAS No. 123R,
the company must determine the appropriate fair value model to be used for
valuing share-based payments, the amortization method for compensation cost and
the transition method to be used at date of adoption. The permitted transition
methods include either retrospective or prospective adoption. Under the
retrospective method of adoption, prior periods may be restated either as of the
beginning of the year of adoption (modified retrospective method) or for all
periods presented. The prospective method requires that compensation expense be
recorded for all unvested share-based compensation awards at the beginning of
the first quarter of adoption of FAS No. 123R, while the retrospective methods
would record compensation expense for all unvested share-based compensation
awards beginning with the first period presented. The company is currently
evaluating the requirements of FAS No. 123R and expects to adopt this standard
no later than July 1, 2005 using either the prospective or the modified
retrospective method of adoption. The company expects that the effect of
adoption will not have a material effect on our financial condition and cash
flows, and that the effect on our results of operations will be comparable to
the current pro forma disclosures under FAS No. 123 included in Note 1 to the
Consolidated Financial Statements.
 
 **Item
7a.**  **Quantitative
and Qualitative Disclosure about Market Risk**
 
 For
information required under this section, see the *Market
Risks* section of Management’s Discussion and Analysis included in Item 7 of this
annual report on Form 10-K.
 
 
  - 73 -
  **Item
8.**  **Financial
Statements and Supplementary Data**
 
 Index
      to the Consolidated Financial Statements
    PAGEManagement’s
      Report on Internal Control over Financial Reporting
    75Report
      of Independent Registered Public Accounting Firmon Internal
      Control over Financial Reporting
    76Report
      of Independent Registered Public Accounting Firmon Consolidated
      Financial Statements
    77Consolidated
      Statement of Operations for the years endedDecember
      31, 2004, 2003 and 2002
    78Consolidated
      Balance Sheet at December 31, 2004 and 2003
    79Consolidated
      Statement of Cash Flows for the years endedDecember
      31, 2004, 2003 and 2002
    80Consolidated
      Statement of Comprehensive Income (Loss)and
      Stockholders’ Equity for the years endedDecember
      31, 2004, 2003 and 2002
    81Notes
      to Consolidated Financial Statements
    82Index
      to Supplementary DataTen-Year
      Financial Summary
    149Ten-Year
      Operating Summary
    150Index
      to the Financial Statement SchedulesSchedule
      II - Valuation Accounts and Reserves
    158
 
 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.
 
  - 74 -
   
 **Management’s
Report on Internal Control over Financial Reporting**
 
 The
management of Kerr-McGee Corporation (the company) is responsible for
establishing and maintaining adequate internal control over financial reporting.
The company's internal control over financial reporting is a process designed
under the supervision of the company's Chief Executive Officer and Chief
Financial Officer to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of the company’s financial statements
for external purposes in accordance with accounting principles generally
accepted in the U.S.
 
 As of
December 31, 2004, management assessed the effectiveness of the company's
internal control over financial reporting based on the criteria for effective
internal control over financial reporting established in "Internal Control -
Integrated Framework," issued by the Committee of Sponsoring Organizations of
the Treadway Commission. Based on the assessment, management determined that the
company maintained effective internal control over financial reporting as of
December 31, 2004, based on those criteria.
 
 Ernst
& Young, LLP, the independent registered public accounting firm that audited
the Consolidated Financial Statements of the company included in this annual
report on Form 10-K, has issued an attestation report on management's assessment
of the effectiveness of the company's internal control over financial reporting
as of December 31, 2004. The report, which expresses unqualified opinions on
management's assessment and on the effectiveness of the company's internal
control over financial reporting as of December 31, 2004, is included under the
heading "Report of Independent Registered Public Accounting Firm on Internal
Control over Financial Reporting."
 
 (Luke
      R. Corbett)
      Luke
      R. Corbett, Director
      Chief
      Executive Officer
    (Robert
      M. Wohleber)
      Robert
      M. Wohleber
      Senior
      Vice President and
      Chief Financial Officer
 
 March
11, 2005
 
 
  - 75 -
 
  **Report
of Independent Registered Public Accounting Firm on Internal Control over
Financial Reporting**
 
 The
Board of Directors and Stockholders
 Kerr-McGee
Corporation
 
 We have
audited management’s assessment, included in the accompanying Management’s
Report on Internal Control over Financial Reporting, that Kerr-McGee Corporation
maintained effective internal control over financial reporting as of December
31, 2004, based on criteria established in Internal Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission
(the COSO criteria). Kerr-McGee Corporation’s management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express an opinion on management’s assessment and an
opinion on the effectiveness of the company’s internal control over financial
reporting based on our audit.
 
 We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management’s assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
 
 A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.
 
 Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
 
 In our
opinion, management’s assessment that Kerr-McGee Corporation maintained
effective internal control over financial reporting as of December 31, 2004, is
fairly stated, in all material respects, based on the COSO criteria. Also, in
our opinion, Kerr-McGee Corporation maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2004,
based on **** the
COSO criteria **.**
 
 We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the 2004 consolidated financial statements of
Kerr-McGee Corporation and our report dated March 11, 2005, expressed an
unqualified opinion thereon.
 
 
 /s/
ERNST & YOUNG LLP
 
 
 Oklahoma
City, Oklahoma
 March
11, 2005
    - 76 -
 ****
 **Report
of Independent Registered Public Accounting Firm on Consolidated Financial
Statements**
 
 
 The
Board of Directors and Stockholders
 Kerr-McGee
Corporation
 
 We have
audited the accompanying consolidated balance sheets of Kerr-McGee Corporation
as of December 31, 2004 and 2003, and the related consolidated statements of
operations, comprehensive income (loss) and stockholders’ equity, and cash flows
for each of the three years in the period ended December 31, 2004. Our audits
also included the financial statement schedule listed in the index in Item 8.
These financial statements and schedule are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial
statements and schedule based on our audits.
 
 We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
 
 In our
opinion, the financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Kerr-McGee Corporation
at December 31, 2004 and 2003, and the consolidated results of its operations
and its cash flows for each of the three years in the period ended December 31,
2004, in conformity with U.S. generally accepted accounting principles. Also, in
our opinion, the related financial statement schedule, when considered in
relation to the basic financial statements taken as a whole, presents fairly in
all material respects, the information set forth thereon.
 
 As
discussed in Note 1 to the consolidated financial statements, effective January
1, 2003, the Company adopted Statement of Financial Accounting Standards No.
143, *Accounting
for Asset Retirement Obligations* . As
discussed in Note 14 to the consolidated financial statements, effective
December 31, 2003, the Company adopted FASB Interpretation No. 46, *Consolidation
of Variable Interest Entities* .
 
 We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of Kerr-McGee Corporation’s
internal control over financial reporting as of December 31, 2004, based on
criteria established in Internal Control—Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report
dated March 11, 2005, expressed an unqualified opinion thereon.
 
 
 /S/
ERNST & YOUNG LLP
 
 
 Oklahoma
City, Oklahoma
 March
11, 2005
 
 
 
  - 77 -
  **Consolidated
      Statement of Operations**(Millions
      of dollars,except
      per-share amounts)
    
    **2004**
    
    2003
    
    2002**Revenues**
    
    **$**
    **5,157**
    
    $
    4,080
    
    $
    3,515**Costs
      and Expenses**Costs
      and operating expenses
    
    
    **1,953**
    
    
    1,563
    
    
    1,343Selling,
      general and administrative expenses
    
    
    **337**
    
    
    365
    
    
    308Shipping
      and handling expenses
    
    
    **166**
    
    
    139
    
    
    124Depreciation
      and depletion
    
    
    **1,060**
    
    
    742
    
    
    809Accretion
      expense
    
    
    **30**
    
    
    25
    
    
    -Asset
      impairments
    
    
    **36**
    
    
    14
    
    
    646Loss
      (gain) associated with assets held for sale
    
    
    **29**
    
    
    (45
    )
    
    176Exploration,
      including exploratory dry holes andamortization
      of undeveloped leases
    
    
    **356**
    
    
    354
    
    
    273Taxes,
      other than income taxes
    
    
    **148**
    
    
    96
    
    
    102Provision
      for environmental remediation and restoration,net
      of reimbursements
    
    
    **86**
    
    
    60
    
    
    53Interest
      and debt expense
    
    
    **245**
    
    
    251
    
    
    275Total
      Costs and Expenses
    
    
    **4,446**
    
    
    3,564
    
    
    4,109**711**
    
    
    516
    
    
    (594
    )**Other
      Income (Expense)**
    
    
    **(40******
    ******)**
    
    (57
    )
    
    (31
    )**Income
      (Loss) from Continuing Operations****before
      Income Taxes**
    
    
    **671**
    
    
    459
    
    
    (625
    )**Benefit
      (Provision) for Income Taxes**
    
    
    **(256******
    ******)**
    
    (195
    )
    
    35**Income
      (Loss) from Continuing Operations**
    
    
    **415**
    
    
    264
    
    
    (590
    )**Income
      (Loss) from Discontinued Operations, including tax****benefit
      of $6 in both 2004 and 2003, and $33 in 2002**
    
    
    **(11**
    **)**
    
    (10
    )
    
    105**Cumulative
      Effect of Change in Accounting Principle,****including
      tax benefit of $18**
    
    
    **-**
    
    
    (35
    )
    
    -**Net
      Income (Loss)**
    
    **$**
    **404**
    
    $
    219
    
    $
    (485
    )**Income
      (Loss) per Common Share**Basic
      -Continuing
      operations
    
    **$**
    **3.29**
    
    $
    2.63
    
    $
    (5.89
    )Discontinued
      operations
    
    
    **(.09**
    **)**
    
    (.10
    )
    
    1.05Cumulative
      effect of change in accounting principle
    
    
    **-**
    
    
    (.35
    )
    
    -Net
      income (loss)
    
    **$**
    **3.20**
    
    $
    2.18
    
    $
    (4.84
    )Diluted
      -Continuing
      operations
    
    **$**
    **3.19**
    
    $
    2.58
    
    $
    (5.89
    )Discontinued
      operations
    
    
    **(.08**
    **)**
    
    (.09
    )
    
    1.05Cumulative
      effect of change in accounting principle
    
    
    **-**
    
    
    (.32
    )
    
    -Net
      income (loss)
    
    **$**
    **3.11**
    
    $
    2.17
    
    $
    (4.84
    )
 
 
 The
accompanying notes are an integral part of this statement.
 
 
 - 78 -
 **Consolidated
      Balance Sheet**(Millions
      of dollars)
    
    **2004**
    
    2003**ASSETS****Current
      Assets**Cash
      and cash equivalents
    
    **$******
    ******76**
    
    $
    142Accounts
      receivable, net of allowance for doubtfulaccounts
      of $14 in 2004 and $10 in 2003
    
    
    **963**
    
    
    583Inventories
    
    
    **329**
    
    
    394Investment
      in equity securities
    
    
    **-**
    
    
    510Derivatives
      and other assets
    
    
    **195**
    
    
    128Deferred
      income taxes
    
    
    **324**
    
    
    76**Total
      Current Assets**
    
    
    **1,887**
    
    
    1,833**Property,
      Plant and Equipment - Net**
    
    
    **10,827**
    
    
    7,399**Investments,
      Derivatives and Other Assets**
    
    
    **165**
    
    
    248**Deferred
      Charges**
    
    
    **343**
    
    
    317**Intangible
      Assets**
    
    
    **91**
    
    
    64**Long-Term
      Assets Associated with Properties Held for
    Disposal**
    
    
    **8**
    
    
    32**Goodwill**
    
    
    **1,197**
    
    
    357**Total
      Assets**
    
    **$**
    **14,518**
    
    $
    10,250**LIABILITIES
      AND STOCKHOLDERS’ EQUITY****Current
      Liabilities**Accounts
      payable
    
    **$******
    ******644**
    
    $
    475Long-term
      debt due within one year
    
    
    **463**
    
    
    574Income
      taxes payable
    
    
    **201**
    
    
    127Derivative
      liabilities
    
    
    **372**
    
    
    354Accrued
      liabilities
    
    
    **825**
    
    
    702**Total
      Current Liabilities**
    
    
    **2,505**
    
    
    2,232**Long-Term
      Debt**
    
    
    **3,236**
    
    
    3,081**Noncurrent
      Liabilities**Deferred
      income taxes
    
    
    **2,177**
    
    
    1,335Asset
      retirement obligations
    
    
    **503**
    
    
    385Derivative
      liabilities
    
    
    **208**
    
    
    2Other
    
    
    **571**
    
    
    563**Total
      Noncurrent Liabilities**
    
    
    **3,459**
    
    
    2,285**Long-Term
      Liabilities Associated with Properties Held for
      Disposal**
    
    
    **-**
    
    
    16**Stockholders’
      Equity**Common
      stock, par value $1.00 - 300,000,000 sharesauthorized,
      152,049,127 shares issued in 2004and
      100,892,354 shares issued in 2003
    
    
    **152**
    
    
    101Capital
      in excess of par value
    
    
    **4,205**
    
    
    1,708Preferred
      stock purchase rights
    
    
    **2**
    
    
    1Retained
      earnings
    
    
    **1,102**
    
    
    927Accumulated
      other comprehensive loss
    
    
    **(79**
    **)**
    
    (45
    )Common
      stock in treasury, at cost - 159,856 sharesin
      2004 and 31,924 shares in 2003
    
    
    **(8**
    **)**
    
    (2
    )Deferred
      compensation
    
    
    **(56******
    ******)**
    
    (54
    )**Total
      Stockholders’ Equity**
    
    
    **5,318**
    
    
    2,636**Total
      Liabilities and Stockholders’ Equity**
    
    **$**
    **14,518**
    
    $
    10,250
 
 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 statement.
  - 79 -
  
 **Consolidated
      Statement of Cash Flows**(Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002**Cash
      Flows from Operating Activities**Net
      income (loss)
    
    **$**
    **404**
    
    $
    219
    
    $
    (485
    )Adjustments
      to reconcile net income (loss) to net cashprovided
      by operating activities -Depreciation,
      depletion and amortization
    
    
    **1,124**
    
    
    814
    
    
    884Deferred
      income taxes
    
    
    **108**
    
    
    156
    
    
    (112
    )Dry
      hole expense
    
    
    **161**
    
    
    181
    
    
    113Asset
      impairments
    
    
    **36**
    
    
    14
    
    
    652(Gain)
      loss on assets held for sale and asset disposal
    
    
    **20**
    
    
    (40
    )
    
    100Accretion
      expense
    
    
    **30**
    
    
    25
    
    
    -Cumulative
      effect of change in accounting principle
    
    
    **-**
    
    
    35
    
    
    -Provision
      for environmental remediationand
      restoration, net of reimbursements
    
    
    **92**
    
    
    62
    
    
    89Other
      noncash items affecting net income (loss)
    
    
    **160**
    
    
    94
    
    
    76Changes
      in assets and liabilities,net
      of effects of operations acquired-(Increase)
      decrease in accounts receivable
    
    
    **(236**
    **)**
    
    45
    
    
    (104
    )Decrease
      in inventories
    
    
    **83**
    
    
    22
    
    
    37Decrease
      in deposits, prepaids and other assets
    
    
    **48**
    
    
    12
    
    
    185Increase
      (decrease) in accounts payable,derivatives
      and accrued liabilities
    
    
    **136**
    
    
    (57
    )
    
    166Increase
      in income taxes payable
    
    
    **28**
    
    
    66
    
    
    49Other
    
    
    **(144******
    ******)**
    
    (130
    )
    
    (202
    )Net
      cash provided by operating activities
    
    
    **2,050**
    
    
    1,518
    
    
    1,448**Cash
      Flows from Investing Activities**Capital
      expenditures
    
    
    **(1,262**
    **)**
    
    (981
    )
    
    (1,159
    )Dry
      hole costs
    
    
    **(78**
    **)**
    
    (181
    )
    
    (113
    )Acquisitions,
      net of cash acquired(1)
    
    
    **43**
    
    
    (110
    )
    
    (24
    )Purchase
      of long-term investments
    
    
    **(29**
    **)**
    
    (39
    )
    
    (65
    )Proceeds
      from sale of long-term investments
    
    
    **39**
    
    
    50
    
    
    12Proceeds
      from sale of assets
    
    
    **23**
    
    
    304
    
    
    756Other
      investing activities
    
    
    **2**
    
    
    6
    
    
    -Net
      cash used in investing activities
    
    
    **(1,262******
    ******)**
    
    (951
    )
    
    (593
    )**Cash
      Flows from Financing Activities**Issuance
      of long-term debt(1)
    
    
    **677**
    
    
    31
    
    
    418Issuance
      of common stock(1)
    
    
    **55**
    
    
    -
    
    
    5Repayment
      of debt
    
    
    **(1,278**
    **)**
    
    (369
    )
    
    (1,101
    )Dividends
      paid
    
    
    **(205**
    **)**
    
    (181
    )
    
    (181
    )Settlement
      of Westport derivatives
    
    
    **(101**
    **)**
    
    -
    
    
    -Other
      financing activities
    
    
    **1**
    
    
    (1
    )
    
    -Net
      cash used in financing activities
    
    
    **(851******
    ******)**
    
    (520
    )
    
    (859
    )**Effects
      of Exchange Rate Changes on Cash and Cash Equivalents**
    
    
    **(3******
    ******)**
    
    5
    
    
    3**Net
      Increase (Decrease) in Cash and Cash Equivalents**
    
    
    **(66**
    **)**
    
    52
    
    
    (1
    )**Cash
      and Cash Equivalents at Beginning of Year**
    
    
    **142**
    
    
    90
    
    
    91**Cash
      and Cash Equivalents at End of Year**
    
    **$**
    **76**
    
    $
    142
    
    $
    90
 
 
 (1)
    See
      Notes 2 and 4 for information regarding the business combination that
      occurred in 2004 and the related noncash financing and investing
      activities.
 
 
 The
accompanying notes are an integral part of this statement.
  - 80 -
  
 **Consolidated
      Statement of Comprehensive Income (Loss) and Stockholders'
      Equity**(Millions
      of dollars)
    
    Common
      Stock
    
    Capital
      in
      Excess
      of
      Par
      Value
    
    Retained
      Earnings
    
    Accumulated
      Other
      Comprehensive
      Income
      (Loss)
    
    Treasury
      Stock
    
    Deferred
      Compensation
      and
      Other
    
    Total
      Stockholders'
      EquityBalance
      at December 31, 2001
    
    $
    100
    
    $
    1,676
    
    $
    1,543
    
    $
    (64
    )
    $
    -
    
    $
    (81
    )
    $
    3,174Comprehensive
      Income (Loss):Net
      loss
    
    
    -
    
    
    -
    
    
    (485
    )
    
    -
    
    
    -
    
    
    -
    
    
    (485
    )Other
      comprehensive income
    
    
    -
    
    
    -
    
    
    -
    
    
    2
    
    
    -
    
    
    -
    
    
    2Comprehensive
      loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (483
    )Shares
      issued
    
    
    -
    
    
    5
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    5Dividends
      declared ($1.80 per share)
    
    
    -
    
    
    -
    
    
    (181
    )
    
    -
    
    
    -
    
    
    -
    
    
    (181
    )Tax
      benefit from stock-based awards
    
    
    -
    
    
    1
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    1Other
    
    
    -
    
    
    5
    
    
    9
    
    
    -
    
    
    -
    
    
    6
    
    
    20Balance
      at December 31, 2002
    
    
    100
    
    
    1,687
    
    
    886
    
    
    (62
    )
    
    -
    
    
    (75
    )
    
    2,536Comprehensive
      Income (Loss):Net
      income
    
    
    -
    
    
    -
    
    
    219
    
    
    -
    
    
    -
    
    
    -
    
    
    219Other
      comprehensive income
    
    
    -
    
    
    -
    
    
    -
    
    
    17
    
    
    -
    
    
    -
    
    
    17Comprehensive
      income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    236Shares
      issued
    
    
    -
    
    
    1
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    1Restricted
      stock activity
    
    
    1
    
    
    21
    
    
    -
    
    
    -
    
    
    (1
    )
    
    (10
    )
    
    11ESOP
      deferred compensation
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    32
    
    
    32Dividends
      declared ($1.80 per share)
    
    
    -
    
    
    -
    
    
    (182
    )
    
    -
    
    
    -
    
    
    -
    
    
    (182
    )Other
    
    
    -
    
    
    (1
    )
    
    4
    
    
    -
    
    
    (1
    )
    
    -
    
    
    2Balance
      at December 31, 2003
    
    
    101
    
    
    1,708
    
    
    927
    
    
    (45
    )
    
    (2
    )
    
    (53
    )
    
    2,636Comprehensive
      Income (Loss):Net
      income
    
    
    -
    
    
    -
    
    
    404
    
    
    -
    
    
    -
    
    
    -
    
    
    404Other
      comprehensive loss
    
    
    -
    
    
    -
    
    
    -
    
    
    (34
    )
    
    -
    
    
    -
    
    
    (34
    )Comprehensive
      income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    370Westport
      merger
    
    
    49
    
    
    2,402
    
    
    -
    
    
    -
    
    
    -
    
    
    (3
    )
    
    2,448Shares
      issued
    
    
    2
    
    
    53
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    55Restricted
      stock activity
    
    
    -
    
    
    24
    
    
    -
    
    
    -
    
    
    (6
    )
    
    (5
    )
    
    13ESOP
      deferred compensation
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    7
    
    
    7Dividends
      declared ($1.80 per share)
    
    
    -
    
    
    -
    
    
    (228
    )
    
    -
    
    
    -
    
    
    -
    
    
    (228
    )Tax
      benefit from stock-based awards
    
    
    -
    
    
    18
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    18Other
    
    
    -
    
    
    -
    
    
    (1
    )
    
    -
    
    
    -
    
    
    -
    
    
    (1
    )Balance
      at December 31, 2004
    
    $
    152
    
    $
    4,205
    
    $
    1,102
    
    $
    (79
    )
    $
    (8
    )
    $
    (54
    )
    $
    5,318
 
 The
accompanying notes are an integral part of this statement.
 
 
 - 81 -
 
   **Notes
to Consolidated Financial
Statements**
   1.  **The
Company and Significant Accounting Policies**
 
 Kerr-McGee
is an energy and inorganic chemical company with worldwide operations. The
exploration and production unit explores for, develops, produces and markets
crude oil and natural gas, with major areas of operation in the United States,
the United Kingdom sector of the North Sea and China. Exploration efforts also
extend to Australia, Benin, Bahamas, Brazil, Morocco, Canada, and the Danish and
Norwegian sectors of the North Sea. The chemical unit is primarily engaged in
production and marketing of titanium dioxide pigment and has production
facilities in the United States, Australia, Germany and the
Netherlands.
 
 **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 a
component of investments, derivatives and other assets 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 forest products operations and oil and gas operations in Kazakhstan,
Indonesia and Australia (see Note 25).
 
 **Reclassifications**
 
 Certain
prior year amounts have been reclassified to conform with the current year
presentation.
 
 **Foreign
Currency Translation**
 
 The
U.S. dollar is considered the functional currency for each of the company’s
international operations, except for its European chemical operations. Foreign
currency transaction gains or losses are recognized in the period incurred and
are included in other income (expense) in the Consolidated Statement of
Operations. The company recorded net foreign currency transaction losses of $21
million, $41 million and $38 million in 2004, 2003 and 2002,
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 reflected as a separate
component of other comprehensive income (loss) in Note 3.
 
 **Cash
Equivalents**
 
 The
company considers all investments with maturity of three months or less to be
cash equivalents. Cash equivalents totaling $17 million in 2004 and $72 million
in 2003 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.
 
 - 82 -
 Under
an accounts receivable monetization program, Kerr-McGee sells selected pigment
customers’ accounts receivable to a special-purpose entity (SPE). The company
does not own any of the common stock of the SPE. 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 SPE. The interest in the preference stock is
essentially a deposit to provide further credit enhancement to the
securitization program, if needed, but otherwise is recoverable by the company
at the end of the program. Management believes the servicing fee represents
adequate compensation and is equal to what would otherwise be charged by an
outside servicing agent. The loss associated with the receivable sales is
determined as the difference in the book value of receivables sold and the total
of cash and fair value of the deposit retained by the SPE. The losses are
recorded in other income (expense). 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.
 
 **Concentration
of Credit Risk**
 
 The
company has significant credit risk exposure due to concentration
of its crude oil and natural gas receivables with several
significant customers.  The two largest purchasers of oil and gas
production accounted for 40% of total crude oil and natural gas sales revenues
in 2004. To reduce credit risk, the company performs ongoing evaluations of its
customers' financial condition, including establishing credit limits for
its customers, and uses credit risk insurance policies from time to time as
deemed appropriate to mitigate credit risk.  The company does not
generally require collateral.
 
 **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 expenditures, including geological and geophysical costs, delay
rentals and exploration department overhead are charged against earnings as
incurred. Costs of drilling exploratory wells are capitalized pending
determination of whether proved reserves can be attributed to the discovery. If
management determines that commercial quantities of hydrocarbons have not been
discovered, capitalized costs associated with exploratory wells are charged to
dry hole costs. Costs of successful exploratory wells, all developmental wells,
production equipment and facilities are capitalized and then depleted using the
unit-of-production method by field as oil and gas are produced.  See
Note 31 for additional information related to capitalized exploratory drilling
costs.
 
 Lease
acquisition costs on unproved oil and gas properties are capitalized and
amortized over their lease terms at rates that provide for full amortization
upon abandonment. Costs of abandoned leases are charged to the accumulated
amortization accounts, while costs of productive leases are transferred
to proved oil and gas properties.  Under this method, the costs of all
unsuccessful leases are charged to exploration expense while the cost of
successful activities become part of the carrying amount of proved properties
and are depleted on a unit-of-production basis as described above.  In the
case of unproved property costs (probable and possible reserve value) associated
with proved fields acquired in a business combination, recoverability is
assessed on a field-by-field basis and a loss is recognized, if indicated, based
on the results of drilling activity, planned future drilling activity and
management's estimate of the remaining value attributed to the probable and
possible reserves.  Costs of fields not expected to be developed are
charged to expense when that determination is made, while successful
activities become part of the carrying amount of proved properties and are
depleted on a unit-of-production basis as described above.
 
 -
83 -
 ***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. Successful exploratory
wells and development costs are amortized using the unit-of-production method
based on total estimated proved developed oil and gas reserves. Producing
leasehold, platform costs, asset retirement costs and acquisition costs of
proved properties are amortized using the unit-of-production method based on
total estimated proved reserves. Non-oil and gas assets are depreciated using
the straight-line method over their estimated useful lives.
 
 ***Retirements
and Sales*** - The
cost and related depreciation, depletion and amortization reserves are removed
from the respective accounts upon retirement or sale of property, plant and
equipment. 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
period of time to complete. Interest capitalized in 2004, 2003 and 2002 was $13
million, $10 million and $8 million, respectively.
 
 **Asset
Impairments**
 
 Proved
oil and gas properties are reviewed for impairment on a field-by-field basis
when facts and circumstances indicate that their carrying amounts may not be
recoverable. In performing this review, future 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 property’s carrying amount over its estimated fair value based
on estimated discounted future cash flows.
 
 Other
assets are reviewed for impairment by asset group for which the lowest level of
independent cash flows can be identified, with impairment loss determined in a
similar manner as for proved oil and gas properties.
 
 **Gain
or Loss on Assets Held for Sale**
 
 Assets
are classified as held for sale when the company commits to a plan to sell the
assets, the sale is probable and is expected to be completed within one year.
Upon transfer to the held-for-sale category, long-lived assets are no longer
depreciated or depleted. A loss is recognized at the time of transfer, and
subsequently thereafter, based on 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 gains above the
assets’ original carrying value are only recognized upon
disposition.
 
 **Investments
in Marketable Securities**
 
 Investments
in marketable securities are classified as either "trading" or "available for
sale" depending on management’s intent. These securities are carried in the
Consolidated Balance Sheet at their estimated fair values based on quoted market
prices. Unrealized gains or losses on trading securities are recognized in
earnings, while unrealized gains or losses on available-for-sale securities are
recorded as a component of other comprehensive income (loss) within
stockholders’ equity. Realized gains and losses are determined using the average
cost method and are reflected as a component of other income (expense) in the
Consolidated Statement of Operations. Investments in debt securities are carried
as current assets or as a component of investments, derivatives and other
assets, depending on their contractual maturities.
 
 -
84 -
 **Goodwill
and Other Intangible Assets**
 
 Goodwill
is initially measured as the excess of the purchase price of an acquired entity
over the fair values of individual assets acquired and liabilities assumed.
Goodwill and certain indefinite-lived intangibles are not amortized but are
reviewed annually for impairment, or more frequently if impairment indicators
arise. The annual test for goodwill impairment was completed in the second
quarter of 2004, with no impairment indicated. Intangibles with finite lives are
amortized over their estimated useful lives. Intangibles subject to amortization
are reviewed for impairment whenever impairment indicators are
present.
  **Derivative
Instruments and Hedging Activities**
 
 The
company accounts for all derivative financial instruments in accordance with
FASB Statement No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (FAS No. 133) Derivative 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 and natural gas prices, foreign currency exchange
rates and interest rates. Unrealized 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 No. 133 are recorded in
accumulated other comprehensive income (loss). Realized hedging gains or losses
are 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. Derivative
instruments that are not designated as hedges or that do not meet the criteria
for hedge accounting and those designated as fair-value hedges under FAS No. 133
are recorded in the Consolidated Balance Sheet at fair value, with gains or
losses reported currently in earnings (together with offsetting gains or losses
on the hedged item for fair value hedges).
 
 Cash
flows associated with derivative instruments are included in the same category
in the Consolidated Statement of Cash Flows as the cash flows from the item
being hedged, unless a derivative instrument includes an
other-than-insignificant financing element at inception, in which case
associated cash flows are reflected in cash flows from financing
activities.
 
 **Environmental
Remediation and Other Contingencies**
 
 
 As
sites of environmental concern are identified, the company assesses the existing
conditions, claims and assertions, 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. Estimates of environmental liabilities, which include the cost of
investigation and remediation, are based on a variety of matters, including, but
not limited to, the stage of investigation, the stage of the remedial design,
evaluation of existing remediation technologies, and presently enacted laws and
regulations. In future periods, a number of factors could significantly change
the company’s estimate of environmental remediation costs, such as changes in
laws and regulations, revisions to the remedial design, unanticipated
construction problems, identification of additional areas or volumes of
contamination, and changes in costs of labor, equipment and technology.
 
 To the
extent costs of investigation and remediation are recoverable from the U.S.
government under Title X and under certain insurance policies and such
recoveries are deemed probable, the company records a receivable for the
estimated amounts recoverable (undiscounted). Receivables are reflected in the
Consolidated Balance Sheet as either accounts receivable or as a component of
investments, derivatives and other assets, depending on estimated timing of
collection.
  ****
 -
85 -
 **Asset
Retirement Obligations**
 In June
2001, the FASB issued Statement No. 143, "Accounting for Asset Retirement
Obligations" (FAS No. 143). FAS No. 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 asset retirement cost, is depreciated over the useful life of the
asset. The company adopted the new standard on January 1, 2003, as discussed
further in Note 16.
 In
accordance with the provisions of FAS No. 143, the company accrues an
abandonment liability associated with its oil and gas wells and platforms when
those assets are placed in service. Generally, the company does not recognize an
asset retirement obligation associated with its operating chemical facilities,
either because no legal obligation exists or the life of such facilities is
indeterminate. However, if a decision to decommission a facility is made and the
timing of liability settlement becomes known, a liability is recognized and the
remaining asset retirement cost is depreciated over the remaining useful life of
the assets. The ARO is recorded at its estimated fair value and accretion
expense is recognized over time as the discounted liability is accreted to its
expected settlement value. Fair value is measured using expected future cash
outflows discounted at the company’s credit-adjusted risk-free interest rate. No
market risk premium has been included in the company's calculation of ARO
balances since no reliable estimate can be made by the company.
  **Employee
Stock-Based Compensation**
  ***Stock
Options*** - FAS
No. 123, “Accounting for Stock-Based Compensation,” prescribes a fair-value
method of accounting for employee stock options. Following this method,
compensation expense is measured based on the estimated fair value of stock
options at the grant date and recognized over the vesting period. 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 with an exercise price equal
to the fair value of the stock on the grant date.
 
 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 (loss) 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.
 
