UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal year ended December 31, 2003
Commission file number 1-16619
KERR-MCGEE CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 73-1612389
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
KERR-MCGEE CENTER, OKLAHOMA CITY, OKLAHOMA 73125
(Address of principal executive offices)
Registrant's telephone number, including area code: (405) 270-1313
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
- ------------------------------- ------------------------
Common Stock $1 Par Value New York Stock Exchange
Preferred Share Purchase Right
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months and (2) has been subject to such filing requirements for
the past 90 days. Yes |X| No ____
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes |X| No ____
The aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant was approximately $4.5 billion computed by
reference to the price at which the common equity was last sold as of June 30,
2003, the last business day of the registrant's most recently completed second
fiscal quarter.
The number of shares of common stock outstanding as of February 27, 2004, was
101,373,405.
DOCUMENTS INCORPORATED BY REFERENCE
The definitive Proxy Statement for the 2004 Annual Meeting of Stockholders,
which will be filed with the Securities and Exchange Commission within 120 days
after December 31, 2003, is incorporated by reference in Part III of this Form
10-K.
KERR-McGEE CORPORATION
PART I
Items 1. and 2. Business and Properties
GENERAL DEVELOPMENT OF BUSINESS
Kerr-McGee Corporation is an energy and inorganic chemical holding company whose
consolidated subsidiaries, joint venture partners and other affiliates
(together, "affiliates") have operations throughout the world. Kerr-McGee
affiliates engaged in the energy business acquire leases and concessions and
explore for, develop, produce and market crude oil and natural gas onshore in
the United States and in the Gulf of Mexico, the United Kingdom sector of the
North Sea and China. The company also holds exploration licenses and concessions
in Australia, Benin, Bahamas, Brazil, Gabon, Morocco, Western Sahara, Canada,
the Danish and Norwegian sectors of the North Sea, and Yemen. Kerr-McGee
affiliates engaged in chemical businesses produce and market titanium dioxide
pigment and certain other specialty chemicals, heavy minerals and forest
products.
Kerr-McGee's worldwide businesses are consolidated for financial reporting and
disclosure purposes. Accordingly, the terms "Kerr-McGee," "the company" and
similar terms are used interchangeably in this Form 10-K to refer to the
consolidated group or to one or more of the companies that are part of the
consolidated group.
On August 1, 2001, in connection with its acquisition of HS Resources, Inc., the
company completed a holding company reorganization in which Kerr-McGee Operating
Corporation, which was formerly known as Kerr-McGee Corporation, changed its
name and became a wholly owned subsidiary of the company. Filings and references
in this Form 10-K to the company include business activity conducted by the
current Kerr-McGee Corporation and the former Kerr-McGee Corporation before it
reorganized as a subsidiary of the company and changed its name to Kerr-McGee
Operating Corporation. At the end of 2002, another reorganization took place
whereby among other changes, Kerr-McGee Operating Corporation distributed its
investment in certain subsidiaries (primarily the oil and gas operating
subsidiaries) to a newly formed intermediate holding company, Kerr-McGee
Worldwide Corporation. Kerr-McGee Operating Corporation formed a new subsidiary,
Kerr-McGee Chemical Worldwide LLC and merged into it.
For a discussion of recent business developments, reference is made to
Management's Discussion and Analysis, which discussion is included in Item 7. of
this Form 10-K, and the Exploration and Production and Chemicals discussions
below.
INDUSTRY SEGMENTS
For financial information as to business segments of the company, reference is
made to Note 28 to the Consolidated Financial Statements, which financial
statements are included in Item 8. of this Form 10-K.
EXPLORATION AND PRODUCTION
Kerr-McGee Corporation owns oil and gas operations worldwide. The company
acquires leases and concessions and explores for, develops, produces, and
markets crude oil and natural gas through its various affiliates.
Kerr-McGee's offshore oil and gas exploration and production activities are
conducted in the U.S. Gulf of Mexico, Alaska, the U.K. sector of the North Sea
and China. Oil and gas exploration activities are also conducted in Australia,
Benin, Brazil, Canada, Morocco, Western Sahara, Gabon, Yemen, Bahamas, and the
Danish and Norwegian sectors of the North Sea. Onshore exploration and
production operations are conducted in the United States and the United Kingdom.
- --------------------------------------------------------------------------------
Except for information or data specifically incorporated herein by reference
under Items 10 through 14, other information and data appearing in the company's
2004 Proxy Statement are not deemed to be filed as part of this annual report on
Form 10-K.
- --------------------------------------------------------------------------------
Kerr-McGee's average daily oil production from continuing operations for 2003
was 150,200 barrels, a 21% decrease from 2002. This decrease in production
volume is largely the result of a divestiture program initiated during 2002 and
subsequently completed in 2003. After adjusting for divestitures, the 2003 oil
production volume was relatively consistent compared with 2002. Kerr-McGee's
average oil price was $26.04 per barrel for 2003, including the impact of
hedges, compared with $22.04 per barrel for 2002.
During 2003, natural gas sales volume averaged 726 million cubic feet per day,
down 4% from 2002. This decrease is also partly the result of the divestiture
program discussed above. On a divestiture-adjusted basis, 2003 gas sales were
down about 2% compared with 2002. The 2003 average natural gas price was $4.37
per thousand cubic feet, including the impact of hedges, compared with $2.95 per
thousand cubic feet in 2002.
Worldwide gross acreage at year-end 2003 was almost 72 million acres, an
increase of 8% compared with year-end 2002. The increase resulted primarily from
the acquisition of acreage in the Bahamas, offset by divestitures of certain
properties in Kazakhstan and the North Sea.
Discontinued Operations and Asset Disposals
- -------------------------------------------
During 2002, the company approved a plan to dispose of its exploration and
production operations in Kazakhstan, its interest in the Bayu-Undan project in
the East Timor Sea offshore Australia, and its interest in the Jabung block of
Sumatra, Indonesia. These divestiture decisions were made as part of the
company's strategic plan to rationalize noncore oil and gas properties. The
results of these operations have been reported separately as discontinued
operations in the company's Consolidated Statement of Operations for all years
presented, which statement is included in Item 8. of this Form 10-K. Sales of
the company's interests in the Bayu-Undan project and the Sumatra operations
were completed during 2002, and the sale of its operations in Kazakhstan was
completed in March 2003. The Kazakhstan assets consisted of one producing
license, one exploration license and an equity ownership in the Caspian Pipeline
Consortium.
Revenues applicable to the discontinued operations totaled $6 million, $36
million and $72 million for 2003, 2002 and 2001, respectively. Pretax income for
the discontinued operations totaled nil, (including a loss on sale of $6
million), $104 million (including gain on sale of $107 million and a loss on
sale of $35 million) and $52 million for the years ended 2003, 2002 and 2001,
respectively.
In addition, certain individually insignificant properties for which operations
and cash flows were not clearly distinguishable from the company's operations
were identified for disposal during 2003. These properties included the
company's interest in the Liuhua field in the South China Sea and selected other
noncore, high-cost properties in the U.S onshore and Gulf of Mexico regions.
These decisions were made as part of the company's strategic plan to rationalize
noncore oil and gas properties, as well as the company's ongoing efforts to
maintain its high-quality asset portfolio. Asset disposals completed in 2003,
including the Kazakhstan operations, resulted in the sale of approximately 41
million equivalent barrels, or 4% of proved reserves.
Costs Incurred, Results of Operations, Sales Prices, Lifting Costs and
Capitalized Costs
- --------------------------------------------------------------------------------
Reference is made to Notes 29, 30 and 31 to the Consolidated Financial
Statements included in Item 8. of this Form 10-K. These notes contain
information on the costs incurred in crude oil and natural gas activities for
each of the past three years; results of operations from crude oil and natural
gas activities, average sales prices per unit of crude oil and natural gas,
lifting costs per barrel of oil equivalent (BOE) for each of the past three
years; and capitalized costs of crude oil and natural gas activities at December
31, 2003 and 2002.
Reserves
- --------
Kerr-McGee's estimated proved crude oil, condensate, natural gas liquids and
natural gas reserves at December 31, 2003, and the changes in net quantities of
such reserves for the three years then ended are shown in Note 32 to the
Consolidated Financial Statements included in Item 8. of this Form 10-K.
Estimates of total proved reserves filed with or included in reports to any
other Federal authority or agency during 2003, if any, are within 5% of amounts
shown in this filing.
Undeveloped Acreage
- -------------------
As of December 31, 2003, the company had leases, concessions, reconnaissance
permits and other interests in undeveloped oil and gas leases in the Gulf of
Mexico; onshore United States; the United Kingdom, Danish and Norwegian sectors
of the North Sea; offshore China; and onshore and offshore in other
international areas, as follows:
Gross Net
Location Acreage Acreage
- -------- ---------- ----------
United States -
Offshore 3,107,918 1,799,541
Onshore 1,565,728 1,083,999
---------- ----------
4,673,646 2,883,540
---------- ----------
North Sea 783,927 368,773
---------- ----------
China 1,686,987 1,487,524
---------- ----------
Other international -
Morocco/Western Sahara 30,245,687 28,021,741
Australia 10,652,553 6,371,482
Yemen 6,037,418 1,911,849
Canada 3,021,825 1,778,128
Gabon 2,471,052 617,763
Benin 2,459,439 1,721,607
Bahamas 6,488,680 6,488,680
Brazil 534,981 267,491
---------- ----------
61,911,635 47,178,741
---------- ----------
Total 69,056,195 51,918,578
========== ==========
Developed Acreage
- -----------------
At December 31, 2003, the company had leases and concessions in developed oil
and gas acreage in the Gulf of Mexico, onshore United States and the United
Kingdom sector of the North Sea, as follows:
Gross Net
Location Acreage Acreage
- -------- ---------- ----------
United States -
Offshore 566,650 264,498
Onshore 1,594,403 1,087,793
---------- ----------
2,161,053 1,352,291
---------- ----------
North Sea 405,427 135,539
---------- ----------
Total 2,566,480 1,487,830
========== ==========
Net Exploratory and Development Wells
- -------------------------------------
Domestic and international exploratory and development wells that were completed
as successful or dry holes during the three years ended December 31, 2003, are
summarized in the following tables.
Net Exploratory (1) Net Development (1)
-------------------------------- --------------------------------
Productive Dry Holes Total Productive Dry Holes Total Total
---------- --------- ----- ---------- --------- ----- -----
2003 (2)
United States 6.7 11.0 17.7 241.6 1.0 242.6 260.3
North Sea - 1.0 1.0 2.1 .1 2.2 3.2
Other international - 5.0 5.0 .7 - .7 5.7
--- ---- ----- ----- --- ----- -----
Total 6.7 17.0 23.7 244.4 1.1 245.5 269.2
=== ==== ===== ===== === ===== =====
2002
United States 4.8 11.1 15.9 186.9 1.4 188.3 204.2
North Sea - 1.9 1.9 8.6 - 8.6 10.5
Other international - 4.2 4.2 .8 - .8 5.0
--- ---- ----- ----- --- ----- -----
Total 4.8 17.2 22.0 196.3 1.4 197.7 219.7
=== ==== ===== ===== === ===== =====
2001
United States 2.4 4.6 7.0 107.3 6.3 113.6 120.6
North Sea - 2.4 2.4 16.1 - 16.1 18.5
Other international - 4.4 4.4 5.2 .3 5.5 9.9
--- ---- ----- ----- --- ----- -----
Total 2.4 11.4 13.8 128.6 6.6 135.2 149.0
=== ==== ===== ===== === ===== =====
(1) Net wells represent the company's fractional working interest in gross
wells expressed as the equivalent number of full-interest wells.
(2) The 2003 net exploratory well count does not include 8.6 successful net
wells drilled in the United States or 1.2 successful net wells drilled in
the North Sea that are currently suspended, nor does it include 4.3
successful net wells drilled in China, 1.4 successful net wells drilled in
the North Sea or 6.0 successful net wells drilled in the United States that
will not be used for production.
Wells in Process of Drilling
- ----------------------------
The following table shows the number of wells in the process of drilling and the
number of wells suspended or awaiting completion as of December 31, 2003:
Wells in Process of Wells Suspended or
Drilling Awaiting Completion
-------------------------- --------------------------
Exploration Development Exploration Development
----------- ----------- ----------- -----------
United States
Gross 3.0 8.0 30.0 25.0
Net 1.5 7.5 17.2 19.7
North Sea
Gross - - 2.0 2.0
Net - - 1.2 .2
China
Gross - 6.0 - -
Net - 2.4 - -
Total
--- ---- ---- ----
Gross 3.0 14.0 32.0 27.0
=== ==== ==== ====
Net 1.5 9.9 18.4 19.9
=== ==== ==== ====
Gross and Net Wells
- -------------------
The number of productive oil and gas wells in which the company had an interest
at December 31, 2003, is shown in the following table. These wells include 96
gross or 17.4 net wells associated with improved recovery projects, and 2,356
gross or 2,278.7 net wells that have multiple completions but are included as
single wells.