 (Millions
      of dollars, except per share amounts)
    
    **2004**
    
    2003
    
    2002Net
      income (loss) as reported
    
    **$**
    **404**
    
    $
    219
    
    $
    (485
    )Add:
      stock-based employee compensation expense includedin
      reported net income (loss), net of taxes
    
    
    **11**
    
    
    7
    
    
    4Deduct:
      stock-based compensation expense determinedusing
      a fair-value method, net of taxes
    
    
    **(24******
    ******)**
    
    (23
    )
    
    (19
    )Pro
      forma net income (loss)
    
    **$**
    **391**
    
    $
    203
    
    $
    (500
    )Net
      income (loss) per share -Basic
      -As
      reported
    
    **$**
    **3.20**
    
    $
    2.18
    
    $
    (4.84
    )Pro
      forma
    
    
    **3.09**
    
    
    2.03
    
    
    (4.99
    )Diluted
      -As
      reported
    
    **$**
    **3.11**
    
    $
    2.17
    
    $
    (4.84
    )Pro
      forma
    
    
    **3.01**
    
    
    2.03
    
    
    (4.99
    )
 
 - 86 -
 The
fair value of each option granted in 2004, 2003 and 2002 was estimated as of the
date of the grant using the Black-Scholes option pricing model with the
following weighted-average assumptions:
 
 Assumptions
    Weighted-AverageRisk-Free
    Expected
    Expected
    Expected
    Fair
      Value ofInterest
      Rate
    Dividend
      Yield
    Life
      (years)
    Volatility
    Options
      Granted2004
    3.5%
    3.6%
    5.8
    22.6%
    $
      8.632003
    3.6
    3.3
    5.8
    32.7
    11.092002
    4.8
    3.4
    5.8
    36.0
    16.97
 
 ***Restricted
Stock*** - The
value of restricted stock and stock opportunity shares is equal to the market
price on the grant date and is recorded as deferred compensation at the date of
grant. Deferred compensation, a component of stockholders’ equity, is amortized
ratably over the vesting periods of the underlying grants, which range from
three to five years, or over the service period, if shorter.
 
 ***Employee
Stock Ownership Plan (ESOP)*** - The
company has a leveraged ESOP plan with both sponsor and third-party financing.
Third-party financing is included in debt balances in the accompanying
Consolidated Balance Sheet, while sponsor financing is excluded. The company
stock owned by the ESOP trust is held in a loan suspense account. Deferred
compensation, representing the unallocated ESOP shares, is reflected as a
reduction of stockholders’ equity. The company’s matching contributions and
dividends on the shares held by the ESOP trust are used to repay the debt, and
stock is released from the loan suspense account as the principal and interest
are paid. The expense is recognized and stock is then allocated to participants’
accounts at market value as the participants’ contributions are made to the
Savings Investment Plan (SIP). Dividends paid on the common stock held in
participants’ accounts are also used to repay the loans, and stock with a value
equal to the amount of dividends is allocated to participants’ accounts. All
ESOP shares are considered outstanding for earnings per share calculations.
Dividends on ESOP shares are charged to retained earnings.
 
 **Revenue
Recognition**
 
 Revenue
derived from product sales is recognized when delivery occurs and title and risk
of loss pass to the customer and collection of the resulting receivable is
probable. Oil and gas sales involving balancing arrangements among partners are
recognized as revenues when the oil or gas is sold using the entitlements method
of accounting based on the company’s net working interest and a receivable or
deferred revenue is recorded for any imbalance. At December 31, 2004 and 2003,
both the quantity and dollar amount of oil and gas balancing arrangements were
immaterial.
 
 **Shipping
and Handling Fees and Costs**
 
 All
amounts billed to a customer in a 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.
 
 **Income
Taxes**
 
 Deferred
income taxes are provided to reflect the future tax consequences of temporary
differences between the tax basis of assets and liabilities and their reported
amounts in the financial statements, except for deferred taxes on income
considered to be permanently reinvested in certain foreign
subsidiaries.
 
 **New/Revised
Accounting Standards**
 
 The
Financial Accounting Standards Board (FASB) has proposed an amendment to
Statement No. 19, “Financial Accounting and Reporting by Oil and Gas Producing
Companies” (FAS No. 19) that may change the way oil and gas producers account
for deferred exploratory drilling costs. Under the current rules, there is a
presumption that all exploratory drilling costs will be expensed within one year
following completion of drilling if proved reserves have not been recorded,
except for costs related to areas where additional exploration wells are
necessary to justify development plans *and* such
additional wells are under way or firmly planned for the near future.
Application of FAS No. 19 to the facts and circumstances commonly faced by oil
and gas producers in today’s exploration and development environment
(particularly in deepwater and international areas) has become a concern for the
industry and there are diverse views in practice. For example, in the case of
deepwater discoveries, additional appraisal wells are almost never under way or
firmly planned when the drilling rig is released due to the time required to
assess the initial discovery well, update geologic models, and plan appraisal
well locations in an extremely high-cost drilling environment.
 
 - 87 -
 The new
standard would relax the one-year limitation, so long as oil and gas reserves
have been discovered and an enterprise “is making sufficient progress assessing
the reserves and the economic and operating viability of the project.” The FASB
staff has developed indicators to help determine whether sufficient progress is
being made. The company believes the adoption of the proposed amendment (once
finalized) will have no impact on its consolidated financial statements.
Additional information related to exploratory drilling costs is included in
Note 31.
 
 In
December 2004, the FASB issued FASB Staff Position No. FAS 109-2 (FSP No.
109-2), “Accounting and Disclosure Guidance for the Foreign Earnings
Repatriation Provisions within the American Jobs Creation Act of 2004” (the Jobs
Act). FSP No. 109-2 provides guidance with respect to reporting the potential
impact of the repatriation provisions of the Jobs Act on an enterprise’s income
tax expense and deferred tax liability. The Jobs Act was enacted on October 22,
2004, and provides for a temporary 85% dividends received deduction on certain
foreign earnings repatriated during a one-year period. The deduction would
result in an approximate 5.25% federal tax rate on the repatriated earnings.
Additionally, withholding taxes may be due in certain tax jurisdictions. To
qualify for the deduction, the earnings must be reinvested in the United States
pursuant to a domestic reinvestment plan established by a company’s chief
executive officer and approved by a company’s board of directors. Certain other
criteria in the Jobs Act must be satisfied as well. FSP No. 109-2 states that an
enterprise is allowed time beyond the financial reporting period to evaluate the
effect of the Jobs Act on its plan for reinvestment or repatriation of foreign
earnings. The company has not yet completed its evaluation of the impact of the
repatriation provisions of the Jobs Act. Accordingly, as provided for in FSP No.
109-2, the company has not adjusted its tax expense or deferred tax liability to
reflect the repatriation provisions of the Jobs Act. Additional disclosures
related to the status of our evaluation of the Jobs Act repatriation provisions
are included in Note 15.
 
 In
December 2004, the FASB issued FASB Staff Position No. FAS 109-1,
"Application of FASB Statement No. 109, Accounting for Income Taxes, to the
Tax Deduction on Qualified Production Activities Provided by the American Jobs
Creation Act of 2004," indicating that this deduction, which will be available
to the company in 2005, should be accounted for as a special deduction in
accordance with the provisions of FAS No. 109, as opposed to a tax-rate
reduction. Beginning in 2005, the company will recognize the allowable
deductions as qualifying activity occurs.
 
 In
December 2004, the FASB issued Statement No. 123 (revised 2004), “Share-Based
Payment” (FAS No. 123R), which replaces FAS No. 123 and supersedes APB Opinion
No. 25, “Accounting for Stock Issued to Employees. ”FAS No. 123R requires all
share-based payments to employees, including grants of employee stock options,
to be recognized in the financial statements based on their fair values
beginning with the first interim period after June 15, 2005, with early adoption
encouraged. The pro forma disclosures previously permitted under FAS No. 123 no
longer will be an alternative to financial statement recognition. The company is
required to adopt FAS No. 123R in the third quarter of 2005. Under FAS No. 123R,
the company must determine the appropriate fair value model to be used for
valuing share-based payments, the amortization method for compensation cost and
the transition method to be used at the date of adoption. The permitted
transition methods include either retrospective or prospective adoption. Under
the retrospective method of adoption, prior periods may be restated either as of
the beginning of the year of adoption (modified retrospective method) or for all
periods presented. The prospective method requires that compensation expense be
recorded for all unvested share-based compensation awards at the beginning of
the first quarter of adoption of FAS No. 123R, while the retrospective methods
would record compensation expense for all unvested share-based compensation
awards beginning with the first period presented. The company is currently
evaluating the requirements of FAS No. 123R and expects to adopt this standard
using either the prospective or the modified retrospective method of adoption.
The company expects that the effect of adoption will not have a material effect
on our financial condition and cash flows, and that the effect on our results of
operations will be comparable to the current pro forma disclosures under FAS No.
123 included in Note 1 to the Consolidated Financial Statements.
 
 
 
  - 88 -
  2.  **Business
Combination**
 
 On June
25, 2004, Kerr-McGee completed a merger with Westport Resources Corporation
(Westport), an independent oil and gas exploration and production company with
operations in the Rocky Mountain, Mid-Continent and Gulf Coast areas onshore
U.S. and in the Gulf of Mexico. The merger increased Kerr-McGee’s proved
reserves by approximately 30%, bringing the combined company’s total reserves as
of December 31, 2003, to approximately 1.3 billion barrels of oil equivalent had
the merger occurred at that date (unaudited).
 
 On the
effective date of the merger, each issued and outstanding share of Westport
common stock was converted into .71 shares of Kerr-McGee common stock. As a
result, Kerr-McGee issued 48.9 million shares of common stock to Westport's
stockholders valued at $2.4 billion based on Kerr-McGee’s weighted average stock
price two days before and after the merger was publicly announced. Kerr-McGee
also exchanged 1.9 million stock options for options held by Westport employees
with a fair value of $34 million, determined using the Black-Scholes option
pricing model.
 
 On June
25, 2004, after completion of the merger, Kerr-McGee paid down all outstanding
borrowings under the Westport revolving credit facility and the facility was
terminated on July 13, 2004.
 
 During
June 2004, Kerr-McGee purchased Westport 8.25% Notes with an aggregate principal
amount of $14 million ($16 million fair value). On July 1, 2004, Kerr-McGee
issued a notice of redemption for the remaining 8.25% Westport notes and the
notes were redeemed on July 31, 2004, at an aggregate redemption price of $786
million. The redemption price consisted of the face value of $700 million, less
the amount previously purchased by Kerr-McGee of $14 million, plus a make-whole
premium of $100 million.
 
 On July
1, 2004, Kerr-McGee issued $650 million of 6.95% notes due July 1, 2024, with
interest payable semi-annually. The notes were issued at 99.2%, resulting in a
discount of $5 million, which will be recognized as additional interest expense
over the term of the notes. The proceeds from this debt issuance, together with
proceeds from borrowings under the company’s revolving credit facilities, were
used to redeem the 8.25% Westport notes discussed above.
 
 In
exchange for Westport’s common stock and options, Kerr-McGee issued stock valued
at $2.4 billion, options valued at $34 million and assumed debt of $1
billion, for a total of $3.5 billion (net of $43 million of cash acquired). The
fair value assigned to assets acquired and goodwill totaled $4.7 billion.
Westport’s assets and liabilities are reflected in the company’s balance sheet
at December 31, 2004, and Westport’s results of operations are included in the
company’s statement of operations from June 25, 2004. The purchase price was
allocated to specific assets and liabilities based on their estimated fair
values at the merger date, with $839 million recorded as goodwill and $596
million recorded for net deferred tax liabilities.
 
 The
strategic benefits of the merger and the principal factors that contributed to
Kerr-McGee recognizing goodwill are as follows:
 
 ·  Provides
complementary high-quality assets in core U.S. onshore and Gulf of Mexico
regions;
  ·  Enhances
the stability of high-margin production;
  ·  Expands
low-risk exploitation opportunities;
  ·  Increases
free cash flow for Kerr-McGee’s high-potential exploration opportunities;
  ·  Reduces
leverage and enables greater financial flexibility; and
  ·  Provides
opportunities for synergies and related cost savings.
  
  - 89 -
  The
condensed balance sheet information presented below shows the allocation of
purchase price to Westport’s assets and liabilities as of the merger
date.
 
 **Condensed
      Balance Sheet**(Millions
      of dollars)AssetsCurrent
      AssetsCash
      and cash equivalents
    
    $
    43Accounts
      receivable
    
    
    122Derivative
      assets
    
    
    2Other
      current assets
    
    
    29Deferred
      income taxes
    
    
    87Total
      Current Assets
    
    
    283Property,
      Plant & Equipment:Proved
      oil and gas properties
    
    
    2,370Unproved
      oil and gas properties
    
    
    1,064Other
      assets
    
    
    60Total
      Property, Plant & Equipment
    
    
    3,494Derivative
      Assets
    
    
    4Transportation
      Contracts
    
    
    35Goodwill
    
    
    839Total
      Assets
    
    $
    4,655Liabilities
      and Stockholders’ EquityCurrent
      LiabilitiesAccounts
      payable and accrued liabilities
    
    $
    206Derivative
      liabilities
    
    
    154Total
      Current Liabilities
    
    
    360Long-Term
      Debt
    
    
    1,046Deferred
      Income Taxes
    
    
    683Asset
      Retirement Obligations
    
    
    70Derivative
      Liabilities
    
    
    48Total
      Noncurrent Liabilities
    
    
    1,847Stockholders’
      Equity
    
    
    2,448Total
      Liabilities and Stockholders’ Equity
    
    $
    4,655
 
  - 90 -
  The pro
forma information presented below has been prepared to give effect to the
Westport merger as if it had occurred at the beginning of the periods presented.
The pro forma information is presented for illustrative purposes only and is
based on estimates and assumptions deemed appropriate by Kerr-McGee. If the
Westport merger had occurred in the past, Kerr-McGee’s operating results would
have been different from those reflected in the pro forma information below;
therefore, the pro forma information should not be relied upon as an indication
of the operating results that Kerr-McGee would have achieved if the merger had
occurred at the beginning of each period presented. The pro forma information
also should not be used as an indication of the future results that Kerr-McGee
will achieve after the Westport merger.
 
 Pro
      Forma Information(Unaudited)Year
      EndedDecember
      31,(Millions
      of dollars, except per-share amounts)
    
    **2004**
    
    2003Revenues
    
    **$**
    **5,607**
    
    $
    4,808Income
      from Continuing Operations
    
    
    **476**
    
    
    307Net
      Income
    
    
    **465**
    
    
    258Income
      per Common Share -Basic
    
    **$**
    **3.10**
    
    $
    1.73Diluted
    
    
    **3.03**
    
    
    1.71
 
 
 3.  **Other
Comprehensive Income (Loss)**
 
 Components
of other comprehensive income (loss) for the years ended December 31, 2004, 2003
and 2002 are as follows:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Foreign
      currency translation adjustments
    
    **$**
    **22**
    
    ****$
    ****56
    
    ****$
    ****48Reclassification
      of foreign currency translation adjustment to net income
    
    
    **7**
    
    
    -
    
    
    -Unrealized
      gain (loss) on cash flow hedges, net of taxesof
      $296, $124 and $55
    
    
    **(531**
    **)**
    
    (203
    )
    
    (93
    )Reclassification
      of realized (gain) loss on cash flow hedges to net income,net
      of taxes of $(267), $(94) and $(33)
    
    
    **462**
    
    
    172
    
    
    54Unrealized
      gain on available-for-sale securities, net of taxesof
      $(3) and $(4) in 2003 and 2002
    
    
    **-**
    
    
    6
    
    
    7Reclassification
      of realized gain on available-for-sale securities, netof
      taxes of $3 and $3 in 2004 and 2003
    
    
    **(5**
    **)**
    
    (7
    )
    
    -Minimum
      pension liability adjustments, net of taxes of$(7),
      $5 and $9
    
    
    **11**
    
    
    (7
    )
    
    (14
    )**$******
    **(34******
    ******)**
    $
    17
    
    $
    2
 
 
 Components
of accumulated other comprehensive loss at December 31, 2004 and 2003, net of
applicable tax effects, are as follows:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003Foreign
      currency translation adjustments
    
    **$**
    **91**
    
    $
    62Unrealized
      loss on cash flow hedges
    
    
    **(157**
    **)**
    
    (88
    )Unrealized
      gain on available-for-sale securities
    
    
    **-**
    
    
    5Minimum
      pension liability adjustments
    
    
    **(13******
    ******)**
    
    (24
    )**$******
    **(79******
    ******)**
    $
    (45
    )
 
 
  - 91 -
  4.  **Cash
Flow Information**
 
 Net
cash provided by operating activities reflects cash payments for income taxes
and interest as follows:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Income
      tax payments
    
    **$**
    **154**
    
    $
    115
    
    $
    89Less
      refunds received
    
    
    **(19******
    ******)**
    
    (49
    )
    
    (268
    )Net
      income tax payments (refunds)
    
    **$**
    **135**
    
    $
    66
    
    $
    (179
    )Interest
      payments
    
    **$**
    **260**
    
    $
    237
    
    $
    258
 
 Other
noncash items included in the reconciliation of net income (loss) to net cash
provided by operating activities include the following:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Increase
      in fair value of embedded options in the DECS(1)
    
    **$**
    **101**
    
    $
    88
    
    $
    34Increase
      in fair value of trading securities(1)
    
    
    **(103**
    **)**
    
    (96
    )
    
    (61
    )Stock-based
      compensation
    
    
    **25**
    
    
    42
    
    
    20Pension
      and postretirement expense
    
    
    **36**
    
    
    44
    
    
    (12
    )Litigation
      reserves
    
    
    **8**
    
    
    8
    
    
    75Equity
      in net losses of equity method investees
    
    
    **26**
    
    
    33
    
    
    25Unrealized
      loss (gain) from nonhedge derivatives
    
    
    **12**
    
    
    5
    
    
    (19
    )Noncash
      spar rental expense
    
    
    **14**
    
    
    8
    
    
    12All
      other(2)
    
    
    **41**
    
    
    (38
    )
    
    2Total
    
    **$**
    **160**
    
    $
    94
    
    $
    76
 
 Details
of changes in other assets and liabilities within the operating section of the
Consolidated Statement of Cash Flows are as follows:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Environmental
      expenditures
    
    **$**
    **(99**
    **)**
    $
    (104
    )
    $
    (128
    )Reimbursements
      of environmental expenditures
    
    
    **50**
    
    
    15
    
    
    -Cash
      abandonment expenditures
    
    
    **(17**
    **)**
    
    (17
    )
    
    (48
    )Employer
      contributions to pension and postretirement plans
    
    
    **(67**
    **)**
    
    (29
    )
    
    (24
    )All
      other(2)
    
    
    **(11**
    **)**
    
    5
    
    
    (2
    )Total
    
    **$******
    **(144******
    ******)**
    $
    (130
    )
    $
    (202
    )
 
 
 (1)See Note 11 for a discussion of the accounting for the
    DECS.(2)No
      other individual item is material to total cash flows from operating
      activities.
  - 92 -
 Information
about noncash investing and financing activities not reflected in the
Consolidated Statement of Cash Flows follows:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Noncash
      investing activities:Increase
      in property, plant and equipment(2)
    
    **$**
    **3,494**
    
    $
    -
    
    $
    -Increase
      (decrease) in property related to Gunnison operatinglease agreement(3)
    
    
    **(83**
    **)**
    
    83
    
    
    -Increase
      in intangible assets(2)
    
    
    **35**
    
    
    -
    
    
    -Trading
      securities used for redemption of long-term debt(4)
    
    
    **(586**
    **)**
    
    -Increase
      in fair value of securities available for sale(1)
    
    
    **-**
    
    
    9
    
    
    11Investment
      in equity affiliate
    
    
    **-**
    
    
    -
    
    
    2Noncash
      financing activities:Issuance
      of common stock and stock options(2)
    
    
    **2,448**
    
    
    -
    
    
    -Long-term
      debt assumed(2)
    
    
    **1,046**
    
    
    -
    
    
    -Increase
      (decrease) in debt related to Gunnison operatinglease agreement(3)
    
    
    **(75**
    **)**
    
    75
    
    
    -Long-term
      debt redeemed with trading securities(4)
    
    
    **(330**
    **)**
    
    -
    
    
    -Settlement
      of DECS derivative(4)
    
    
    **(256**
    **)**
    
    -
    
    
    -Increase
      in valuation of the DECS(1)
    
    
    **-**
    
    
    8
    
    
    8(1)See Note 11 for a discussion of the accounting for the
    DECS.(2)Noncash transaction related to the Westport merger, see Note
      2.(3)See Note 14 for a discussion of the Gunnison lease.(4)See
      Note 7 for a discussion of the redemption of the
DECS.
 
 
 5.  **Accounts
Receivable Sales**
 
 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. During the third quarter of 2004, the company completed its
renewal of the program, extending the term through July 27, 2005. The maximum
availability under the program is $165 million. Under the terms of the program,
selected qualifying customer accounts receivable are 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. 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 SPE, which
essentially represents a retained deposit to provide further credit
enhancements, if needed, but is otherwise recoverable by the company at the end
of the program. The carrying value of our investment in the preference stock was
$4 million at December 31, 2004 and 2003.
 
  - 93 -
  The
program includes a ratings downgrade trigger in the event Kerr-McGee's corporate
senior unsecured debt rating falls below BBB- by S&P or Baa3 by Moody's, or
in the event such rating has been suspended or withdrawn by S&P or Moody's.
The result of the downgrade trigger is an increase in the cost of the program,
along with other program modifications. In addition, the program includes a
ratings downgrade termination event, upon which the program effectively
liquidates over time and the third-party multi-seller commercial paper conduit
is repaid by the collections on accounts receivable sold by the SPE. The ratings
downgrade termination event is triggered if Kerr-McGee's corporate senior
unsecured debt (i) is rated less than BBB- by S&P and Baa3 by Moody's, (ii)
is rated less than BB+ by S&P or Ba1 by Moody's or (iii) is withdrawn or
suspended by S&P or Moody's.
 
 During
2004, 2003 and 2002, the company sold $1.1 billion, $836 million and $609
million, respectively, of its pigment receivables, resulting in pretax losses of
$8 million, $5 million and $5 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. Both at
year-end 2004 and 2003, the outstanding balance on receivables sold, net of the
company's retained interest in receivables serving as over-collateralization,
totaled $165 million. The outstanding balance of receivables serving as
over-collateralization totaled $39 million and $36 million at December 31, 2004
and 2003, respectively. There were no delinquencies as of year-end
2004.
 
 
 6.  **Inventories**
 
 Major
categories of inventories at December 31, 2004 and 2003 are:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003Chemicals
      and other products
    
    **$**
    **236**
    
    $
    307Materials
      and supplies
    
    
    **85**
    
    
    80Crude
      oil and natural gas liquids
    
    
    **8**
    
    
    7Total
    
    **$**
    **329**
    
    $
    394
 
 
 7.  **Financial
Instruments**
 
 The
company invests in certain securities classified as available for sale or
trading and holds or issues financial instruments for other than trading
purposes. At December 31, 2004, the company held debt securities classified as
available for sale. At December 31, 2003, the company’s investments consisted of
available for sale debt securities and common shares of Devon Energy Corporation
(Devon stock). The company had an option to use Devon stock to repay its debt
exchangeable for stock (DECS). Accounting for options embedded in the DECS is
discussed in Note 11. The portion of the company’s Devon stock holdings
necessary to repay the DECS was classified as trading and consisted of 8.4
million shares, with the remaining shares designated as available for sale. On
August 2, 2004, the company’s DECS matured and were settled with the
distribution of shares of Devon common stock, at which time the fair values of
the embedded put and call options in the DECS were nil and $256 million,
respectively, and the fair value of the 8.4 million Devon shares was $586
million. The fair value of the Devon shares less the call option liability
resulted in a net asset carrying value of $330 million, which was exactly offset
by the fair value of the DECS resulting in no gain or loss on redemption of the
debt. The company recognized, as a component of other income (expense), a charge
against earnings of $7 million related to a cumulative translation adjustment
recorded prior to 1999 when the company accounted for its investment in Devon
using the equity method. Under the provisions of FAS No. 52, “Foreign Currency
Translation,” the proportionate share of Devon’s cumulative translation
adjustment was removed from equity and reported in earnings in 2004, when the
liquidation of the associated investment occurred.
 
 
  - 94 -
  **Investments
in Available-for-Sale Securities**
 
 The
company has certain investments that are considered to be available for sale. At
December 31, 2004 and 2003, available-for-sale securities for which fair value
can be determined are as follows:
 
 **2004**
    
    2003**Gross**
    
    
    
    
    
    Gross**Unrealized**
    
    
    
    
    
    Unrealized**Fair**
    
    
    
    **Holding**
    
    Fair
    
    
    
    Holding(Millions
      of dollars)
    
    **Value**
    
    **Cost**
    
    **Gains**
    
    Value
    
    Cost
    
    GainsEquity
      securities
    
    **$**
    **-**
    
    **$**
    **-**
    
    **$**
    **-**
    
    $
    27
    
    $
    10
    
    $
    8U.S.
      government obligations
    
    
    **4**
    
    
    **4**
    
    
    **-**
    
    
    4
    
    
    4
    
    
    -Total
    
    
    
    
    
    
    
    **$**
    **-**
    
    
    
    
    
    
    
    $
    8
 
 
 The
equity securities represented the company’s investment in Devon common stock.
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 2003 sales totaled $59 million ($47 million received in 2003 and
$12 million received in 2004) and proceeds from the January 2004 sales totaled
$27 million.
 
 **Trading
Securities**
 
 The
market value of 8.4 million shares of Devon stock was $483 million at December
31, 2003. Unrealized pretax gains recognized in other income (expense) in the
Consolidated Statement of Operations amounted to $103 million in 2004 through
the date of disposition, as discussed above, $96 million in 2003 and $61 million
in 2002. These gains were partially offset by unrealized losses on the embedded
options associated with the DECS of $101 million in 2004 through the date of
DECS redemption, $88 million in 2003 and $34 million in 2002.
 
 **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,
2004 and 2003, the carrying amount and estimated fair value of these instruments
are as follows:
 
 **2004**
    
    2003**Carrying**
    
    **Fair**
    
    Carrying
    
    Fair(Millions
      of dollars)
    
    **Amount**
    
    **Value**
    
    Amount
    
    ValueCash
      and cash equivalents
    
    **$**
    **76**
    
    **$**
    **76**
    
    $
    142
    
    $
    142Long-term
      receivables
    
    
    **24**
    
    
    **21**
    
    
    95
    
    
    82Debt
      exchangeable for stock, excluding options
    
    
    **-**
    
    
    **-**
    
    
    326
    
    
    330Long-term
      debt, excluding DECS in 2003
    
    
    **3,699**
    
    
    **4,039**
    
    
    3,329
    
    
    3,761
 
 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 the company’s long-term
debt is based on the quoted market prices for the same or similar debt issues or
on the current rates offered to the company for debt with the same remaining
maturity. Carrying values of derivative instruments, all of which approximate
their fair values, are disclosed in Note 11.
 
 
  - 95 -
  8.  **Property,
Plant and Equipment**
 
 Property,
plant and equipment at December 31, 2004 and 2003, is as follows:
 
 AccumulatedDepreciation
      andGross
      Property
    
    Depletion
    
    Net
      Property(Millions
      of dollars)
    
    **2004**
    
    2003(1)
    
    **2004**
    
    2003(1)
    
    **2004**
    
    2003(1)Exploration
      and production
    
    **$**
    **16,730**
    
    $
    12,068
    
    **$**
    **(6,866**
    **)**
    $
    (5,709
    )
    **$**
    **9,864**
    
    $
    6,359Chemicals
    
    
    **2,059**
    
    
    2,006
    
    
    **(1,184**
    **)**
    
    (1,052
    )
    
    **875**
    
    
    954Other
    
    
    **195**
    
    
    184
    
    
    **(107**
    **)**
    
    (98
    )
    
    **88**
    
    
    86Total
    
    **$**
    **18,984**
    
    $
    14,258
    
    **$**
    **(8,157**
    **)**
    $
    (6,859
    )
    **$**
    **10,827**
    
    $
    7,399
 
 (1) Certain
prior year balances were reclassified to intangible assets.  See Note
10.
 
 
 9.  **Deferred
Charges**
 
 Deferred
charges are as follows at December 31, 2004 and 2003:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003Prepaid
      pension cost
    
    **$**
    **262**
    
    $
    243Nonqualified
      benefit plan deposits
    
    
    **48**
    
    
    35Unamortized
      debt issue costs and other
    
    
    **33**
    
    
    39Total
    
    **$**
    **343**
    
    $
    317
 
 
 10.  **Goodwill
and Intangible Assets**
 
 Goodwill
and other intangible assets recorded in the Westport merger were valued at $839
million and $35 million, respectively, at the merger date.
 
 The
changes in the carrying amount of goodwill for 2003 and 2004 are as
follows:
 
 Segment(Millions
      of dollars)
    
    Exploration
      and Production
    
    Chemical
      - Pigment
    
    Total
      Carrying AmountBalance,
      December 31, 2002:
    
    $
    347
    
    $
    9
    
    $
    356Other
      changes (including foreign currency translation)
    
    
    (1
    )
    
    2
    
    
    1Balance,
      December 31, 2003:
    
    
    **346**
    
    
    **11**
    
    
    **357**Goodwill
      associated with the Westport merger
    
    
    **839**
    
    
    **-**
    
    
    **839**Other
      changes (including foreign currency translation)
    
    
    **-**
    
    
    **1**
    
    
    **1**Balance,
      December 31, 2004:
    
    **$**
    **1,185**
    
    **$**
    **12**
    
    **$**
    **1,197**
 
  - 96 -
  The
changes in the carrying amount of indefinite-lived intangible assets for 2003
and 2004 are as follows:
 
 (Millions
      of dollars)
    
    Carrying
      Amount*Intellectual
      Property*Balance
      at December 31, 2002:
    
    $
    52Other
      changes (including foreign currency translation)
    
    
    3Balance
      at December 31, 2003:
    
    
    **55**Impairment
      associated with the Savannah sulfate plant shutdown (1)
    
    
    **(8**
    **)**Other
      changes (including foreign currency translation)
    
    
    **6**Balance
      at December 31, 2004:
    
    **$**
    **53**
 
 (1) Refer
to Note 25 for more information on the Savannah sulfate impairment.
 
 Intangible
assets subject to amortization at December 31, 2003 and 2004 are as
follows:
 
 (Millions
      of dollars)
    
    Gross
      Carrying Amount
    
    Accumulated
      Amortization
    
    Net
      Carrying AmountBalance
      at December 31, 2003:Transportation
      contracts
    
    $
    16
    
    $
    (9
    )
    $
    7Other
    
    
    3
    
    
    (1
    )
    
    2Total
    
    $
    19
    
    $
    (10
    )
    $
    9Balance
      at December 31, 2004:Transportation
      contracts
    
    **$**
    **49**
    
    **$**
    **(13**
    **)**
    **$**
    **36**Other
    
    
    **3**
    
    
    **(1******
    ******)**
    
    **2**Total
    
    **$**
    **52**
    
    **$******
    **(14******
    ******)**
    **$**
    **38**
 
 Intangible
asset amortization expense was $6 million, $5 million and $5 million in 2004,
2003 and 2002, respectively. The estimated amortization expense for the next
five years totals $26 million, ranging from $4 million to $8 million annually.
The remaining weighted average amortization period for the transportation
contracts is eight years.
  - 97 -
  11.  **Derivative
Instruments**
 
 The
company is exposed to market risk from fluctuations in crude oil and natural gas
prices, foreign currency exchange rates, and interest rates. To reduce the
impact of these risks on earnings and to increase the predictability of its cash
flows, the company enters into certain derivative contracts, primarily swaps and
collars for a portion of its oil and gas production, forward contracts to buy
and sell foreign currencies, and interest rate swaps.
 
 The
following tables summarize the balance sheet presentation of the company’s
derivatives as of December 31, 2004 and 2003:
 
 December
      31, 2004Derivative
      Fair ValueCurrent
    
    Long-Term
    
    Current
    
    Long-Term
    
    Deferred
      Gain(Millions
      of dollars)
    
    Asset
    
    Asset
    
    Liability
    
    Liability
    
    (Loss)
      in AOCI(1)Oil
      and gas commodity derivatives -Kerr-McGee
      positions
    
    $
    54
    
    $
    12
    
    $
    (235
    )
    $
    (188
    )
    $
    (167
    )Acquired
      Westport positions
    
    
    1
    
    
    1
    
    
    (123
    )
    
    (16
    )
    
    (7
    )Gas
      marketing-related derivatives
    
    
    6
    
    
    2
    
    
    (6
    )
    
    (2
    )
    
    -Foreign
      currency derivatives
    
    
    20
    
    
    -
    
    
    (6
    )
    
    -
    
    
    16Interest
      rate swaps
    
    
    4
    
    
    -
    
    
    (1
    )
    
    (2
    )
    
    -Other
    
    
    3
    
    
    -
    
    
    (1
    )
    
    -
    
    
    1Total
      derivative contracts
    
    $
    88
    
    $
    15
    
    $
    (372
    )
    $
    (208
    )
    $
    (157
    )
 
 
 December
      31, 2003Derivative
      Fair ValueCurrent
    
    Long-Term
    
    Current
    
    Long-Term
    
    Deferred
      Gain(Millions
      of dollars)
    
    Asset
    
    Asset
    
    Liability
    
    Liability
    
    (Loss)
      in AOCI(1)Oil
      and gas commodity derivatives
    
    $
    8
    
    $
    15
    
    $
    (181
    )
    $
    -
    
    $
    (105
    )Gas
      marketing-related derivatives
    
    
    8
    
    
    2
    
    
    (7
    )
    
    (2
    )
    
    -Foreign
      currency derivatives
    
    
    28
    
    
    -
    
    
    (11
    )
    
    -
    
    
    17Interest
      rate swaps
    
    
    -
    
    
    15
    
    
    -
    
    
    -
    
    
    -DECS
      call option
    
    
    -
    
    
    -
    
    
    (155
    )
    
    -
    
    
    -Total
      derivative contracts
    
    $
    44
    
    $
    32
    
    $
    (354
    )
    $
    (2
    )
    $
    (88
    )
 
 
 (1)  Amounts
deferred in accumulated other comprehensive income (AOCI) are reflected net of
tax.
 