Location Crude Oil Natural Gas Total
- -------- --------- ----------- -----
United States
Gross 1,765 3,051 4,816
Net 1,513 2,448 3,961
North Sea
Gross 266 5 271
Net 49 - 49
Total
----- ----- -----
Gross 2,031 3,056 5,087
===== ===== =====
Net 1,562 2,448 4,010
===== ===== =====
Crude Oil and Natural Gas Sales
- -------------------------------
The following table summarizes the sales of the company's crude oil and natural
gas sales from continuing operations for each of the three years in the period
ended December 31, 2003:
(Millions) 2003 2002 2001
- ---------- -------- -------- --------
Crude oil and condensate - barrels
United States 27.9 29.7 28.4
North Sea 26.1 37.2 37.3
China .8 1.2 1.4
Other international - 1.4 2.0
-------- -------- --------
54.8 69.5 69.1
======== ======== ========
Crude oil and condensate sales revenues (1)
United States $ 728.4 $ 639.6 $ 625.5
North Sea 673.9 832.8 865.6
China 23.2 29.5 30.3
Other international - 28.9 38.6
-------- -------- --------
$1,425.5 $1,530.8 $1,560.0
======== ======== ========
Natural gas - Mcf
United States 229.5 240.8 194.9
North Sea 35.4 36.7 22.8
-------- -------- --------
264.9 277.5 217.7
======== ======== ========
Natural gas sales revenues (1)
United States $1,046.9 $ 732.7 $ 777.2
North Sea 109.3 86.4 56.2
-------- -------- --------
$1,156.2 $ 819.1 $ 833.4
======== ======== ========
(1) Includes the results of the company's hedging program, which began in 2002.
Product Sales and Marketing
- ---------------------------
The company's crude oil and natural gas is sold at prevailing market prices, and
the realized revenue on the physical sale is adjusted for any gains or losses on
hedging contracts.
The company markets all of its crude oil under a combination of spot and term
contracts to refiners, marketers and end-users under market-reflective prices.
Kerr-McGee's single largest purchaser of crude oil during 2003 was BP PLC,
accounting for approximately 31% of total crude oil sales and 21% of total crude
oil and natural gas sales. The creditworthiness of each successful bidder is
reviewed prior to delivery of product.
Kerr-McGee's single largest purchaser of domestic natural gas is Cinergy
Marketing & Trading LLC, whose purchases are guaranteed by its parent company,
Cinergy Corporation. Purchases by Cinergy represented approximately 68% of total
gas sales and 30% of total crude oil and natural gas sales for 2003.
Additionally, Kerr-McGee manages its single-customer exposure through a credit
risk insurance policy.
Marketing of the company's domestic natural gas from the Wattenberg field,
located in northeastern Colorado, is facilitated through its subsidiary,
Kerr-McGee Energy Services Corporation (KMES). KMES is primarily engaged in the
sale of the company's equity gas production. KMES sells natural gas to a number
of customers in the Denver, Colorado, market adjacent to the company's
Wattenberg field. To fulfill its direct sales obligations and to fully utilize
its contracted transportation capacity, KMES also purchases and markets
nonequity natural gas.
North Sea natural gas is sold both under contract and through spot market sales
in the geographic area of production.
Improved Recovery
- -----------------
As part of the company's strategic plan to rationalize noncore, high-cost
assets, Kerr-McGee's improved-recovery projects in Texas were sold during 2003.
As of December 31, 2003, the company participated in 17 active improved-recovery
projects located in the United Kingdom sector of the North Sea. Most of these
improved-recovery operations incorporate water injection.
Exploration and Development Activities
- --------------------------------------
Gulf of Mexico:
Kerr-McGee has been one of the pioneering exploration companies in the Gulf of
Mexico since 1947, when the company drilled the first successful well out of the
sight of land. This tradition has continued with the advancement of technology
and the pursuit of oil and gas farther offshore and in deeper water. To achieve
and maintain its competitive advantage, Kerr-McGee has continued to utilize new,
cost-efficient production and drilling technology, allowing the company to
explore for new oil and gas resources in water depths of almost 10,000 feet.
Kerr-McGee was the first company to utilize floating production spar technology
in the Gulf of Mexico in 1997 for its Neptune development at Viosca Knoll block
826. Kerr-McGee has continued to advance this technology through utilization of
improved truss spar designs for its developments at the Nansen, Boomvang and
Gunnison discoveries, which were sanctioned for development in 2000 and 2001.
Kerr-McGee sanctioned the Red Hawk development in 2002, which will use a new
cell spar design. New technology, such as the cell spar, lowers the reserve
threshold for economic development of deepwater reservoirs, allowing the company
to exploit new resources cost effectively.
In 2003, Gulf of Mexico production represented 38% of the company's worldwide
crude oil and condensate production and 38% of its natural gas sales. The Gulf
of Mexico represents about 35% of Kerr-McGee's total worldwide proved reserves.
Kerr-McGee is one of the largest independent exploration and production
companies operating in the Gulf of Mexico, with leases covering almost 3.7
million gross acres. In 2003, Kerr-McGee maintained its position as the largest
independent leaseholder in the deepwater Gulf of Mexico with almost 480
deepwater blocks. The company believes this extensive acreage holding provides a
significant competitive advantage in its effort to maintain and develop a
high-quality prospect inventory.
In 2003, Kerr-McGee was an active explorer in the Gulf of Mexico, participating
in the drilling of 37 gross exploration wells, with 25 of those in water depth
greater than 1,000 feet. The prospects were a mixture of near-field wildcats,
appraisal wells and deeper pool tests, as well as larger new-field wildcat
prospects that would require the installation of new infrastructure for
development. Successful wells were drilled in Breton Sound, Main Pass, Garden
Banks 197 and 216, East Breaks 598 and 686, Ewing Bank 1006, Viosca Knoll 990,
and at the Constitution prospect in Green Canyon 679/680.
During 2003, Kerr-McGee continued drilling under terms of a joint-venture
agreement with Devon Energy (following the merger of Ocean Energy with Devon),
which covers an area comprised of 181 blocks. Kerr-McGee and Devon drilled three
exploratory wells in 2003, with Devon paying a disproportionate share of the
drilling cost to earn its equity interest in the venture. Two of these wells
were unsuccessful, and the third (Yorktown prospect in Mississippi Canyon block
886) was temporarily suspended during the year. The company plans to resume
drilling on this prospect in 2004. The joint-venture arrangement with Devon will
continue for approximately two more years.
The majority of geological and geophysical expenditures in 2003 were focused on
acquiring regional 3-D seismic data and on the continued development of a
high-potential prospect inventory. Much of the geologic section above salt has
been heavily explored in the Gulf of Mexico, and numerous subsalt trends are
emerging through industry activity. In 2003, Kerr-McGee also focused on
acquisition of geophysical data aimed at developing subsalt prospects. This data
is currently being used to build the company's prospect inventory in this new
play.
In 2003, Kerr-McGee continued to capitalize on its appraisal and development
expertise in the Gulf of Mexico, resulting in a new development project at its
Constitution discovery in Green Canyon block 679/680. During 2003, a second
exploration test and discovery were made on the Constitution prospect. This was
followed by a successful appraisal program, which led to sanctioning of the
Constitution development in January 2004. Development of infrastructure for the
Constitution discovery will provide a new operating hub for Kerr-McGee, and
additional drilling opportunities in this area are being evaluated for the 2004
exploration program.
Kerr-McGee's development activity in the deepwater Gulf of Mexico also continued
at a high level during 2003 in terms of capital outlay, wells drilled and
construction activity. Installation of a truss spar was completed at Gunnison
during 2003, and significant progress was made on the Red Hawk cell spar
construction. Subsea wells were completed for Gunnison, Red Hawk, East Breaks
598, East Breaks 686 and Viosca Knoll 869 (Triton) during 2003. In addition,
Kerr-McGee finalized plans for construction of a new truss spar for the
Constitution project. Well completion activities at the Nansen and Boomvang
fields were also completed during the year. A summary of these and other major
producing fields, including Kerr-McGee's working interest, follows:
Nansen field, East Breaks blocks 602 and 646 (50%): The Nansen field was
sanctioned for development in March 2000, and first production was achieved in
January 2002. Average 2003 gross production was 26,000 barrels of oil per day
and 140 million cubic feet of gas per day. Completion activities concluded in
August 2003, and the completion rig was demobilized. The Nansen field has nine
dry-tree producers and three subsea wells tied back to the spar from a subsea
cluster.
Boomvang field, East Breaks (EB) blocks 642, 643 and 688 (30%): The Boomvang
field was sanctioned for development in July 2000, and first production was
achieved in June 2002. Average 2003 gross production was 33,200 barrels of oil
per day and 158 million cubic feet of gas per day. Completion activities
concluded at Boomvang in March 2003, and the completion rig was demobilized from
the spar. The Boomvang field has five dry-tree producers and three subsea wells
tied back to the spar from two subsea clusters. During 2003, a development well
was drilled on EB 688 and was completed in the fourth quarter of 2003. This well
will begin production in early 2004 from one of the existing subsea clusters.
Two exploration wells were successfully drilled on Kerr-McGee leases adjacent to
the Boomvang field in 2003. EB 686 (42%) and EB 598 (50%) have been completed
and will be tied back to the Boomvang spar in 2004. The EB 686 well will be tied
back through an existing subsea cluster and pipeline system, while EB 598 will
be tied back to the spar through a new subsea pipeline and cluster system. The
EB 598 well will share the new subsea system with another successful exploration
well previously drilled on EB 599.
Navajo field, East Breaks 690 area (50%): The Navajo field cluster is located on
East Breaks blocks 646, 689 and 690. The Navajo discovery well, located in block
690, was drilled in September 2001. Following discovery, the well was completed
and tied back to the Nansen spar located approximately 5 miles to the north.
First production from Navajo was achieved in June 2002. Two previously drilled
exploration wells were completed and began production through the Navajo subsea
system in 2003. Gross production from Navajo, West Navajo and Northwest Navajo
wells averaged 47 million cubic feet of gas per day and 4,200 barrels of oil per
day in 2003.
Gunnison field, Garden Banks block 668 area (50%): The Gunnison field,
sanctioned for development in October 2001, incorporates a truss spar and
processing facilities with a capacity of 40,000 barrels of oil per day and 200
million cubic feet of natural gas per day. The development includes seven
dry-tree wells and three subsea wells. The Gunnison spar, located in 3,100 feet
of water, is Kerr-McGee's third truss spar in the deepwater Gulf of Mexico.
Development during 2003 included the final development well drilled in January
2003 and completion of the three subsea wells prior to the installation of the
spar. First production was achieved in December 2003 from the three subsea
wells. By year-end 2003, the average gross production rate was about 3,600
barrels of oil per day and 125 million cubic feet of gas per day. Gross
production is expected to peak at 30,000 barrels of oil per day and 180 million
cubic feet of gas per day by year-end 2004.
Red Hawk field, Garden Banks block 877 (50%): Development of Red Hawk, a 2001
discovery, was sanctioned in July 2002 utilizing a new spar design referred to
as a cell spar. Located in approximately 5,300 feet of water, the field will be
developed using two subsea development wells that will be tied back to the cell
spar. Development drilling was completed in the first quarter of 2003, and the
two wells were completed during the summer of 2003. At year-end 2003,
construction of the cell spar and production facilities was more than 75%
complete. First production is anticipated in mid-2004, with peak gross
production rates estimated at 120 million cubic feet of gas per day.
Neptune field, Viosca Knoll block 826 (50%): Average 2003 gross production from
the Neptune field was 14,000 barrels of oil per day and 23 million cubic feet of
gas per day. Production from the Neptune field began in March 1997 from the
world's first floating production spar. Presently there are 12 dry-tree wells
and three subsea satellite wells producing through the Neptune spar. A fourth
subsea well (Viosca Knoll 869 No. 1) was drilled and completed in late 2003,
with first production expected in early 2004.