 
  - 98 -
  The
following tables summarize the gain (loss) on the company’s derivative
instruments and its classification in the Consolidated Statement of Operations
for each of the last three years:
 
 **2004**
    
    2003
    
    2002**Other**
    
    
    
    
    
    Other
    
    
    
    
    
    Other**Costs
      and**
    
    **Income**
    
    
    
    Costs
      and
    
    Income
    
    
    
    Costs
      and
    
    Income**Revenues**
    
    **Expenses**
    
    **(Expense)**
    
    Revenues
    
    Expenses
    
    (Expense)
    
    Revenues
    
    Expenses
    
    (Expense)Hedge
      Activity:Oil
      and gas commodity derivatives
    
    **$**
    **(748**
    **)**
    **$******
    ******-**
    
    **$**
    **-**
    
    $
    (279
    )
    $
    -
    
    $
    -
    
    $
    (81
    )
    $
    -
    
    $
    -Foreign
      currency derivatives
    
    
    **(1**
    **)**
    
    **19**
    
    
    **-**
    
    
    -
    
    
    13
    
    
    -
    
    
    -
    
    
    (6
    )
    
    -Interest
      rate swaps
    
    
    **-**
    
    
    **15**
    
    
    **-**
    
    
    -
    
    
    11
    
    
    -
    
    
    -
    
    
    6
    
    
    -Other
    
    
    **-**
    
    
    **1**
    
    
    **-**
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Total
      hedging contracts
    
    
    **(749******
    ******)**
    
    **35**
    
    
    **-**
    
    
    (279
    )
    
    24
    
    
    -
    
    
    (81
    )
    
    -
    
    
    -Nonhedge
      Activity:Oil
      and gas commodity derivatives -Kerr-McGee
      positions
    
    
    **(10**
    **)**
    
    **-**
    
    
    **1**
    
    
    -
    
    
    -
    
    
    2
    
    
    -
    
    
    -
    
    
    8Acquired
      Westport positions
    
    
    **(13**
    **)**
    
    **-**
    
    
    **-**
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Gas
      marketing-related derivatives
    
    
    **7**
    
    
    **-**
    
    
    **(1**
    **)**
    
    (7
    )
    
    -
    
    
    (5
    )
    
    (20
    )
    
    -
    
    
    -DECS
      call option(1)
    
    
    **-**
    
    
    **-**
    
    
    **(101**
    **)**
    
    -
    
    
    -
    
    
    (88
    )
    
    -
    
    
    -
    
    
    (34
    )Foreign
      currency derivatives
    
    
    **-**
    
    
    **-**
    
    
    **(8******
    ******)**
    
    -
    
    
    -
    
    
    (7
    )
    
    -
    
    
    -
    
    
    1Total
      nonhedge contracts
    
    
    **(16******
    ******)**
    
    **-**
    
    
    **(109******
    ******)**
    
    (7
    )
    
    -
    
    
    (98
    )
    
    (20
    )
    
    -
    
    
    (25
    )Total
      derivative contracts
    
    **$******
    **(765******
    ******)**
    **$******
    ******35**
    
    **$**********
    ******(109******
    **********)**
    $
    (286
    )
    $
    24
    
    $
    (98
    )
    $
    (101
    )
    $
    -
    
    $
    (25
    )
 
 (1)
    As
      discussed in Note 7, other income (expense) also includes unrealized gains
      on Devon stock classified as trading.
 
 ***Oil
and Gas Commodity Derivatives*** - The
company periodically enters into financial derivative instruments that generally
fix the commodity prices to be received for a portion of its future oil and gas
production. The fair value of the company’s oil and gas commodity derivative
instruments was determined based on prices actively quoted, generally NYMEX and
Dated Brent prices. For derivative instruments designated as cash flow hedges,
gains and losses are deferred in accumulated other comprehensive income (loss)
and reclassified into earnings when the associated hedged production is sold.
The company expects to reclassify net after-tax deferred losses of $52 million
into earnings during the next 12 months (assuming no further changes in the fair
value of the related contracts). Gains and losses for hedge ineffectiveness are
recognized as a component of revenues in the Consolidated Statement of
Operations and were not material for all periods presented. Realized and
unrealized gains and losses arising from derivative instruments that have not
been designated as hedges or that do not qualify for hedge accounting (“nonhedge
derivatives”) are recognized in current earnings.
 
 Nonhedge
derivative losses represent net realized and unrealized gains and losses related
to crude oil and natural gas derivative instruments that have not been
designated as hedges or that do not qualify for hedge accounting treatment. In
the second quarter of 2004, the company entered into financial derivative
instruments in the form of fixed-price swaps and costless collars relating to
specified quantities of projected 2004-2006 production that was not already
hedged, including unhedged production from the Westport properties. Certain
crude oil and natural gas swaps covering the period from August to December 2004
were characterized initially as nonhedge derivatives since either our U.S.
production (excluding Westport volumes) was already hedged or, in the case of
Rocky Mountain production, the company did not have sufficient basis swaps in
place to ensure that the hedges would be highly effective. Consequently, the
company recognized mark-to-market losses of $10 million in earnings during the
second quarter associated with these derivatives. After the Westport merger
closed and with sufficient oil and gas production available, these swaps were
designated as hedges and, as such, realized gains and losses thereafter were
recognized in earnings when the hedged production was sold.
 
 - 99 -
 In
connection with the Westport merger, the company recognized a $196 million net
liability associated with Westport’s existing commodity derivatives at the
merger date (June 25, 2004). Some of these derivative instruments were
designated as hedges in July 2004 in connection with the redesignation of
acquisition-related derivatives described above, while others do not qualify for
hedge accounting treatment. In the second quarter of 2004, a mark-to-market gain
of $15 million was recognized in earnings since the value of the net derivative
liability had decreased to $181 million by June 30, 2004.
 
 Westport’s
derivatives in place at the merger date consisted of fixed-price oil and gas
swaps, natural gas basis swaps, and costless and three-way collars. The swaps
qualify for hedge accounting and were designated as hedges after the merger
date. Accordingly, future realized gains and losses on those derivative
instruments are reflected in earnings when the hedged production is sold.
However, the costless and three-way collars - each of which was in a liability
position - do not qualify for hedge accounting treatment under existing
accounting standards because they represent “net written options” at the merger
date. As a result, even though these collars effectively reduce commodity price
risk, the company will continue to recognize mark-to-market gains and losses in
earnings until the collars mature, rather than defer such amounts in accumulated
other comprehensive income (loss). In the second half of 2004, the company
recognized losses of $28 million associated with Westport’s collars. The net
derivative liability associated with these derivatives at year-end 2004 was $69
million.
 
 In
addition to the company's hedging program, Kerr-McGee holds certain gas basis
swaps settling between 2005 and 2008 that were acquired in the 2001 merger with
HS Resources. The company initially treated these gas basis swaps as nonhedge
derivatives, with changes in fair value recognized in earnings. In 2004, the
company designated those swaps settling in 2005 as hedges, since the basis swaps
have been coupled with natural gas fixed-price swaps, while the remainder
settling between 2006 and 2008 will continue to be treated as nonhedge
derivatives. From time to time, the company also enters into basis swaps to help
mitigate its exposure to localized natural gas indices by, in effect, converting
that exposure to NYMEX-based pricing. To the extent such basis swaps are coupled
with NYMEX natural gas fixed-price swaps, they are accounted for as hedges;
otherwise, any mark-to-market gains or losses are recognized in earnings
currently.
 
 ***Gas
Marketing-Related Derivatives*** - The
company’s marketing subsidiary, Kerr-McGee Energy Services (KMES) purchases
third-party natural gas for aggregation and sale with the company’s own
production in the Rocky Mountain area. Under some of its marketing arrangements,
KMES receives fixed prices for the sale of natural gas. Existing contracts for
the physical delivery of gas at fixed prices have not been designated as hedges
and are marked-to-market through earnings in accordance with FAS No. 133. KMES
has entered into natural gas swaps and basis swaps that largely offset its
fixed-price risk on physical contracts and lock in margins associated with
the physical sales. The gains and losses on the swaps, which also are
marked-to-market through earnings, substantially offset the gains and losses
from the fixed-price physical delivery contracts.
 
 ***Foreign
Currency Derivatives*** -  From
time to time, the company enters into forward contracts to buy and sell foreign
currencies. Certain of these contracts (purchases of Australian dollars and
British pound sterling, and sales of euro) have been designated and have
qualified as cash flow hedges of the company’s anticipated future cash flows
related to pigment sales, capital expenditures, raw material purchases and
operating costs. These forward contracts generally have durations of less than
three years. 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 the hedged forecasted pigment sales occur or operating costs are incurred,
when hedged assets are depreciated in the case of a capital expenditures hedge,
and upon the sale of finished inventory in the case of a hedged raw material
purchase). Realized gains and losses on foreign currency derivatives are
classified in the Consolidated Statement of Operations consistent with the
classification of the items being hedged. In 2005, the company expects to
reclassify from accumulated other comprehensive income (loss) into earnings net
after-tax gains of $4 million, assuming no further changes in the fair value of
the related contracts. No hedges were discontinued during 2004, and no
ineffectiveness was recognized.
 
 ***DECS*** - The
company issued 5.5% notes exchangeable for common stock (DECS) in August 1999,
which allowed each holder to receive between .85 and 1.0 share of Devon common
stock or, at the company’s option, an equivalent amount of cash at maturity in
August 2004. Embedded options in the DECS provide the company a floor price on
Devon’s common stock of $33.19 per share (the put option). The company also had
the right to retain up to 15% of the shares if Devon’s stock price was greater
than $39.16 per share (the DECS holders had an imbedded call option on 85% of
the shares). Using the Black-Scholes valuation model, the company estimated the
fair value of the put and call options and recognized gains or losses resulting
from changes in their fair value in other income (expenses) in the Consolidated
Statement of Operations, along with the changes in the market value of Devon
stock classified as trading.
 
 - 100 -
 As
discussed in Note 7, the DECS were settled through the distribution of shares of
Devon stock on August
2, 2004.
 
 ***Interest
Rate Derivatives*** - In
connection with the issuance of $350 million of 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%. 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, were
converted to pay a variable rate of LIBOR plus 3.35%; $109 million of
8.125% notes due October 15, 2005, were converted to pay a variable rate of
LIBOR plus 5.86%; and $307 million of 5.875% notes due September 15, 2006, were
converted to pay a variable rate of LIBOR plus 3.1%. The company considers these
swaps to be hedges against the change in fair value of the related debt as a
result of interest rate changes. The swaps are carried in the Consolidated
Balance Sheet at their estimated fair value. Any unrealized gain or loss on the
swaps is offset by a comparable gain or loss resulting from recording
changes in the fair value of the related debt. Gains and losses on interest
rate swaps, along with the changes in the fair value of the related debt, are
reflected in interest and debt expense in the Consolidated Statement of
Operations. The critical terms of the swaps match the terms of the debt;
therefore, the swaps are considered highly effective and no hedge
ineffectiveness has been recognized.
 
 
 12.  **Accrued
Liabilities**
 
 Accrued
liabilities at December 31, 2004 and 2003 are as follows:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003Accrued
      operating expenses and explorationand
      development costs
    
    **$**
    **318**
    
    $
    260Employee-related
      costs and benefits
    
    
    **156**
    
    
    141Reserves
      for environmental remediation and restoration
    
    
    **97**
    
    
    98Interest
      payable
    
    
    **97**
    
    
    109Taxes,
      other than income taxes
    
    
    **75**
    
    
    37Current
      asset retirement obligations
    
    
    **21**
    
    
    20Other
    
    
    **61**
    
    
    37Total
    
    **$**
    **825**
    
    $
    702
 
 
 13.  **Work
Force Reduction,**  **Restructuring
Provisions and Exit Activities**
 
 The
following table presents a reconciliation of the beginning and ending balances
of reserves for exit and restructuring activities for 2004 and 2003, with
discussion of material components of the activity provided below.
 
 **2004**
    
    2003**Dismantlement**
    
    
    
    
    
    Dismantlement**Personnel**
    
    **and**
    
    
    
    Personnel
    
    and(Millions
      of dollars)
    
    **Total**
    
    **Costs**
    
    **Closure**
    
    Total
    
    Costs
    
    ClosureBeginning
      balance
    
    **$**
    **39**
    
    **$**
    **27**
    
    **$**
    **12**
    
    $
    27
    
    $
    4
    
    $
    23Westport
      severance/relocation
    
    
    **19**
    
    
    **19**
    
    
    **-**
    
    
    -
    
    
    -
    
    
    -Provisions
    
    
    **7**
    
    
    **4**
    
    
    **3**
    
    
    37
    
    
    37
    
    
    -Payments
    
    
    **(46**
    **)**
    
    **(40**
    **)**
    
    **(6**
    **)**
    
    (22
    )
    
    (16
    )
    
    (6
    )Adjustments(1)
    
    
    **(1******
    ******)**
    
    **(2******
    ******)**
    
    **1**
    
    
    (3
    )
    
    2
    
    
    (5
    )Ending
      balance
    
    **$**
    **18**
    
    **$**
    **8**
    
    **$**
    **10**
    
    $
    39
    
    $
    27
    
    $
    12
 
 (1)
    Includes
      foreign-currency translation adjustments related to the Antwerp, Belgium
      accrual.
 
  - 101 -
  In
September 2004, the company shut down sulfate and gypsum production at its
Savannah, Georgia facility. In 2004, the company recognized a pretax charge of
$105 million for costs associated with the shutdown. Of the total, $68 million
represented accelerated depreciation of plant assets (of which $13 million
related to an asset retirement obligation recognized during the third quarter of
2004), $15 million for inventory revaluation, $8 million for impairment of
intangible assets, $7 million for severance and benefit plan curtailment costs,
and $7 million for other closure costs. Severance cost of $2 million was paid
during 2004 and $2 million remained in the reserve at the end of the year. See
Note 16 for additional discussion regarding the asset retirement obligation. The
shutdown will result in the elimination of approximately 100 positions, the last
of which will occur in early 2005. In addition, an $18 million charge was
recognized in the third quarter of 2004 for accelerated depreciation of other
plant assets at the Savannah facility that are no longer in service. The
company’s 2004 Consolidated Statement of Operations includes $86 million in
depreciation and depletion expense, $29 million in costs and operating expenses
and $8 million in asset impairments, for total pretax charges of $123 million
associated with the Savannah facility.
 
 In
connection with the Westport merger discussed in Note 2, the company recognized
liabilities of $19 million associated with severance and relocation costs for
certain former Westport employees. Affected employees, including those
remaining for transitional purposes, will be terminated no later than June 2006.
Of the $19 million, approximately $18 million has been paid through year-end
2004, with about $1 million remaining in the reserve at December 31,
2004.
 
 In
September 2003, the company announced a program to reduce its U.S. nonbargaining
work force through both voluntary retirements and involuntary terminations. As a
result of the program, the company’s eligible U.S. nonbargaining work force was
reduced by approximately 9%, or 271 employees. Qualifying employees terminated
under this program were eligible for enhanced benefits under the company's
pension and postretirement plans, along with severance payments. The program was
substantially complete by the end of 2003, with certain retiring employees
staying into 2004 for transition purposes. In connection with the work force
reduction, the company incurred a pretax charge of $56 million in 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.
Of the severance-related provision of $22 million, $21 million was paid and the
program was completed by the end of 2004. The remaining reserve balance of $1
million, representing an excess of estimated provisions over actual costs, was
reversed in the fourth quarter of 2004.
 
 During
2003, the company’s chemical - pigment operating unit provided $61 million
pretax for costs associated with the closure of its synthetic rutile plant in
Mobile, Alabama. Included in the $61 million were $14 million for the cumulative
effect of change in accounting principle related to the recognition of an asset
retirement obligation, $15 million for accelerated depreciation, $15 million for
other closure costs, $11 million for severance benefits and $6 million for
benefit plan curtailment costs. Additionally, in 2004, $7 million was provided
by the company for additional costs associated with the plant closure, of which
$4 million relates to accelerated depreciation of additional asset retirement
costs and $1 million to environmental remediation costs. See Note 16 for a
discussion of the related asset retirement obligation. The reserve balance
related to this plant closure was $2 million at the end of 2004 and 2003.
Approximately 127 employees will ultimately be terminated in connection with
this plant closure, of which 111 had been terminated as of December 31, 2004.
Payments are expected to continue through the end of 2007.
 
 During
2002, the company's chemical - other operating unit provided $17 million for
costs associated with exiting its forest products business. Additional
provisions of $5 million and $2 million were recorded in 2003 and 2004,
respectively, for a total of $24 million over the three-year period. Of this
amount, $18 million was provided for dismantlement and closure costs, and $6
million for severance costs. Through December 31, 2004, $17 million had been
paid, with $7 million remaining in the reserve at year-end. Payments related to
the plant closures are expected to continue for several years in connection with
dismantlement and cleanup efforts; however, all of the severance costs are
expected to be paid by the end of March 2005. The company operated its fifth
plant, a leased facility located in The Dalles, Oregon, through December 2004.
In January 2005, the assets located at The Dalles were sold. In connection with
the plant closures, approximately 235 employees will be terminated, of which 216
were terminated as of year-end 2004. In addition to the provisions for
severance, dismantlement and closure, the company recognized $9 million in 2003
and $8 million in 2004 for other costs associated with the shutdown. The 2003
costs included accelerated depreciation on plant assets, curtailment costs and
special termination benefits related to pension and postretirement plans, while
2004 costs represented operating costs during the shutdown period. As discussed
in Note 25, in the fourth quarter of 2004, criteria for presenting results
of operations of the forest products business as discontinued operations have
been met. Therefore, the provisions for plant closures discussed above are
included in income (loss) from discontinued operations for all periods
presented.
 
 - 102 -
 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 remained in the restructuring accrual
at the end of both 2004 and 2003. As a result of this plant closure, 121
employees have been terminated as of December 31, 2004. Payments related to
severance are expected to continue until early 2016. Payments related to other
shutdown costs could extend into 2017.
 
 14.  **Debt**
 
 **Lines
of Credit**
 
 In
November 2004, the company entered into a $1.5 billion unsecured revolving
credit agreement with a term of five years. Concurrent with this transaction,
the company terminated two revolving credit facilities with an aggregate maximum
availability of $1.35 billion. Interest on borrowings under the new revolving
credit facility may be based, at the company’s option, on LIBOR, EURIBOR or on
the JPMorgan prime rate. The interest rate margin varies based on the company’s
debt rating and facility utilization.
 
 At
year-end 2004, the company had maximum available capacity under the revolving
credit facility and bank lines of credit of $1.55 billion.
 
 The
company has arrangements to maintain compensating balances with certain banks
that provide credit. At year-end 2004, the aggregate amount of such compensating
balances was not material, and the company was not legally restricted from
withdrawing all or a portion of such balances at any time during the
year.
 
 **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 2004 and 2003, debt
totaling $41 million and nil, respectively, was classified as long-term
consistent with this policy.
 
 In
connection with the Westport merger in June 2004, the company assumed $1 billion
of debt, all of which was subsequently repaid. See further discussion in Note
2.
 
  - 103 -
  Long-term
debt consisted of the following at December 31, 2004 and 2003:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003Debentures
      -5.25%
      Convertible subordinated debentures due February 15, 2010(convertible
      at $61.08 per share, subject to certain adjustments)(1)
    
    **$**
    **600**
    
    $
    6007%
      Debentures due November 1, 2011, net of unamortized debtdiscount
      of $77 in 2004 and $84 in 2003 (14.25% effective rate)
    
    
    **173**
    
    
    1667.125%
      Debentures due October 15, 2027 (7.01% effective rate)
    
    
    **150**
    
    
    150Notes
      payable -Floating
      rate notes due June 28, 2004 (1.92% average interest rateat
      December 31, 2003)
    
    
    **-**
    
    
    1008.375%
      Notes due July 15, 2004
    
    
    **-**
    
    
    1455.5%
      Exchangeable Notes (DECS) due August 2, 2004, net of
      unamortizeddebt
      discount of $4 in 2003 (5.60% effective rate) (See Note 7)
    
    
    **-**
    
    
    3265.375%
      Notes due April 15, 2005 (includes a premium of $4 in 2004for
      fair value hedge adjustment)
    
    
    **354**
    
    
    3508.125%
      Notes due October 15, 2005 (net of discount of $1 in 2004for
      fair value hedge adjustment)
    
    
    **108**
    
    
    1095.875%
      Notes due September 15, 2006 (5.89% effective rate)
    
    
    **307**
    
    
    3076.625%
      Notes due October 15, 2007 (net of discount of $2 in 2004for
      fair value hedge adjustment)
    
    
    **148**
    
    
    1506.875%
      Notes due September 15, 2011, net of unamortized debtdiscount
      of $1 in both 2004 and 2003 (6.90% effective rate)
    
    
    **674**
    
    
    6746.95%
      Notes due July 1, 2024, net of unamortized debt discount of
    $5(7.02%
      effective rate)
    
    
    **645**
    
    
    -7.875%
      Notes due September 15, 2031, net of unamortized debtdiscount
      of $2 in both 2004 and 2003 (7.91% effective rate)
    
    
    **498**
    
    
    498Commercial
      paper (2.7% average effective interest rate at December 31,
      2004)
    
    
    **41**
    
    
    -Guaranteed
      Debt of Employee Stock Ownership Plan 9.61%Notesdue
      in installments through January 2, 2005
    
    
    **1**
    
    
    5Gunnison
      Trust floating rate notes due November 8, 2006(1.93%
      average interest rate at December 31, 2003)
    
    
    **-**
    
    
    75**3,699**
    
    
    3,655Long-term
      debt due within one year
    
    
    **(463******
    ******)**
    
    (574
    )Total
    
    **$**
    **3,236**
    
    $
    3,081
 
 
 Future
maturities of long-term debt as of December 31, 2004, are as
follows:
  There-(Millions
      of dollars)
    
    2005
    
    2006
    
    2007
    
    2008
    
    2009
    
    after(1)
    
    Total
    (2)Long-term
      debt
    
    $
    463
    
    $
    307
    
    $
    148
    
    $
    -
    
    $
    41
    
    $
    2,740
    
    $
    3,699
 
 (1)
    As
      discussed in Note 35, in March 2005 all of the 5.25% debentures were
      converted by the holders into 9.8 million shares of common
      stock.
 
 (2)
    These
      amounts are inclusive of the unamortized discount on issuance of $85
      million and the net fair value hedge adjustments of $(1)
      million.
 
  - 104 -
  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 maximum total debt to total capitalization ratio, as
defined in the agreements, of 65%. At December 31, 2004, the company had a total
debt to capitalization ratio of 41% and was in compliance with its other debt
covenants. 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 was 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.
 
 The
company adopted provisions of the FASB Interpretation No. 46, “Consolidation of
Variable Interest Entities” (FIN No. 46) effective December 31, 2003. Both the
Gunnison Trust and the new operating lease trust are considered variable
interest entities under the provisions of FIN No. 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 was considered the primary
beneficiary of the Gunnison Trust at December 31, 2003. Accordingly, the
remaining assets and liabilities of the Gunnison Trust were reflected in the
company’s Consolidated Balance Sheet at December 31, 2003, which included $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 were secured by the platform assets of $83
million included in property, plant and equipment 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 was 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 was no longer subject to consolidation. As a result, the
related property and debt is not reflected in the company’s Consolidated Balance
Sheet at December 31, 2004. The operating lease commitment is discussed in Note
20.
 
   - 105 -
  15.  **Income
Taxes**
 
 The
2004, 2003 and 2002 income tax provisions (benefits) from continuing operations
are summarized below:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002U.S.
      Federal -Current
    
    **$**
    **26**
    
    $
    23
    
    $
    13Deferred
    
    
    **83**
    
    
    11
    
    
    (94
    )**109**
    
    
    34
    
    
    (81
    )International
      -Current
    
    
    **123**
    
    
    58
    
    
    36Deferred
    
    
    **21**
    
    
    100
    
    
    10**144**
    
    
    158
    
    
    46State
    
    
    **3**
    
    
    3
    
    
    -Total
    
    **$**
    **256**
    
    $
    195
    
    $
    (35
    )
 
 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.
 
 **2004**
    
    2003
    
    2002U.S.
      statutory rate - provision (benefit)
    
    
    **35.0**
    **%**
    
    35.0
    %
    
    (35.0
    )%Increases
      (decreases) resulting from -Adjustment
      of deferred tax balances dueto
      tax rate changes
    
    
    **(.6**
    **)**
    
    -
    
    
    19.9Taxation
      of foreign operations
    
    
    **4.8**
    
    
    8.6
    
    
    12.1Federal
      income tax credits
    
    
    **-**
    
    
    -
    
    
    (1.8
    )State
      income taxes
    
    
    **.3**
    
    
    .5
    
    
    -Other
      - net
    
    
    **(1.3******
    ******)**
    
    (1.6
    )
    
    (.8
    )Total
    
    
    **38.2******
    ******%**
    
    42.5
    %
    
    (5.6
    )%
 
 Net
deferred tax liabilities at December 31, 2004 and 2003, are comprised of the
following:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003Deferred
      tax liabilities -Property,
      plant and equipment
    
    **$**
    **2,444**
    
    $
    1,587Investments
    
    
    **-**
    
    
    170Undistributed
      earnings of certain foreign subsidiaries
    
    
    **28**
    
    
    28Deferred
      state, local and other taxes
    
    
    **23**
    
    
    24Intangible
      assets
    
    
    **31**
    
    
    12Other
    
    
    **52**
    
    
    92Total
      deferred tax liabilities
    
    
    **2,578**
    
    
    1,913Deferred
      tax assets -Net
      operating loss and other carryforwards
    
    
    **(209**
    **)**
    
    (206
    )Derivative
      instruments
    
    
    **(107**
    **)**
    
    (88
    )Asset
      retirement and environmental obligations
    
    
    **(224**
    **)**
    
    (192
    )Foreign
      exploration expenses
    
    
    **(83**
    **)**
    
    (63
    )Obligations
      for pension and other benefits
    
    
    **(28**
    **)**
    
    (43
    )Financial
      accruals and deferrals
    
    
    **(59**
    **)**
    
    (59
    )Other
    
    
    **(23**
    ******)**
    
    (12
    )**(733**
    **)**
    
    (663
    )Valuation
      allowance associated with loss carryforwards
    
    
    **8**
    
    
    9Net
      deferred tax assets
    
    
    **(725**
    ******)**
    
    (654
    )Net
      deferred tax liability
    
    **$**
    **1,853**
    
    $
    1,259
 
 - 106 -
 Taxation
for a company with operations in several foreign countries involves many complex
variables, such as tax structures that differ from country to country and the
effect on U.S. taxation of international earnings. These complexities do not
permit meaningful comparisons between the U.S. and international components of
income before income taxes and the provision for income taxes, and disclosures
of these components do not necessarily provide reliable indicators of
relationships in future periods. Income (loss) from continuing operations before
income taxes is comprised of the following:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002United
      States
    
    **$**
    **339**
    
    $
    161
    
    $
    (84
    )International
    
    
    **332**
    
    
    298
    
    
    (541
    )Total
    
    **$**
    **671**
    
    $
    459
    
    $
    (625
    )
 
 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, 2004, the company had foreign operating loss carryforwards totaling
$351 million. Of this amount, $13 million expires in 2006, $1 million in 2007,
$106 million in 2009 and $231 million has no expiration date. Realization of
these operating loss carryforwards depends on generating sufficient taxable
income in future periods. A valuation allowance of $8 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 $891 million at
December 31, 2004. No provision for deferred U.S. income taxes has been made for
these earnings because they are considered to be indefinitely invested outside
the United States. The distribution of these earnings in the form of dividends
or otherwise, may subject the company to U.S. income taxes and, possibly,
foreign withholding taxes. However, because of the complexities of U.S. taxation
of foreign earnings, it is not practicable to estimate the amount of additional
tax that might be payable on the eventual remittance of these
earnings.
 
 On
October 22, 2004, the President of the United States signed the American Jobs
Creation Act of 2004 (the “Act”) into law. A provision of the Act includes a
deduction of 85% of certain foreign earnings that are repatriated, as defined in
the Act. We may elect to apply this provision to qualifying earnings repatriated
during the reporting period ending December 31, 2005. We are currently
evaluating the potential impact of this legislation, including assessing the
details of the Act and analyzing the funds available for repatriation. However,
given the preliminary status of the evaluation, we do not expect to be able to
complete the analysis until after Congress or the Department of the Treasury
provides additional clarifying language. Currently, the range of possible
amounts that we are considering for repatriation under this provision is between
zero and $500 million. The related potential range of income and foreign
withholding tax for such repatriation is between zero and $29
million.
 
 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 1996 have been closed with the exception of issues for which a refund
claim has been filed. The Oryx Energy Company income tax returns have been
examined through 1997, and the years through 1978 have been closed, as have the
years 1988 through 1997. Oryx and Kerr-McGee merged in 1999. The company
believes that it has made adequate provision for income taxes that may be
payable with respect to open years.
 
  - 107 -
  16.  **Asset
Retirement Obligations**
 
 As
discussed in Note 1, the company adopted FAS No. 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 standard. If the provisions of FAS No. 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.
 
 A
summary of the changes in the abandonment liability during 2004 and 2003 is
included in the table below.
 
 (Millions
      of dollars)
    
    **2004**
    
    2003Balance,
      January 1
    
    **$**
    **421**
    
    $
    395New
      obligations incurred
    
    
    **30**
    
    
    11Liability
      assumed in the Westport merger
    
    
    **79**
    
    
    -Accretion
      expense
    
    
    **30**
    
    
    25Changes
      in estimates, including timing
    
    
    **(16**
    **)**
    
    22Abandonment
      expenditures
    
    
    **(17**
    **)**
    
    (17
    )Abandonment
      obligations settled through property divestitures
    
    
    **(3******
    ******)**
    
    (15
    )Balance,
      December 31
    
    
    **524**
    
    
    421Less:
      current asset retirement obligation
    
    
    **(21**
    **)**
    
    (20
    )Less:
      asset retirement obligation classified as held for
disposal
    
    
    **-**
    
    
    (16
    )Noncurrent
      asset retirement obligation
    
    **$**
    **503**
    
    $
    385
 
 
 As
discussed in Note 13, the company closed its synthetic rutile plant in Mobile,
Alabama, in 2003. In September 2004, the company shut down sulfate and gypsum
production at its Savannah, Georgia, plant. Until the decisions to shut down
these facilities had been made, it was indeterminable when the asset
retirement liability associated with these facilities would be settled.
 Upon deciding to shut down the facilities, the timing of settlement
became estimable and the related asset retirement obligation was recorded at the
estimated fair value. For the synthetic rutile plant in Mobile, Alabama, an $18
million liability was recognized at the beginning of 2003.  For the
sulfate production facility at the company's Savannah, Georgia, plant, an
abandonment liability of $13 million was recognized in September
2004.
 
 Operations at the
Mobile, Alabama, facility included production of feedstock
for titanium dioxide pigment plants of the company's chemical business. The
facility ceased operations in June 2003.  Operations prior to closure had
resulted in minor contamination of groundwater adjacent to surface impoundments.
A groundwater recovery system was installed prior to closure and continues in
operation as required under the National Pollutant Discharge
Elimination System (NPDES) permit. Future remediation work, including
groundwater recovery, closure of the impoundments and other minor work, is
expected to be substantially completed in about five years. As of December 31,
2004, the company had a remaining abandonment reserve of $11 million.
Although actual costs may exceed current estimates, the amount of any increases
cannot be reasonably estimated at this time.
 
 An
abandonment reserve related to the titanium dioxide pigment sulfate
production at Savannah, Georgia, was established to address probable remediation
activities, including environmental assessment, closure of certain impoundments,
groundwater monitoring, asbestos abatement, and other work, which are expected
to take over 25 years. As of December 31, 2004, the reserve remained at about
$13 million. Although actual costs may exceed current estimates, the amount of
any increase cannot be reasonably estimated at this time.
 