Conger field, Garden Banks block 215 (25%): Average 2003 gross production from
the Conger field was 28,500 barrels of oil per day and 90 million cubic feet of
gas per day. First production from the Conger field began in December 2000 from
the first of three subsea wells. The three-well subsea development is the first
multi-well, 15,000-psi subsea development and is located in approximately 1,460
feet of water. One additional well, a sidetrack of the Garden Banks 215 No. 6
well, was completed in late 2003 and was producing 6,600 barrels of oil per day
and 20 million cubic feet of gas per day at year-end.
Baldpate field, Garden Banks block 260 (50%): Average 2003 gross production from
the Baldpate field, including the Penn State subsea satellite wells, was 20,100
barrels of oil per day and 40 million cubic feet of gas per day. The field is in
1,690 feet of water and is producing from an articulated compliant tower. A
successful exploration well was drilled in late 2003 in Garden Banks 216 (Penn
State) and was completed at year-end. This well will be tied back to the
existing Penn State subsea system, with first production scheduled for early
2004.
Pompano field, Viosca Knoll block 989 area (25%): Average 2003 gross production
from the Pompano field was 23,500 barrels of oil per day and 55 million cubic
feet of gas per day. One well was drilled in the Pompano field during 2003 and
was successfully brought on-line in early July 2003 at a production rate of 5
million cubic feet of gas per day.
North Sea:
Kerr-McGee has been active in the North Sea area since 1976. As of December 31,
2003, Kerr-McGee had interests in 20 producing fields in the United Kingdom
sector. In 2003, North Sea production represented 48% of the company's worldwide
crude oil and condensate production and 13% of its gas sales. The North Sea
represents about 27% of Kerr-McGee's total worldwide proved reserves.
During 2003, the company launched a six-well North Sea exploration and appraisal
program with the drilling of five operated wells and one nonoperated well. Four
of these wells were successful. In addition, the company was successful in the
United Kingdom 21st Licence Round with the awards of block 21/4b, licence P.1104
(100%, operator); block 30/7b, licence P.1123 (100%, operator); and block
16/13b, license P.1094 (50%, operator).
Business development initiatives during 2003 to strengthen the North Sea core
area included acquiring an 85% interest and operatorship of block 30/14 and a
39.9% interest in Norwegian block 1/5. Kerr-McGee also acquired a 30%
nonoperated interest in block 30/13 area C. These blocks contain known
hydrocarbon discoveries which the company believes may have future appraisal or
development potential. In addition, Kerr-McGee increased its equity holding in
the operated Gryphon field (9/18a, 9/18b) by acquiring an additional 25%
interest, increasing Kerr-McGee's total equity interest to 86.5%.
During 2003, production began on the Braemar field, in which Kerr-McGee has a 5%
interest. The field was developed using a subsea tieback to the East Brae field
(7.3% Kerr-McGee interest). First oil on Braemar occurred in September 2003.
Average gross production in 2003 from first oil was 3,900 barrels of oil per day
and 55.6 million cubic feet of gas per day.
The following is a summary of the company's five key developments in the North
Sea. These developments contributed approximately 76% of total net North Sea
production.
Gryphon area, blocks 9/18a, 9/18b, 9/19 and 9/23a (Maclure field 33.3%, Gryphon
field 86.5%, South Gryphon field 89.9% and Tullich field 100%): Average 2003
gross production from the Gryphon area was 29,400 barrels of oil per day and
10.5 million cubic feet of gas per day. The Maclure and Tullich subsea
satellites began production in August 2002. The Gryphon area is produced into a
floating production, storage and offloading (FPSO) vessel, with oil exported via
shuttle tanker. Gas is exported to the Leadon facility for fuel usage and/or
sold on the spot market via the St. Fergus terminal. An additional 25% equity
interest was acquired in the Gryphon field in 2003.
Janice field, block 30/17a (75.3%): Average 2003 gross production from the
Janice field was 12,100 barrels of oil per day and 1 million cubic feet of gas
per day.
Leadon field, block 9/14a and 9/14b (100%): Average 2003 gross production from
the Leadon field was 10,700 barrels of oil per day. The Leadon field is being
produced into an FPSO vessel, and the oil is exported via shuttle tanker.
Harding field, block 9/23b (30%): Average 2003 gross production from the Harding
field was 48,900 barrels of oil per day. The Harding field provides Kerr-McGee
with additional infrastructure in the strategically important quadrant 9 area of
the North Sea. Within the same quadrant, Kerr-McGee also has equity interests in
the Gryphon, Leadon, Buckland, Skene, Maclure, Tullich, Blue Sky and Blue Sky 2
fields.
Skene field, block 9/19 (33.3%): The Skene field began production in December
2001. Average 2003 gross field production was 135 million cubic feet of gas per
day and 6,500 barrels of oil per day. The Skene field is being produced through
a subsea tieback to the Beryl Alpha platform. The oil is exported via shuttle
tanker, while the gas is exported via pipeline to the St. Fergus terminal.
U.S. Onshore:
Kerr-McGee is active in the U.S. onshore region with production operations in
Texas, Oklahoma, New Mexico, Louisiana and Colorado. In 2003, U.S. onshore
production represented 49% of the company's worldwide gas production, 13% of its
oil production, and 34% of total proved reserves.
Following is a summary of key U.S. onshore developments:
Wattenberg field (94%): The Wattenberg gas field is located in the
Denver-Julesburg (DJ) basin in northeast Colorado. Kerr-McGee's 2003 net
production from this field was 10,400 barrels of oil per day and 184 million
cubic feet of gas per day. During 2003, the company completed nearly 500
development projects in the field, including deepenings, fracture stimulations,
recompletions and an aggressive infill drilling program. The J Sand infill and
Codell refracture programs continue to supply significant low-risk development
opportunities. In addition, significant success was achieved in 2003 by
performing a third fracture stimulation operation, or "tri-frac," on existing
Codell producers. Likewise, initial results indicated a 50-well pilot infill
drilling program in the Codell was highly successful, leading to substantial new
exploitation opportunities in the field.
In support of the ongoing DJ basin exploitation program, the company continued
the successful integration of the Wattenberg Gathering System into its operating
activities. During 2003, one new compressor was added, bringing the total system
horsepower to 65,000. This addition, combined with several modifications to
existing compressor units, reduced the overall pipeline system pressure by 10%
and reduced production downtime associated with pipeline pressure variations.
Kerr-McGee operates more than 3,100 wells in the DJ basin, nearly 2,100 of which
are connected to the Wattenberg Gathering System. The company-operated
production represents about 70% of the total system throughput of approximately
255 million cubic feet of natural gas per day, 30 million cubic feet of which is
processed at the company's Ft. Lupton plant.
Flores and Jeffress fields, Starr and Hidalgo counties, Texas (80%): The company
completed nine new wells and an additional 31 workover projects during 2003.
More than 60 wells have been drilled since 2001. Kerr-McGee's 2003 net
production from both fields averaged 2,200 barrels of oil per day and 41 million
cubic feet of gas per day.
Rincon field, Starr County, Texas (40%): Kerr-McGee acquired this interest in
2003. The company initiated a development drilling program at year-end 2003 in
this field, which is expected to continue to enhance its position in South
Texas.
Chambers County, Texas (75%): Four new wells and an additional 15 workover
projects were completed in 2003. Kerr-McGee's net production from the area
during 2003 averaged 1,000 barrels of oil per day and 20 million cubic feet of
gas per day.
Kerr-McGee participated in eight exploratory wells during 2003 in the Northern
Rockies area. This activity included five wells in the northeastern Colorado
Niobrara play, one in western Colorado and two in southwest Wyoming. Production
has been established from the western Colorado well, and development drilling is
planned for 2004. The Wind River basin well in central Wyoming was being
completed at year-end 2003. Three discoveries in the northeastern Colorado
Niobrara play were successful and are currently under evaluation. Further
exploration activity is planned for 2004 in four prospect areas, including
additional wells in both the Wind River basin and the northeastern Colorado
Niobrara prospects.
Kerr-McGee signed a participation agreement with Armstrong Oil and Gas on
December 24, 2003, to jointly explore areas of the prolific Alaska North Slope.
Kerr-McGee acquired a 70% working interest in eight leases totaling
approximately 12,000 acres off the Alaska coast, northwest of Prudhoe Bay.
Kerr-McGee will operate the leases and spud an exploratory well during February
2004. The agreement includes the right to acquire an interest in 13 additional
leases in the area, totaling 54,000 acres.
China:
Bohai Bay block 04/36 (81.8% contractor interest): During 2003, Kerr-McGee
gained government approval for the development of the CFD 11-1 and CFD 11-2
fields. Development drilling began in November 2003 on CFD 11-1. Both platform
jackets and pipelines have been installed. Construction of the topsides for both
jackets has progressed, and installation is planned in the second quarter of
2004. Construction of the FPSO was initiated in 2003 and is progressing as
planned. First production is expected in late 2004 following offshore
installation of the Single Point Mooring system and the FPSO. Also during 2003,
Kerr-McGee was granted a two-year extension by the China National Offshore Oil
Company (CNOOC) for the third exploration phase of the 04/36 Block concession.
The extension runs through September 2005.
Exploration efforts continued during 2003 with the discovery of the CFD 11-5 and
CFD 11-6 fields. The results of CFD 11-5, along with the results of the adjacent
CFD 11-3 area, are being integrated into a formal report on Oil In Place (OIP)
for submission to the Chinese government by the end of the first quarter of
2004. The CFD 11-3 area was discovered in 2002 and is located approximately 3
kilometers from the CFD 11-1 FPSO. Evaluation of resource potential was
initiated for the CFD 11-6 field, which is located approximately 15 kilometers
from the FPSO. A combined OIP report for the CFD 11-6 field in 04/36 and the CFD
12-1/12-1S field in 05/36 is in progress. Appraisal wells drilled in 2003 on the
CFD 16-1 and CFD 2-1 discoveries were unsuccessful; however, CFD 16-1 is still
under evaluation.
Bohai Bay block 05/36 (50% contractor interest): Two appraisal wells were
successfully drilled in the CFD 12-1/12-1S field during 2003. Two wildcat
exploration wells drilled during the year were unsuccessful. Evaluation of a
combined development program to include the CFD 12-1 and CFD 12-1S fields as
well as the CFD 11-6 field in 04/36 is ongoing. New prospects are being
evaluated for drilling in 2004.
Bohai Bay block 09/18 (100% contractor interest): The first exploration phase
has been extended from September 2003 to September 2004. The 2003 exploration
program included one wildcat well for phase one, which was unsuccessful. Two
exploration wells are planned for 2004 on this 550,000-acre block.
Bohai Bay block 09/06 (100% contractor interest): The company signed a new
exploration contract in August 2003 for this 440,000-acre block in Bohai Bay
adjacent to the other concessions operated by Kerr-McGee. Seismic data have been
purchased, including 146 square kilometers of 3-D and 2,220 kilometers of 2-D
data. Additional data purchase and geological and geophysical evaluation are in
progress.
Liuhua field, South China Sea (24.5% contractor interest): Gross production for
2003 was 9,200 barrels of oil per day. One sidetrack and one extended-reach well
were drilled in 2003. The company completed the divestiture of its Liuhua
interest in July 2003.
Other International:
Australia
WA 278P (39%): At year end, a retention lease application was being negotiated
with the Australian government for the areas around Kerr-McGee's Prometheus and
Rubicon wells. These wells, drilled in 2000, successfully encountered natural
gas but were considered noncommercial.
WA 295 (50%): Kerr-McGee operated this 3.5 million-acre block in the Carnarvon
basin. Acquisition of 4,800 kilometers of 2-D seismic data was completed in
2001, and a two-well drilling program was initiated in late 2002. The first well
of the program was unsuccessful, and the company's obligation to drill the
second well was eliminated through negotiation with the Australian government.
The block was surrendered in October 2003.
WA 301, 302, 303, 304 and 305 (50%): Kerr-McGee has an interest in 6.4 million
acres in the deepwater Browse basin. The first exploration well, Maginnis, was
drilled early in 2003 and was unsuccessful. Kerr-McGee has successfully
renegotiated and entered into phase two of exploration, and has acquired a new
3-D seismic survey over a portion of two blocks.
WA 337 (100%) and WA 339 (50%): In early 2003, Kerr-McGee acquired an interest
in 2.3 million acres in the deepwater Perth basin. Seismic acquisition began
over both blocks in late 2003.
EPP 33 (100%): In late 2003, Kerr-McGee was awarded an interest in 1.35 million
acres in the deepwater Otway basin.