 
  - 108 -
  17.  **Noncurrent
Liabilities - Other**
 
 Other
noncurrent liabilities consist of the following at year-end 2004 and
2003:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003Postretirement
      benefit obligations
    
    **$**
    **209**
    
    $
    215Reserves
      for environmental remediation and restoration
    
    
    **158**
    
    
    152Pension
      plan liabilities
    
    
    **47**
    
    
    73Litigation
      reserves
    
    
    **24**
    
    
    32Accrued
      rent for spar operating leases
    
    
    **46**
    
    
    32Ad
      valorem taxes
    
    
    **33**
    
    
    31Other
    
    
    **54**
    
    
    28Total
    
    **$**
    **571**
    
    $
    563
 
 
 18.  **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 2004,
the company recognized a curtailment loss and special termination benefits
associated with the shutdown of sulfate production at the Savannah, Georgia,
facility. Also in 2004, the company recognized losses on settlement of certain
qualified and nonqualified benefits as a result of cash settlements associated
with normal retirements and retirements resulting from the 2003 work force
reduction program. In 2003, the company recognized a curtailment loss with
respect to pension and postretirement benefits in connection with its work force
reduction program and 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 Medicare Prescription Drug, Improvement and Modernization Act
of 2003 (the Act) was signed into law. The Act expands Medicare to include, for
the first time, coverage for prescription drugs. The Act also introduces a
federal subsidy to sponsors of retiree health care benefit plans that provide a
benefit that is at least actuarially equivalent to Medicare Part D. In May 2004,
the FASB issued Staff Position (FSP) FAS 106-2, “Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003,” to provide guidance on accounting for the effects of
the Act. Kerr-McGee adopted FSP FAS 106-2 in the third quarter of 2004 and, as a
result, the company's accumulated postretirement benefit obligation as of
July 1, 2004, the date of remeasurement, was reduced by $46 million and the
third quarter 2004 net periodic postretirement cost was reduced by
approximately $2 million. This reduction is reflected as an actuarial gain and
is not treated as a change in plan provisions.
 
 On
November 1, 2004, the company announced that the prescription drug coverage
provided by its U.S. postretirement benefit plan will become secondary to
Medicare Part D effective January 1, 2006, causing the plan to no longer qualify
for the federal subsidy. As a result of the plan change, the company’s
accumulated postretirement benefit obligation (remeasured as of November 1,
2004) was further reduced by $30 million.  The combined
impact of the FSP FAS 106-2 adoption and the plan change
on fourth quarter 2004 net periodic postretirement cost was a
reduction of expense of approximately $2 million.
 
 On
January 21, 2005, the centers for Medicare and Medicaid Services (CMS) released
the final regulations (the Regulations) implementing the Act. Generally, the
regulations are expected to cause more retiree health programs to meet the Act’s
actuarial equivalence standard. Together with our actuarial advisor, Kerr-McGee
determined our plan’s actuarial equivalence in mid-2004 and, as previously
mentioned, adopted FSP FAS 106-2 in the third quarter of 2004. Based on review
of the final regulations, the company and its actuary believe that the impact on
the accumulated benefit obligation and the net periodic cost recognized in 2004
is not material.
 
  - 109 -
  Following
are the changes in the benefit obligations during the past two
years:
 
 PostretirementRetirement
      Plans
    
    Health
      and Life Plans(Millions
      of dollars)
    
    **2004**
    
    2003
    
    **2004**
    
    2003Benefit
      obligation, beginning of year
    
    **$**
    **1,250**
    
    $
    1,147
    
    **$**
    **314**
    
    $
    327Service
      cost
    
    
    **30**
    
    
    25
    
    
    **3**
    
    
    3Interest
      cost
    
    
    **73**
    
    
    74
    
    
    **18**
    
    
    17Plan
      amendments/law changes
    
    
    **1**
    
    
    (3
    )
    
    **(72**
    **)**
    
    10Net
      actuarial loss (gain)
    
    
    **90**
    
    
    84
    
    
    **38**
    
    
    (28
    )Foreign
      exchange rate changes
    
    
    **12**
    
    
    17
    
    
    **-**
    
    
    -Contributions
      by plan participants
    
    
    **-**
    
    
    -
    
    
    **9**
    
    
    9Special
      termination benefits, settlementand
      curtailment (gains) losses
    
    
    **(1**
    **)**
    
    28
    
    
    **-**
    
    
    9Benefits
      paid
    
    
    **(195******
    ******)**
    
    (122
    )
    
    **(34******
    ******)**
    
    (33
    )Benefit
      obligation, end of year
    
    **$**
    **1,260**
    
    $
    1,250
    
    **$**
    **276**
    
    $
    314
 
 Following
are the expected benefit payments for the next five years and in the aggregate
for the years 2010 through 2014:
 
 
 2010-(Millions
      of dollars)
    
    2005
    
    2006
    
    2007
    
    2008
    
    2009
    
    2014Retirement
      Plans
    
    $
    109
    
    $
    89
    
    $
    100
    
    $
    92
    
    $
    95
    
    $
    537Postretirement
      Health and Life Plans
    
    
    24
    
    
    18
    
    
    19
    
    
    19
    
    
    19
    
    
    94
 
 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 nonqualified plans designed to maintain benefits for all employees
at the plan formula level and to provide senior executives with benefits equal
to a specified percentage of their final average compensation.
 
 The
following table summarizes the accumulated benefit obligations and the projected
benefit obligations associated with the company's unfunded benefit
plans.
 
 **At
      December 31, 2004**
    
    At
      December 31, 2003U.S.
    
    U.S.
    
    Germany
    
    U.S.
    
    U.S.
    
    GermanyNonqualified
    
    Postretirement
    
    Retirement
    
    Nonqualified
    
    Postretirement
    
    Retirement(Millions
      of dollars)
    
    Plans
      (1)
    
    Plan
    
    Plan
    
    Plans
      (1)
    
    Plan
    
    PlanAccumulated
      benefit obligation
    
    **$**
    **37**
    
    **$**
    **276**
    
    **$**
    **12**
    
    $
    41
    
    $
    314
    
    $
    10Projected
      benefit obligation
    
    
    **55**
    
    
    **276**
    
    
    **13**
    
    
    50
    
    
    314
    
    
    10
 
 (1)
    Although
      not considered plan assets, a grantor trust was established from which
      payments for certain U.S. supplemental benefits are made. The trust assets
      had a balance of $50 million at year-end 2004 and $37 million at year-end
      2003.
 
  - 110 -
  Summarized
below are the accumulated benefit obligation, the projected benefit obligation,
the market value of plan assets and the funded status of the company's funded
retirement plans.
 
 **At
      December 31, 2004**
    
    At
      December 31, 2003U.S.
    
    The
      Netherlands
    
    U.K.
    
    U.S.
    
    The
      Netherlands
    
    U.K.Qualified
    
    Retirement
    
    Retirement
    
    Qualified
    
    Retirement
    
    Retirement(Millions
      of dollars)
    
    Plan
    
    Plan
    
    Plan
    
    Plan
    
    Plan
    
    PlanAccumulated
      benefit obligation
    
    **$**
    **941**
    
    **$**
    **61**
    
    **$**
    **73**
    
    $
    984
    
    $
    49
    
    $
    63Projected
      benefit obligation
    
    **$**
    **1,034**
    
    **$**
    **70**
    
    **$**
    **88**
    
    $
    1,063
    
    $
    53
    
    $
    75Market
      value of plan assets
    
    
    **1,109**
    
    
    **59**
    
    
    **79**
    
    
    1,188
    
    
    51
    
    
    44Funded
      status
    
    **$**
    **75**
    
    **$******
    **(11******
    ******)**
    **$******
    **(9******
    ******)**
    $
    125
    
    $
    (2
    )
    $
    (31
    )
 
 
 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, 2004 and 2003:
 PostretirementRetirement
      Plans
    
    Health
      and Life Plans(Millions
      of dollars)
    
    **2004**
    
    2003
    
    **2004**
    
    2003Fair
      value of plan assets, beginning of year
    
    **$**
    **1,283**
    
    $
    1,190
    
    **$**
    **-**
    
    $
    -Actual
      return on plan assets
    
    
    **107**
    
    
    198
    
    
    **-**
    
    
    -Employer
      contributions(1)
    
    
    **42**
    
    
    5
    
    
    **25**
    
    
    24Participant
      contributions
    
    
    **-**
    
    
    -
    
    
    **9**
    
    
    9Foreign
      exchange rate changes
    
    
    **10**
    
    
    12
    
    
    **-**
    
    
    -Benefits
      paid
    
    
    **(195******
    ******)**
    
    (122
    )
    
    **(34******
    ******)**
    
    (33
    )Fair
      value of plan assets, end of year(2)
    
    
    **1,247**
    
    
    1,283
    
    
    **-**
    
    
    -Benefit
      obligation
    
    
    **(1,260******
    ******)**
    
    (1,250
    )
    
    **(276******
    ******)**
    
    (314
    )Funded
      status of plans - over (under)
    
    
    **(13**
    **)**
    
    33
    
    
    **(276**
    **)**
    
    (314
    )Amounts
      not recognized in theConsolidated
      Balance Sheet -Prior
      service costs
    
    
    **49**
    
    
    58
    
    
    **(16**
    **)**
    
    12Net
      actuarial loss
    
    
    **193**
    
    
    106
    
    
    **59**
    
    
    68Prepaid
      expense (accrued liability)
    
    **$**
    **229**
    
    $
    197
    
    **$******
    **(233******
    ******)**
    $
    (234
    )Accumulated
      benefit obligation
    
    **$******
    **(1,124******
    ******)**
    $
    (1,147
    )
 
 (1)
    During
      2004, the company made a discretionary contribution of approximately $26
      million to the U.K. trust fund to increase plan assets above the
      accumulated benefit obligation level. The company expects to contribute $4
      million to its U.S. nonqualified plans, $24 million to its U.S.
      postretirement plan and approximately $6 million to its foreign retirement
      plans in 2005. No contributions are expected in 2005 for the U.S.
      qualified retirement plan.
 
 (2)
    Excludes
      the grantor trust assets of $50 million and $37 million at year-end 2004
      and 2003, respectively, associated with the company’s supplemental
      nonqualified U.S. plans.
 
 
 Following
is the classification of the amounts recognized in the Consolidated Balance
Sheet at December 31, 2004 and 2003:
 PostretirementRetirement
      Plans
    
    Health
      and Life Plans(Millions
      of dollars)
    
    **2004**
    
    2003
    
    **2004**
    
    2003Prepaid
      pension cost
    
    **$**
    **262**
    
    $
    230
    
    **$**
    **-**
    
    $
    -Accrued
      benefit liability
    
    
    **(55**
    **)**
    
    (72
    )
    
    **(233**
    **)**
    
    (234
    )Additional
      minimum liability - intangible asset
    
    
    **-**
    
    
    1
    
    
    **-**
    
    
    -Accumulated
      other comprehensiveincome
      (before tax)
    
    
    **20**
    
    
    38
    
    
    **-**
    
    
    -Total
    
    **$**
    **227**
    
    $
    197
    
    **$******
    **(233******
    ******)**
    $
    (234
    )
 
 - 111 -
 For
2004, 2003 and 2002, the company had after-tax gains (losses) of $11 million,
$(7) million and $(14) 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 last three years, were as follows:
 
 PostretirementRetirement
      Plans
    
    Health
      and Life Plans**2004**
    
    2003
    
    2002
    
    **2004**
    
    2003
    
    2002Net
      periodic cost -Service
      cost
    
    **$**
    **30**
    
    $
    25
    
    $
    24
    
    **$**
    **3**
    
    $
    3
    
    $
    3Interest
      cost
    
    
    **73**
    
    
    73
    
    
    76
    
    
    **18**
    
    
    17
    
    
    19Expected
      return on plan assets
    
    
    **(116**
    **)**
    
    (122
    )
    
    (130
    )
    
    **-**
    
    
    -
    
    
    -Special
      termination benefits, settlementand
      curtailment losses(1)
    
    
    **14**
    
    
    38
    
    
    -
    
    
    **-**
    
    
    10
    
    
    -Net
      amortization -Prior
      service cost
    
    
    **8**
    
    
    9
    
    
    10
    
    
    **1**
    
    
    -
    
    
    1Net
      actuarial (gain) loss
    
    
    **3**
    
    
    (9
    )
    
    (16
    )
    
    **2**
    
    
    -
    
    
    1Total
    
    **$**
    **12**
    
    $
    14
    
    $
    (36
    )
    **$**
    **24**
    
    $
    30
    
    $
    24
 
 (1)
    2004
      net periodic pension cost included special termination benefit and
      curtailment costs associated with the shutdown of sulfate production at
      the Savannah, Georgia, facility and plan settlement losses related to
      normal retirements and retirements resulting from the 2003 work force
      reduction program. The 2003 period includes special termination benefit
      and curtailment costs associated with the shutdown of the forest products
      operations and the Mobile, Alabama facility and curtailment costs
      associated with the 2003 work force reduction
program.
 
 The
following assumptions were used in estimating the net periodic
expense:
 
 **2004**
    
    2003
    
    2002**United**
    
    
    
    
    
    United
    
    
    
    United**States**
    
    
    
    **International**
    
    States
    
    International
    
    States
    
    InternationalDiscount
      rate
    
    
    **6.25**
    **%**
    
    **(1**
    **)**
    
    **5.25
      - 5.5**
    **%**
    
    6.75
    %
    
    5.5
      - 5.75
    %
    
    7.25
    %
    
    5.75
    %Expected
      return onplan
      assets
    
    
    **8.5**
    
    
    
    
    
    **5.75
      - 7.25**
    
    
    8.5
    
    
    5.25
      - 7.25
    
    
    9.0
    
    
    5.75
      - 7.0Rate
      of compensationincreases
    
    
    **4.5**
    
    
    
    
    
    **2.75
      - 5.0**
    
    
    4.5
    
    
    2.5
      - 6.5
    
    
    5.0
    
    
    2.5
      - 7.5
  (1)
    Following
      remeasurement at July 1, 2004 to recognize a settlement for the qualified
      plan, the discount rate for the qualified plan was 6.5% for the remainder
      of the year.
 
 The
following assumptions were used in estimating the actuarial present value of the
plans' benefit obligations:
 
 **2004**
    
    2003
    
    2002**United**
    
    
    
    United
    
    
    
    United**States**
    
    **International**
    
    States
    
    International
    
    States
    
    InternationalDiscount
      rate
    
    
    **5.75**
    **%**
    
    **4.75
      - 5.25**
    **%**
    
    6.25
    %
    
    5.25
      - 5.5
    %
    
    6.75
    %
    
    5.5
      - 5.75
    %Rate
      of compensationincreases
    
    
    **4.5**
    
    
    **3.0
      - 4.75**
    
    
    4.5
    
    
    2.75
      - 5.0
    
    
    4.5
    
    
    2.5
      - 6.5
 
  - 112 -
  The
health care cost trend rates used to determine the year-end 2004 postretirement
benefit obligation were 10% in 2005, gradually declining to 5% in the year 2010
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, 2004, by $14 million and increase the aggregate of the service and
interest cost components of the net periodic postretirement expense for 2004 by
$1 million. A 1% decrease in the trend rate for each future year would reduce
the benefit obligation at year-end 2004 by $15 million and decrease the
aggregate of the service and interest cost components of the net periodic
postretirement expense for 2004 by $1 million.
 
 Asset
categories for the company’s U.S. and foreign funded retirement plans and the
weighted-average asset allocations at December 31, 2004 and 2003, by asset
category are as follows:
 
 
 
 U.S.
      Plan Assets
    
    Foreign
      Plan Assetsat
      December 31,
    
    at
      December 31,**2004**
    
    2003
    
    **2004**
    
    2003Equity
      securities
    
    
    **57**
    **%**
    
    55
    %
    
    **50**
    **%**
    
    42
    %Debt
      securities
    
    
    **41**
    **%**
    
    41
    %
    
    **46**
    **%**
    
    57
    %Cash
    
    
    **2**
    **%**
    
    4
    %
    
    **4**
    **%**
    
    1
    %Total
    
    
    **100**
    **%**
    
    100
    %
    
    **100**
    **%**
    
    100
    %
 
 In
forming the assumption of the U.S. long-term rate of return, the company takes
into account the expected earnings on funds already invested, earnings on
contributions expected to be received in the current year, and earnings on
reinvested returns. The long-term rate of return estimation methodology for U.S.
plans is based on a capital asset pricing model using historical data. An
expected return analysis is performed and updated semi-annually by a third-party
consultant and incorporates the portfolio allocation, historical asset-class
returns and an assessment of expected future performance using asset-class risk
factors. Our assumption of the long-term rate of return for the U.K. and the
Netherlands plans is based on the advice of third-party consultants, considering
portfolio mix and the rates of return on local government and corporate bonds.
 
 The
company selects a discount rate assumption based on the average current yields
on high quality long-term fixed income instruments. For U.S. plans, the average
Moody’s Long-Term AA Corporate Bond Yield and the Citigroup Pension Liability
Index are used as a guide in the selection of the discount rate. For foreign
plans, the company bases the discount rate assumption on local corporate bond
index rates.
 
 The
U.S. plan is administered by a board-appointed committee that has fiduciary
responsibility for the plan’s management. The committee maintains an investment
policy stating the guidelines for the performance and allocation of plan assets,
performance review procedures and updating of the policy. At least annually, the
U.S. plan’s asset allocation guidelines are reviewed in light of evolving risk
and return expectations. Current guidelines permit the committee to manage the
allocation of funds between equity and debt securities at its discretion;
however, throughout 2003 and 2004, the committee has maintained an allocation of
assets in the range of 40-60% equity securities and 40-60% debt
securities.
 
 Substantially
all of the plan’s assets are invested with eight equity fund managers and six
fixed-income fund managers. At year-end 2004 and 2003, equity securities held by
the plan included $3 million and $2 million of Kerr-McGee stock, respectively,
or 50,737 shares. Dividends paid on these shares were less than $100,000 in 2004
and 2003. To control risk, equity fund managers are prohibited from entering
into the following transactions, (i) investing in commodities, including all
futures contracts, (ii) purchasing letter stock, (iii) short selling and (iv)
option trading. In addition, equity fund managers are prohibited from purchasing
on margin and are prohibited from purchasing Kerr-McGee securities. Equity
managers are monitored to ensure investments are in line with their style and
are generally permitted to invest in U.S. common stock, U.S. preferred stock,
U.S. securities convertible into common stock, common stock of foreign companies
listed on major U.S. exchanges, common stock of foreign companies listed on
foreign exchanges, covered call writing, and cash and cash equivalents.
 
  - 113 -
  Fixed-income
fund managers are prohibited from investing in (i) foreign debt securities, (ii)
direct real estate mortgages or commingled real estate funds, (iii) private
placements above certain portfolio thresholds, (iv) tax exempt debt of state and
local governments above certain portfolio thresholds, (v) fixed income
derivatives that would cause leverage, (vi) guaranteed investment contracts, and
(vii) Kerr-McGee securities. They are permitted to invest in debt securities
issued by the U.S. government, its agencies or instrumentalities, commercial
paper rated A1/P1, FDIC insured certificates of deposit or bankers acceptances,
and corporate debt obligations. 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 of A or
better.
 
 The
Netherlands plan is administered by a pension committee representing the
employer, the employees and the pensioners, each with one equal vote. The
pension committee members are approved by the state's lead pension agency based
upon experience and character. The pension committee meets at least quarterly to
discuss regulatory changes, asset performance and asset allocation. The plan
assets are managed by one Dutch fund manager against a mandate set at least
annually by the pension committee. Annually the plan assets are evaluated by a
multinational benefits consultant against state defined actuarial tests to
determine funding requirements.
 
 The
company’s U.K. plan is administered by a board of six trustees; four of whom are
appointed by the company and two who are elected by the plan’s membership.
Meetings of the trustees are held at least quarterly to discuss pension-related
issues. The trustees are assisted by external advisers who provide advice on
legal, funding and investment allocation matters.
 
 
 19.  **Contingencies**
 
 The
following table summarizes the contingency reserve balances, provisions,
payments and settlements for 2002, 2003 and 2004, as well as balances, accruals
and receipts of reimbursements of environmental costs from other
parties.
 
 
 Reserves
      for
    
    TotalLegal
    
    Environmental
    
    Contingency
    
    Reimbursements(Millions
      of dollars)
    
    Reserves
    
    Remediation(1)
    
    Reserves
    
    ReceivableBalance,
      December 31, 2001
    
    $
    46
    
    $
    182
    
    $
    228
    
    $
    -Provisions
      / Accruals
    
    
    75
    
    
    202
    
    
    277
    
    
    113Payments
      / Settlements
    
    
    (48
    )
    
    (126
    )
    
    (174
    )
    
    -Balance,
      December 31, 2002
    
    
    73
    
    
    258
    
    
    331
    
    
    113Provisions
      / Accruals
    
    
    8
    
    
    94
    
    
    102
    
    
    32Payments
      / Settlements
    
    
    (44
    )
    
    (104
    )
    
    (148
    )
    
    (15
    )**Balance,
      December 31, 2003**
    
    
    **37**
    
    
    **248**
    
    
    **285**
    
    
    **130****Provisions
      / Accruals**
    
    
    **15**
    
    
    **106**
    
    
    **121**
    
    
    **14****Payments
      / Settlements**
    
    
    **(13******
    ******)**
    
    **(99******
    ******)**
    
    **(112******
    ******)**
    
    **(50******
    ******)****Balance,
      December 31, 2004**
    
    **$**
    **39**
    
    **$**
    **255**
    
    **$**
    **294**
    
    **$**
    **94**
 
 (1)
    Provisions
      for environmental remediation and restoration in 2002, 2003 and 2004
      include $27 million, $2 million and $6 million, respectively, related to
      the company’s forest products operations. These charges are reflected in
      the Consolidated Statement of Operations as a component of income (loss)
      from discontinued operations.
 
 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. Following are discussions regarding certain
environmental sites and litigation. Reserves for each environmental site are
based on assumptions regarding the volumes of contaminated soils and groundwater
involved, as well as associated excavation, transportation and disposal
costs.
 
  - 114 -
  The
company provides for costs related to contingencies when a loss is probable and
the amount is reasonably estimable. It is not possible for the company to
reliably estimate the amount and timing of all future expenditures related to
environmental and legal matters and other contingencies because, among other
reasons:
 
 ·
    some
      sites are in the early stages of investigation, and other sites may be
      identified in the future;
 
 ·
    remediation
      activities vary significantly in duration, scope and cost from site to
      site depending on the mix of unique site characteristics, applicable
      technologies and regulatory agencies
involved;
 
 ·
    cleanup
      requirements are difficult to predict at sites where remedial
      investigations have not been completed or final decisions have not been
      made regarding cleanup requirements, technologies or other factors that
      bear on cleanup costs;
 
 ·
    environmental
      laws frequently impose joint and several liability on all potentially
      responsible parties, and it can be difficult to determine the number and
      financial condition of other potentially responsible parties and their
      respective shares of responsibility for cleanup
costs;
 
 ·
    environmental
      laws and regulations, as well as enforcement policies, are continually
      changing, and the outcome of court proceedings and discussions with
      regulatory agencies are inherently
uncertain;
 
 ·
    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;
 
 ·
    unanticipated
      construction problems and weather conditions can hinder the completion of
      environmental remediation; the inability to implement a planned
      engineering design or use planned technologies and excavation methods may
      require revisions to the design of remediation measures, which delay
      remediation and increase costs; and the identification of additional areas
      or volumes of contamination and changes in costs of labor, equipment and
      technology generate corresponding changes in environmental remediation
      costs.
 
 **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 those soils to a licensed disposal facility.
Surface restoration was completed in 2004, except for areas designated for use
in connection with the Kress Creek and Sewage Treatment Plant remediation
discussed below. Groundwater monitoring and remediation is expected to continue
for approximately 10 years.
 
 **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 damages 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. It is anticipated that the
consent decree will be filed with the court in 2005 and approved by the court in
due course thereafter. 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 early 2005. 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.
 
 - 115 -
 **Financial
Reserves** - In
2004, $28 million was added to the reserve for the West Chicago site to cover
increased soil volumes encountered at the closed facility, anticipated
groundwater remediation the company believes will be required following soil
removal at the closed facility and increased soil volumes at Kress Creek. As of
December 31, 2004, the company had reserves of $100 million for costs related to
West Chicago. Although actual costs may exceed current estimates, the amount of
any increase 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, 2004, Chemical had been
reimbursed approximately $215 million under Title X.
 
 Reimbursements
under Title X are provided by congressional appropriations. Historically,
congressional appropriations have lagged Chemical's cleanup expenditures. As of
December 31, 2004, the government's share of costs incurred by Chemical but not
yet reimbursed by the DOE totaled approximately $79 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. Approximately $49 million of the $79
million arrearage was received during the first quarter of 2005, with additional
funds expected to be received later in 2005. The company will recognize recovery
of the government's share of future remediation costs for the West Chicago sites
as Chemical incurs the cash expenditures.
 
 **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.
Construction of a long-term remediation system is complete, and the system is
operating in compliance with the consent orders. While the remediation system
currently is projected to operate through 2007, the scope, duration and cost 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 drinking water standards. One state
agency, the California Environmental Protection Agency (CalEPA), has set a
public health goal for perchlorate, and the federal EPA has established a
reference dose for perchlorate, which are preliminary steps to setting drinking
water standards. The establishment of drinking water standards could materially
affect the scope, duration and cost of the long-term groundwater remediation
that Chemical is required to perform.
 
 - 116 -
 **Financial
Reserves** -
Remaining reserves for Henderson totaled $10 million as of December 31, 2004. As
noted above, the long-term scope, duration and cost of groundwater remediation
are uncertain and, therefore, additional costs beyond those accrued may be
incurred in the future. However, the amount of any additional costs cannot be
reasonably estimated at this time.
 
 **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 discovery stage of litigation is substantially complete, and the
parties have filed certain pretrial motions that are being considered by the
court. 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.
 
 In
addition, on July 26, 2004, the company was served with a lawsuit, which was
filed in the United States District Court for the District of Arizona. The
lawsuit, Alan Curtis and Linda Curtis v. City of Bullhead City, et al., in which
the company is one of several defendants (the Defendants), alleges various
causes of action under a variety of common law theories and federal
environmental laws and seeks recovery for damages allegedly caused by the
alleged exposure to and the migration of various chemical contaminants contained
in the Colorado River. The two plaintiffs, who are not suing on behalf of any
other party, also seek an order requiring the Defendants to remediate the
contamination. The company intends to vigorously defend against the lawsuit. The
company believes that the litigation will not have a material adverse effect on
its financial condition or results of operations.
 
 **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.
 
 At
December 31, 2004, expenditures incurred to date of approximately $67 million
plus remaining costs to be incurred of approximately $9 million exceed the
self-insured retention, resulting in an expected insurance reimbursement of
about $15 million based on current cost estimates. The company believes that the
reimbursement is probable and, accordingly, the company has recorded a
receivable in the financial statements of $15 million.
 
 **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.
 
 - 117 -
 Groundwater
treatment was initiated in 1996 to remediate groundwater contamination below and
in the vicinity of the former wood-treatment area. It is not possible to
reliably predict how groundwater conditions will be affected by soil removal in
the vicinity of the former wood-treatment area, which has been completed, and
ongoing 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. Completion of the creek remedy is expected to take about three more
years.
 
 **Financial
Reserves** - In
2004, $4 million was added to the reserves for the excavation and disposal of
additional soil volumes encountered during remediation of the tributary creek of
the Menominee River. As of December 31, 2004, the company had reserves of $6
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 beyond those accrued 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. All known radiological
contamination has been removed from the site and shipped to a licensed disposal
facility.
 
 **Financial
Reserves** - In
2004, $17 million was added to the reserves primarily for groundwater treatment,
excavation, disposal of contaminated soil and costs attributable to the final
stages of the radiological cleanup at Cushing. As of December 31, 2004, the
company had reserves of $21 million for the costs of the ongoing remediation and
decommissioning work described above. 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 PRPs 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. Actual costs incurred by EPA through 2004 were
approximately $164 million.
 
 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 PRPs, 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 the
liability Chemical or its parent may have for the cleanup because of the
aforementioned uncertainties and the existence of other PRPs.
 
 - 118 -
 **Los
Angeles County, California**
 
 During
the second quarter of 2004, the company began remediation and restoration of an
oil and gas field in Los Angeles County, California. The company’s obligation
for remediation and restoration of this oil and gas field is expected to take
about five years. In 2004, $25 million was added to the reserve based on the
results of engineering studies and subsequent field experience at the site,
which indicated that soil volumes requiring remediation were greater than
initially anticipated. As of December 31, 2004, the company had environmental
reserves of $25 million for this project. Although actual costs may exceed
current estimates, the amount of any increase cannot be reasonably estimated at
this time.
 
 **Other
Sites**
 
 In
addition to the sites described above, the company is responsible for
environmental costs related to certain other sites. These sites relate primarily
to wood-treating, chemical production, landfills, mining and oil and gas
production and refining distribution and marketing. As of December 31, 2004, the
company had remaining reserves of $93 million for the environmental costs in
connection with these other sites. This includes the remaining portion of $32
million added to the reserves in 2004 primarily because additional remediation,
characterization and/or monitoring costs were identified for certain of these
sites. Although actual costs may exceed current estimates, the amount of any
increase cannot be reasonably estimated at this time.
 
 **Coal
Supply Contract**
 
 An
affiliate of the company entered into a coal supply contract with Peabody
Coaltrade, Inc. (“PCI”) in February 1998. In 1998, the company exited the coal
business and assigned its rights and obligations under the coal supply contract
to a third party. In connection with the assignment, the company agreed to
guarantee performance under the contract. PCI has notified the company of a
threatened default by the assignee under the coal supply contract and that PCI
may seek to hold the company liable under the 1998 guaranty in the event of a
default. In addition to other defenses to the enforceability of the guaranty,
the company believes the guaranty expired in January 2003 when the primary term
of the coal supply contract expired. No reserve has been provided for
performance under the guaranty because the company does not believe a loss is
probable and the amount of any loss is not reasonably estimable.
 
 **CNR
Contract**
 
 In
2002, an affiliate of the company entered into a contract with CNR International
(“CNR”) to sell certain assets located in the United Kingdom sector of the North
Sea. In the fourth quarter of 2004, CNR asserted claims for alleged breaches of
contractual representations and warranties and demanded damages. The company’s
evaluation of the claims is in its early stages. The company has not provided a
reserve for the claims because at this time the company cannot reasonably
determine the probability of a loss and the amount of loss, if any, cannot be
reasonably estimated. The company does not expect the resolution of the claims
to have a material adverse effect on the company’s financial condition or
results of operations.
 
 **Forest
Products Litigation**
 
 Between
1999 and 2001, 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. Chemical has executed settlement agreements that are expected to
resolve substantially all of the Louisiana, Pennsylvania and Columbus,
Mississippi, lawsuits described above. Accordingly most of the suits have been,
or are expected to be, dismissed.
 
 - 119 -
 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 court has consolidated these lawsuits for pretrial and discovery purposes.
On December 31, 2002, June 13, 2003, and June 25, 2004, three lawsuits were
filed against Chemical in connection with a former wood-treatment plant located
in Hattiesburg, Mississippi. On September 9, 2004, February 11, 2005, and March
2, 2005, three lawsuits were filed against Chemical in connection with a former
wood-treatment plant located in Texarkana, Texas. In addition, on January 3,
2005, and February 16, 2005, 30 lawsuits were filed against Chemical in
connection with the Avoca, Pennsylvania facility described above. These lawsuits
seek recovery on legal theories substantially similar to those advanced in the
litigation described above. A total of approximately 3,300 claimants now have
asserted claims in connection with the Hattiesburg plant, there are 63
plaintiffs named in the Texarkana lawsuits and approximately 4,600 plaintiffs
are named in the new Avoca lawsuits. Chemical has resolved approximately 1,490
of the Hattiesburg 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 the follow-on Columbus and Avoca claims, the
remaining Hattiesburg claims and the claims related to the Texarkana plants are
without substantial merit and are vigorously defending against them. The company
has not provided a reserve for these lawsuits because at this time it cannot
reasonably determine the probability of a loss, and the amount of loss, if any,
cannot be reasonably estimated. The company believes that the ultimate
resolution of the forest products 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. In the ordinary course of its business, the
company experiences disputes with federal, state, tribal and other regulatory
authorities, as well as with private parties, regarding royalty payments. These
disputes, individually and in the aggregate, are not expected to have a material
adverse effect on the company. These are also 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.
 
 
 20.  **Commitments**
 
 **Lease
Obligations and Guarantees**
 
 The
company has various commitments under noncancelable operating lease agreements,
principally for office space, production and gathering facilities and other
equipment. The company 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, 2004), total $823 million, of
which $69 million is due in 2005, $66 million in 2006, $60 million in 2007, $60
million in 2008, $49 million in 2009 and $519 million thereafter. Total lease
rental expense was $84 million in 2004, $65 million in 2003 and $61 million in
2002. Subsequent to December 31, 2004, an office space lease was renegotiated
resulting in additional annual rentals totaling $16 million of which nil is due
in 2005, $1 million in each of the years 2006 through 2009 and $12 million
thereafter.
 
 - 120 -
 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 company’s portion of platform
construction costs 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. See Note 14 for
discussion regarding the application of provisions of FIN 46 to the Gunnison
Trust and operating lease.
 
 The
company has guaranteed that the Nansen, Boomvang and Gunnison platforms will
have residual values at the end of the operating leases equal to at least 10% of
the fair value of the platform at the inception of the lease. For Nansen and
Boomvang, the guaranteed values are $14 million and $8 million, respectively, in
2022, and for Gunnison the guarantee is $15 million in 2024.
 
 During
2003 and 2002, the company entered into sale-leaseback arrangements with General
Electric Capital Corporation (GECC) covering assets associated with a
gas-gathering system in the Wattenberg field. The lease agreements were entered
into for the purpose of monetizing certain of the gathering system 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 may be required
to make payments in connection with residual value guarantees ranging from $35
million at the end of the initial terms to $27 million at the end of the last
renewal option. The company recorded no gain or loss associated with the GECC
sale-leaseback agreements. The future minimum annual rentals due under
noncancelable operating leases shown above include payments related to these
agreements.
 
 In
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 generally would 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 has entered into
indemnifications related to title claims, environmental matters, litigation and
other claims. The company has recorded no material obligations in connection
with its indemnification agreements.
 
 **Purchase
Obligations**
 
 In the
normal course of business, the company enters into contractual agreements to
purchase raw materials, pipeline capacity, utilities and other services.
Aggregate future payments under these contracts total $1.1 billion, of which
$409 million is expected to be paid in 2005, $264 million in 2006, $201 million
in 2007, $88 million in 2008, $36 million in 2009, and $122 million
thereafter.
 
  - 121 -
  **Drilling
Rig Commitments**
 
 During
2004, the company entered into arrangements to participate in the use of various
drilling rigs. The commitment with respect to these arrangements totals up
to $117 million, depending on partner utilization. These agreements extend
through 2005. Subsequent to December 31, 2004, the company entered into
additional agreements totaling $31 million, of which $21 million is due in 2005
and $10 million is due in 2006.
 
 **Letters
of Credit and Other**
 
 At
December 31, 2004, the company had outstanding letters of credit in the amount
of approximately $106 million. Most of these letters of credit have been granted
by financial institutions to support our international drilling
commitments.
 
 As
discussed in Notes 1 and 16, the company has obligations associated with the
retirement of tangible long-lived assets. In addition to asset retirement
obligations reflected in the company’s Consolidated Balance Sheet, obligations
exist for certain chemical facilities that are not estimable until the timing of
settlement is known and, therefore, have not been reflected in the consolidated
financial statements.
 
 
 21.  **Capital
Stock**
 
 Authorized
capital stock of the company consists of 300 million shares of common stock, par
value of $1.00 per share, and 40 million shares of preferred stock without par
value. No shares of preferred stock have been issued. In June 2004, the company
issued 48.9 million shares of its common stock in connection with its merger
with Westport (see Note 2).
 
 Changes
in common stock issued and treasury stock held for 2004, 2003 and 2002 are as
follows:
 
 Common
    
    Treasury(Thousands
      of shares)
    
    Stock
    
    StockBalance
      at December 31, 2001
    
    
    100,186
    
    
    1Exercise
      of stock options
    
    
    112
    
    
    -Issuance
      of restricted stock
    
    
    94
    
    
    (5
    )Forfeiture
      of restricted stock
    
    
    (2
    )
    
    11Issuance
      of shares for achievement awards
    
    
    1
    
    
    -Balance
      at December 31, 2002
    
    
    100,391
    
    
    7Exercise
      of stock options
    
    
    18
    
    
    -Issuance
      of restricted stock
    
    
    483
    
    
    -Forfeiture
      of restricted stock
    
    
    -
    
    
    25Balance
      at December 31, 2003
    
    
    100,892
    
    
    32Shares
      issued in Westport merger
    
    
    48,949
    
    
    -Exercise
      of stock options
    
    
    1,725
    
    
    -Issuance
      of restricted stock
    
    
    483
    
    
    -Forfeiture
      of restricted stock
    
    
    -
    
    
    128Balance
      at December 31, 2004
    
    
    152,049
    
    
    160
 
 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.
 
 At
December 31, 2004, approximately 2.6 million shares of common stock were
reserved for issuance pursuant to the company’s long-term incentive plans, and
approximately 9.8 million shares of common stock were issuable upon conversion
of outstanding 5.25% convertible debentures. As discussed in Note 14, in March
2005 all of the debentures were converted by the holders into 9.8 million shares
of common stock.
 
 - 122 -
 ***Preferred
Share Purchase Rights Plan****-*The company has had a
stockholders’ rights plan since 1986. The current rights plan is dated July 26,
2001, and replaced the previous plan prior to its expiration. Rights were
distributed as a dividend at the rate of one right for each share of the
company’s common stock and continue to trade together with each share of common
stock. Generally, the rights become exercisable the earlier of 10 days after a
public announcement that a person or group has acquired, or a tender offer has
been made for, 15% or more of the company’s then-outstanding stock. If either of
these events occurs, each right would entitle the holder (other than a holder
owning more than 15% of the outstanding stock) to buy the number of shares of
the company’s common stock having a market value two times the exercise price.
The exercise price is $215. Generally, the rights may be redeemed at $.01 per
right until a person or group has acquired 15% or more of the company’s stock.
The rights expire in July 2006.
 
 
 22.  **Employee
Stock-Based Compensation 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, none of which were outstanding at December 31,
2004 and 2003. Upon the exercise of stock appreciation rights, the associated
options are surrendered. A total of 7,000,000 shares of the company’s common
stock is authorized to be issued under the 2002 Plan, of which a maximum of
1,750,000 shares of common stock is authorized for issuance in connection with
awards of restricted stock and performance awards. Performance awards may be
granted in the form of performance shares or performance units. Performance
shares define a benefit to the grantee by reference to shares of stock, while
performance units provide for cash awards based on the company’s achievement of
certain financial performance measures over a stated period. There were 19
million and 11 million performance units outstanding at December 31, 2004 and
2003, respectively. Compensation expense associated with these awards was not
material for all periods presented.
 
 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 at any time prior to December 31, 2007.
 
 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.
 
 ***Stock
Options*** - 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.
As discussed in Note 2, on June 25, 2004, the company completed its merger with
Westport. In connection with the merger, the company exchanged Westport options
outstanding as of the merger date for Kerr-McGee options based on the exchange
factor set forth in the merger agreement.
 
  - 123 -
  The
following table summarizes the stock option transactions during 2004, 2003 and
2002 under the compensation plans described above and in connection with the
Westport merger:
 
 **2004**
    
    2003
    
    2002**Weighted-**
    
    
    
    Weighted-
    
    
    
    Weighted-**Average**
    
    
    
    Average
    
    
    
    Average**Exercise**
    
    
    
    Exercise
    
    
    
    Exercise**Price
      per**
    
    
    
    Price
      per
    
    
    
    Price
      per**Options**
    
    **Option**
    
    Options
    
    Option
    
    Options
    
    OptionOutstanding,
      beginning of year
    
    
    **6,418,719**
    
    **$**
    **56.02**
    
    
    5,406,424
    
    $
    59.27
    
    
    3,433,745
    
    $
    61.18Options
      issued in Westport merger
    
    
    **1,901,988**
    
    
    **29.55**
    
    
    -
    
    
    -
    
    
    -
    
    
    -Options
      granted
    
    
    **1,385,536**
    
    
    **49.45**
    
    
    1,353,100
    
    
    42.93
    
    
    2,544,562
    
    
    57.08Options
      exercised
    
    
    **(1,744,179**
    **)**
    
    **32.42**
    
    
    (18,500
    )
    
    44.55
    
    
    (111,411
    )
    
    46.78Options
      forfeited
    
    
    **(183,545**
    **)**
    
    **47.26**
    
    
    (189,638
    )
    
    55.35
    
    
    (141,116
    )
    
    58.42Options
      expired
    
    
    **(261,864******
    ******)**
    
    **60.99**
    
    
    (132,667
    )
    
    57.78
    
    
    (319,356
    )
    
    67.09Outstanding,
      end of year
    
    
    **7,516,655**
    
    
    **53.63**
    
    
    6,418,719
    
    
    56.02
    
    
    5,406,424
    
    
    59.27Exercisable,
      end of year
    
    
    **4,636,210**
    
    
    **56.89**
    
    
    3,382,550
    
    
    59.81
    
    
    2,179,960
    
    
    59.60
 
 
 The
following table summarizes information about stock options issued under the
plans described above that are outstanding and exercisable at December 31,
2004:
 
 Options
      Outstanding
    
    Options
      ExercisableWeighted-
    
    Weighted-
    
    
    
    Weighted-Average
    
    Average
    
    
    
    AverageRange
      of Exercise
    
    Remaining
    
    Exercise
    
    
    
    ExercisePrices
      per
    
    Contractual
    
    Price
      per
    
    
    
    Price
      perOptions
    
    Option
    
    Life
      (years)
    
    Option
    
    Options
    
    Option328,125
    
    $
    15.00
      - $29.99
    
    
    5.4
    
    $
    26.53
    
    
    230,674
    
    $
    25.9564,425
    
    
    30.00
      - 39.99
    
    
    4.0
    
    
    33.45
    
    
    57,801
    
    
    33.462,743,893
    
    
    40.00
      - 49.99
    
    
    8.1
    
    
    46.10
    
    
    572,724
    
    
    43.111,644,756
    
    
    50.00
      - 59.99
    
    
    5.4
    
    
    55.15
    
    
    1,287,661
    
    
    55.422,621,156
    
    
    60.00
      - 69.99
    
    
    5.3
    
    
    63.59
    
    
    2,373,050
    
    
    63.81111,956
    
    
    70.00
      - 79.99
    
    
    2.1
    
    
    72.66
    
    
    111,956
    
    
    72.662,344
    
    
    90.00
      - 99.99
    
    
    1.4
    
    
    98.62
    
    
    2,344
    
    
    98.627,516,655
    
    
    
    
    
    6.3
    
    
    53.63
    
    
    4,636,210
    
    
    56.89
 
 
 ***Restricted
Stock*** -
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 2002 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. The company granted 483,000, 483,000 and
99,000 shares of restricted common stock in 2004, 2003 and 2002, for which the
weighted average fair value at the date of grant was $22 million, $20 million
and $4 million, respectively. The company granted 7,000 and 9,000 stock
opportunity shares in 2004 and 2003, the fair value of which was not material.
There were no stock opportunity grants issued in 2002. Compensation expense
associated with restricted stock and stock opportunity awards was $17 million,
$10 million and $6 million in 2004, 2003, and 2002, respectively.
 
 ***Employee
Stock Ownership Plan*** - In
1989, the company’s Board of Directors approved a leveraged Employee Stock
Ownership Plan (ESOP) into which the company’s matching contribution for the
employees’ contributions to the Kerr-McGee Corporation Savings Investment Plan
(SIP) is paid. 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. Effective December 31, 2004, the ESOP
and the Savannah Plan were merged into the SIP.
 
 - 124 -
 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
due within one year (see Note 14).
 
 In
1999, the company merged with Oryx Energy Company, which sponsored the Oryx
Capital Accumulation Plan (CAP). CAP was a combined stock bonus and leveraged
employee stock ownership plan available to substantially all U.S. employees of
the former Oryx operations. During 1999, the company merged the Oryx CAP into
the ESOP and SIP. In 1989, Oryx privately placed $110 million of notes pursuant
to the provisions of the CAP. Oryx loaned the proceeds to the CAP, which used
the funds to purchase Oryx common stock that was placed in a trust. Because this
loan represents sponsor financing, it does not appear in the accompanying
balance sheet. The remaining balance of the sponsor financing is $30 million at
year-end 2004.
 
 Shares
of stock allocated to the ESOP participants' accounts and in the loan suspense
account are as follows:
 
 (Thousands
      of shares)
    **2004**
    2003Participants’
      accounts
    **1,432**
    1,496Loan
      suspense account
    **246**
    315
 
 The
shares in the loan suspense account at December 31, 2004, included approximately
17,000 released shares that were allocated to participants’ accounts in January
2005. At December 31, 2003, the shares in the loan suspense account included
approximately 5,000 released shares that were allocated to participants’
accounts in January 2004.
 
 Compensation
expense related to the plan was $13 million, $33 million and $19 million in
2004, 2003 and 2002, respectively. These amounts include interest expense
incurred on the third-party ESOP debt, which was not material for 2004, 2003 or
2002. The company contributed $17 million, $42 million and $27 million to the
ESOP in 2004, 2003 and 2002, respectively. Included in the respective
contributions were $10 million, $37 million and $19 million for principal and
interest payments on the financings. The cash contributions are net of $3
million, $4 million and $5 million for the dividends paid on the company stock
held by the ESOP trust in 2004, 2003 and 2002, respectively.
 
 
 23.  **Taxes,
Other than Income Taxes**
 
 Taxes,
other than income taxes, as shown in the Consolidated Statement of Operations
for the years ended December 31, 2004, 2003 and 2002, are comprised of the
following:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Production/severance
    
    **$**
    **84**
    
    $
    46
    
    $
    58Payroll
    
    
    **28**
    
    
    29
    
    
    20Property
    
    
    **31**
    
    
    18
    
    
    19Other
    
    
    **5**
    
    
    3
    
    
    5Total
    
    **$**
    **148**
    
    $
    96
    
    $
    102
 
 
 - 125 -
 24.  **Other
Income (Expense)**
 
 Other
income (expense) included the following during each of the years in the
three-year period ended December 31, 2004:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Net
      foreign currency transaction loss
    
    **$**
    **(21**
    **)**
    $
    (41
    )
    $
    (38
    )Equity
      in net losses of equity method investees
    
    
    **(26**
    **)**
    
    (33
    )
    
    (25
    )Gain
      on sale of Devon stock
    
    
    **9**
    
    
    17
    
    
    -Derivatives
      and Devon stock revaluation(1)
    
    
    **2**
    
    
    4
    
    
    35Interest
      income
    
    
    **6**
    
    
    5
    
    
    5Loss
      on accounts receivables sales and other
    
    
    **(10******
    ******)**
    
    (9
    )
    
    (8
    )Total
    
    **$******
    **(40******
    ******)**
    $
    (57
    )
    $
    (31
    )
 
 (1) See
Notes 7 and 11 for additional information related to accounting for Devon stock
and DECS.
 
 
 25.  **Asset
Impairments, Asset Disposals and Discontinued Operations**
 
 ***Asset
Impairments*** - In
September 2004, the company shut down sulfate-process titanium dioxide pigment
production at its Savannah, Georgia facility. In connection with the closure,
the company recognized an $8 million asset impairment loss on indefinite-lived
intangible assets in 2004. See Note 13 for information on other provisions
related to the shutdown.
 
 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.
As of the end of the year, the company continued to operate its new
high-productivity oxidation line and continued to evaluate its performance. The
company expects to have a better understanding of how the Savannah site might be
reconfigured to exploit its capabilities in 2005. The possible reconfiguration
of the Savannah site, if any, could include redeployment of certain assets,
idling of certain assets and reduction of the future useful life of certain
assets, resulting in the acceleration of depreciation expense and the
recognition of other charges.
 
 Impairment
losses on held-for-use assets totaled $28 million and $14 million in 2004 and
2003, respectively. The 2004 impairments related primarily to two U.S. Gulf of
Mexico fields that experienced premature water breakthrough and ceased
production sooner than expected ($17 million), as well as $8 million for a U.K.
North Sea field that is no longer certain to be developed and $3 million
associated with other minor onshore U.S. properties. The 2003 impairments
related to mature oil and gas producing assets in the U.S. onshore and Gulf of
Mexico shelf areas. Impairment losses totaling $646 million were recorded in
2002, including $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. 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.
 
 - 126 -
 The
company continues to review its options with respect to its 100%-owned Leadon
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, 2004, the carrying value of the Leadon field assets totaled $336
million. Given the uncertainty concerning possible outcomes, it is at least
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 anticipated,
and/or (iii) failure to locate a strategic buyer or suitable redeployment
opportunity for the FPSO. 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.
 
 ***Discontinued
Operations*** -
During 2002, the company approved a plan to exit its forest products business,
which was part of the chemical - other operating unit. This decision was made as
part of the company’s strategic plan to focus on its core businesses. At the
time of this decision, five plants were in operation. Four of these plants were
closed and abandoned during 2003. Provisions associated with the closure of
these plants are discussed in more detail in Note 13. The fifth plant, a leased
facility, was operated throughout 2004 until the lease expired and the fixed
assets at the facility were sold in January 2005. Criteria for classification of
these assets as held for sale were met in the fourth quarter 2004, at which time
the results of forest products operations met the requirements for reporting as
discontinued operations in the accompanying Consolidated Statement of Operations
for all years presented. The assets held for sale at December 31, 2004 are
included in Long-Term Assets Associated with Properties Held for Disposal in the
Consolidated Balance Sheet at estimated sales price less costs to sell of $3
million. No gain or loss was recognized on the disposition of these
assets.
 
 Revenues
applicable to the discontinued operations totaled $22 million, $105 million and
$131 million for 2004, 2003, and 2002, respectively. Pretax loss
from discontinued operations totaled $17 million, $16 million and $32
million for the years 2004, 2003, and 2002, respectively.
 
 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 and $36 million for
2003 and 2002, respectively. Pretax income for the discontinued operations
totaled nil (including the loss on sale of $6 million) and $104 million
(including the gains on sale of $107 million and the loss on sale of $35
million) for the years 2003 and 2002, respectively.
 
 ***Asset
Disposals*** - The
company recognized a net loss on sale of assets of $29 million in 2004. The loss
was associated primarily with the conveyance of the company’s interest in a
nonproducing Gulf of Mexico field to another participating partner ($25
million), as well as losses of $6 million and gains of $2 million on sales of
noncore properties in the Gulf of Mexico shelf and U.S. onshore areas. At
December 31, 2004, the company had oil and gas properties with a carrying amount
of $5 million classified as held for sale.
 
 - 127 -
 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. 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 were used to reduce long-term debt.
   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 from continuing operations for the years ended December 31, 2004, 2003 and
2002:
 
 **2004**
    
    2003
    
    2002Income
    
    
    
    
    
    Income
    
    
    
    
    
    Loss(Millions
      of dollars, except
    
    from
    
    
    
    Per-
    
    from
    
    
    
    Per-
    
    from
    
    
    
    Per-per-share
      amounts, and
    
    Continuing
    
    
    
    share
    
    Continuing
    
    
    
    share
    
    Continuing
    
    
    
    sharethousands
      of shares)
    
    Operations
    
    Shares
    
    Income
    
    Operations
    
    Shares
    
    Income
    
    Operations
    
    Shares
    
    LossBasic
      earnings per share
    
    **$**
    **415**
    
    
    **126,313**
    
    **$**
    **3.29**
    
    $
    264
    
    
    100,145
    
    $
    2.63
    
    $
    (590
    )
    
    100,330
    
    $
    (5.89
    )Effect
      of dilutive securities:5.25% convertibledebentures
    
    
    **21**
    
    
    **9,824**
    
    
    
    
    
    21
    
    
    9,824
    
    
    
    
    
    -
    
    
    -Restricted stock
    
    
    **-**
    
    
    **449**
    
    
    
    
    
    -
    
    
    697
    
    
    
    
    
    -
    
    
    -Employee stock options
    
    
    **-**
    
    
    **333**
    
    
    
    
    
    -
    
    
    17
    
    
    
    
    
    -
    
    
    -Diluted
      earnings per share
    
    **$**
    **436**
    
    
    **136,919**
    
    **$**
    **3.19**
    
    $
    285
    
    
    110,683
    
    $
    2.58
    
    $
    (590
    )
    
    100,330
    
    $
    (5.89
    )
 
 The
weighted average of diluted shares outstanding during 2004 and 2003 did not
include the effect of employee stock options that were antidilutive because they
were not "in the money" during the respective years.  At December 31, 2004
and 2003 there were 2,981,936 and 4,866,144 of such options outstanding, with
weighted average exercise prices of $63.63 and $60.26, respectively. Because the
company incurred a loss from continuing operations for 2002, all of the
potentially issuable common shares were antidilutive, including 5,018,856
of shares potentially issuable upon exercise of the employee stock
options and 9,823,778 shares issuable upon conversion of the 5.25 %
Convertible Subordinated Debentures.
 
 As
discussed in Note 35, in March 2005 all of the 5.25% debentures were converted
by the holders into 9.8 million shares of common stock.
 
 
 27.  **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 chemical products. The exploration and production unit
explores for, develops, produces and markets crude oil and natural gas, with
major areas of operation in the United States, the United Kingdom sector of the
North Sea and China. Exploration efforts also extend to Australia, Benin,
Bahamas, Brazil, Morocco, Canada, 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 chemical products segment represents the company’s
electrolytic manufacturing and marketing operations. All operations of the
chemical - other segment are located in the United States.  Segment
performance is evaluated based on operating profit (loss), which represents
results of operations before considering general corporate expenses, interest
and debt expense, environmental provisions related to businesses in which the
company's affiliates are no longer engaged, other income (expense) and income
taxes.
 
  - 128 -
  Crude
oil sales to individually significant customers totaled $499 million to BP PLC
and subsidiaries (BP) in 2004; $446 million to BP in 2003; and $408 million to
Texon L.P. and $450 million to BP in 2002. In addition, natural gas sales
totaled $183 million to BP and $952 million to Cinergy Marketing & Trading
LP (Cinergy) in 2004; $103 million to BP and $782 million to Cinergy in 2003;
and $72 million to BP and $496 million to Cinergy in 2002. Sales to subsidiary
companies are eliminated as described in Note 1.
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Revenues
      -Exploration
      and production
    
    **$**
    **3,855**
    
    $
    2,923
    
    $
    2,450Chemical
      -Pigment
    
    
    **1,209**
    
    
    1,079
    
    
    995Other
    
    
    **93**
    
    
    78
    
    
    70Total
      Chemical
    
    
    **1,302**
    
    
    1,157
    
    
    1,065Total
    
    **$**
    **5,157**
    
    $
    4,080
    
    $
    3,515Operating
      profit (loss) -Exploration
      and production
    
    **$**
    **1,249**
    
    $
    1,002
    
    $
    (140
    )Chemical
      -Pigment
    
    
    **(80**
    **)**
    
    (13
    )
    
    24Other
    
    
    **(1******
    ******)**
    
    (23
    )
    
    (13
    )Total
      Chemical
    
    
    **(81******
    ******)**
    
    (36
    )
    
    11Total
    
    
    **1,168**
    
    
    966
    
    
    (129
    )Interest
      and debt expense
    
    
    **(245**
    **)**
    
    (251
    )
    
    (275
    )Corporate
      expenses
    
    
    **(130**
    **)**
    
    (152
    )
    
    (158
    )Provision
      for environmental remediation and restoration,net
      of reimbursements(1)
    
    
    **(82**
    **)**
    
    (47
    )
    
    (32
    )Other
      income (expense)(2)
    
    
    **(40**
    **)**
    
    (57
    )
    
    (31
    )Benefit
      (provision) for income taxes
    
    
    **(256**
    **)**
    
    (195
    )
    
    35Discontinued
      operations, net of taxes
    
    
    **(11**
    **)**
    
    (10
    )
    
    105Cumulative
      effect of change in accounting principle,net
      of taxes
    
    
    **-**
    
    
    (35
    )
    
    -Net
      income (loss)
    
    **$**
    **404**
    
    $
    219
    
    $
    (485
    )Depreciation,
      depletion and amortization -Exploration
      and production(3)
    
    **$**
    **917**
    
    $
    678
    
    $
    758Chemical
      -Pigment
    
    
    **182**
    
    
    110
    
    
    97Other
    
    
    **14**
    
    
    15
    
    
    15Total
      Chemical
    
    
    **196**
    
    
    125
    
    
    112Other
    
    
    **10**
    
    
    8
    
    
    6Discontinued
      operations
    
    
    **1**
    
    
    3
    
    
    8Total
    
    **$**
    **1,124**
    
    $
    814
    
    $
    884
 
 (1)
    Includes
      provisions, net of reimbursements, related to various businesses in which
      the company’s affiliates are no longer engaged; for example, the refining
      and marketing of oil and gas and associated petroleum products, and the
      mining and processing of uranium and thorium. See Note
  19.
 
 (2)
    The
      company owns a 50% interest in Avestor, a joint venture involved in
      production of lithium-metal-polymer batteries. Investment in Avestor is
      accounted for under the equity method. The company's equity in the net
      losses of  Avestor amounts to $39 million, $28 million and $24
      million in 2004, 2003 and 2002, respectively. The carrying value of the
      company’s investment in Avestor at December 31, 2004 and 2003 was $60
      million and $74 million, respectively.
 
 (3)
    Includes
      amortization of nonproducing leasehold costs that is reported in
      exploration expense in the Consolidated Statement of Operations.
  - 129 -
  
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Capital
      expenditures -Exploration
      and production(excludes
      Gunnison lease of $83 in 2003)
    
    **$**
    **1,152**
    
    $
    869
    
    $
    988Chemical
      -Pigment
    
    
    **83**
    
    
    90
    
    
    78Other
    
    
    **9**
    
    
    7
    
    
    7Total
      Chemical
    
    
    **92**
    
    
    97
    
    
    85Other
    
    
    **18**
    
    
    15
    
    
    58Discontinued
      operations
    
    
    **-**
    
    
    -
    
    
    28Total
    
    
    **1,262**
    
    
    981
    
    
    1,159Exploration
      expense -Exploration
      and production -Dry
      hole expense
    
    
    **161**
    
    
    181
    
    
    113Amortization
      of undeveloped leases
    
    
    **63**
    
    
    69
    
    
    67Other
    
    
    **132**
    
    
    104
    
    
    93Total
    
    
    **356**
    
    
    354
    
    
    273Total
      capital expendituresand
      exploration expense
    
    **$**
    **1,618**
    
    $
    1,335
    
    $
    1,432Total
      assets -Exploration
      and production
    
    **$**
    **12,246**
    
    $
    7,385
    
    $
    7,030Chemical
      -Pigment
    
    
    **1,359**
    
    
    1,521
    
    
    1,413Other
    
    
    **184**
    
    
    213
    
    
    242Total
      Chemical
    
    
    **1,543**
    
    
    1,734
    
    
    1,655Total
    
    
    **13,789**
    
    
    9,119
    
    
    8,685Corporate
      and other assets
    
    
    **726**
    
    
    1,127
    
    
    1,038Discontinued
      operations
    
    
    **3**
    
    
    4
    
    
    186Total
    
    **$**
    **14,518**
    
    $
    10,250
    
    $
    9,909Revenues
      -U.S.
      operations
    
    **$**
    **3,720**
    
    $
    2,755
    
    $
    2,059International
      operations -North
      Sea - exploration and production
    
    
    **759**
    
    
    791
    
    
    936China
      - exploration and production
    
    
    **92**
    
    
    23
    
    
    30Other
      - exploration and production
    
    
    **-**
    
    
    -
    
    
    28Europe
      - pigment
    
    
    **361**
    
    
    313
    
    
    294Australia
      - pigment
    
    
    **225**
    
    
    198
    
    
    168**1,437**
    
    
    1,325
    
    
    1,456Total
    
    **$**
    **5,157**
    
    $
    4,080
    
    $
    3,515Operating
      profit (loss) -U.S.
      operations
    
    **$**
    **880**
    
    $
    634
    
    $
    332International
      operations -North
      Sea - exploration and production
    
    
    **277**
    
    
    353
    
    
    (412
    )China
      - exploration and production
    
    
    **41**
    
    
    1
    
    
    7Other
      - exploration and production
    
    
    **(52**
    **)**
    
    (66
    )
    
    (59
    )Europe
      - pigment
    
    
    **(16**
    **)**
    
    14
    
    
    (21
    )Australia
      - pigment
    
    
    **38**
    
    
    30
    
    
    24**288**
    
    
    332
    
    
    (461
    )Total
    
    **$**
    **1,168**
    
    $
    966
    
    $
    (129
    )Net
      property, plant and equipment -U.S.
      operations
    
    **$**
    **8,425**
    
    $
    4,973
    
    $
    4,590International
      operations -North
      Sea - exploration and production
    
    
    **1,754**
    
    
    1,874
    
    
    1,912China
      - exploration and production
    
    
    **226**
    
    
    165
    
    
    115Other
      - exploration and production
    
    
    **26**
    
    
    4
    
    
    13Europe
      - pigment
    
    
    **303**
    
    
    281
    
    
    238Australia
      - pigment
    
    
    **93**
    
    
    102
    
    
    110**2,402**
    
    
    2,426
    
    
    2,388Total
    
    **$**
    **10,827**
    
    $
    7,399
    
    $
    6,978
 
 
 - 130 -
 28.  **Condensed
Consolidating Financial Information**
 
 On
October 3, 2001, Kerr-McGee Corporation issued $1.5 billion of long-term notes
in a public offering.  On July 1, 2004, Kerr-McGee Corporation issued an
additional $650 million of long-term notes. The notes are general, unsecured
obligations of the company and rank in parity with all of the company’s other
unsecured and unsubordinated indebtedness. The notes have been fully and
unconditionally guaranteed, on a joint and several basis, by Kerr-McGee Chemical
Worldwide LLC and Kerr-McGee Rocky Mountain Corporation.  Additionally,
Kerr-McGee Corporation has guaranteed all indebtedness of its subsidiaries. As a
result of these guarantee arrangements, the company is required to present
condensed consolidating financial information.
 
 The
following tables present condensed consolidating financial information for (a)
Kerr-McGee Corporation, the parent company, (b) the guarantor subsidiaries, and
(c) the nonguarantor subsidiaries on a consolidated basis.  The guarantor
subsidiaries include Kerr-McGee Chemical Worldwide LLC and Kerr-McGee Rocky
Mountain Corporation, wholly-owned subsidiaries of Kerr-McGee Corporation. 
Other income (expense) in the Condensed Consolidating Statement of Operations
includes equity interest in income (loss) of subsidiaries for all periods
presented.
 