Bahamas
On June 25, 2003, Kerr-McGee signed an exploration contract (100%) on 6.5
million acres in northern Bahamian waters, 90 miles east of the Florida coast.
Water depths range from 650 feet to 7,000 feet. Kerr-McGee began a speculative
seismic acquisition program in late 2003.
Benin
Block 4 (70%): Kerr-McGee owns a 70% working interest in 2.5 million acres
offshore Benin. Water depths on this block range from 300 feet to 10,000 feet. A
two-well drilling program was initiated in late 2002, and both wells found
noncommercial amounts of hydrocarbons. Acquisition of additional 2-D seismic
data was completed in 2003 to evaluate areas not covered by the current 3-D
seismic data. In late 2002, Kerr-McGee and Petronas Carigali Overseas Sdn Bhd.
entered into a partnership on the block. The joint venture entered the next
three-year phase of exploration in August 2003.
Brazil
BM-ES-9 (50%): This offshore block was acquired in 2001 and extends over 535,000
acres in the Espirito Santo basin in water depths ranging from 4,400 feet to
9,600 feet. During 2002, 3-D seismic data was acquired and is currently being
evaluated. Kerr-McGee plans to drill one well on the block in 2004.
BM-C-7 (33 1/3%): In December 2003, Kerr-McGee acquired an interest in the
BM-C-7 block in the Campos basin, subject to government approvals. In 2004,
Kerr-McGee expects to participate in one exploratory well on this 161,000-acre
block in approximately 400 feet of water. EnCanBrasil operates the block with 66
2/3% interest.
Gabon
Olonga Marin block (25%): Kerr-McGee and partners conducted seismic operations
in 2003. The company intends to relinquish its acreage when the first
exploration period expires in March 2004.
Morocco and Western Sahara
Cap Draa block (25%): Kerr-McGee and partners have an exploration contract
covering approximately 3 million acres along the deepwater shelf edge offshore
Morocco, in water depths ranging from 650 feet to 6,500 feet. A 3-D seismic
acquisition was completed in 2002 and is currently being evaluated. Kerr-McGee
plans to participate in the drilling of one exploratory well in 2004. In
February 2004, the company executed a farm-out agreement with Shell, reducing
its interest in this block to 11.25%.
Boujdour block (100%): In October 2001, Kerr-McGee acquired a reconnaissance
permit covering approximately 27 million acres offshore Western Sahara from the
shoreline to a water depth of more than 10,000 feet. A reconnaissance permit
allows Kerr-McGee to perform seismic and related activities for evaluation
purposes. Kerr-McGee completed its acquisition of a large 2-D seismic grid in
early 2003. A new seismic and drop core survey will begin in early 2004.
Nova Scotia, Canada
EL2383, EL2386, EL2393 and EL2396 (50%): Kerr-McGee is operator of four
deepwater blocks covering approximately 1.5 million acres offshore Nova Scotia,
Canada, in water depths ranging from 500 feet to 9,200 feet. A 3-D seismic
survey across two of the blocks was interpreted in 2001. Additional 2-D seismic
data is being acquired outside the area covered by the current 3-D survey.
EL2398 (66 2/3%), EL2399 (100%) and EL2404 (50%): These Kerr-McGee operated
blocks, covering more than 1.5 million acres, are in water depths ranging from
350 feet to 10,000 feet. A regional 2-D seismic program was interpreted in 2001,
and additional 2-D seismic data was acquired in 2003.
Yemen
Block 50 (47.5%): Kerr-McGee and Nexen (operator) farmed out a portion of their
interest to Petronas Carigali Overseas Sdn Bhd. in 2002. Terms of the farm-out
arrangement called for Petronas to pay a disproportionate share of forward costs
for seismic data and exploratory wells. The company intends to relinquish its
interest in block 50 in April 2004.
CHEMICALS
Kerr-McGee Corporation's chemical operations consist of two segments (pigment
and other) that produce and market inorganic industrial chemicals, heavy
minerals and forest products through its affiliates Kerr-McGee Chemical LLC,
KMCC Western Australia Pty. Ltd., Kerr-McGee Pigments GmbH, Kerr-McGee Pigments
International GmbH, Kerr-McGee Pigments Ltd., Kerr-McGee Pigments (Holland) B.V.
and Kerr-McGee Pigments (Savannah) Inc. Many of the pigment products are
manufactured using proprietary chloride technology developed by the company.
Industrial chemicals include titanium dioxide, synthetic rutile, manganese
dioxide, boron and sodium chlorate. Heavy minerals produced are ilmenite,
natural rutile, leucoxene and zircon. Forest products operations treat railroad
crossties and other hardwood products and provide other wood-treating services.
On December 16, 2002, the company announced plans to exit the forest products
business due to the strategic focus on the growth of the core businesses, oil
and gas exploration and production and the production and marketing of titanium
dioxide pigment. Four of the company's five wood-treatment facilities were
closed during 2003 and the fifth will cease operations by the end of 2004.
During 2003 and 2002, the company took after-tax charges of $9 million and $15
million, respectively, for plant and equipment impairment, decommissioning and
environmental expenses.
In June 2003, Kerr-McGee closed its synthetic rutile plant in Mobile, Alabama.
This plant closure was another step in the company's plan to enhance its
operating profitability. The Mobile plant processed and supplied a portion of
the feedstock for the company's titanium dioxide pigment plants in the United
States. Through ongoing supply-chain initiatives, Kerr-McGee can now purchase
the feedstock more economically than it could be manufactured at the Mobile
plant. In connection with the shutdown, the company took an after-tax charge of
$30 million for severance, accelerated depreciation and other decommissioning
expenses during 2003. As a result of these steps, the company anticipates
significant savings.
In July 2003, the company filed an anti-dumping action against low-priced
electrolytic manganese dioxide (EMD) illegally imported into the U.S. and
temporarily idled the Henderson, Nevada, EMD manufacturing facility due to the
impact of these imports on market conditions. Partly as a result of the
anti-dumping petition, demand for U.S. EMD products increased and the plant
resumed operations in December 2003. The company withdrew the anti-dumping
petition in February 2004, but will continue to monitor market conditions.
In January 2004, the company announced the temporary idling of its sulfate
process titanium dioxide pigment production train at the Savannah manufacturing
facility, which is one of two sulfate process trains operated by the company
worldwide. Production is expected to resume as market conditions improve.
Titanium Dioxide Pigment
- ------------------------
The company's primary chemical product is titanium dioxide pigment (TiO2), a
white pigment used in a wide range of products, including paint, coatings,
plastics, paper and specialty applications. TiO2 is used in these products for
its unique ability to impart whiteness, brightness and opacity.
Titanium dioxide pigment is produced in two crystalline forms - rutile and
anatase. The rutile form has a higher refractive index than anatase titanium
dioxide, providing better opacity and tinting strength. Rutile titanium dioxide
products also provide a higher level of durability (resistance to weathering).
In general, the rutile form of titanium dioxide is preferred for use in paint,
coatings, plastics and inks. Anatase titanium dioxide is less abrasive than
rutile and is preferred for use in fibers, rubber, ceramics and some paper
applications.
Titanium dioxide is produced using one of two different technologies, the
chloride process and the sulfate process, both of which are used by Kerr-McGee.
Because of market considerations, chloride-process capacity has increased to a
substantially higher level than sulfate-process capacity during the past 20
years. The chloride process currently makes up about 60% of total industry
capacity and accounts for approximately 76% of the company's gross production
capacity.
The company produces TiO2 pigment at six production facilities. Three are
located in the United States, the others in Australia, Germany and the
Netherlands. The following table outlines the company's production capacity by
location and process.
TiO2 Capacity
As of January 1, 2004
(Gross tonnes per year)
Facility Capacity Process
- -------- -------- --------
Hamilton, Mississippi 225,000 Chloride
Savannah, Georgia 110,000 Chloride
Kwinana, Western Australia (1) 100,000 Chloride
Botlek, Netherlands 72,000 Chloride
Uerdingen, Germany 107,000 Sulfate
Savannah, Georgia 54,000 Sulfate
-------
Total 668,000
=======
(1) The Kwinana facility is part of the Tiwest Joint Venture, in which the
company owns a 50% undivided interest.
The company owns a 50% undivided interest in a joint venture that operates an
integrated TiO2 project in Western Australia (the Tiwest Joint Venture). The
venture consists of a heavy-minerals mine, a minerals separation facility, a
synthetic rutile plant and a titanium dioxide plant.
Heavy minerals are mined from 8,513 hectares (21,037 acres) leased by the Tiwest
Joint Venture. The company's 50% interest in the properties' remaining in-place
proven and probable reserves is 6 million tonnes of heavy minerals contained in
215 million tonnes of sand averaging 2.8% heavy minerals. The valuable heavy
minerals are composed of 61% ilmenite, 4.5% natural rutile, 3.4% leucoxene and
10% zircon, with the remaining 21.1% of heavy minerals having no significant
value.
Heavy-mineral concentrate from the mine is processed at a 750,000 tonne-per-year
dry separation plant. Some of the recovered ilmenite is upgraded at a nearby
synthetic rutile facility, which has a capacity of 220,000 tonnes per year.
Synthetic rutile is a high-grade titanium dioxide feedstock. The Tiwest Joint
Venture provides synthetic rutile feedstock to a 100,000 tonne-per-year titanium
dioxide plant located at Kwinana, Western Australia. Production of ilmenite,
synthetic rutile, natural rutile and leucoxene in excess of the Tiwest Joint
Venture's requirements is sold to third parties, as well as to Kerr-McGee as
part of its feedstock requirement for TiO2 under a long-term agreement executed
in September 2000.
Information regarding heavy-mineral reserves, production and average prices for
the three years ended December 31, 2003, is presented in the following table.
Mineral reserves in this table represent the estimated quantities of proven and
probable ore that, under presently anticipated conditions, may be profitably
recovered and processed for the extraction of their mineral content. Future
production of these resources depends on many factors, including market
conditions and government regulations.
Heavy-Mineral Reserves, Production and Prices
---------------------------------------------
(Thousands of tonnes) 2003 2002 2001
- --------------------------------------------------------------------------------
Proven and probable reserves 5,970 5,700 5,800
Production 294 289 280
Average market price (per tonne) $152 $150 $143
Titanium-bearing ores used for the production of TiO2 include ilmenite, natural
rutile, synthetic rutile, titanium-bearing slag and leucoxene. These products
are mined and processed in many parts of the world. In addition to ores
purchased from the Tiwest Joint Venture, the company obtains ores for its TiO2
business from a variety of suppliers in the United States, Australia, Canada,
South Africa, Norway, India and Ukraine. Ores are generally purchased under
multiyear agreements.
The global market in which the company's titanium dioxide business operates is
highly competitive. The company actively markets its TiO2 utilizing primarily
direct sales but also through a network of agents and distributors. In general,
products produced in a given market region will be sold there to minimize
logistical costs. However, the company actively exports products, as required,
from its facilities in the United States, Europe and Australia to other market
regions.
Titanium dioxide applications are technically demanding, and the company
utilizes a strong technical sales and services organization to carry out its
marketing efforts. Technical sales and service laboratories are strategically
located in major market areas, including the United States, Europe and the
Asia-Pacific region. The company's products compete on the basis of price and
product quality, as well as technical and customer service.
Stored Power
- ------------
The company owns a 50% interest in AVESTOR, a joint venture formed in 2001 to
produce and commercialize a solid-state lithium-metal-polymer (LMP) battery.
Compared with traditional lead-acid batteries, AVESTOR's no-maintenance battery
offers superior performance at one-third the size, one-fifth the weight and two
to four times the life. The batteries also provide an environmentally preferred
alternative since they contain no acid or liquid that may spill or leak. The
AVESTOR joint venture began battery sales in late 2003 from its plant near
Montreal and expects to increase production during 2004. Initial battery sales
and customer feedback indicate strong demand in the telecommunications industry,
the initial target market. Battery quality and performance will be carefully
monitored and evaluated as production rates increase. Development of AVESTOR
batteries for industrial, utility and electric vehicle markets is under way.
Other Products
- --------------
The other segment within the chemical operations consists of the company's
electrolytic operations and forest products business.
Electrolytic Products - Plants at the company's Hamilton, Mississippi, complex
include a 135,000 tonne-per-year sodium chlorate facility. Sodium chlorate is
used in the environmentally preferred chlorine dioxide process for bleaching
pulp. Sodium chlorate demand in the United States is expected to increase
approximately 2% to 3% per year in the near term as the pulp and paper industry
recovers and completes conversion to the chlorine dioxide process.