 **Condensed
      Consolidating Statement of Operations for the Year Ended December 31,
      2004**(Millions
      of dollars)
    
    Kerr-McGee
      Corporation
    
    Guarantor
      Subsidiaries
    
    Non-Guarantor
      Subsidiaries
    
    Eliminations
    
    Consolidated**Revenues**
    
    $
    -
    
    $
    864
    
    $
    4,293
    
    $
    -
    
    $
    5,157**Costs
      and Expenses**Costs
      and operating expenses
    
    
    -
    
    
    519
    
    
    1,436
    
    
    (2
    )
    
    1,953Selling,
      general and administrative expenses
    
    
    1
    
    
    7
    
    
    329
    
    
    -
    
    
    337Shipping
      and handling expenses
    
    
    -
    
    
    8
    
    
    158
    
    
    -
    
    
    166Depreciation
      and depletion
    
    
    -
    
    
    120
    
    
    940
    
    
    -
    
    
    1,060Accretion
      expense
    
    
    -
    
    
    3
    
    
    27
    
    
    -
    
    
    30Asset
      impairments
    
    
    -
    
    
    3
    
    
    33
    
    
    -
    
    
    36Loss
      associated with assetsheld
      for sale
    
    
    -
    
    
    -
    
    
    29
    
    
    -
    
    
    29Exploration,
      including exploratory dry holesand
      amortization of undeveloped leases
    
    
    -
    
    
    14
    
    
    342
    
    
    -
    
    
    356Taxes,
      other than income taxes
    
    
    -
    
    
    38
    
    
    110
    
    
    -
    
    
    148Provision
      for environmental remediation andrestoration,
      net of reimbursements
    
    
    -
    
    
    66
    
    
    20
    
    
    -
    
    
    86Interest
      and debt expense
    
    
    138
    
    
    36
    
    
    304
    
    
    (233
    )
    
    245Total
      Costs and Expenses
    
    
    139
    
    
    814
    
    
    3,728
    
    
    (235
    )
    
    4,446(139
    )
    
    50
    
    
    565
    
    
    235
    
    
    711**Other
      Income (Expense)**
    
    
    793
    
    
    (117
    )
    
    108
    
    
    (824
    )
    
    (40
    )**Income
      (Loss) before Income Taxes**
    
    
    654
    
    
    (67
    )
    
    673
    
    
    (589
    )
    
    671**Benefit
      (Provision) for Income Taxes**
    
    
    (250
    )
    
    24
    
    
    (259
    )
    
    229
    
    
    (256
    )**Income
      from Continuing Operations**
    
    
    404
    
    
    (43
    )
    
    414
    
    
    (360
    )
    
    415**Income
      (Loss) from Discontinued****Operations,
      net of taxes**
    
    
    -
    
    
    -
    
    
    (11
    )
    
    -
    
    
    (11
    )**Net
      Income (Loss)**
    
    $
    404
    
    $
    (43
    )
    $
    403
    
    $
    (360
    )
    $
    404
 
  - 131 -
  
 **Condensed
      Consolidating Statement of Operations for the Year Ended December 31,
      2003**(Millions
      of dollars)
    
    Kerr-McGee
      Corporation
    
    Guarantor
      Subsidiaries
    
    Non-Guarantor
      Subsidiaries
    
    Eliminations
    
    Consolidated**Revenues**
    
    $
    -
    
    $
    694
    
    $
    3,386
    
    $
    -
    
    $
    4,080**Costs
      and Expenses**Costs
      and operating expenses
    
    
    -
    
    
    351
    
    
    1,214
    
    
    (2
    )
    
    1,563Selling,
      general and administrative expenses
    
    
    -
    
    
    14
    
    
    351
    
    
    -
    
    
    365Shipping
      and handling expenses
    
    
    -
    
    
    9
    
    
    130
    
    
    -
    
    
    139Depreciation
      and depletion
    
    
    -
    
    
    122
    
    
    620
    
    
    -
    
    
    742Accretion
      expense
    
    
    -
    
    
    2
    
    
    23
    
    
    -
    
    
    25Asset
      impairments
    
    
    -
    
    
    -
    
    
    14
    
    
    -
    
    
    14Loss(gain) associated with assetsheld
      for sale
    
    
    -
    
    
    1
    
    
    (46
    )
    
    -
    
    
    (45
    )Exploration,
      including exploratory dry holes andamortization
      of undeveloped leases
    
    
    -
    
    
    15
    
    
    339
    
    
    -
    
    
    354Taxes,
      other than income taxes
    
    
    -
    
    
    25
    
    
    71
    
    
    -
    
    
    96Provision
      for environmental remediation andrestoration,
      net of reimbursements
    
    
    -
    
    
    31
    
    
    29
    
    
    -
    
    
    60Interest
      and debt expense
    
    
    116
    
    
    36
    
    
    277
    
    
    (178
    )
    
    251Total
      Costs and Expenses
    
    
    116
    
    
    606
    
    
    3,022
    
    
    (180
    )
    
    3,564(116
    )
    
    88
    
    
    364
    
    
    180
    
    
    516**Other
      Income (Expense)**
    
    
    506
    
    
    (9
    )
    
    67
    
    
    (621
    )
    
    (57
    )**Income
      (Loss) from Continuing Operations****before
      Income Taxes**
    
    
    390
    
    
    79
    
    
    431
    
    
    (441
    )
    
    459**Benefit
      (Provision) for Income Taxes**
    
    
    (189
    )
    
    23
    
    
    (177
    )
    
    148
    
    
    (195
    )**Income
      (Loss) from Continuing Operations**
    
    
    201
    
    
    102
    
    
    254
    
    
    (293
    )
    
    264**Income
      (Loss) from Discontinued Operations,****net
      of taxes**
    
    
    -
    
    
    12
    
    
    (20
    )
    
    (2
    )
    
    (10
    )**Cumulative
      Effect of Change in Accounting****Principle,
      net of taxes**
    
    
    -
    
    
    (1
    )
    
    (34
    )
    
    -
    
    
    (35
    )**Net
      Income (Loss)**
    
    $
    201
    
    $
    113
    
    $
    200
    
    $
    (295
    )
    $
    219
 
 **Condensed
      Consolidating Statement of Operations for the Year Ended December 31,
      2002**(Millions
      of dollars)
    
    Kerr-McGee
      Corporation
    
    Guarantor
      Subsidiaries
    
    Non-Guarantor
      Subsidiaries
    
    Eliminations
    
    Consolidated**Revenues**
    
    $
    -
    
    $
    351
    
    $
    3,423
    
    $
    (259
    )
    $
    3,515**Costs
      and Expenses**Costs
      and operating expenses
    
    
    -
    
    
    105
    
    
    1,498
    
    
    (260
    )
    
    1,343Selling,
      general and administrative expenses
    
    
    -
    
    
    4
    
    
    304
    
    
    -
    
    
    308Shipping
      and handling expenses
    
    
    -
    
    
    9
    
    
    115
    
    
    -
    
    
    124Depreciation
      and depletion
    
    
    -
    
    
    121
    
    
    688
    
    
    -
    
    
    809Asset
      impairments
    
    
    -
    
    
    3
    
    
    643
    
    
    -
    
    
    646Loss
      associated with assets held for sale
    
    
    -
    
    
    -
    
    
    176
    
    
    -
    
    
    176Exploration,
      including exploratory dry holes andamortization
      of undeveloped leases
    
    
    -
    
    
    12
    
    
    261
    
    
    -
    
    
    273Taxes,
      other than income taxes
    
    
    -
    
    
    16
    
    
    86
    
    
    -
    
    
    102Provision
      for environmental remediation andrestoration,
      net of reimbursements
    
    
    -
    
    
    -
    
    
    53
    
    
    -
    
    
    53Interest
      and debt expense
    
    
    115
    
    
    36
    
    
    323
    
    
    (199
    )
    
    275Total
      Costs and Expenses
    
    
    115
    
    
    306
    
    
    4,147
    
    
    (459
    )
    
    4,109(115
    )
    
    45
    
    
    (724
    )
    
    200
    
    
    (594
    )**Other
      Income (Expense)**
    
    
    (438
    )
    
    484
    
    
    (123
    )
    
    46
    
    
    (31
    )**Income
      (Loss) from Continuing Operations****before
      Income Taxes**
    
    
    (553
    )
    
    529
    
    
    (847
    )
    
    246
    
    
    (625
    )**Benefit
      (Provision) for Income Taxes**
    
    
    68
    
    
    (26
    )
    
    33
    
    
    (40
    )
    
    35**Income
      (Loss) from Continuing Operations**
    
    
    (485
    )
    
    503
    
    
    (814
    )
    
    206
    
    
    (590
    )**Income
      from Discontinued Operations,****net
      of taxes**
    
    
    -
    
    
    -
    
    
    105
    
    
    -
    
    
    105**Net
      Income (Loss)**
    
    $
    (485
    )
    $
    503
    
    $
    (709
    )
    $
    206
    
    $
    (485
    )
 
 
 - 132 -
 **Condensed
      Consolidating Balance Sheet as of December 31,
    2004**(Millions
      of dollars)
    
    Kerr-McGee
      Corporation
    
    Guarantor
      Subsidiaries
    
    Non-Guarantor
      Subsidiaries
    
    Eliminations
    
    Consolidated**ASSETS****Current
      Assets**Cash
      and cash equivalents
    
    $
    2
    
    $
    -
    
    $
    74
    
    $
    -
    
    $
    76Intercompany
      receivables
    
    
    -
    
    
    -
    
    
    58
    
    
    (58
    )
    
    -Accounts
      receivable
    
    
    -
    
    
    206
    
    
    757
    
    
    -
    
    
    963Inventories
    
    
    -
    
    
    5
    
    
    324
    
    
    -
    
    
    329Derivatives
      and other assets
    
    
    4
    
    
    24
    
    
    167
    
    
    -
    
    
    195Deferred
      income taxes
    
    
    2
    
    
    13
    
    
    309
    
    
    -
    
    
    324Total
      Current Assets
    
    
    8
    
    
    248
    
    
    1,689
    
    
    (58
    )
    
    1,887**Property,
      Plant and Equipment - Net**
    
    
    -
    
    
    1,947
    
    
    8,880
    
    
    -
    
    
    10,827**Investments
      in Subsidiaries**
    
    
    6,306
    
    
    645
    
    
    -
    
    
    (6,951
    )
    
    -**Investments,
      Derivatives and Other Assets**
    
    
    17
    
    
    24
    
    
    547
    
    
    (80
    )
    
    508**Goodwill**
    
    
    -
    
    
    346
    
    
    851
    
    
    -
    
    
    1,197**Other
      Intangible Assets**
    
    
    -
    
    
    5
    
    
    86
    
    
    -
    
    
    91**Long-Term
      Assets Associated****with
      Properties Held for Disposal**
    
    
    -
    
    
    -
    
    
    8
    
    
    -
    
    
    8Total
      Assets
    
    $
    6,331
    
    $
    3,215
    
    $
    12,061
    
    $
    (7,089
    )
    $
    14,518**LIABILITIES
      AND STOCKHOLDERS' EQUITY****Current
      Liabilities**Intercompany
      borrowings
    
    $
    68
    
    $
    598
    
    $
    1,189
    
    $
    (1,855
    )
    $
    -Accounts
      payable
    
    
    68
    
    
    55
    
    
    521
    
    
    -
    
    
    644Long-term
      debt due within one year
    
    
    354
    
    
    -
    
    
    109
    
    
    -
    
    
    463Derivative
      liabilities
    
    
    6
    
    
    71
    
    
    295
    
    
    -
    
    
    372Accrued
      liabilities
    
    
    10
    
    
    203
    
    
    813
    
    
    -
    
    
    1,026Total
      Current Liabilities
    
    
    506
    
    
    927
    
    
    2,927
    
    
    (1,855
    )
    
    2,505**Long-Term
      Debt**
    
    
    2,125
    
    
    -
    
    
    1,111
    
    
    -
    
    
    3,236**Noncurrent
      Liabilities**Deferred
      income taxes
    
    
    (2
    )
    
    545
    
    
    1,634
    
    
    -
    
    
    2,177Derivative
      liabilities
    
    
    -
    
    
    59
    
    
    149
    
    
    -
    
    
    208Other
      noncurrent liabilities
    
    
    -
    
    
    224
    
    
    853
    
    
    (3
    )
    
    1,074Total
      Noncurrent Liabilities
    
    
    (2
    )
    
    828
    
    
    2,636
    
    
    (3
    )
    
    3,459**Stockholders'
      Equity**
    
    
    3,702
    
    
    1,460
    
    
    5,387
    
    
    (5,231
    )
    
    5,318Total
      Liabilities and Stockholders' Equity
    
    $
    6,331
    
    $
    3,215
    
    $
    12,061
    
    $
    (7,089
    )
    $
    14,518
  - 133 -
  
 **Condensed
      Consolidating Balance Sheet as of December 31,
    2003**(Millions
      of dollars)
    
    Kerr-McGee
      Corporation
    
    Guarantor
      Subsidiaries
    
    Non-Guarantor
      Subsidiaries
    
    Eliminations
    
    Consolidated**ASSETS****Current
      Assets**Cash
      and cash equivalents
    
    $
    2
    
    $
    -
    
    $
    140
    
    $
    -
    
    $
    142Intercompany
      receivables
    
    
    7
    
    
    -
    
    
    59
    
    
    (66
    )
    
    -Accounts
      receivable
    
    
    -
    
    
    125
    
    
    458
    
    
    -
    
    
    583Inventories
    
    
    -
    
    
    6
    
    
    388
    
    
    -
    
    
    394Investment
      in equity securities
    
    
    -
    
    
    -
    
    
    510
    
    
    -
    
    
    510Derivatives
      and other assets
    
    
    -
    
    
    18
    
    
    109
    
    
    -
    
    
    127Deferred
      income taxes
    
    
    1
    
    
    18
    
    
    57
    
    
    -
    
    
    76Current
      assets associated with propertiesheld
      for disposal
    
    
    -
    
    
    -
    
    
    1
    
    
    -
    
    
    1Total
      Current Assets
    
    
    10
    
    
    167
    
    
    1,722
    
    
    (66
    )
    
    1,833**Property,
      Plant and Equipment - Net**
    
    
    -
    
    
    1,967
    
    
    5,432
    
    
    -
    
    
    7,399**Investments
      in Subsidiaries**
    
    
    3,182
    
    
    732
    
    
    -
    
    
    (3,914
    )
    
    -**Investments,
      Derivatives and Other Assets**
    
    
    10
    
    
    96
    
    
    539
    
    
    (80
    )
    
    565**Goodwill**
    
    
    -
    
    
    346
    
    
    11
    
    
    -
    
    
    357**Other
      Intangible Assets**
    
    
    -
    
    
    9
    
    
    55
    
    
    -
    
    
    64**Long-Term
      Assets Associated with Properties****Held
      for Disposal**
    
    
    -
    
    
    -
    
    
    32
    
    
    -
    
    
    32Total
      Assets
    
    $
    3,202
    
    $
    3,317
    
    $
    7,791
    
    $
    (4,060
    )
    $
    10,250**LIABILITIES
      AND STOCKHOLDERS' EQUITY****Current
      Liabilities**Intercompany
      borrowings
    
    $
    69
    
    $
    893
    
    $
    1,089
    
    $
    (2,051
    )
    $
    -Accounts
      payable
    
    
    45
    
    
    39
    
    
    391
    
    
    -
    
    
    475Long-term
      debt due within one year
    
    
    -
    
    
    -
    
    
    574
    
    
    -
    
    
    574Derivative
      liabilities
    
    
    4
    
    
    7
    
    
    343
    
    
    -
    
    
    354Accrued
      liabilities
    
    
    33
    
    
    167
    
    
    629
    
    
    -
    
    
    829Total
      Current Liabilities
    
    
    151
    
    
    1,106
    
    
    3,026
    
    
    (2,051
    )
    
    2,232**Long-Term
      Debt**
    
    
    1,829
    
    
    -
    
    
    1,252
    
    
    -
    
    
    3,081**Noncurrent
      Liabilities**Deferred
      income taxes
    
    
    (5
    )
    
    483
    
    
    857
    
    
    -
    
    
    1,335Derivative
      liabilities
    
    
    -
    
    
    2
    
    
    -
    
    
    -
    
    
    2Other
      noncurrent liabilities
    
    
    -
    
    
    211
    
    
    739
    
    
    (2
    )
    
    948Total
      Noncurrent Liabilities
    
    
    (5
    )
    
    696
    
    
    1,596
    
    
    (2
    )
    
    2,285**Long-Term
      Liabilities Associated with Properties****Held
      for Disposal**
    
    
    -
    
    
    -
    
    
    16
    
    
    -
    
    
    16**Stockholders'
      Equity**
    
    
    1,227
    
    
    1,515
    
    
    1,901
    
    
    (2,007
    )
    
    2,636Total
      Liabilities and Stockholders' Equity
    
    $
    3,202
    
    $
    3,317
    
    $
    7,791
    
    $
    (4,060
    )
    $
    10,250
 
 
 
   - 134 -
  
 **Condensed
      Consolidating Statement of Cash Flows for the Year Ended December 31,
      2004**(Millions
      of dollars)
    
    Kerr-McGee
      Corporation
    
    Guarantor
      Subsidiaries
    
    Non-Guarantor
      Subsidiaries
    
    Eliminations
    
    Consolidated**Cash
      Flow from Operating Activities**Net
      income (loss)
    
    $
    404
    
    $
    (43
    )
    $
    403
    
    $
    (360
    )
    $
    404Adjustments
      to reconcile net income (loss) to net cashprovided
      by operating activities -Depreciation,
      depletion and amortization
    
    
    -
    
    
    125
    
    
    999
    
    
    -
    
    
    1,124Deferred
      income taxes
    
    
    2
    
    
    (4
    )
    
    110
    
    
    -
    
    
    108Dry
      hole expense
    
    
    -
    
    
    2
    
    
    159
    
    
    -
    
    
    161Asset
      impairments
    
    
    -
    
    
    3
    
    
    33
    
    
    -
    
    
    36(Gain)
      loss on assets held for sale and asset
      disposal
    
    
    -
    
    
    (1
    )
    
    21
    
    
    -
    
    
    20Accretion
      expense
    
    
    -
    
    
    3
    
    
    27
    
    
    -
    
    
    30Provision
      for environmental remediation andrestoration,
      net of reimbursements
    
    
    -
    
    
    66
    
    
    26
    
    
    -
    
    
    92Equity
      in losses (earnings) of subsidiaries
    
    
    (439
    )
    
    77
    
    
    -
    
    
    362
    
    
    -Other
      noncash items affecting net income (loss)
    
    
    2
    
    
    114
    
    
    44
    
    
    -
    
    
    160Other
      net cash provided by (used in) operatingactivities
    
    
    (19
    )
    
    4
    
    
    (68
    )
    
    (2
    )
    
    (85
    )Net
      cash provided by (used in) operatingactivities
    
    
    (50
    )
    
    346
    
    
    1,754
    
    
    -
    
    
    2,050**Cash
      Flow from Investing Activities**Capital
      expenditures
    
    
    -
    
    
    (108
    )
    
    (1,154
    )
    
    -
    
    
    (1,262
    )Dry
      hole costs
    
    
    -
    
    
    (2
    )
    
    (76
    )
    
    -
    
    
    (78
    )Acquisitions,
      net of cash acquired
    
    
    -
    
    
    -
    
    
    43
    
    
    -
    
    
    43Proceeds
      from sales of assets
    
    
    -
    
    
    7
    
    
    16
    
    
    -
    
    
    23Other
      investing activities
    
    
    -
    
    
    -
    
    
    12
    
    
    -
    
    
    12Net
      cash used in investing activities
    
    
    -
    
    
    (103
    )
    
    (1,159
    )
    
    -
    
    
    (1,262
    )**Cash
      Flow from Financing Activities**Issuance
      of long-term debt
    
    
    636
    
    
    -
    
    
    41
    
    
    -
    
    
    677Issuance
      of common stock
    
    
    56
    
    
    -
    
    
    -
    
    
    -
    
    
    56Repayment
      of debt
    
    
    -
    
    
    -
    
    
    (1,278
    )
    
    -
    
    
    (1,278
    )Increase
      (decrease) in intercompany notes payable
    
    
    (437
    )
    
    (243
    )
    
    680
    
    
    -
    
    
    -Dividends
      paid
    
    
    (205
    )
    
    -
    
    
    -
    
    
    -
    
    
    (205
    )Settlement
      of Westport derivatives
    
    
    -
    
    
    -
    
    
    (101
    )
    
    -
    
    
    (101
    )Net
      cash provided by (used in) financingactivities
    
    
    50
    
    
    (243
    )
    
    (658
    )
    
    -
    
    
    (851
    )**Effects
      of Exchange Rate Changes on Cash and Cash****Equivalents**
    
    
    -
    
    
    -
    
    
    (3
    )
    
    -
    
    
    (3
    )**Net
      Decrease in Cash and Cash Equivalents**
    
    
    -
    
    
    -
    
    
    (66
    )
    
    -
    
    
    (66
    )**Cash
      and Cash Equivalents at Beginning of Year**
    
    
    2
    
    
    -
    
    
    140
    
    
    -
    
    
    142**Cash
      and Cash Equivalents at End of Year**
    
    $
    2
    
    $
    -
    
    $
    74
    
    $
    -
    
    $
    76
 
  - 135 -
  
 
 **Condensed
      Consolidating Statement of Cash Flows for the Year Ended December 31,
      2003**(Millions
      of dollars)
    
    Kerr-McGee
      Corporation
    
    Guarantor
      Subsidiaries
    
    Non-Guarantor
      Subsidiaries
    
    Eliminations
    
    Consolidated**Cash
      Flow from Operating Activities**Net
      income (loss)
    
    $
    201
    
    $
    113
    
    $
    200
    
    $
    (295
    )
    $
    219Adjustments
      to reconcile net income (loss) to net cashprovided
      by operating activities -Depreciation,
      depletion and amortization
    
    
    -
    
    
    127
    
    
    687
    
    
    -
    
    
    814Deferred
      income taxes
    
    
    (6
    )
    
    (8
    )
    
    170
    
    
    -
    
    
    156Dry
      hole expense
    
    
    -
    
    
    -
    
    
    181
    
    
    -
    
    
    181Asset
      impairments
    
    
    -
    
    
    -
    
    
    14
    
    
    -
    
    
    14Gain
      on assets held for sale and asset disposal
    
    
    -
    
    
    (12
    )
    
    (28
    )
    
    -
    
    
    (40
    )Accretion
      expense
    
    
    -
    
    
    2
    
    
    23
    
    
    -
    
    
    25Cumulative
      effect of change in accounting principle
    
    
    -
    
    
    1
    
    
    34
    
    
    -
    
    
    35Provision
      for environmental remediation andrestoration,
      net of reimbursements
    
    
    -
    
    
    31
    
    
    31
    
    
    -
    
    
    62Equity
      in losses (earnings) of subsidiaries
    
    
    (227
    )
    
    65
    
    
    -
    
    
    162
    
    
    -Other
      noncash items affecting net income (loss)
    
    
    1
    
    
    15
    
    
    78
    
    
    -
    
    
    94Other
      net cash provided by (used in) operatingactivities
    
    
    3
    
    
    (138
    )
    
    93
    
    
    -
    
    
    (42
    )Net
      cash provided by (used in) operatingactivities
    
    
    (28
    )
    
    196
    
    
    1,483
    
    
    (133
    )
    
    1,518**Cash
      Flow from Investing Activities**Capital
      expenditures
    
    
    -
    
    
    (129
    )
    
    (852
    )
    
    -
    
    
    (981
    )Dry
      hole costs
    
    
    -
    
    
    -
    
    
    (181
    )
    
    -
    
    
    (181
    )Acquisitions,
      net of cash acquired
    
    
    -
    
    
    -
    
    
    (110
    )
    
    -
    
    
    (110
    )Proceeds
      from sales of assets
    
    
    -
    
    
    8
    
    
    296
    
    
    -
    
    
    304Other
      investing activities
    
    
    -
    
    
    -
    
    
    17
    
    
    -
    
    
    17Net
      cash used in investing activities
    
    
    -
    
    
    (121
    )
    
    (830
    )
    
    -
    
    
    (951
    )**Cash
      Flow from Financing Activities**Issuance
      of long-term debt
    
    
    -
    
    
    -
    
    
    31
    
    
    -
    
    
    31Repayment
      of debt
    
    
    (18
    )
    
    -
    
    
    (351
    )
    
    -
    
    
    (369
    )Increase
      (decrease) in intercompany notes payable
    
    
    226
    
    
    (75
    )
    
    (152
    )
    
    1
    
    
    -Dividends
      paid
    
    
    (181
    )
    
    -
    
    
    (134
    )
    
    134
    
    
    (181
    )Other
      financing activities
    
    
    -
    
    
    -
    
    
    1
    
    
    (2
    )
    
    (1
    )Net
      cash provided by (used in) financingactivities
    
    
    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
 
  - 136 -
  
 **Condensed
      Consolidating Statement of Cash Flows for the Year Ended December 31,
      2002**(Millions
      of dollars)
    
    Kerr-McGee
      Corporation
    
    Guarantor
      Subsidiaries
    
    Non-Guarantor
      Subsidiaries
    
    Eliminations
    
    Consolidated**Cash
      Flow from Operating Activities**Net
      income (loss)
    
    $
    (485
    )
    $
    503
    
    $
    (709
    )
    $
    206
    
    $
    (485
    )Adjustments
      to reconcile net income (loss) to net cashprovided
      by operating activities -Depreciation,
      depletion and amortization
    
    
    -
    
    
    124
    
    
    760
    
    
    -
    
    
    884Deferred
      income taxes
    
    
    -
    
    
    9
    
    
    (121
    )
    
    -
    
    
    (112
    )Dry
      hole expense
    
    
    -
    
    
    -
    
    
    113
    
    
    -
    
    
    113Asset
      impairments
    
    
    -
    
    
    3
    
    
    649
    
    
    -
    
    
    652Loss
      on assets held for sale and asset disposal
    
    
    -
    
    
    -
    
    
    100
    
    
    -
    
    
    100Provision
      for environmental remediation andrestoration,
      net of reimbursements
    
    
    -
    
    
    -
    
    
    89
    
    
    -
    
    
    89Equity
      in losses (earnings) of subsidiaries
    
    
    465
    
    
    (25
    )
    
    -
    
    
    (440
    )
    
    -Other
      noncash items affecting net income (loss)
    
    
    -
    
    
    (26
    )
    
    102
    
    
    -
    
    
    76Other
      net cash provided by (used in) operatingactivities
    
    
    (16
    )
    
    341
    
    
    (194
    )
    
    -
    
    
    131Net
      cash provided by (used in) operatingactivities
    
    
    (36
    )
    
    929
    
    
    789
    
    
    (234
    )
    
    1,448**Cash
      Flow from Investing Activities**Capital
      expenditures
    
    
    -
    
    
    (179
    )
    
    (980
    )
    
    -
    
    
    (1,159
    )Dry
      hole costs
    
    
    -
    
    
    -
    
    
    (113
    )
    
    -
    
    
    (113
    )Acquisitions,
      net of cash acquired
    
    
    -
    
    
    -
    
    
    (24
    )
    
    -
    
    
    (24
    )Proceeds
      from sales of assets
    
    
    -
    
    
    61
    
    
    695
    
    
    -
    
    
    756Other
      investing activities
    
    
    -
    
    
    (700
    )
    
    647
    
    
    -
    
    
    (53
    )Net
      cash provided by (used in) investingactivities
    
    
    -
    
    
    (818
    )
    
    225
    
    
    -
    
    
    (593
    )**Cash
      Flow from Financing Activities**Issuance
      of long-term debt
    
    
    350
    
    
    -
    
    
    68
    
    
    -
    
    
    418Issuance
      of common stock
    
    
    5
    
    
    -
    
    
    -
    
    
    -
    
    
    5Repayment
      of debt
    
    
    -
    
    
    -
    
    
    (1,101
    )
    
    -
    
    
    (1,101
    )Increase
      (decrease) in intercompany notes payable
    
    
    (135
    )
    
    (112
    )
    
    248
    
    
    (1
    )
    
    -Dividends
      paid
    
    
    (181
    )
    
    -
    
    
    (235
    )
    
    235
    
    
    (181
    )Net
      cash provided by (used in) financingactivities
    
    
    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
 
 
  - 137 -
 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, 2004, are reflected in the following table:
 
 (Millions
      of dollars)
    
    Property
      Acquisition Costs(1)
    
    Exploration
      Costs(2)
    
    Development
      Costs(3)
    
    Total2004
      -United
      States
    
    $
    3,405
    
    $
    231
    
    $
    746
    
    $
    4,382North
      Sea
    
    
    4
    
    
    36
    
    
    107
    
    
    147China
    
    
    1
    
    
    19
    
    
    75
    
    
    95Other
      international
    
    
    25
    
    
    51
    
    
    -
    
    
    76Total
      finding, development andacquisition
      costs incurred
    
    
    3,435
    
    
    337
    
    
    928
    
    
    4,700Asset
      retirement costs(4)
    
    
    72
    
    
    -
    
    
    14
    
    
    86Total
      costs incurred
    
    $
    3,507
    
    $
    337
    
    $
    942
    
    $
    4,7862003
      -United
      States
    
    $
    121
    
    $
    357
    
    $
    473
    
    $
    951North
      Sea
    
    
    46
    
    
    43
    
    
    55
    
    
    144China
    
    
    1
    
    
    31
    
    
    45
    
    
    77Other
      international
    
    
    1
    
    
    49
    
    
    -
    
    
    50Total
      finding, development andacquisition
      costs incurred
    
    
    169
    
    
    480
    
    
    573
    
    
    1,222Asset
      retirement costs(4)
    
    
    9
    
    
    -
    
    
    2
    
    
    11Total
      costs incurred
    
    $
    178
    
    $
    480
    
    $
    575
    
    $
    1,2332002
      -United
      States
    
    $
    89
    
    $
    206
    
    $
    426
    
    $
    721North
      Sea
    
    
    55
    
    
    14
    
    
    296
    
    
    365China
    
    
    -
    
    
    14
    
    
    16
    
    
    30Other
      international
    
    
    2
    
    
    44
    
    
    -
    
    
    46Total
      continuing operations
    
    
    146
    
    
    278
    
    
    738
    
    
    1,162Discontinued
      operations
    
    
    2
    
    
    1
    
    
    5
    
    
    8Total
      costs incurred
    
    $
    148
    
    $
    279
    
    $
    743
    
    $
    1,170
 
 
 (1)
    Includes
      $2.374 billion, $103 million and $69 million applicable to purchases of
      proved reserves in place in 2004, 2003 and 2002,
    respectively.
 
 (2)
    Exploration
      costs include delay rentals, exploratory dry holes, dry hole and bottom
      hole contributions, geological and geophysical costs, costs of carrying
      and retaining properties, and capital expenditures, such as costs of
      drilling and equipping successful exploratory
wells.
 
 (3)
    Development
      costs include costs incurred to obtain access to proved reserves
      (surveying, clearing ground, building roads), to drill and equip
      development wells, and to acquire, construct and install production
      facilities and improved-recovery systems. Development costs also include
      costs of developmental dry holes.
 
 (4)
    Assetretirementcosts 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 16 regarding the 2003 adoption of FAS No.
143.
 
 
 
 
  - 138 -
  **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, 2004, consist of the following:
 
 Loss
      (Gain) onHeld
      for Sale
    
    Income
    
    Results
      ofProduction
    
    
    
    
    
    
    Depreciation,
    
    Properties
    
    Tax
    
    Operations,(Lifting)
    
    Other
    
    
    Exploration
    
    Depletion
      and
    
    and
      Asset
    
    Expense
    
    Producing(Millions
      of dollars)
    
    Revenues
    
    Costs
    
    Costs
    
    
    Expenses
    
    Accretion
    
    Impairments
    
    (Benefit)
    
    Activities2004
      -United
      States
    
    $
    2,520
    
    $
    385
    
    $
    188
    
    
    $
    265
    
    $
    620
    
    $
    50
    
    $
    355
    
    $
    657North
      Sea
    
    
    741
    
    
    158
    
    
    53
    
    
    
    32
    
    
    229
    
    
    8
    
    
    116
    
    
    145China
    
    
    92
    
    
    13
    
    
    5
    
    
    
    11
    
    
    22
    
    
    (1
    )
    
    14
    
    
    28Other
      international
    
    
    -
    
    
    -
    
    
    6
    
    
    
    48
    
    
    1
    
    
    -
    
    
    (19
    )
    
    (36
    )Total
      crude oil andnatural
      gas activities
    
    
    3,353
    
    
    556
    
    
    252
    (1)
    
    
    356
    
    
    872
    
    
    57
    
    
    466
    
    
    794Other
      (2)
    
    
    502
    
    
    -
    
    
    501
    
    
    
    -
    
    
    12
    
    
    -
    
    
    (3
    )
    
    (8
    )Total
    
    $
    3,855
    
    $
    556
    
    $
    753
    
    
    $
    356
    
    $
    884
    
    $
    57
    
    $
    463
    
    $
    7862003-United
      States
    
    $
    1,775
    
    $
    235
    
    $
    149
    
    
    $
    249
    
    $
    400
    
    $
    (4
    )
    $
    255
    
    $
    491North
      Sea
    
    
    783
    
    
    146
    
    
    60
    
    
    
    27
    
    
    220
    
    
    (15
    )
    
    147
    
    
    198China
    
    
    23
    
    
    5
    
    
    8
    
    
    
    19
    
    
    2
    
    
    (12
    )
    
    1
    
    
    -Other
      international
    
    
    -
    
    
    -
    
    
    6
    
    
    
    59
    
    
    1
    
    
    -
    
    
    (22
    )
    
    (44
    )Total
      crude oil andnatural
      gas activities
    
    
    2,581
    
    
    386
    
    
    223
    (1)
    
    
    354
    
    
    623
    
    
    (31
    )
    
    381
    
    
    645Other
      (2)
    
    
    342
    
    
    -
    
    
    355
    
    
    
    -
    
    
    11
    
    
    -
    
    
    (8
    )
    
    (16
    )Total
      from continuingoperations
    
    
    2,923
    
    
    386
    
    
    578
    
    
    
    354
    
    
    634
    
    
    (31
    )
    
    373
    
    
    629Discontinued
      operations
    
    
    6
    
    
    1
    
    
    2
    
    
    
    -
    
    
    -
    
    
    6
    
    
    -
    
    
    (3
    )Total
    
    $
    2,929
    
    $
    387
    
    $
    580
    
    
    $
    354
    
    $
    634
    
    $
    (25
    )
    $
    373
    
    $
    6262002-United
      States
    
    $
    1,367
    
    $
    254
    
    $
    106
    
    
    $
    159
    
    $
    389
    
    $
    111
    
    $
    116
    
    $
    232North
      Sea
    
    
    920
    
    
    244
    
    
    60
    
    
    
    48
    
    
    288
    
    
    706
    
    
    33
    
    
    (459
    )China
    
    
    30
    
    
    10
    
    
    5
    
    
    
    5
    
    
    3
    
    
    -
    
    
    2
    
    
    5Other
      international
    
    
    29
    
    
    7
    
    
    14
    
    
    
    61
    
    
    -
    
    
    5
    
    
    (17
    )
    
    (41
    )Total
      crude oil andnatural
      gas activities
    
    
    2,346
    
    
    515
    
    
    185
    (1)
    
    
    273
    
    
    680
    
    
    822
    
    
    134
    
    
    (263
    )Other
      (2)
    
    
    104
    
    
    -
    
    
    105
    
    
    
    -
    
    
    10
    
    
    -
    
    
    (4
    )
    
    (7
    )Total
      from continuingoperations
    
    
    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
    )
 (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.
 