The company operates facilities at Henderson, Nevada, producing electrolytic
manganese dioxide and boron trichloride. Annual production capacity is 29,500
tonnes for manganese dioxide and 340,000 kilograms for boron trichloride. Boron
trichloride is used in the production of pharmaceuticals and in the manufacture
of semiconductors.
Manganese dioxide is a major component of alkaline batteries. The company's
share of the North American manganese dioxide market is approximately one-third.
Demand is being driven by the need for alkaline batteries for portable
electronic devices.
As part of the company's strategic decision to focus on the titanium dioxide
pigment business, the company continues to investigate divestiture options for
the electrolytic business.
Forest Products - The principal product of the forest products business is
treated railroad crossties. Other products include railroad crossing materials,
bridge timbers and utility poles. As previously discussed, the company is in the
process of closing its plants and exiting the forest products business. Only one
of the company's five wood-treating plants, located in The Dalles, Oregon,
remained in operation at December 31, 2003. The Dalles plant is a leased
facility, and the company will continue operations at the plant for the term of
the lease, which expires November 30, 2004.
OTHER
Research and Development
- ------------------------
The company's Technical Center in Oklahoma City performs research and
development in support of existing businesses and for the development of new and
improved products and processes. The primary focus of the company's research and
development efforts is on the titanium dioxide business. A separate dedicated
group at the Technical Center performs research and development in support of
the company's battery materials business.
Employees
- ---------
On December 31, 2003, the company and its affiliates had 3,915 employees.
Approximately 1,025, or 26%, of these employees were represented by chemical
industry collective bargaining agreements in the United States and Europe.
Competitive Conditions
- ----------------------
The petroleum industry is highly competitive, and competition exists from the
initial process of bidding for leases to the sale of crude oil and natural gas.
Competitive factors include finding and developing petroleum reserves, producing
crude oil and natural gas efficiently, transporting the produced crude oil and
natural gas, and developing successful marketing strategies. Many of the
company's competitors have substantially larger financial resources, staffs and
facilities than Kerr-McGee, which test Kerr-McGee's ability to compete with
them.
The titanium dioxide pigment business is highly competitive. The number of
competitors in the industry has declined due to recent consolidations, and this
trend is expected to continue. Significant consolidation among the consumers of
titanium dioxide has also taken place during the past five years and is expected
to continue. Worldwide, Kerr-McGee is one of only five producers that own
proprietary chloride-process technology to produce titanium dioxide pigment.
Cost efficiency and product quality as well as technical and customer service
are key competitive factors in the titanium dioxide business.
It is not possible to predict the effect of future competition on Kerr-McGee's
operating and financial results.
GOVERNMENT REGULATIONS AND ENVIRONMENTAL MATTERS
General
- -------
The company's affiliates are subject to extensive regulation by federal, state,
local and foreign governments. The production and sale of crude oil and natural
gas are subject to special taxation by federal, state, local and foreign
authorities and regulation with respect to allowable rates of production,
exploration and production operations, calculations and disbursements of royalty
payments, and environmental matters. Additionally, governmental authorities
regulate the generation and treatment of waste and air emissions at the
operations and facilities of the company's affiliates. At certain operations,
the company's affiliates also comply with certain worldwide, voluntary standards
such as ISO 9002 for quality management and ISO 14001 for environmental
management, which are standards developed by the International Organization for
Standardization, a nongovernmental organization that promotes the development of
standards and serves as an external oversight for quality and environmental
issues.
Environmental Matters
- ---------------------
Federal, state and local laws and regulations relating to environmental
protection affect almost all company operations. Under these laws, the company's
affiliates are or may be required to obtain or maintain permits and/or licenses
in connection with their operations. In addition, these laws require the
company's affiliates to remove or mitigate the effects on the environment of the
disposal or release of certain chemical, petroleum, low-level radioactive and
other substances at various sites. Operation of pollution-control equipment
usually entails additional expense. Some expenditures to reduce the occurrence
of releases into the environment may result in increased efficiency; however,
most of these expenditures produce no significant increase in production
capacity, efficiency or revenue.
During 2003, direct capital and operating expenditures related to environmental
protection and cleanup of existing sites totaled $37 million. Additional
expenditures totaling $104 million were charged to environmental reserves. While
it is difficult to estimate the total direct and indirect costs to the company
of government environmental regulations, the company presently estimates that in
2004 it will incur $13 million in direct capital expenditures, $10 million in
operating expenditures and $98 million in expenditures charged to reserves.
Additionally, the company estimates that in 2005 it will incur $5 million in
direct capital expenditures, $4 million in operating expenditures and $66
million in expenditures charged to reserves.
The company and its affiliates are parties to a number of legal and
administrative proceedings involving environmental matters and/or other matters
pending in various courts or agencies in the United States and other
jurisdictions. These include proceedings associated with facilities currently or
previously owned, operated or used by the company's affiliates and/or their
predecessors, some of which include claims for personal injuries and property
damages. The current and former operations of the company's affiliates also
involve management of regulated materials and are subject to various
environmental laws and regulations. These laws and regulations obligate the
company's affiliates to clean up various sites at which petroleum and other
hydrocarbons, chemicals, low-level radioactive substances and/or other materials
have been contained, disposed of or released. Some of these sites have been
designated Superfund sites by the U.S. Environmental Protection Agency (EPA)
pursuant to the Comprehensive Environmental Response, Compensation, and
Liability Act of 1980 (CERCLA) and are listed on the National Priority List
(NPL).
The company provides for costs related to environmental contingencies when a
loss is probable and the amount is reasonably estimable. It is not possible for
the company to reliably estimate the amount and timing of all future
expenditures related to environmental matters because, among other reasons:
o some sites are in the early stages of investigation, and other sites may be
identified in the future;
o remediation activities vary significantly in duration, scope and cost from
site to site depending on the mix of unique site characteristics,
applicable technologies and regulatory agencies involved;
o cleanup requirements are difficult to predict at sites where remedial
investigations have not been completed or final decisions have not been
made regarding cleanup requirements, technologies or other factors that
bear on cleanup costs;
o environmental laws frequently impose joint and several liability on all
potentially responsible parties, and it can be difficult to determine the
number and financial condition of other potentially responsible parties and
their respective shares of responsibility for cleanup costs;
o environmental laws and regulations, as well as enforcement policies, are
continually changing, and the outcome of court proceedings and discussions
with regulatory agencies are inherently uncertain;
o unanticipated construction problems and weather conditions can hinder the
completion of environmental remediation;
o the inability to implement a planned engineering design or use planned
technologies and excavation methods may require revisions to the design of
remediation measures, which delay remediation and increase its costs; and
o the identification of additional areas or volumes of contamination and
changes in costs of labor, equipment and technology generate corresponding
changes in environmental remediation costs.
The company believes that currently it has reserved adequately for the
reasonably estimable costs of contingencies. However, additions to the reserves
may be required as additional information is obtained that enables the company
to better estimate its liabilities, including any liabilities at sites now under
review. The company cannot now reliably estimate the amount of future additions
to the reserves. Additionally, there may be other sites where the company has
potential liability for environmental-related matters but for which the company
does not have sufficient information to determine that the liability is probable
and/or reasonably estimable. The company has not established reserves for such
sites.
For an expanded discussion of environmental matters, see "Item 3. Legal
Proceedings," "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations," and Note 16 to the Consolidated Financial
Statements contained in Item 8. to this Form 10-K.
RISK FACTORS
In addition to the risks identified in Management's Discussion and Analysis
included in Item 7. of this Form 10-K, investors should consider carefully the
following risks.
Volatile Product Prices and Markets Could Adversely Affect Results
- ------------------------------------------------------------------
The company's results of operations are highly dependent on the prices of and
demand for oil and gas and the company's chemical products. Historically, the
markets for oil and gas have been volatile and are likely to continue to be
volatile in the future. Accordingly, the prices received by the company for its
oil and gas production depend on numerous factors that are beyond its control.
These factors include, but are not limited to, the domestic and foreign supply
of oil and natural gas, the level of ultimate consumer product demand,
governmental regulations and taxes, the price and availability of alternative
fuels, the level of imports and exports of oil and gas, actions of the
Organization of Petroleum Exporting Countries, the political and economic
uncertainty of foreign governments, international conflicts and civil
disturbances, weather conditions, and the overall economic environment. A
sustained decline in prices for oil and gas could have a material adverse effect
on the company's financial condition, revenues, results of operations, cash
flows and quantities of reserves recoverable on an economic basis.
Demand for titanium dioxide depends on the demand for finished products that use
titanium dioxide pigment. This demand generally depends on the condition of the
economy. The profitability of the company's products depends on the price
realized for them, the efficiency of manufacturing processes, and the ability to
acquire feedstock at a competitive price.
Should the industries in which the company operates experience significant price
declines or other adverse market conditions, the company may not be able to
generate sufficient cash flow from operations to meet its obligations and make
planned capital expenditures. In order to manage its exposure to price risks in
the sale of oil and gas, the company may from time to time enter into
commodities contracts to hedge a portion of its crude oil and natural gas sales
volume. Any such hedging activities may prevent the company from realizing the
benefits of price increases above the levels reflected in such hedges.
Failure to Fund Continued Capital Expenditures Could Decrease Production Over
Time and Adversely Affect Results
- --------------------------------------------------------------------------------
Maintaining the company's current level of oil and gas reserves requires the
successful exploration and development and/or acquisition of oil and gas
producing properties. As such, the company expects to continue to make capital
expenditures for the acquisition, exploration and development of oil and gas
reserves. If its revenues substantially decrease as a result of lower oil and
gas prices or other factors, the company may have a limited ability to expend
the capital necessary to replace its reserves or to maintain production at
current levels, resulting in a decrease in production over time. Historically,
the company has financed expenditures for the acquisition, exploration and
development of oil and gas reserves primarily with cash flow from operations and
proceeds from debt and equity financings, asset sales, and sales of partial
interests in foreign concessions. Management believes that the company will have
sufficient cash flow from operations, available drawings under its credit
facilities and other debt financings to fund capital expenditures. However, if
the company's cash flow from operations is not sufficient to satisfy its capital
expenditure requirements, there can be no assurance that additional debt or
equity financing or other sources of capital will be available to meet these
requirements. If the company is not able to fund its capital expenditures, its
interests in some properties may be reduced or forfeited. Failure to find and
develop reserves may have a material adverse effect on the company's ability to
generate future cash flows.
Oil and Gas Reserve Information Is Estimated, and Material Inaccuracies in
Assumptions and/or Estimates Could Adversely Affect Results
- --------------------------------------------------------------------------------
The proved oil and gas reserve information included in this Form 10-K is
estimated. These estimates are based primarily on reports prepared by the
company's geologists and engineers. Petroleum reserve estimation is a subjective
process of estimating underground accumulations of oil and gas that cannot be
measured in a direct or exact manner. Estimates of economically recoverable oil
and gas reserves and associated future net cash flows necessarily depend on a
number of variable factors and assumptions, including:
o historical production from the area compared with production from other
similar producing areas;
o the assumed effects of regulations by governmental agencies;
o assumptions concerning future oil and gas prices; and
o assumptions concerning future operating costs, severance and excise taxes,
development costs, and workover and remedial costs.
Because all reserve estimates are to some degree subjective, each of the
following items may differ materially from those assumed in estimating reserves:
o the quantities of oil and gas that are ultimately recovered;
o the production and operating costs incurred;
o the amount and timing of future development expenditures; and
o future oil and gas sales prices.
Furthermore, different reserve engineers may make different estimates of
reserves and cash flows based on the same available data. The company's actual
production, revenues and expenditures with respect to reserves will likely be
different from estimates, and the differences may be material. The discounted
future net cash flows included in this Form 10-K should not be considered as the
current market value of the estimated oil and gas reserves attributable to the
company's properties. As required by the U.S. Securities and Exchange Commission
(SEC), the estimated discounted future net cash flows from proved reserves are
based on prices and costs as of the date of the estimate, while actual future
prices and costs may be materially higher or lower. Actual future net cash flows
also will be affected by factors such as:
o the amount and timing of actual production;
o supply and demand for oil and gas;
o increases or decreases in consumption; and
o changes in governmental regulations or taxation.
The 10% discount factor, which is required by the SEC to be used to calculate
discounted future net cash flows for reporting purposes, is not necessarily the
most appropriate discount factor based on interest rates in effect from time to
time and risks associated with the company or the oil and gas industry in
general.
The Company's Debt Level May Limit Its Financial Flexibility
- ------------------------------------------------------------
The company incurs debt from time to time in connection with the financing of
company operations, acquisitions, recapitalizations and refinancings. The level
of the company's debt could have several important effects on future operations,
including, among others: a portion of the company's cash flow from operations
will be applied to the payment of principal and interest on the debt and will
not be available for other purposes; credit-rating agencies have changed, and
may continue to change, their ratings of the company's debt and other
obligations, which in turn impacts the costs, terms and conditions and
availability of financing; covenants contained in the company's existing and
future debt arrangements will require the company to meet financial tests that
may affect its flexibility in planning for and reacting to changes in its
business, including possible acquisition opportunities; the company's ability to
obtain additional financing for working capital, capital expenditures,
acquisitions, general corporate and other purposes may be limited or burdened by
increased costs or more restrictive covenants; the company may be at a
competitive disadvantage to similar companies that have less debt; and the
company's vulnerability to adverse economic and industry conditions may
increase.
Many of the Company's Competitors Have Greater Resources, Which Could Make It
Difficult For The Company to Compete In Its Industries
- --------------------------------------------------------------------------------
The oil and gas business and the titanium dioxide pigment business are each
highly competitive. The company competes with major integrated and other
independent oil and gas companies for the acquisition of oil and gas leases and
other properties; for the equipment and personnel required to explore, develop
and produce from those properties; and in the marketing of oil and natural gas
production. Likewise, the company competes with chemical companies in the
development, production and marketing of titanium dioxide. Many of the company's
competitors have substantially larger financial resources, staffs and facilities
than Kerr-McGee, which may give them a competitive advantage when responding to
market conditions and capitalizing on operating efficiencies.
Oil and Gas Operations Involve Substantial Operating and Economic Risks
- -----------------------------------------------------------------------
Drilling for oil and gas involves numerous risks, including the risk that the
company will not encounter commercially productive oil or gas reservoirs. The
costs of drilling, completing and operating wells are often uncertain, and
drilling operations may be curtailed, delayed or canceled as a result of a
variety of factors, including: unexpected drilling conditions; unanticipated
pressure or geologic irregularities; equipment failures or accidents;
miscalculations; fires, explosions, blow-outs and surface cratering; marine
risks such as currents, capsizing, collisions and hurricanes; other adverse
weather conditions; and shortages or delays in the delivery of equipment. This
could result in a total loss of the company's investment in a particular
property. If certain exploration efforts are unsuccessful in establishing proved
reserves and exploration activities cease, the amounts accumulated as unproved
property costs would be charged against earnings as impairments.
While all drilling, whether developmental or exploratory, involves these risks,
exploratory drilling involves greater risks of dry holes or failure to find
commercial quantities of hydrocarbons. As a part of its strategy, the company
explores for oil and gas offshore, often in deep water or at deep drilling
depths, where operations are more difficult and costly than on land or than at
shallower depths and in shallower waters. Deepwater operations generally require
a significant amount of time between a discovery and the time that the company
can produce and market the oil or gas, increasing both the operational and
financial risks associated with these activities. In addition, because a high
percentage of the company's capital budget is devoted to higher-risk exploratory
projects, it is likely that the company will continue to experience significant
exploration and dry hole expenses.
Kerr-McGee May Not Be Insured Against All Operating Risks to Which Its Business
Is Exposed
- --------------------------------------------------------------------------------
As protection against financial loss resulting from operating hazards, the
company maintains insurance coverage, including certain physical damage,
comprehensive general liability and worker's compensation insurance. However,
because of deductibles and other limitations, the company is not fully insured
against all risks in its business. The occurrence of a significant event against
which the company is not fully insured could have a material adverse effect on
its results of operations and/or financial position.
Kerr-McGee Operates in Foreign Countries and Will Be Subject to Political,
Economic and Other Uncertainties
- --------------------------------------------------------------------------------
The company conducts significant operations in foreign countries and may expand
its foreign operations in the future. Operations in foreign countries are
subject to political, economic and other uncertainties, including:
o the risk of war, acts of terrorism, revolution, border disputes,
expropriation, renegotiation or modification of existing contracts, import,
export and transportation regulations and tariffs;
o taxation policies, including royalty and tax increases and retroactive tax
claims;
o exchange controls, currency fluctuations and other uncertainties arising
out of foreign government sovereignty over the company's international
operations;
o laws and policies of the United States affecting foreign trade, taxation
and investment; and
o the possibility of being subject to the exclusive jurisdiction of foreign
courts in connection with legal disputes and the possible inability to
subject foreign persons to the jurisdiction of courts in the United States.
Foreign countries have occasionally asserted rights to land, including oil and
gas properties, through border disputes. If a country claims superior rights to
oil and gas leases or concessions granted to the company by another country, the
company's interests could be lost or decrease in value. Various regions of the
world have a history of political and economic instability. This instability
could result in new governments or the adoption of new policies that might
assume a substantially more hostile attitude toward foreign investment. In an
extreme case, such a change could result in termination of contract rights and
expropriation of foreign-owned assets. This could adversely affect the company's
interests. The company seeks to manage these risks by, among other things,
concentrating its international exploration efforts in areas where the company
believes that the existing government is stable and favorably disposed towards
U.S. exploration and production companies.
Regulation of Chemical Manufacturing Operations, Oil and Gas Development and
Surface Development Conflicts Could Adversely Affect Results
- --------------------------------------------------------------------------------
Regulatory authorities have established rules and regulations governing, among
other things, the operation of chemical manufacturing facilities, permits for
drilling and production, operations, performance bonds, reports concerning
operations, discharge, disposal and other waste-related permits, well spacing,
unitization and pooling of operations, surface use of properties where the
company has mineral interests, taxation, and environmental and conservation
matters. The company's continued compliance with amended, new or more stringent
requirements, as well as stricter interpretations of existing requirements, may
require the company to make material expenditures or subject the company to
liabilities beyond that which is currently anticipated. In addition, any failure
by the company to comply with existing or future laws could result in civil or
criminal fines and other enforcement actions.
Kerr-McGee Is Subject to Significant Environmental Compliance and Remediation
Costs That Can Adversely Affect the Cost of Doing Business
- --------------------------------------------------------------------------------
As more fully detailed below in Item 7, Management's Discussion and Analysis,
the company's plants and operations are subject to numerous laws and regulations
relating to the protection of the environment. The company has incurred, and
will continue to incur, substantial operating, maintenance, remediation and
capital expenditures as a result of these laws and regulations. The company's
continued compliance with amended, new or more stringent requirements, as well
as stricter interpretations of existing requirements, may require the company to
make material expenditures or subject the company to liabilities beyond that
which is currently anticipated. In addition, any failure by the company to
comply with existing or future laws could result in civil or criminal fines and
other enforcement actions.
The Company Is Subject to Lawsuits and Claims
- ---------------------------------------------
A number of lawsuits and claims are pending against the company, some of which
seek large amounts of damages. Although management believes that none of them
will have a material adverse effect on the company's financial condition or
liquidity, litigation is inherently uncertain, and the lawsuits and claims could
have a material adverse effect on the company's results of operations for the
accounting period or periods in which one or more of them might be resolved
adversely.
AVAILABILITY OF REPORTS AND GOVERNANCE DOCUMENTS
Kerr-McGee makes available at no cost on its Internet website,
www.kerr-mcgee.com, its Annual Report on Form 10-K, Quarterly Reports on Form
10-Q, Current Reports on Form 8-K and any amendments to those reports as soon as
reasonably practicable after the company electronically files or furnishes such
reports to the SEC. Interested parties should refer to the Investor Relations
link on the company's website. In addition, the company's Code of Business
Conduct and Ethics, Code of Ethics for The Chief Executive Officer and Principal
Financial Officers, Corporate Governance Guidelines and the charters for the
Board of Directors' Audit Committee, Executive Compensation Committee, Finance
Committee, and Nominating and Corporate Governance Committee, all of which were
adopted by the company's Board of Directors, can be found on the company's
website under the Corporate Governance link. The company will provide these
governance documents in print to any stockholder who requests them. Any
amendment to, or waiver of, any provision of the Code of Ethics for the Chief
Executive Officer and Principal Financial Officers and any waiver of the Code of
Business Conduct and Ethics for directors or executive officers will be
disclosed on the company's website under the Corporate Governance link.
Item 3. Legal Proceedings
A. In 2001, the company's chemical affiliate (Chemical) received a Notice of
Violation (NOV) from EPA, Region 9. The NOV claims that Chemical has been in
continuous violation of the Clean Air Act new source review requirements
applicable to the construction in 1994 and continued operation of an open-hearth
furnace at its Henderson, Nevada, facility. Chemical operated the open-hearth
furnace in compliance with state-issued permits and believes that the NOV is
without substantial merit. Chemical is vigorously defending against the claims
made in the NOV and believes that any fines and penalties related to the NOV
will not have a material adverse effect on the company.
B. In 2002, Tiwest Pty Ltd, an Australian joint venture that produces titanium
dioxide and in which Chemical indirectly has a 50% interest, received a
complaint and notice of violation from the Department of Environmental Waters
and Catchment Protection in Western Australia alleging violations of the
Environmental Protection Act (1986). This matter concerns an alleged chlorine
release at the facility. Tiwest defended the proceeding in the Court of Petty
Sessions, Perth, Western Australia, and expects a decision in the matter around
the end of the first quarter. As currently filed, the maximum fine is $625,000
(Australian dollars), but the liability of the joint venture and the amount of
any monetary fine are uncertain.
C. On December 15, 2003, the District Court of Rotterdam, Netherlands,
determined that Kerr-McGee Pigments (Holland) B.V., an affiliate of the company,
had violated regulations imposed by the Netherlands Environmental Management
Act. The violations primarily relate to the failure to notify authorities of the
release of process gases from the affiliate's facility in Botlek, Netherlands,
as required by the facility's environmental permit. The Court imposed a fine of
(euro)80,000, which concludes the case.
D. On January 7, 2004, the United States filed a civil lawsuit in the U.S.
District Court for the District of Oregon against Kerr-McGee Chemical Worldwide
LLC and two other private parties in connection with the remediation of
contaminated materials at the White King/Lucky Lass uranium mines in Lakeview,
Oregon. The mines were owned and operated by a predecessor of Kerr-McGee
Chemical Worldwide LLC and are currently designated as a Superfund site. The
lawsuit seeks reimbursement of Forest Service response costs, an injunction
requiring compliance with an Administrative Order issued to the private parties
regarding cleanup of the site, and civil penalties for alleged noncompliance
with the Administrative Order. The company expects all legal proceedings to be
stayed pending discussions to resolve outstanding issues. The company believes
that the litigation will not have a material adverse effect on the company.
E. On September 8, 2003, the Environmental Protection Division of the Georgia
Department of Natural Resources (EPD) issued a unilateral Administrative Order
to Kerr-McGee Pigments (Savannah) Inc., claiming that the Savannah plant
exceeded emission allowances provided for in the facility's Title V air permit.
The EPD is seeking monetary penalties of approximately $178,000. The company
appealed the order on October 8, 2003, which stayed the effectiveness of the
order. Meanwhile, the company is vigorously defending against the claims made in
the order and believes that any penalties related to them will not have a
material adverse effect on the company.
F. For a discussion of other legal proceedings and contingencies, reference is
made to (1) the Environmental Matters section of Management's Discussion and
Analysis of Financial Condition and Results of Operations included in Item 7.
and (2) Note 16 to the Consolidated Financial Statements included in Item 8. of
this Form 10-K, both of which are incorporated herein by reference.
Item 4. Submission of Matters to a Vote of Security Holders
None submitted during the fourth quarter of 2003.
Executive Officers of the Registrant
The following is a list of executive officers, their ages, and their positions
and offices as of March 1, 2004:
Name Age Office
- ----------------------- --- --------------------------------------------
Luke R. Corbett 57 Chief Executive Officer since 1997.
Chairman of the Board since May 1999 and
from 1997 to February 1999. President and
Chief Operating Officer from 1995 until
1997.
Kenneth W. Crouch 60 Executive Vice President since March 2003.
Senior Vice President from 1996 to 2003.
Senior Vice President, Exploration and
Production Operations, from 1998 to 2003.
Senior Vice President, Exploration, from
1996 to 1998.
David A. Hager 47 Senior Vice President, Exploration and
Production Operations, since March 2003.