 
  - 139 -
  
 The
table below presents the company’s average per-unit sales price of crude oil and
natural gas and lifting costs (lease operating expense and production and ad
valorem taxes) per barrel of oil equivalent from continuing operations for each
of the three years in the period ended December 31, 2004. Natural gas production
has been converted to a barrel of oil equivalent based on approximate relative
heating value (6 Mcf equals 1 barrel).
 
 **2004**
    
    2003
    
    2002Average
      realized price of crude oil sold (per barrel) -(1)United
      States
    
    **$**
    **29.11**
    
    $
    26.14
    
    $
    21.56North
      Sea
    
    
    **26.50**
    
    
    25.82
    
    
    22.41China
    
    
    **32.37**
    
    
    29.66
    
    
    24.84Other
      international
    
    
    **-**
    
    
    -
    
    
    20.28Average
    
    
    **28.23**
    
    
    26.04
    
    
    22.04Average
      realized price of natural gas sold (per Mcf) -(1)United
      States
    
    **$**
    **5.24**
    
    $
    4.56
    
    $
    3.04North
      Sea
    
    
    **4.06**
    
    
    3.09
    
    
    2.35Average
    
    
    **5.13**
    
    
    4.37
    
    
    2.95Lifting
      costs (per barrel of oil equivalent) -United
      States
    
    **$**
    **4.63**
    
    $
    3.57
    
    $
    3.64North
      Sea
    
    
    **5.56**
    
    
    4.52
    
    
    5.64China
    
    
    **4.37**
    
    
    6.02
    
    
    8.08Other
      international
    
    
    **-**
    
    
    -
    
    
    5.05Average
    
    
    **4.86**
    
    
    3.90
    
    
    4.45
 
 (1)
    Includes
      the results of the company's hedging program, which reduced the average
      price of crude oil sold by $8.53, $2.46 and $1.13 per barrel and natural
      gas sold by $.75, $.55 and $.01 per Mcf in 2004, 2003 and 2002,
      respectively.
 
 
 31.
    **Capitalized
      Costs Related to Crude Oil and Natural Gas
    Activities**
 
 Capitalized
costs related to crude oil and natural gas activities and the related reserves
for depreciation, depletion and amortization at the end of 2004 and 2003 are set
forth in the table below.
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    (1)Capitalized
      costs -Proved
      properties
    
    **$**
    **14,538**
    
    $
    10,875Unproved
      properties
    
    
    **1,753**
    
    
    837Other
    
    
    **439**
    
    
    356Total
    
    
    **16,730**
    
    
    12,068Assets
      held for disposal
    
    
    **6**
    
    
    467Total
    
    
    **16,736**
    
    
    12,535Reserves
      for depreciation, depletion and amortization -Proved
      properties
    
    
    **6,524**
    
    
    5,403Unproved
      properties
    
    
    **222**
    
    
    206Other
    
    
    **120**
    
    
    100Total
    
    
    **6,866**
    
    
    5,709Assets
      held for disposal
    
    
    **1**
    
    
    439Total
    
    
    **6,867**
    
    
    6,148Net
      capitalized costs
    
    **$**
    **9,869**
    
    $
    6,387
 
 (1)
    Certain
      prior year balances were reclassified to intangible assets.  See
      Note 10.
  - 140 -
 **
 **Exploratory
Drilling Costs**
 
 Under
the successful efforts method of accounting, the costs of drilling an
exploratory well are capitalized pending determination of whether proved
reserves can be attributed to the discovery. In the case of onshore wells and
offshore wells in relatively shallow water, that determination usually can be
made upon or shortly after cessation of exploratory drilling operations.
However, such determination may take longer in other areas (specifically,
deepwater exploration and international locations) depending upon, among other
things, (i) the amount of hydrocarbons discovered, (ii) the outcome of planned
geological and engineering studies, (iii) the need for additional appraisal
drilling to determine whether the discovery is sufficient to support an economic
development plan and (iv) the requirement for government sanctioning in certain
international locations before proceeding with development activities. As a
consequence, the company has capitalized costs associated with exploratory wells
on its Consolidated Balance Sheet at any point in time that may be charged to
earnings in a future period if management determines that commercial quantities
of hydrocarbons have not been discovered.
 
 ***Initial
and Ongoing Assessment of Deferred Exploratory Drilling
Costs*** ** - When
initial drilling operations are complete, management determines whether the well
has discovered oil and gas reserves and, if so, whether those reserves can be
classified as proved. Often, the determination of whether proved reserves can be
recorded under strict Securities and Exchange Commission (SEC) guidelines cannot
be made when drilling is completed. In those situations where management
believes that commercial hydrocarbons have not been discovered, the exploratory
drilling costs are reflected in the Consolidated Statement of Operations as dry
hole costs (a component of exploration expense). Where sufficient hydrocarbons
have been discovered to justify further exploration and/or appraisal activities,
exploratory drilling costs are deferred on the Consolidated Balance Sheet
pending the outcome of those activities.
 
 At the
end of each quarter, operating and financial management review the status of all
deferred exploratory drilling costs in light of ongoing exploration activities -
in particular, whether the company is making sufficient progress in its ongoing
exploration and appraisal efforts or, in the case of discoveries requiring
government sanctioning, whether development negotiations are under way and
proceeding as planned. If management determines that future appraisal drilling
or development activities are not likely to occur in the future, any associated
exploratory well costs are expensed in that period.
 
 ***Financial
Statement Balances*** - The
following table presents the amount of capitalized exploratory drilling costs at
December 31 for each of the last three years, and changes in those amounts
during the years then ended:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Balance,
      January 1
    
    **$**
    **143**
    
    $
    117
    
    $
    124Additions,
      pending determination of proved reserves
    
    
    **81**
    
    
    71
    
    
    49Reclassification
      to proved oil and gas properties
    
    
    **(20**
    **)**
    
    (39
    )
    
    (1
    )Capitalized
      exploratory well costs charged to expense
    
    
    **(68**
    **)**
    
    (6
    )
    
    (24
    )Sales
      and conveyances
    
    
    **-**
    
    
    -
    
    
    (31
    )Balance,
      December 31
    
    **$**
    **136**
    
    $
    143
    
    $
    117
 
  - 141 -
  At
December 31, 2004, the company had capitalized costs of approximately $136
million associated with ongoing exploration and/or appraisal activities,
primarily in the deepwater Gulf of Mexico, China, Alaska and Brazil. The
following table presents the total amount of exploratory drilling costs at
year-end 2004 by geographic area, including the length of time such costs have
been carried on the Consolidated Balance Sheet:
 
 Costs
      Incurred(Millions
      of dollars)
    
    Total
    
    **2004**
    
    2003
    
    2002
    
    Prior
      to 2002Gulf
      of Mexico
    
    $
    59
    
    **$**
    **32**
    
    $
    27
    
    $
    -
    
    $
    -China
    
    
    36
    
    
    **9**
    
    
    7
    
    
    1
    
    
    19Alaska
    
    
    20
    
    
    **20**
    
    
    -
    
    
    -
    
    
    -Brazil
    
    
    10
    
    
    **10**
    
    
    -
    
    
    -
    
    
    -North
      Sea
    
    
    6
    
    
    **5**
    
    
    1
    
    
    -
    
    
    -Other
    
    
    5
    
    
    **5**
    
    
    -
    
    
    -
    
    
    -Total
      capitalized exploratory drilling costs
    
    $
    136
    
    **$**
    **81**
    
    $
    35
    
    $
    1
    
    $
    19
 
 ***Analysis
of Exploratory Costs at December 31, 2004*** - The
vast majority of exploratory drilling costs deferred at year-end are associated
with wells that are either (i) drilling at December 31, (ii) in an area
requiring a major capital expenditure or additional appraisal activities before
recording proved reserves such as the deepwater Gulf of Mexico, Alaska, Brazil
and China, or (iii) subject to government review and approval of our development
plans. The company has no deferred drilling costs associated with areas that
require gas sales contracts or project financing in order to proceed with
development plans. The following discussion describes major projects shown in
the table above with costs deferred beyond one year from the balance sheet
date.
 
 *China
-* Costs
incurred in China prior to 2004 are associated with 13 successful exploratory
wells in the CFD 11-6/12-1 area on Blocks 04/36 and 05/36 in Bohai Bay. Such
costs have been deferred pending government approval of a sanctioned development
plan. The formal development plan for the CFD 11-6/12-1 area is currently in the
process of final approval by China National Offshore Oil Corporation (CNOOC) and
the Chinese government. The company believes approval will be received in 2005,
at which time the assessment of proved reserves for this area also is expected
to be completed.
 
 *Deepwater
Gulf of Mexico* -
Costs incurred in the deepwater Gulf of Mexico prior to 2004 relate to two
exploration wells that are located in areas that require a major capital
expenditure and/or additional appraisal activities before the determination of
proved reserves can be made. In the case of the first well ($25 million), the
drilling rig was released in October 2003 after successfully encountering
hydrocarbons. The company is actively planning appraisal drilling at this time.
Management expects that appraisal drilling will occur during 2005; however, if
management determines during the year that future appraisal drilling is not
likely to occur, all capitalized costs may be charged to exploration expense. In
the case of the second well ($2 million), additional appraisal drilling
activities occurred during 2004 and development planning is currently under
way.
 
 
 
 32.
    **Crude
      Oil, Condensate, Natural Gas Liquids and Natural Gas Net Reserves
      (Unaudited)**
 
 The
following tables show estimates of proved reserves prepared by the
company’s engineers and, for certain acquired Westport properties, by
third-party reserve engineers, in accordance with the SEC definitions. Data is
shown for crude oil in millions of barrels, for natural gas in billions of cubic
feet (Bcf) at a pressure base of 14.73 pounds per square inch and for total
proved reserves in millions of barrels of oil equivalent. For total proved
reserves, natural gas is converted to barrels of oil equivalent using a
conversion factor of six thousand cubic feet of natural gas per barrel.
 
 - 142 -
 During
2004, the company expanded the involvement of third-party engineers in its
reserve estimation processes. In July 2004, the company engaged Netherland,
Sewell & Associates, Inc. (NSAI), to provide independent third-party review
of the company’s procedures and methods for reserves estimation. The purpose of
NSAI’s review was to verify that the reserve estimates prepared by the company’s
internal technical staff are in accordance with the guidelines and definitions
of the SEC using generally accepted petroleum engineering and evaluation
principles. During 2004, NSAI’s review covered approximately 50% of the
company’s year-end 2003 proved reserve base (43% of year-end 2004 proved
reserves). NSAI determined that the procedures and methods were reasonable and
estimates had been prepared in accordance with Rule 4-10(a) of SEC Regulation
S-X and generally accepted petroleum engineering and evaluation principles. A
copy of the NSAI report is included as exhibit 99 to this annual report on Form 10-K.
 
 In
addition to NSAI’s review, certain reserves acquired in the Westport merger in
June 2004 were estimated by Ryder Scott Company L.P. under an ongoing agreement
with Westport. Following the merger, Kerr-McGee retained Ryder Scott Company
L.P. to complete a year-end 2004 evaluation of both the Greater Natural Buttes
and Moxa Arch fields, both of which were major assets acquired in the Westport
transaction. Including these fields, approximately 55% of the company’s 2004
proved reserve base was reviewed by a third party in 2004. In 2005, the company
plans to expand third-party reviews to cover approximately 75 percent of its
year-end 2004 proved reserves.
 
 The
company’s estimates of proved reserves are derived from data prepared by its
engineers using available geological and reservoir data, as well as production
performance data. These estimates are reviewed annually and revised, either
upward or downward, as warranted by additional data. Revisions of previous
estimates can occur due to changes in, among other things, reservoir
performance, prices, economic conditions and governmental restrictions. For
example, a decrease in commodity price could result in a decrease in proved
reserves as the economic limit of a reservoir might be reached sooner.
Conversely, an improvement in reservoir performance could result in an increase
in proved reserves, indicating higher ultimate recovery from previous
estimates.
 
 The
company’s engineering staff is highly skilled with average industry experience
of over 20 years. The company relies primarily on its internal engineering
expertise, augmented by third-party engineering oversight and advice to ensure
objective estimates of the company’s proved reserves. The company mitigates the
inherent risks associated with reserve estimation through a comprehensive
reserves administration process. The company’s process includes:
 
 ·
    Independent
      third-party procedures and methods assessment
 ·
    Internal
      peer review and third-party assessment of all individually significant
      reserve additions (defined as those in excess of 5 million barrels of oil
      equivalent on a net basis)
 ·
    Annual
      internal review of about 80% of the company’s total proved
      reserves
 
 The
following tables summarize changes in the estimated quantities of proved
reserves for the three years ended December 31, 2004. As described in Note 2, we
completed a merger with Westport in 2004, which resulted in reserve additions of
281 million barrels of oil equivalent. During 2002, we experienced significant
downward reserve revisions primarily related to the Leadon field in the U.K.
North Sea. Additionally, during 2002 we completed a divestiture program to
rationalize noncore oil and gas properties. For further details related to the
Leadon field and asset divestitures refer to discussion included in Note 25.
 
 - 143 -
 Continuing
      OperationsTotal**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, 2001
    
    
    317
    
    
    388
    
    
    35
    
    
    39
    
    
    779
    
    
    62
    
    
    841Revisions
      of previous estimates
    
    
    8
    
    
    (101
    )
    
    1
    
    
    -
    
    
    (92
    )
    
    -
    
    
    (92
    )Purchases
      of reserves in place
    
    
    1
    
    
    13
    
    
    -
    
    
    -
    
    
    14
    
    
    -
    
    
    14Sales
      of reserves in place
    
    
    (62
    )
    
    (61
    )
    
    -
    
    
    (37
    )
    
    (160
    )
    
    (51
    )
    
    (211
    )Extensions,
      discoveries and other additions
    
    
    6
    
    
    1
    
    
    -
    
    
    -
    
    
    7
    
    
    -
    
    
    7Production
    
    
    (29
    )
    
    (38
    )
    
    (1
    )
    
    (2
    )
    
    (70
    )
    
    (2
    )
    
    (72
    )Balance
      December 31, 2002
    
    
    241
    
    
    202
    
    
    35
    
    
    -
    
    
    478
    
    
    9
    
    
    487Revisions
      of previous estimates
    
    
    7
    
    
    (7
    )
    
    2
    
    
    -
    
    
    2
    
    
    -
    
    
    2Purchases
      of reserves in place
    
    
    3
    
    
    12
    
    
    -
    
    
    -
    
    
    15
    
    
    -
    
    
    15Sales
      of reserves in place
    
    
    (16
    )
    
    -
    
    
    (3
    )
    
    -
    
    
    (19
    )
    
    (9
    )
    
    (28
    )Extensions,
      discoveries and other additions
    
    
    55
    
    
    14
    
    
    6
    
    
    -
    
    
    75
    
    
    -
    
    
    75Production
    
    
    (28
    )
    
    (26
    )
    
    (1
    )
    
    -
    
    
    (55
    )
    
    -
    
    
    (55
    )Balance
      December 31, 2003
    
    
    262
    
    
    195
    
    
    39
    
    
    -
    
    
    496
    
    
    -
    
    
    496Revisions
      of previous estimates
    
    
    9
    
    
    6
    
    
    1
    
    
    -
    
    
    16
    
    
    -
    
    
    16Purchases
      of reserves in place
    
    
    67
    
    
    -
    
    
    -
    
    
    -
    
    
    67
    
    
    -
    
    
    67Sales
      of reserves in place
    
    
    (10
    )
    
    -
    
    
    -
    
    
    -
    
    
    (10
    )
    
    -
    
    
    (10
    )Extensions,
      discoveries and other additions
    
    
    14
    
    
    1
    
    
    -
    
    
    -
    
    
    15
    
    
    -
    
    
    15Production
    
    
    (32
    )
    
    (23
    )
    
    (3
    )
    
    -
    
    
    (58
    )
    
    -
    
    
    (58
    )Balance
      December 31, 2004
    
    
    310
    
    
    179
    
    
    37
    
    
    -
    
    
    526
    
    
    -
    
    
    526**Natural
      Gas**(Billions
      of cubic feet)**Proved
      developed and undeveloped reserves -**Balance
      December 31, 2001
    
    
    2,945
    
    
    527
    
    
    -
    
    
    -
    
    
    3,472
    
    
    535
    
    
    4,007Revisions
      of previous estimates
    
    
    (70
    )
    
    (7
    )
    
    -
    
    
    -
    
    
    (77
    )
    
    -
    
    
    (77
    )Purchases
      of reserves in place
    
    
    17
    
    
    16
    
    
    -
    
    
    -
    
    
    33
    
    
    -
    
    
    33Sales
      of reserves in place
    
    
    (76
    )
    
    (9
    )
    
    -
    
    
    -
    
    
    (85
    )
    
    (535
    )
    
    (620
    )Extensions,
      discoveries and other additions
    
    
    204
    
    
    6
    
    
    -
    
    
    -
    
    
    210
    
    
    -
    
    
    210Production
    
    
    (241
    )
    
    (37
    )
    
    -
    
    
    -
    
    
    (278
    )
    
    -
    
    
    (278
    )Balance
      December 31, 2002
    
    
    2,779
    
    
    496
    
    
    -
    
    
    -
    
    
    3,275
    
    
    -
    
    
    3,275Revisions
      of previous estimates
    
    
    (10
    )
    
    11
    
    
    -
    
    
    -
    
    
    1
    
    
    -
    
    
    1Purchases
      of reserves in place
    
    
    57
    
    
    30
    
    
    -
    
    
    -
    
    
    87
    
    
    -
    
    
    87Sales
      of reserves in place
    
    
    (77
    )
    
    -
    
    
    -
    
    
    -
    
    
    (77
    )
    
    -
    
    
    (77
    )Extensions,
      discoveries and other additions
    
    
    152
    
    
    8
    
    
    -
    
    
    -
    
    
    160
    
    
    -
    
    
    160Production
    
    
    (230
    )
    
    (35
    )
    
    -
    
    
    -
    
    
    (265
    )
    
    -
    
    
    (265
    )Balance
      December 31, 2003
    
    
    2,671
    
    
    510
    
    
    -
    
    
    -
    
    
    3,181
    
    
    -
    
    
    3,181Revisions
      of previous estimates
    
    
    86
    
    
    (98
    )
    
    -
    
    
    -
    
    
    (12
    )
    
    -
    
    
    (12
    )Purchases
      of reserves in place
    
    
    1,289
    
    
    -
    
    
    -
    
    
    -
    
    
    1,289
    
    
    -
    
    
    1,289Sales
      of reserves in place
    
    
    (27
    )
    
    -
    
    
    -
    
    
    -
    
    
    (27
    )
    
    -
    
    
    (27
    )Extensions,
      discoveries and other additions
    
    
    59
    
    
    -
    
    
    -
    
    
    -
    
    
    59
    
    
    -
    
    
    59Production
    
    
    (306
    )
    
    (31
    )
    
    -
    
    
    -
    
    
    (337
    )
    
    -
    
    
    (337
    )Balance
      December 31, 2004
    
    
    3,772
    
    
    381
    
    
    -
    
    
    -
    
    
    4,153
    
    
    -
    
    
    4,153
  - 144 -
    Continuing
      Operations**Crude
      Oil, Condensate and Natural Gas Liquids**(Millions
      of barrels)
    
    United
      States
    
    North
      Sea
    
    China
    
    Other
      International
    
    Total
      Continuing Operations
    
    Discontinued
      Operations
    
    Total**Proved
      developed reserves -**December
      31, 2002
    
    
    147
    
    
    130
    
    
    2
    
    
    -
    
    
    279
    
    
    5
    
    
    284December
      31, 2003
    
    
    122
    
    
    125
    
    
    -
    
    
    -
    
    
    247
    
    
    -
    
    
    247December
      31, 2004
    
    
    197
    
    
    120
    
    
    16
    
    
    -
    
    
    333
    
    
    -
    
    
    333**Natural
      Gas**(Billions
      of cubic feet)Proved
      developed reserves -December
      31, 2002
    
    
    1,658
    
    
    168
    
    
    -
    
    
    -
    
    
    1,826
    
    
    -
    
    
    1,826December
      31, 2003
    
    
    1,502
    
    
    113
    
    
    -
    
    
    -
    
    
    1,615
    
    
    -
    
    
    1,615December
      31, 2004
    
    
    2,620
    
    
    135
    
    
    -
    
    
    -
    
    
    2,755
    
    
    -
    
    
    2,755
 
 The
following presents the company's barrel of oil equivalent proved developed and
undeveloped reserves based on approximate heating value (6 Mcf equals 1
barrel).
 
 Continuing
      Operations**Barrels
      of Oil Equivalent**(Millions of barrels)
    
    United
      States
    
    North
      Sea
    
    China
    
    Other
      International
    
    Total
      Continuing Operations
    
    Discontinued
      Operations
    
    TotalProved
      developed and undeveloped reserves -Balance
      December 31, 2001
    
    
    808
    
    
    476
    
    
    35
    
    
    39
    
    
    1,358
    
    
    151
    
    
    1,509Revisions
      of previous estimates
    
    
    (4
    )
    
    (102
    )
    
    1
    
    
    -
    
    
    (105
    )
    
    -
    
    
    (105
    )Purchases
      of reserves in place
    
    
    3
    
    
    16
    
    
    -
    
    
    -
    
    
    19
    
    
    -
    
    
    19Sales
      of reserves in place
    
    
    (74
    )
    
    (63
    )
    
    -
    
    
    (37
    )
    
    (174
    )
    
    (140
    )
    
    (314
    )Extensions,
      discoveries and other additions
    
    
    40
    
    
    2
    
    
    -
    
    
    -
    
    
    42
    
    
    -
    
    
    42Production
    
    
    (69
    )
    
    (44
    )
    
    (1
    )
    
    (2
    )
    
    (116
    )
    
    (2
    )
    
    (118
    )Balance
      December 31, 2002
    
    
    704
    
    
    285
    
    
    35
    
    
    -
    
    
    1,024
    
    
    9
    
    
    1,033Revisions
      of previous estimates
    
    
    5
    
    
    (5
    )
    
    2
    
    
    -
    
    
    2
    
    
    -
    
    
    2Purchases
      of reserves in place
    
    
    12
    
    
    17
    
    
    -
    
    
    -
    
    
    29
    
    
    -
    
    
    29Sales
      of reserves in place
    
    
    (29
    )
    
    -
    
    
    (3
    )
    
    -
    
    
    (32
    )
    
    (9
    )
    
    (41
    )Extensions,
      discoveries and other additions
    
    
    81
    
    
    15
    
    
    6
    
    
    -
    
    
    102
    
    
    -
    
    
    102Production
    
    
    (66
    )
    
    (32
    )
    
    (1
    )
    
    -
    
    
    (99
    )
    
    -
    
    
    (99
    )Balance
      December 31, 2003
    
    
    707
    
    
    280
    
    
    39
    
    
    -
    
    
    1,026
    
    
    -
    
    
    1,026Revisions
      of previous estimates
    
    
    24
    
    
    (11
    )
    
    1
    
    
    -
    
    
    14
    
    
    -
    
    
    14Purchases
      of reserves in place
    
    
    282
    
    
    -
    
    
    -
    
    
    -
    
    
    282
    
    
    -
    
    
    282Sales
      of reserves in place
    
    
    (15
    )
    
    -
    
    
    -
    
    
    -
    
    
    (15
    )
    
    -
    
    
    (15
    )Extensions,
      discoveries and other additions
    
    
    24
    
    
    1
    
    
    -
    
    
    -
    
    
    25
    
    
    -
    
    
    25Production
    
    
    (83
    )
    
    (28
    )
    
    (3
    )
    
    -
    
    
    (114
    )
    
    -
    
    
    (114
    )Balance
      December 31, 2004
    
    
    939
    
    
    242
    
    
    37
    
    
    -
    
    
    1,218
    
    
    -
    
    
    1,218
 
 
 Continuing
      Operations(Millions
      of equivalent barrels)
    United
      States
    North
      Sea
    China
    Other
      International
    Total
      Continuing Operations
    Discontinued
      Operations
    TotalProved
      developed reserves -December
      31, 2002
    423
    158
    2
    -
    583
    5
    588December
      31, 2003
    372
    144
    -
    -
    516
    -
    516December
      31, 2004
    634
    142
    16
    -
    792
    -
    792Proved
      undeveloped reserves -December
      31, 2002
    281
    127
    33
    -
    441
    4
    445December
      31, 2003
    335
    136
    39
    -
    510
    -
    510December
      31, 2004
    305
    100
    21
    -
    426
    -
    426
 
 
   - 145 -
   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
proved reserves, development costs and production rates were based on the best
information available, the development and production of the oil and gas
reserves may not occur in the periods assumed. Actual prices realized, costs
incurred and production quantities may vary significantly from those used.
Therefore, such estimated future net  cash
flow computations should not be considered to represent the company's estimate
of the expected revenues or the current value of existing proved
reserves.
 StandardizedFuture
    
    
    
    Measure
      ofFuture
    
    Future
    
    Future
    
    Future
    
    Net
    
    10%
    
    DiscountedCash
    
    Production
    
    Development
    
    Income
    
    Cash
    
    Annual
    
    Future
      Net(Millions
      of dollars)
    
    Inflows
      (1)
    
    Costs
    
    Costs
    
    Taxes
    
    Flows
    
    Discount
    
    Cash
      Flows2004United
      States
    
    $
    33,512
    
    $
    7,976
    
    $
    2,752
    
    $
    7,158
    
    $
    15,626
    
    $
    6,549
    
    $
    9,077North
      Sea
    
    
    8,927
    
    
    2,988
    
    
    999
    
    
    1,863
    
    
    3,077
    
    
    934
    
    
    2,143China
    
    
    986
    
    
    306
    
    
    83
    
    
    113
    
    
    484
    
    
    148
    
    
    336Total
    
    $
    43,425
    
    $
    11,270
    
    $
    3,834
    
    $
    9,134
    
    $
    19,187
    
    $
    7,631
    
    $
    11,556
    
    (2)2003United
      States
    
    $
    23,850
    
    $
    5,002
    
    $
    2,067
    
    $
    5,467
    
    $
    11,314
    
    $
    4,721
    
    $
    6,593North
      Sea
    
    
    7,770
    
    
    2,437
    
    
    790
    
    
    1,552
    
    
    2,991
    
    
    970
    
    
    2,021China
    
    
    1,114
    
    
    306
    
    
    130
    
    
    178
    
    
    500
    
    
    208
    
    
    292Total
    
    $
    32,734
    
    $
    7,745
    
    $
    2,987
    
    $
    7,197
    
    $
    14,805
    
    $
    5,899
    
    $
    8,906
    
    (2)2002United
      States
    
    $
    17,195
    
    $
    4,909
    
    $
    1,642
    
    $
    3,372
    
    $
    7,272
    
    $
    2,951
    
    $
    4,321North
      Sea
    
    
    7,332
    
    
    1,484
    
    
    602
    
    
    1,887
    
    
    3,359
    
    
    923
    
    
    2,436China
    
    
    1,052
    
    
    280
    
    
    154
    
    
    162
    
    
    456
    
    
    214
    
    
    242Total
      continuingoperations
    
    
    25,579
    
    
    6,673
    
    
    2,398
    
    
    5,421
    
    
    11,087
    
    
    4,088
    
    
    6,999
    
    (2)Discontinuedoperations
    
    
    224
    
    
    84
    
    
    11
    
    
    34
    
    
    95
    
    
    32
    
    
    63Total
    
    $
    25,803
    
    $
    6,757
    
    $
    2,409
    
    $
    5,455
    
    $
    11,182
    
    $
    4,120
    
    $
    7,062
 
 (1)
    Future
      cash inflows from sales of crude oil and natural gas are based on average
      year-end prices of $37.02, $29.05 and $28.61 per barrel of oil and $5.78,
      $5.77 and $3.63 per Mcf of natural gas for 2004, 2003 and 2002,
      respectively.
 
 (2)
    Estimated
      future net cash flows before income tax expense, discounted at 10%,
      totaled approximately $17.0 billion, $13.2 billion and $10.3 billion, for
      2004, 2003 and 2002, respectively.
 
  - 146 -
  The
changes in the standardized measure of future net cash flows are presented below
for each of the past three years:
 
 (Millions
      of dollars)
    
    **2004**
    
    2003
    
    2002Net
      change in sales prices and production costs
    
    **$**
    **2,069**
    
    $
    3,308
    
    $
    6,870Sales
      revenues less production costs
    
    
    **(3,454**
    **)**
    
    (2,383
    )
    
    (1,795
    )Purchases
      of reserves in place
    
    
    **3,850**
    
    
    344
    
    
    243Extensions,
      discoveries and other additions
    
    
    **438**
    
    
    1,183
    
    
    347Revisions
      in quantity estimates
    
    
    **(66**
    **)**
    
    63
    
    
    (1,433
    )Sales
      of reserves in place
    
    
    **(204**
    **)**
    
    (255
    )
    
    (1,920
    )Current-period
      development costs incurred
    
    
    **928**
    
    
    573
    
    
    743Changes
      in estimated future development costs
    
    
    **(852**
    **)**
    
    (472
    )
    
    (209
    )Accretion
      of discount
    
    
    **1,323**
    
    
    1,033
    
    
    701Change
      in income taxes
    
    
    **(1,097**
    **)**
    
    (978
    )
    
    (1,336
    )Timing
      and other
    
    
    **(285******
    ******)**
    
    (572
    )
    
    (137
    )Net
      change
    
    
    **2,650**
    
    
    1,844
    
    
    2,074Total
      at beginning of year
    
    
    **8,906**
    
    
    7,062
    
    
    4,988Total
      at end of year
    
    **$**
    **11,556**
    
    $
    8,906
    
    $
    7,062
 
 34.  **Quarterly
Financial Information (Unaudited)**
 
 A
summary of quarterly consolidated results for 2004 and 2003 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
    
    
    
    Income
      fromfrom
    
    
    
    Continuing
      Operations(Millions
      of dollars,
    
    
    
    Operating
    
    Continuing
    
    Net
    
    per
      Common Shareexcept
      per-share amounts)
    
    Revenues
      (1)
    
    Profit
      (1)
    
    Operations(1)
    
    Income
    
    Basic(1)
    
    Diluted(1)**2004
      Quarter Ended -****March
      31**
    
    **$**
    **1,109**
    
    **$**
    **334**
    
    **$**
    **155**
    
    **$**
    **152**
    
    **$**
    **1.55**
    
    **$**
    **1.44****June
      30**
    
    
    **1,091**
    
    
    **277**
    
    
    **115**
    
    
    **111**
    
    
    **1.11**
    
    
    **1.05****September
      30**
    
    
    **1,361**
    
    
    **216**
    
    
    **9**
    
    
    **7**
    
    
    **.06**
    
    
    **.06****December
      31**
    
    
    **1,596**
    
    
    **341**
    
    
    **136**
    
    
    **134**
    
    
    **.90**
    
    
    **.87****Total**
    
    **$**
    **5,157**
    
    **$**
    **1,168**
    
    **$**
    **415**
    
    **$**
    **404**
    
    
    **3.29**
    
    
    **3.19**2003
      Quarter Ended -March
      31
    
    $
    1,069
    
    $
    269
    
    $
    104
    
    $
    70
    
    $
    1.04
    
    $
    .99June
      30
    
    
    1,024
    
    
    258
    
    
    76
    
    
    70
    
    
    .76
    
    
    .73September
      30
    
    
    980
    
    
    227
    
    
    30
    
    
    29
    
    
    .30
    
    
    .30December
      31
    
    
    1,007
    
    
    212
    
    
    54
    
    
    50
    
    
    .54
    
    
    .54Total
    
    $
    4,080
    
    $
    966
    
    $
    264
    
    $
    219
    
    
    2.63
    
    
    2.58
 
 (1)
    As
      discussed in Note 25, in the fourth quarter of 2004, criteria for
      presenting results of operations of the company’s forest products business
      as discontinued operations were met. Therefore, revenues, results of
      operations and per-share data in the above table differ from the quarterly
      amounts disclosed in the respective Forms
10-Q.
 
  - 147 -
  The
company’s common stock is listed for trading on the New York Stock Exchange and
at year-end 2004 was held by approximately 21,655 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**2004**
    
    2003
    
    per
      Share**High**
    
    **Low**
    
    High
    
    Low
    
    **2004**
    
    2003Quarter
      Ended -March
      31
    
    **$**
    **53.39**
    
    **$**
    **46.92**
    
    $
    44.90
    
    $
    37.82
    
    **$**
    **.45**
    
    $
    .45June
      30
    
    
    **56.00**
    
    
    **47.05**
    
    
    48.59
    
    
    39.90
    
    
    **.45**
    
    
    .45September
      30
    
    
    **58.67**
    
    
    **50.49**
    
    
    45.50
    
    
    41.08
    
    
    **.45**
    
    
    .45December
      31
    
    
    **63.24**
    
    
    **55.57**
    
    
    47.20
    
    
    40.10
    
    
    **.45**
    
    
    .45
 
 35.  **Subsequent
Events**
 
 **Company
to Pursue the Separation of its Chemical Business**
 
 The
company announced on March 8, 2005, that its Board of Directors (the Board)
authorized management to proceed with its proposal to pursue alternatives for
the separation of the chemical business, including a spinoff or sale.
 