Vice President of Exploration and
Production, 2002 to 2003. Vice President of
Gulf of Mexico and Worldwide Deepwater
Exploration and Production, 2001 to 2002;
Vice President of Worldwide Deepwater
Exploration and Production, 2000 to 2001;
Vice President of International Operations,
2000; previously Vice President of Gulf of
Mexico operations. Joined Sun Oil Co.,
predecessor of Oryx Energy Company, in
1981.
Gregory F. Pilcher 43 Senior Vice President, General Counsel and
Corporate Secretary since July 2000. Vice
President, General Counsel and Corporate
Secretary from 1999 to 2000. Deputy General
Counsel for Business Transactions from 1998
to 1999. Associate/Assistant General
Counsel for Litigation and Civil
Proceedings from 1996 to 1998.
Carol A. Schumacher 47 Senior Vice President of Corporate Affairs
since February 2002. Prior to joining the
company in 2002, served as Vice President
of Public Relations for The Home Depot,
1998 to 2001; Executive Vice President and
General Manager, Atlanta office of Edelman
Worldwide, 1997 to 1998; and Executive Vice
President of Cohn & Wolfe, a division of
Young & Rubicam, Inc.
Robert M. Wohleber 53 Senior Vice President and Chief Financial
Officer since December 1999. Prior to
joining the company in 1999, served as
Executive Vice President and Chief
Financial Officer of Freeport-McMoRan
Exploration Company, President and Chief
Executive Officer of Freeport-McMoRan
Sulfur and Senior Vice President of
Freeport-McMoRan Gold and Copper
Corporation.
W. Peter Woodward 55 Senior Vice President since 1997. Senior
Vice President of Marketing for Kerr-McGee
Chemical from 1996 to 1997.
George D. Christiansen 59 Vice President, Safety and Environmental
Affairs, since 1998. Vice President,
Environmental Assessment and Remediation,
from 1996 to 1998.
Fran G. Heartwell 57 Vice President of Human Resources since
March 2003; Director of Human Resources,
Kerr-McGee Oil & Gas, from September 2002
to January 2003; Vice President of Human
Resources and Administration, Oryx Energy
Company, from 1995 until the 1999 merger of
Oryx and Kerr-McGee.
J. Michael Rauh 54 Vice President since 1987. Controller since
January 2002 and 1987 to 1996. Treasurer
from 1996 to 2002.
John F. Reichenberger 51 Vice President, Deputy General Counsel and
Assistant Secretary since July 2000.
Assistant Secretary and Deputy General
Counsel from 1999 to 2000. Deputy General
Counsel from 1998 to 1999. Associate
General Counsel from 1996 to 1999.
Elizabeth T. Wilkinson 46 Vice President and Treasurer since November
2002. Previously Assistant Treasurer -
Corporate Finance, GlobalSantaFe
Corporation (Global Marine Inc. until 2001
merger); Manager of Planning and Analysis
from 1998 to 1999 and Manager of Budgets
and Planning from 1994 to 1998, Global
Marine Inc.
There is no family relationship between any of the executive officers.
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Statements in this Form 10-K regarding the company's or management's intentions,
beliefs or expectations, or that otherwise speak to future events, are
"forward-looking statements" within the meaning of the Private Securities
Litigation Reform Act of 1995. These forward-looking statements include those
statements preceded by, followed by or that otherwise include the words
"believes," "expects," "anticipates," "intends," "estimates," "projects,"
"target," "budget," "goal," "plans," "objective," "outlook," "should," or
similar words. In addition, any statements regarding possible commerciality,
development plans, capacity expansions, drilling of new wells, ultimate
recoverability of reserves, future production rates, future cash flows and
changes in any of the foregoing are forward-looking statements. Future results
and developments discussed in these statements may be affected by numerous
factors and risks, such as the accuracy of the assumptions that underlie the
statements, the success of the oil and gas exploration and production program,
drilling risks, the market value of Kerr-McGee's products, uncertainties in
interpreting engineering data, demand for consumer products for which
Kerr-McGee's businesses supply raw materials, the financial resources of
competitors, changes in laws and regulations, the ability to respond to
challenges in international markets, including changes in currency exchange
rates, political or economic conditions in areas where Kerr-McGee operates,
trade and regulatory matters, general economic conditions, and other factors and
risks discussed herein and in the company's other SEC filings. Actual results
and developments may differ materially from those expressed or implied in this
Form 10-K.
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
Information relative to the market in which the company's common stock is
traded, the high and low sales prices of the common stock by quarters for the
past two years, and the approximate number of holders of common stock is
furnished in Note 34 to the Consolidated Financial Statements, which note is
included in Item 8. of this Form 10-K.
Quarterly dividends declared totaled $1.80 per share for each of the years 2003,
2002 and 2001. Cash dividends have been paid continuously since 1941 and totaled
$181 million in 2003, $181 million in 2002 and $173 million in 2001.
For information required under Item 201(d) of Regulation S-K related to the
company's securities authorized for issuance under equity compensation plans,
reference is made to Item 12. of this Form 10-K.
Item 6. Selected Financial Data
Information regarding selected financial data required in this item is presented
in the schedule captioned "Ten-Year Financial Summary" included in Item 8. of
this Form 10-K.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Management's Discussion and Analysis
- --------------------------------------------------------------------------------
Overview
Kerr-McGee Corporation is one of the largest U.S.-based independent oil and gas
exploration and production companies and the world's third-largest producer and
marketer of titanium dioxide pigment. The company has three reportable business
segments, oil and gas exploration and production, production and marketing of
titanium dioxide pigment (chemical - pigment), and production and marketing of
other chemicals (chemical - other). The company's assets total approximately $10
billion. Proved oil and gas reserves are approximately 1 billion barrels of oil
equivalent and the company's equity production capacity for titanium dioxide
pigment is 618,000 tonnes per year. For 2003, revenues from continuing
operations totaled $4.2 billion, of which $2.9 billion (69%) was generated by
the company's oil and gas exploration and production operations and $1.3 billion
(31%) was generated by the company's chemical operations. Revenues for the
exploration and production operations are generated primarily from the sale of
crude oil and natural gas, as well as marketing revenues associated with the
company's sale of nonequity gas. Revenues for the company's chemical operations
are generated from the sale of titanium dioxide pigment and other chemical
products. An overview of each operating unit and certain other economic
considerations are included below to provide background for the various
discussions that will follow in Management's Discussion and Analysis of
Financial Condition and Results of Operations (MD&A). A detailed discussion of
each operating unit's business and properties is included in Items 1. and 2. of
this Form 10-K.
Exploration and Production - The company's exploration and production business
is primarily focused on finding and developing new oil and gas reserves. The
success of the company depends heavily on a successful exploration program. As a
benchmark, the company works to replace at least 100% of its production each
year through a combination of its drilling and development programs and tactical
acquisitions. During 2003, Kerr-McGee replaced 135% of its 2003 worldwide
production from continuing operations, of which 105% resulted from replacement
through the company's exploration program. Kerr-McGee has established a
competitive average finding, development and acquisition cost of $7.19 per
barrel of oil equivalent (BOE) and annual average production replacement of 192%
over the past five years, and remains focused on adding value to its reserve
base. The company faces many challenges in executing a successful exploration
program, including obtaining accurate and reliable geological and geophysical
data, understanding reservoir complexity, and inherent risks associated with
deepwater exploration, among others. Consequently, a portion of the company's
total exploration costs is dry hole cost for unsuccessful drilling activity. The
company works to mitigate these risks by attracting and retaining talented
exploration and engineering personnel with wide ranging experience in its core
exploration areas. The company utilizes advanced technology to maximize the
impact of its exploration efforts including both extensive geological and
geophysical data acquisition and analysis as well as state-of-the-art
visualization interpretation techniques. In addition, Kerr-McGee maintains an
extensive world-wide acreage position which the company believes provides it
with a significant competitive advantage in its effort to maintain and develop a
high-quality prospect inventory. The company believes its prospect inventory is
a key component in mitigating the inherent risk of its exploration program.
In addition, profitability and cash flows for exploration and production
operations are heavily dependent on market prices for crude oil and natural gas,
as well as production costs, taxation levels and other operating costs. To
mitigate uncertainties related to commodity price fluctuations, the company
hedged the sales price of a substantial portion of its 2003 oil and gas sales.
The company has entered into additional hedge contracts for 2004 to maximize the
predictability of its cash flows. In addition to hedging, the company monitors
its cost performance in an effort to maximize overall profitability and ensure
its ability to compete within the industry. In 2003, the company completed a
major divestiture program which was partially directed at reducing the overall
production cost of its asset portfolio. Completion of this program contributed
to a 12% reduction in the company's per unit production costs. Changes in
operating costs from year to year are discussed in the Segment Operations
section below.
While the company's drilling program and subsequent development of successful
projects generally yield attractive economic returns, they do require a
substantial capital commitment. An overview of historical capital spending, as
well as a discussion of the 2004 capital spending budget, major projects and
exploratory drilling program are included in the Capital Spending section of
MD&A below. On an ongoing basis, the carrying values of the company's oil and
gas properties are evaluated for recoverability relative to their future cash
flows. Likewise, reservoir performance and reserve quantities are periodically
reviewed. Negative revisions to reserve quantities or negative changes in the
market prices of crude oil and natural gas can adversely affect the company's
estimates of future cash flows and may result in asset impairments. Because of
the large capital investment required to develop oil and gas fields and the
uncertain mineral resources associated with each field, asset impairment
evaluations are common in the oil and gas industry and are indicative of
projects for which previous capital investments are no longer recoverable under
current economic conditions. Such impairments may occur in the future; however,
the company cannot predict the timing or magnitude of future asset impairment
charges.
Chemical - The chemical operating unit has focused its strategy on its titanium
dioxide pigment operations. As part of this strategic decision, the company
continues to investigate divestiture options for the electrolytic business and
plans to exit the forest products business by the end of 2004 when the lease on
its only facility still in operation expires.
The profitability of the company's pigment operations is tied to consumption of,
and demand for, titanium dioxide pigment, which generally follow global economic
trends (discussed in the Operating Environment and Outlook section below). The
profitability of the company's pigment operations also depends on the company's
ability to manage operating costs. As part of its efforts to manage operating
costs, the company closed its synthetic rutile plant in Mobile, Alabama, in June
2003. The Mobile plant supplied a portion of the feedstock for the company's
pigment plants in the United States; however, through ongoing supply-chain
initiatives, feedstock can now be purchased more economically than it could be
manufactured at the Mobile plant. In connection with the shutdown, the company
recorded after-tax charges of $30 million for severance, accelerated
depreciation and other decommissioning expenses during 2003.
Chemical is working on technological advancements that will allow it to add
plant capacity with low-cost expansions to take advantage of future market
growth. As a result of these efforts, production began through a new
high-productivity oxidation line at the Savannah, Georgia, chloride process
pigment plant in January 2004. This new technology is expected to result in
low-cost, incremental capacity increases through modification of existing
chloride oxidation lines and should allow for improved operating efficiencies
through simplification of hardware configurations and reduced maintenance
requirements.
Based on the future outcome of these technological advancements, the company may
need to review its existing configuration at the Savannah plant to optimize the
plant's resources in relation to capacity requirements. The company will
evaluate the performance of the new high-productivity line, analyze the
implications on the capacity of existing assets and have a plan for
reconfiguration, if any, by the latter part of 2004. If the new
high-productivity line performs as expected, the outcome of this review may
result in the redeployment of certain assets to alternate uses and/or the need
to idle certain other assets. If this occurs, the future useful life of such
assets may be adjusted, resulting in the acceleration of depreciation expense.
The AVESTOR joint venture was created by Kerr-McGee and Hydro-Quebec, one of
North America's largest utilities, to commercialize and produce a
lithium-metal-polymer battery. The company's investment in the joint venture
aligns core competencies with new business expansion opportunities. Commercial
battery production and sales commenced in late 2003 to the telecommunications
industry. It is expected that production will continue to increase during 2004.
AVESTOR's unique technical and product offering capability is expected to create
additional high-market-value opportunities in the utility and industrial power
generation markets. With market demand growing, the company anticipates sales to
match plant capacity.
Other Economic Considerations - Other challenges facing Kerr-McGee include
balancing its opportunities for growth with the company's desire to maintain a
lower debt structure, reducing the company's overall cost structure to improve
longer-term profitability, managing ongoing and legacy environmental
obligations, and maintaining the over-funded status of its U.S. qualified
pension plan.
Strategically, Kerr-McGee has committed its focus to growing its exploration and
production operations and improving the profitability of its titanium dioxide
pigment business. This has been achieved through selective acquisitions, the
success of the company's exploration program and technological advancements. At
the same time, the company must balance the capital commitment required to grow
its core operations with its goal of reducing the company's total debt burden to
remain competitive and to increase financial flexibility. Discussions of the
company's cash flow, liquidity and debt-reduction plans in 2004 are included in
the Financial Condition section below.