 **Share
Repurchase Program**
 
 On
March 8, 2005, the Board authorized the company to proceed with a share
repurchase program initially set at $1 billion. The Board expects to expand the
share repurchase program as the chemical business separation proceeds.
 
 The
timing and final number of shares to be repurchased under an expanded repurchase
program will depend on the outcome of the chemical business separation, as well
as business and market conditions, applicable securities law limitations and
other factors. Shares may be purchased from time to time in the open market or
through privately negotiated transactions at prevailing prices, and the program
may be suspended or discontinued at any time without prior notice.
 
 **Recommendation
to Increase Authorized Stock**
 
 The
company’s Board of Directors in the March 8, 2005 meeting recommended for the
stockholders to approve an increase of the authorized number of shares of
the company’s common stock, par value $1.00 share, from 300 million shares to
500 million shares.
 
 **Conversion
of 5.25% Debentures**
 
 In
February 2005, the company called for redemption all of the $600 million
aggregate principal amount of its 5.25% convertible subordinated debentures due
2010 at a price of 102.625%. Prior to March 4, 2005, the redemption date, all of
the debentures were converted by the holders into approximately 9.8 million
shares of common stock.
 
 
  - 148 -
  
 **Ten-Year
      Financial Summary**(Millions
      of dollars, except per-share amounts)2004
      (a)
    
    2003
    
    2002(b)
    
    2001
      (c)
    
    2000
    
    1999
    
    1998
    
    1997
    
    1996
    
    1995**Statement
      of Operations Summary**Revenues
    
    **$**
    **5,157**
    
    $
    4,080
    
    $
    3,515
    
    $
    3,451
    
    $
    3,955
    
    $
    2,602
    
    $
    2,079
    
    $
    2,527
    
    $
    2,663
    
    $
    2,350Costs
      and operating expenses
    
    
    **4,201**
    
    
    3,313
    
    
    3,834
    
    
    2,730
    
    
    2,551
    
    
    2,216
    
    
    2,489
    
    
    1,949
    
    
    2,052
    
    
    2,242Interest
      and debt expense
    
    
    **245**
    
    
    251
    
    
    275
    
    
    195
    
    
    208
    
    
    191
    
    
    159
    
    
    141
    
    
    145
    
    
    194Total
      costs and expenses
    
    
    **4,446**
    
    
    3,564
    
    
    4,109
    
    
    2,925
    
    
    2,759
    
    
    2,407
    
    
    2,648
    
    
    2,090
    
    
    2,197
    
    
    2,436**711**
    
    
    516
    
    
    (594
    )
    
    526
    
    
    1,196
    
    
    195
    
    
    (569
    )
    
    437
    
    
    466
    
    
    (86
    )Other
      income (expense)
    
    
    **(40**
    **)**
    
    (57
    )
    
    (31
    )
    
    231
    
    
    50
    
    
    36
    
    
    40
    
    
    81
    
    
    109
    
    
    147Benefit
      (provision) for income taxes
    
    
    **(256**
    **)**
    
    (195
    )
    
    35
    
    
    (277
    )
    
    (434
    )
    
    (100
    )
    
    179
    
    
    (178
    )
    
    (222
    )
    
    44Income
      (loss) from continuingoperations
    
    **$**
    **415**
    
    $
    264
    
    $
    (590
    )
    $
    480
    
    $
    812
    
    $
    131
    
    $
    (350
    )
    $
    340
    
    $
    353
    
    $
    105**Effective
      Income Tax Rate**
    
    
    **38.2**
    **%**
    
    42.5
    %
    
    (5.6
    )%
    
    36.6
    %
    
    34.8
    %
    
    43.3
    %
    
    (33.8
    )%
    
    34.4
    %
    
    38.6
    %
    
    72.1
    %**Net
      income (loss) from continuing****operations
      per common share**Basic
    
    **$**
    **3.29**
    
    $
    2.63
    
    $
    (5.89
    )
    $
    4.94
    
    $
    8.69
    
    $
    1.51
    
    $
    (4.04
    )
    $
    3.91
    
    $
    4.01
    
    $
    1.18Diluted
    
    **$**
    **3.19**
    
    $
    2.58
    
    $
    (5.89
    )
    $
    4.68
    
    $
    8.08
    
    $
    1.51
    
    $
    (4.04
    )
    $
    3.89
    
    $
    3.99
    
    $
    1.18**Shares
      outstanding at year-end****(thousands)**
    
    
    **151,889**
    
    
    100,860
    
    
    100,384
    
    
    100,185
    
    
    94,485
    
    
    86,483
    
    
    86,367
    
    
    86,794
    
    
    87,032
    
    
    89,613**Per
      share information**Dividends
      declared
    
    **$**
    **1.80**
    
    $
    1.80
    
    $
    1.80
    
    $
    1.80
    
    $
    1.80
    
    $
    1.80
    
    $
    1.80
    
    $
    1.80
    
    $
    1.64
    
    $
    1.55Stockholders'
      equity (d)
    
    
    **32.86**
    
    
    23.79
    
    
    23.01
    
    
    28.83
    
    
    25.01
    
    
    17.19
    
    
    15.58
    
    
    17.88
    
    
    14.59
    
    
    12.47Market
      high for the year
    
    
    **63.24**
    
    
    48.59
    
    
    63.58
    
    
    74.10
    
    
    71.19
    
    
    62.00
    
    
    73.19
    
    
    75.00
    
    
    74.13
    
    
    64.00Market
      low for the year
    
    
    **46.92**
    
    
    37.82
    
    
    38.02
    
    
    46.94
    
    
    39.88
    
    
    28.50
    
    
    36.19
    
    
    55.50
    
    
    55.75
    
    
    44.00Market
      price at year-end
    
    
    **57.79**
    
    
    46.49
    
    
    44.30
    
    
    54.80
    
    
    66.94
    
    
    62.00
    
    
    38.25
    
    
    63.31
    
    
    72.00
    
    
    63.50**Balance
      Sheet Information**Property,
      plant and equipment - net
    
    **$**
    **10,827**
    
    $
    7,399
    
    $
    6,978
    
    $
    7,320
    
    $
    5,178
    
    $
    3,967
    
    $
    4,038
    
    $
    3,838
    
    $
    3,652
    
    $
    3,784Total
      assets
    
    
    **14,518**
    
    
    10,250
    
    
    9,909
    
    
    11,076
    
    
    7,666
    
    
    5,899
    
    
    5,451
    
    
    5,339
    
    
    5,194
    
    
    5,006Long-term
      debt
    
    
    **3,236**
    
    
    3,081
    
    
    3,798
    
    
    4,540
    
    
    2,244
    
    
    2,496
    
    
    1,978
    
    
    1,736
    
    
    1,809
    
    
    1,683Total
      debt
    
    
    **3,699**
    
    
    3,655
    
    
    3,904
    
    
    4,574
    
    
    2,425
    
    
    2,525
    
    
    2,250
    
    
    1,766
    
    
    1,849
    
    
    1,938Stockholders'
      equity
    
    
    **5,318**
    
    
    2,636
    
    
    2,536
    
    
    3,174
    
    
    2,633
    
    
    1,492
    
    
    1,346
    
    
    1,558
    
    
    1,279
    
    
    1,124**Cash
      Flow Information**Net
      cash provided by operatingactivities
    
    **$**
    **2,050**
    
    $
    1,518
    
    $
    1,448
    
    $
    1,143
    
    $
    1,840
    
    $
    708
    
    $
    418
    
    $
    1,114
    
    $
    1,144
    
    $
    732Capital
      expenditures (e)
    
    
    **1,340**
    
    
    1,162
    
    
    1,272
    
    
    1,864
    
    
    896
    
    
    571
    
    
    1,106
    
    
    904
    
    
    884
    
    
    795Dividends
      paid
    
    
    **205**
    
    
    181
    
    
    181
    
    
    173
    
    
    166
    
    
    138
    
    
    86
    
    
    85
    
    
    83
    
    
    79Treasury
      stock purchased
    
    
    **-**
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    25
    
    
    60
    
    
    195
    
    
    45**Ratios**Current
      ratio
    
    
    **.8**
    
    
    .8
    
    
    .8
    
    
    1.2
    
    
    1.0
    
    
    1.4
    
    
    .8
    
    
    1.0
    
    
    1.2
    
    
    .9Average
      price/earnings ratio
    
    
    **17.7**
    
    
    19.9
    
    
    NM
    
    
    12.8
    
    
    6.6
    
    
    27.6
    
    
    NM
    
    
    14.9
    
    
    13.9
    
    
    42.5Total
      debt to total capitalization
    
    
    **41**
    **%**
    
    58
    %
    
    61
    %
    
    59
    %
    
    48
    %
    
    63
    %
    
    63
    %
    
    53
    %
    
    59
    %
    
    63
    %**Employees**Total
      wages and benefits
    
    **$**
    **558**
    
    $
    541
    
    $
    412
    
    $
    369
    
    $
    333
    
    $
    327
    
    $
    359
    
    $
    367
    
    $
    367
    
    $
    402Number
      of employees at year-end
    
    
    **4,084**
    
    
    3,915
    
    
    4,470
    
    
    4,638
    
    
    4,426
    
    
    3,653
    
    
    4,400
    
    
    4,792
    
    
    4,827
    
    
    5,176
 
 (a)
    As
      described in Note 2 to the Consolidated Financial Statements, on June 25,
      2004, the company completed a merger with Westport Resources
      Corporation.
 
 (b)
    2002
      loss from continuing operations includes an asset impairment charge of
      $652 million. See Note 25 to the Consolidated Financial
      Statements.
 
 (c)
    On
      August 1, 2001, the company completed an acquisition of HS Resources for a
      total cost of $1.8 billion, consisting of cash of $955 million, assumption
      of debt of $506 million and issuance of 5.1 million common shares.
      Additionally, effective January 1, 2001, the company implemented FAS 133,
      “Accounting for Derivatives and Hedging Activities” (FAS 133), as amended.
      In conjunction with implementation, the company recorded the fair value of
      its derivative instruments on the balance sheet, including options
      embedded in the company’s debt exchangeable for stock (DECS) of Devon
      Energy Corporation owned by the company. Further, the company chose to
      reclassify a portion of Devon shares owned from available-for-sale to
      trading category. As a result, the company recognized, as a component of
      other income (expense), an unrealized gain on securities of $181
      million.
 
 (d)
    Stockholder’s
      equity per share for all periods presented reflects the effect of
      potential dilution, assuming potentially issuable shares are issued at the
      end of the reporting period.
  (e)  Inclusive
of dry hole costs and exclusive of acquisition cost (net of cash
acquired).
 - 149 -
  
 **Ten-Year
      Operating Summary****2004**
    
    2003
    
    2002
    
    2001
    
    2000
    
    1999
    
    1998
    
    1997
    
    1996
    
    1995**Exploration
      and Production**Crude
      oil and condensate production -(thousands
      of barrels per day)United
      States
    
    
    **88.1**
    
    
    76.5
    
    
    81.3
    
    
    77.7
    
    
    73.7
    
    
    79.3
    
    
    66.2
    
    
    70.6
    
    
    73.8
    
    
    74.8North
      Sea
    
    
    **62.3**
    
    
    71.6
    
    
    102.8
    
    
    101.9
    
    
    117.7
    
    
    102.9
    
    
    87.4
    
    
    83.3
    
    
    86.5
    
    
    91.9China
    
    
    **8.4**
    
    
    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
    
    
    16.4Total
    
    
    **158.8**
    
    
    150.2
    
    
    191.3
    
    
    188.9
    
    
    200.4
    
    
    191.7
    
    
    166.9
    
    
    169.6
    
    
    175.2
    
    
    183.1Average
      price of crude oil sold (per barrel) -United
      States
    
    **$**
    **29.11**
    
    $
    26.14
    
    $
    21.56
    
    $
    22.05
    
    $
    27.50
    
    $
    16.90
    
    $
    12.78
    
    $
    18.45
    
    $
    19.56
    
    $
    15.78North
      Sea
    
    
    **26.50**
    
    
    25.82
    
    
    22.41
    
    
    23.23
    
    
    27.92
    
    
    17.88
    
    
    12.93
    
    
    18.93
    
    
    19.60
    
    
    16.56China
    
    
    **32.37**
    
    
    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
    
    
    14.91Average
    
    **$**
    **28.23**
    
    $
    26.04
    
    $
    22.04
    
    $
    22.60
    
    $
    27.69
    
    $
    17.30
    
    $
    12.63
    
    $
    18.40
    
    $
    19.26
    
    $
    16.10Natural
      gas sales (MMcf per day)
    
    
    **921**
    
    
    726
    
    
    760
    
    
    596
    
    
    531
    
    
    580
    
    
    584
    
    
    685
    
    
    781
    
    
    809Average
      price of natural gas sold (per Mcf)
    
    **$**
    **5.13**
    
    $
    4.37
    
    $
    2.95
    
    $
    3.83
    
    $
    3.87
    
    $
    2.38
    
    $
    2.13
    
    $
    2.44
    
    $
    2.11
    
    $
    1.63Net
      exploratory wells drilled (1)-Productive
    
    
    **13.6**
    
    
    6.7
    
    
    4.8
    
    
    2.4
    
    
    1.3
    
    
    1.7
    
    
    4.4
    
    
    7.7
    
    
    6.9
    
    
    4.7Dry
    
    
    **15.3**
    
    
    17.0
    
    
    17.2
    
    
    11.4
    
    
    10.5
    
    
    3.8
    
    
    14.4
    
    
    7.4
    
    
    5.5
    
    
    11.2Total
    
    
    **28.9**
    
    
    23.7
    
    
    22.0
    
    
    13.8
    
    
    11.8
    
    
    5.5
    
    
    18.8
    
    
    15.1
    
    
    12.4
    
    
    15.9Net
      development wells drilled (1)-Productive
    
    
    **429.8**
    
    
    244.4
    
    
    196.3
    
    
    128.6
    
    
    47.8
    
    
    46.2
    
    
    62.3
    
    
    95.8
    
    
    143.3
    
    
    135.9Dry
    
    
    **7.5**
    
    
    1.1
    
    
    1.4
    
    
    6.6
    
    
    5.4
    
    
    5.9
    
    
    9.0
    
    
    7.0
    
    
    13.1
    
    
    11.9Total
    
    
    **437.3**
    
    
    245.5
    
    
    197.7
    
    
    135.2
    
    
    53.2
    
    
    52.1
    
    
    71.3
    
    
    102.8
    
    
    156.4
    
    
    147.8Undeveloped
      net acreage (thousands) (1)-United
      States
    
    
    **3,367**
    
    
    2,884
    
    
    2,399
    
    
    2,382
    
    
    2,020
    
    
    1,560
    
    
    1,487
    
    
    1,353
    
    
    1,099
    
    
    1,280North
      Sea
    
    
    **392**
    
    
    369
    
    
    871
    
    
    932
    
    
    923
    
    
    861
    
    
    908
    
    
    523
    
    
    560
    
    
    570China
    
    
    **1,469**
    
    
    1,488
    
    
    1,046
    
    
    917
    
    
    961
    
    
    346
    
    
    1,481
    
    
    2,183
    
    
    925
    
    
    341Other
      international
    
    
    **30,455**
    
    
    47,178
    
    
    41,514
    
    
    50,450
    
    
    25,117
    
    
    18,693
    
    
    13,235
    
    
    12,447
    
    
    3,631
    
    
    3,690Total
    
    
    **35,683**
    
    
    51,919
    
    
    45,830
    
    
    54,681
    
    
    29,021
    
    
    21,460
    
    
    17,111
    
    
    16,506
    
    
    6,215
    
    
    5,881Developed net
      acreage (thousands) (1)-United
      States
    
    
    **2,134**
    
    
    1,352
    
    
    1,266
    
    
    1,192
    
    
    729
    
    
    796
    
    
    810
    
    
    830
    
    
    871
    
    
    1,190North
      Sea
    
    
    **122**
    
    
    136
    
    
    109
    
    
    149
    
    
    115
    
    
    105
    
    
    115
    
    
    70
    
    
    79
    
    
    58China
    
    
    **9**
    
    
    -
    
    
    17
    
    
    17
    
    
    17
    
    
    19
    
    
    19
    
    
    19
    
    
    19
    
    
    19Other
      international
    
    
    **-**
    
    
    -
    
    
    1
    
    
    639
    
    
    639
    
    
    766
    
    
    593
    
    
    182
    
    
    179
    
    
    188Total
    
    
    **2,265**
    
    
    1,488
    
    
    1,393
    
    
    1,997
    
    
    1,500
    
    
    1,686
    
    
    1,537
    
    
    1,101
    
    
    1,148
    
    
    1,455Estimated
      proved reserves (1)-(millions
      of equivalent barrels)
    
    
    **1,218**
    
    
    1,026
    
    
    1,033
    
    
    1,509
    
    
    1,088
    
    
    920
    
    
    901
    
    
    892
    
    
    849
    
    
    864**Chemicals**Titanium
      dioxide pigmentproduction
      (thousands of tonnes)
    
    
    **549**
    
    
    532
    
    
    508
    
    
    483
    
    
    480
    
    
    320
    
    
    284
    
    
    168
    
    
    155
    
    
    154
 
 (1) Includes
discontinued operations.
 
 - 150 -
 
 ****Item
9**.**Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure****
 
 None.
 ****
 **Item
9A.**  **Controls
and Procedures**
 
 As of
the end of the period covered by this report, an evaluation was carried out
under the supervision and with the participation of the company's management,
including its Chief Executive Officer and Chief Financial Officer, of the
effectiveness of the company's disclosure controls and procedures pursuant to
Exchange Act Rule 13a-15. Based on that evaluation, the Chief Executive Officer
and Chief Financial Officer concluded that the company's disclosure controls and
procedures are effective in alerting them in a timely manner to material
information relating to the company (including its consolidated subsidiaries)
required to be included in the company's periodic SEC filings. There was no
change in the company's internal control over financial reporting that occurred
during the fourth quarter of 2004 that has materially affected or is reasonably
likely to materially affect the company’s internal control over financial
reporting.
 
 **Management’s
Report on Internal Control over Financial Reporting**
 
 This
report is included in Item 8 on page 75 of this report and is incorporated
by reference.
 
 **PART
III**
 
 **Item
10.**  **Directors
and Executive Officers of the Registrant**
 
 (a)  Identification
of directors -
 
 For
information required under this section, reference is made to the "Director
Information" section of the company's proxy statement made in connection with
its Annual Stockholders' Meeting to be held on May 10, 2005.
 
 (b)  Identification
of executive officers -
 
 The
information required under this section is set forth in the caption "Executive
Officers of the Registrant" on pages 28 and 29 of this annual report on
Form 10-K pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General
Instruction G(3) to Form 10-K.
 
 (c)  Compliance
with Section 16(a) of the 1934 Act -
 
 For
information required under this section, reference is made to the "Section 16(a)
Beneficial Ownership Reporting Compliance" section of the company's proxy
statement made in connection with its Annual Stockholders' Meeting to be held on
May 10, 2005.
 
 (d)  Code of
Ethics for the Chief Executive Officer and Principal Financial Officers
-
 
 Information
regarding the Code of Ethics for the Chief Executive Officer and Principal
Financial Officers can be found in Items 1 and 2 of this annual report on Form
10-K under "Availability of Reports and Governance Documents."
 
 **Item
11.**  **Executive
Compensation**
 
 For
information required under this section, reference is made to the executive
compensation sections of the company's proxy statement made in connection with
its Annual Stockholders' Meeting to be held on May 10, 2005.
 
 
  - 151 -
 **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, 2004, is included in the following
table:
 
 
 Number
      of shares of common stock to be issued upon exercise of outstanding
      options, warrants and rights
    Weighted-average
      exercise price of outstanding options, warrants and rights
    Number
      of shares remaining available for future issuance under equity
      compensation plans
    (1)Equity
      compensation plans approvedby
      security holders
    5,991,192
    $54.84
    2,576,646Equity
      compensation plans notapproved
      by security holders
    1,525,463
    48.88
    592,217Total
    7,516,655
    53.63
    3,168,863
 (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, 2004
Form 10-K.
 
 Awards
under certain equity compensation plans of Oryx Energy Company and Westport
Resources Corporation were assumed by the company in connection with its
acquisitions of Oryx and Westport. The terms of those awards are governed by the
Oryx and Westport plans, respectively. The plans, which provided for the
granting of stock options to officers and employees of Oryx and Westport, did
not require approval of Kerr-McGee stockholders. No further grants may be made
under the Oryx or Westport plans.
 
 For
information required under Item 403 of Regulation S-K, reference is made to the
"Ownership of Stock of the Company" section of the company's proxy statement
made in connection with its Annual Stockholders' Meeting to be held on May 10,
2005.
 
 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 10,
2005.
 
  - 152 -
  **PART
IV**
 
 **Item
      15.**
    
    **Exhibits,
      Financial Statement Schedules, and Reports on Form
      8-K**(a)
    1.
    Financial
      Statements - See the Index to the Consolidated Financial Statements
      included in Item 8 of this annual report on Form 10-K.(a)
    2.
    Financial
      Statement Schedules - See the Index to the Financial Statement Schedules
      included in Item 8 of this annual report on Form 10-K.(a)
    3.
    Exhibits
      - The following documents are filed under 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 ByLaws of Kerr-McGee Corporation, filed as Exhibit 3.1 to the
      current report on Form 8-K dated January 18, 2005, and incorporated herein
      by reference.4.1
    Rights
      Agreement dated as of July 26, 2001, by and between the company and UMB
      Bank, N.A., filed as Exhibit 4.1 to the 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 Registrant: the Note
      Agreement dated as of November 29, 1989, among the Kerr-McGee Corporation
      Employee Stock Ownership Plan Trust, referred to as the Trust, and several
      lenders, providing for a loan guaranteed by the company of $125 million to
      the Trust; the $150 million, 81/8%
      Note Agreement entered into by Oryx dated as of October 20, 1995, and due
      October 15, 2005; and the Credit Agreement dated as of November 10, 2004,
      between the company or certain subsidiary borrowers and various banks
      providing for revolving credit up to $1.5 billion through November 10,
      2009. The total amount of securities authorized under each of such
      instruments does not exceed 10% of the total assets of the Registrant and
      its subsidiaries on a consolidated basis.
  - 153 -
 Exhibit
      No.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,
      andincorporated
      herein by reference.4.7
    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's5-1/4%
      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.4.8
    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; $500 million 7-7/8% notes due
      September 15, 2031; and $650 million, 6.95% notes due July 1, 2024, filed
      as Exhibit 4.1 to 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, filed as
      Exhibit 10.3 to the Form 10-K for the year ended December 31, 2003, and
      incorporated herein by reference.10.4*
    First
      Supplement to Benefits Restoration Plan as amended and restated effective
      January 1, 2000, filed as Exhibit 10.4 to the Form 10-K for the year ended
      December 31, 2003, and incorporated herein by
reference.10.5*
    Second
      Supplement to Benefits Restoration Plan as amended and restated effective
      January 1, 2001, filed as Exhibit 10.5 to the Form 10-K for the year ended
      December 31, 2003, and incorporated herein by
reference.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*
    Amended
      and Restated Second Supplement to the Kerr-McGee Corporation Supplemental
      Executive Retirement Plan as amended and restated effective February 26,
      1999.10.9*
    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.
  - 154 -
  
 Exhibit
      No.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
      10.2 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, filed as Exhibit 10.15 to the Form 10-K for the year ended
      December 31, 2003, and incorporated herein by
reference.10.16*
    Oryx
      Energy Company 1997 Long-Term Incentive Plan, as amended and restated May
      1, 1997, filed as Exhibit 10.16 to the Form 10-K for the year ended
      December 31, 2003, and incorporated herein by
reference.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 Gregory F. Pilcher filed as Exhibit 10.14 on Form 10-K for the
      year ended December 31, 2000, and incorporated herein by
      reference.10.21*
    Agreement,
      dated as of September 3, 2002, between the company and David A.
      Hager.10.22*
    Registration
      Rights Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation,
      Westport Energy LLC, Medicor Foundation and EQT Investments, LLC, filed as
      Exhibit 99.7 to the company's Current Report on Form 8-K dated April 8,
      2004, and incorporated herein by reference.10.23*
    Compensation
      Plan for Directors and tax reimbursement arrangement, filed as Exhibit
      10.1 to the current report on Form 8-K dated January 18, 2005, and
      incorporated herein by reference.
 
  - 155 -
  
 Exhibit
      No.10.24*
    2005
      Performance Measures for Annual Incentive Compensation Plan, filed as
      Exhibit 10.2 to the current report on Form 8-K dated January 18, 2005, and
      incorporated herein by reference.10.25
    Voting
      Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation, Belfer
      Corp., Renee Holdings Partnership, L.P., Vantz Limited Partnership, LDB
      Two Corp., Belfer Two Corp., Liz Partners, L.P., filed as Exhibit 99.2 to
      the company’s Current Report on Form 8-K dated April 8, 2004, and
      incorporated herein by reference.10.26
    Voting
      Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation and EQT
      Investments, LLC., filed as Exhibit 99.3 to the company’s Current Report
      on Form 8-K dated April 8, 2004, and incorporated herein by
      reference.10.27
    Voting
      Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation and
      Medicor Foundation, filed as Exhibit 99.4 to the company’s Current Report
      on Form 8-K dated April 8, 2004, and incorporated herein by
      reference.10.28
    Voting
      Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation and
      Westport Energy LLC., filed as Exhibit 99.5 to the company’s Current
      Report on Form 8-K dated April 8, 2004, and incorporated herein by
      reference.10.29
    Voting
      Agreement, dated as of April 6, 2004, among Kerr-McGee Corporation and
      Donald D. Wolf, filed as Exhibit 99.6 to the company’s Current Report on
      Form 8-K dated April 8, 2004, and incorporated herein by
      reference.10.30
    Amended
      and Restated Gas Purchase Agreement, dated July 1, 1998, among Oryx Gas
      Marketing Limited Partnership, Sun Operating Limited Partnership and
      Producers Energy Marketing, LLC, filed as Exhibit 10.23 to the Amendment
      to Form 10-K for the year ended December 31, 2003, and incorporated herein
      by reference.10.31
    Amendment
      to Amended and Restated Gas Purchase Agreement, dated May 1, 2000, among
      Oryx Gas Marketing Limited Partnership, Kerr-McGee Oil & Gas
      Corporation, Kerr-McGee Oil and Gas Onshore LP, and Cinergy Marketing
      & Trading, LLC, filed as Exhibit 10.24 to the Amendment to Form 10-K
      for the year ended December 31, 2003, and incorporated herein by
      reference.10.32
    Amendment
      No. 2 to Amended and Restated Gas Purchase Agreement, dated July 1, 2002,
      among Oryx Gas Marketing Limited Partnership, Kerr-McGee Oil & Gas
      Corporation, Kerr-McGee Oil and Gas Onshore LP, and Cinergy Marketing
      & Trading, LLC, filed as Exhibit 10.25 to the Amendment to Form 10-K
      for the year ended December 31, 2003, and incorporated herein by
      reference.10.33
    Letter
      Agreement, dated May 23, 2003, amending Amended and Restated Gas Purchase
      Agreement, dated July 1, 1998, among Kerr-McGee Oil & Gas Corporation,
      Kerr-McGee Oil and Gas Onshore LP, and Cinergy Marketing & Trading,
      LLC, filed as Exhibit 10.26 to the Amendment to Form 10-K for the year
      ended December 31, 2003, and incorporated herein by
    reference.10.34*
    Oryx
      Energy Company Executive Retirement Plan, as amended and restated January
      1, 1995.12
    Computation
      of ratio of earnings to fixed charges.21
    Subsidiaries
      of the Registrant.
  - 156 -
 Exhibit
      No.23.1
    Consent
      of Ernst & Young LLP.23.2
    Consent
      of Netherland, Sewell & Associates, Inc.23.3
    Consent
      of Ryder Scott Company, L.P.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 200231.2
    Certification
      pursuant to Securities Exchange Act Rule 15d-14(a), as adopted pursuant to
      Section 302 of the Sarbanes-Oxley Act of 2002.32.1
    Certification
      pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
      the Sarbanes-Oxley Act of 2002.32.2
    Certification
      pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
      the Sarbanes-Oxley Act of 2002.99
    Report
      of Netherland, Sewell & Associates,
Inc.
 
 
 *These
exhibits relate to the compensation plans and arrangements of the
company.
 
  - 157 -
  
 **SCHEDULE
II**
 
 **KERR-McGEE
CORPORATION AND SUBSIDIARY COMPANIES**
 **VALUATION
ACCOUNTS AND RESERVES**
 
 
 AdditionsBalance
      at
    
    Charged
      to
    
    Charged
      to
    
    Deductions
    
    Balance
      atBeginning
    
    Profit
      and
    
    Other
    
    from
    
    End
      of(Millions
      of dollars)
    
    of
      Year
    
    Loss
    
    Accounts
    
    Reserves
    
    YearYear
      Ended December 31, 2004Deducted
      from asset accountsAllowance
      for doubtful notesand
      accounts receivable
    
    $
    19
    
    $
    3
    
    $
    2
    
    $
    1
    
    $
    23Valuation
      allowance fordeferred
      tax assets
    
    
    9
    
    
    1
    
    
    -
    
    
    2
    
    
    8Warehouse
      inventoryobsolescence
    
    
    8
    
    
    5
    
    
    -
    
    
    1
    
    
    12Total
    
    $
    36
    
    $
    9
    
    $
    2
    
    $
    4
    
    $
    43Year
      Ended December 31, 2003Deducted
      from asset accountsAllowance
      for doubtful notesand
      accounts receivable
    
    $
    19
    
    $
    1
    
    $
    -
    
    $
    1
    
    $
    19Valuation
      allowance fordeferred
      tax assets
    
    
    -
    
    
    9
    
    
    -
    
    
    -
    
    
    9Warehouse
      inventoryobsolescence
    
    
    4
    
    
    6
    
    
    -
    
    
    2
    
    
    8Total
    
    $
    23
    
    $
    16
    
    $
    -
    
    $
    3
    
    $
    36Year
      Ended December 31, 2002Deducted
      from asset accountsAllowance
      for doubtful notesand
      accounts receivable
    
    $
    21
    
    $
    -
    
    $
    -
    
    $
    2
    
    $
    19Warehouse
      inventoryobsolescence
    
    
    5
    
    
    1
    
    
    -
    
    
    2
    
    
    4Total
    
    $
    26
    
    $
    1
    
    $
    -
    
    $
    4
    
    $
    23
 
 
  - 158 -
  SIGNATURES
 
 Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
 
 KERR-McGEE
      CORPORATIONBy:
    Luke
      R. Corbett*Luke
      R. Corbett, DirectorChief
      Executive OfficerMarch
      13, 2005
    By:
    (Robert
      M. Wohleber)Date
    
    Robert
      M. WohleberSenior
      Vice President andChief
      Financial OfficerBy:
    (John
      M. Rauh)John
      M. RauhVice
      President and Controllerand
      Chief Accounting Officer
 
 
 * By
his signature set forth below, John M. Rauh has signed this Annual Report on
Form 10-K as attorney-in-fact for the officer noted above, pursuant to power of
attorney filed with the Securities and Exchange Commission.
 
 
 By:
    (John
      M. Rauh)John
      M. Rauh
 
  - 159 -
  Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons in the capacities and on the date
indicated.
 
 
 By:
    Luke
      R. Corbett*Luke
      R. Corbett, DirectorBy:
    William
      E. Bradford*William
      E. Bradford, DirectorBy:
    Sylvia
      A. Earle*Sylvia
      A. Earle, DirectorBy:
    David
      C. Genever-Watling*David
      C. Genever-Watling, DirectorMarch
      13, 2005
    By:
    Martin
      C. Jischke*Date
    
    Martin
      C. Jischke, DirectorBy:
    Leroy
      C. Richie*Leroy
      C. Richie, DirectorBy:
    William
      F. Wallace*William
      F. Wallace, DirectorBy:
    Farah
      M. Walters*Farah
      M. Walters, DirectorBy:
    Ian
      L. White-Thomson*Ian
      L. White-Thomson, Director
 
 
 * By
his signature set forth below, John M. Rauh has signed this Annual Report on
Form 10-K as attorney-in-fact for the directors noted above, pursuant to the
powers of attorney filed with the Securities and Exchange
Commission.
 
 
 By:
    (John
      M. Rauh)John
      M. Rauh


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