In the global marketplace, economic pressures continue and the economy is
recovering more slowly than anticipated. In order to remain competitive, the
company has taken a disciplined approach in reviewing its cost structure and
initiated a work-force reduction plan during the third quarter of 2003. As a
result of the program, the company's eligible U.S. nonbargaining work force was
reduced by approximately 9%, or 271 employees. The reduction consisted of both
voluntary retirements and involuntary terminations. Qualifying employees
terminated under this program are eligible for enhanced benefits under the
company's pension and postretirement plans, along with severance payments. The
program was substantially completed by the end of 2003, with certain retiring
employees staying into the first half of 2004 for transition purposes. In
connection with the work-force reduction, the company took a pretax charge of
$56 million during 2003, of which $34 million was for curtailment and special
termination benefits associated with the company's retirement plans and $22
million was for severance-related costs.
Because of the nature of Kerr-McGee's current and historical operations, the
company has significant environmental remediation responsibilities and continues
to provide reserves for these remediation projects. During 2003, the company
expensed an additional $62 million (net of reimbursements) for environmental
costs and funded $104 million of expenditures associated with its environmental
projects. A discussion of the status and circumstances surrounding these
projects is included in the Environmental Matters discussion below.
With the substantial stock market losses experienced between 2000 and 2002, many
corporations are facing a significant financial challenge with respect to the
funded status of their pension plans. The company's U.S. qualified pension plan
remains over funded and estimated returns on plan assets continue to exceed the
company's other periodic pension costs, generating a net periodic pension
benefit of $38 million in 2003. No contributions to the company's U.S. qualified
pension plan will be necessary in 2004. The critical assumptions used in
measuring the company's pension and postretirement obligations and the
sensitivity of the various estimates associated with the company's benefit plans
are discussed in the Critical Accounting Policies section below.
- --------------------------------------------------------------------------------
Operating Environment and Outlook
Oil and Gas Exploration and Production
During 2003, global geopolitical uncertainties affected investment decisions in
the oil and gas industry. However, these risks were mitigated by consistently
strong oil and gas prices. The near-month futures price of West Texas
Intermediate (WTI) crude oil closed at or above $30 per barrel for most of the
year, and natural gas maintained an average price above $5 per million British
thermal units (MMBtu) during 2003.
Crude Oil - During 2003, disruptions to crude oil production in Venezuela and
Nigeria due to political unrest and ethnic violence, combined with uncertainties
linked to the war in Iraq, created global uncertainty about the reliability of
crude oil supply. U.S. crude oil inventories began 2003 below the normal
operating range resulting from a reduction in U.S. imports due to a strike in
Venezuela and strong demand for distillates during the 2003 U.S. heating season.
In January 2003, OPEC announced plans to increase production by 1.5 million
barrels per day to compensate for the Venezuelan shortfalls. However, this
increase was not enough to overcome a perceived shortfall in supply due to low
U.S. inventories and expectation of a war in Iraq. Crude oil WTI prices were
near $38 per barrel by the end of the 2003 first quarter. Following the onset of
the Iraqi war, prices fell sharply to approximately $25 per barrel due to the
war's short duration, coupled with increases in crude oil imports from Saudi
Arabia and Venezuela.
Decreasing U.S. domestic oil production, delays in Iraqi oil production
increases and the effect of OPEC's April 2003 production cut of 2 million
barrels per day resulted in WTI crude futures prices recovering to above $30 per
barrel early in the 2003 third quarter. Prices generally remained at this level
for the remainder of the year.
Numerous factors are expected to influence the U.S. crude oil market in 2004.
Oil production in Nigeria, Venezuela and Iraq continued to recover, although not
to full capacity. OPEC's recent remarks concerning the intention to shift its
strategy to revenue enhancement from market share protection could also impact
crude oil markets. Finally, a continued rebound in global economies could absorb
some oversupply.
Natural Gas - Higher-trending natural gas prices in 2003 are the result of
fundamental shifts in the natural gas supply and demand balance. Gas prices
began the year at about $5.25 per MMBtu and reached a high of more than $9 per
MMBtu during February due to storage levels falling to record lows. This event
heightened concerns regarding the decline of U.S. gas supplies, and
deliverability issues continued to underpin market activity throughout the year.
By fall 2003, U.S. gas storage volumes had recovered to comfortable levels, but
fears of the previous winter's supply shortfall, as well as reports of declining
domestic production, kept prices strong. Throughout summer and fall, natural gas
prices remained above $4.50 per MMBtu, maintaining a range of $4.50 to $6.50 per
MMBtu until December, when seasonally cold winter weather began to push prices
up towards $7 per MMBtu.
The 2004 environment for U.S. natural gas prices remains volatile and will be
influenced by several factors, including the balance between supply and demand,
weather patterns, the rate and development of liquefied natural gas imports,
crude oil and distillate prices, and government policy.
To mitigate the above uncertainties related to price fluctuations, the company
has entered into hedges covering approximately 80% of expected 2004 worldwide
crude oil and condensate production, and 75% of the U.S. natural gas production.
By ensuring greater predictability of cash flows to fund major exploration and
capital programs, hedging enhances the company's ability to meet financial
requirements. Details of the company's commodity hedging program are included in
the Market Risks section below.
Chemicals
In the global titanium dioxide pigment industry, the company is the
third-largest producer and marketer and one of five companies that own chloride
technology. The chloride process produces a pigment with optical properties
preferred by the paint, coatings and plastics industries. In early 2004,
chloride technology accounted for 76% of the company's gross pigment production
capacity. The remaining capacity is sulfate-process production, which produces
pigment used primarily in paper and specialty products.
Titanium dioxide is a quality-of-life product, and its consumption follows
general economic trends. Throughout 2003, challenging business conditions
existed for the company's chemical operations due to near-recessionary
conditions in Europe, high energy prices, the effect of the SARS epidemic on
economic conditions in Asia and continued weakness in the U.S. manufacturing
sector. These economic forces placed pressure on product prices, overall product
demand and profitability. While overall global economic growth was stagnant to
recessionary during the first half of 2003, the last quarter of 2003 did begin
to show improvement as observed in the leading U.S. economic indicators and
Euro-zone GDP. General economic conditions are expected to improve in 2004 for
North America and Europe, with continued growth in the Asian markets.
The strategy for Kerr-McGee's chemical unit focuses on continued improvement in
asset productivity, process and product capability, cost reductions, and
providing superior products for market-segment growth. Multiple initiatives are
in place to capture new market growth through segmentation strategies that align
products with customer needs, low-cost plant expansions to increase volume
capacity, continuous improvement programs to increase efficiency and lower
operating costs, and technology-based programs to improve product quality and
lower costs.
- --------------------------------------------------------------------------------
Results of Consolidated Operations
Net income (loss) and per-share amounts for each of the years in the three-year
period ended December 31, 2003, were as follows:
(Millions of dollars, except per-share amounts) 2003 2002 2001
- --------------------------------------------------------------------------------
Net income (loss) $219 $(485) $486
Net income (loss) per share -
Basic 2.18 (4.84) 5.01
Diluted 2.17 (4.84) 4.74
The major variances in net income on an operating unit basis (after income
taxes) are outlined in the table below. The variances in individual line items
in the Consolidated Statement of Operations are explained in the section that
follows.
Favorable (Unfavorable)
Variance
-------------------------
2003 2002
Versus Versus
(Millions of dollars) 2002 2001
- --------------------------------------------------------------------------------
Net operating profit -
Exploration and production $ 898 $(850)
Chemical - pigment (17) 25
Chemical - other (7) (4)
Net interest expense 15 (56)
Other income/expense (24) (202)
Discontinued operations (126) 96
Cumulative effect of accounting change (35) 20
----- -----
Net income $ 704 $(971)
===== =====
The 2003 increase in exploration and production net operating profit is
primarily due to a decrease in asset impairments of $385 million in 2003 and net
gains associated with assets held for sale of $29 million in 2003 versus losses
of $167 million in 2002. The remaining $317 million increase is due to the 2002
deferred tax effect of $132 million resulting from a 33% increase in the U.K.
corporate tax rate for oil and gas companies, combined with lower production
costs and depreciation and depletion expense and higher average realized sales
prices for both crude oil and natural gas in 2003, partially offset by lower oil
and gas sales volumes and higher exploration expense.
The decline in chemical - pigment net operating profit in 2003 is principally
the result of plant closure and workforce reduction provisions totaling $42
million and higher average per-unit production costs, partially offset by higher
pigment sales prices.
Lower interest expense in 2003 is due to lower average debt outstanding and a
slightly lower weighted average interest rate. The negative variance for other
income/expense is mainly due to higher general and administrative costs,
workforce reduction costs and lower net gains on the revaluation of nonoperating
derivatives and trading securities, partially offset by lower 2003 litigation
provisions and a gain on sale of Devon Energy Corporation (Devon) shares.
Discontinued operations for all three years resulted from the company's decision
in early 2002 to dispose of its exploration and production interests in
Indonesia and Kazakhstan and its interest in the Bayu-Undan project in the East
Timor Sea offshore Australia. These divestiture decisions were made as part of
the company's strategic plan to rationalize noncore oil and gas properties. The
negative variance from discontinued operations in 2003 and the positive variance
in 2002 are both due primarily to the $107 million gain on sale in 2002 related
to the disposals in Indonesia and Australia.
The 2003 cumulative effect of change in accounting principle is the result of
the company's adoption of the Financial Accounting Standards Board's Statement
No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). See the
New/Revised Accounting Standards section below for a discussion of the adoption.
The 2002 decline in exploration and production net operating profit resulted
from asset impairments of $394 million, losses associated with assets held for
sale of $167 million and the deferred tax effect of $132 million for the U.K.
corporate tax law change, as well as higher lease operating expense, shipping
and handling expense, depreciation and depletion, and exploration expenses. The
improvement in chemical's pigment net operating profit in 2002 was principally
the result of higher pigment sales volumes and lower average per-unit production
costs. Higher interest expense in 2002 was due to significantly higher average
debt outstanding and lower capitalized interest, partially offset by a lower
overall average interest rate.
The 2002 negative variance for other income/expense was mainly due to the 2001
adoption of FAS 133, "Accounting for Derivative Instruments and Hedging
Activities," which resulted in the company recognizing a $118 million net
unrealized gain on shares of Devon reclassified to "trading" from the "available
for sale" category of investments. Additionally, a 2002 net-of-tax litigation
provision of $47 million and after-tax foreign currency losses of $33 million
contributed to the other income/expense variance for 2002 versus 2001.
The 2002 positive variance from the change in accounting principle also resulted
from the company's adoption of FAS 133 in 2001. This standard required the
recording of all derivative instruments as assets or liabilities, measured at
fair value. Kerr-McGee recorded the fair value of all its outstanding foreign
currency forward contracts and the fair value of the options associated with the
company's debt exchangeable for common stock (DECS) of Devon owned by the
company. The net effect of recording these fair values resulted in a $20 million
decrease in income as a cumulative effect of a change in accounting principle
and a $3 million reduction in equity (other comprehensive income) for the
foreign currency contracts designated as hedges.
- --------------------------------------------------------------------------------
Statement of Operations Comparisons
(Billions of dollars) 2003 2002 2001
- --------------------- ---- ---- ----
Revenues $4.2 $3.6 $3.6
The increase in 2003 revenues was primarily due to higher average realized sales
prices for crude oil, natural gas and titanium dioxide pigment, combined with
higher gas marketing sales revenue. These increases were partially offset by
lower production quantities due primarily to oil and gas properties divested
during 2002 and 2003. Revenues in 2002 increased slightly over 2001 due to a
full year of revenues from the Rocky Mountain region compared with only five
months in 2001 following the acquisition of HS Resources, combined with the
favorable impact of higher pigment sales volumes, partially offset by the
recognition of lower revenues from properties divested during 2002. These
variances are discussed in more detail in the segment discussions that follow.
See Note 1 to the Consolidated Financial Statements for a discussion of
reclassifications made to revenues for 2002 and 2001.
(Millions of dollars) 2003 2002 2001
- ---------------------------- ------ ------ ------
Costs and Operating Expenses $1,668 $1,456 $1,264
Costs and operating expenses for 2003 increased $212 million over the prior
year, primarily due to higher gas marketing product costs of $233 million (which
offsets higher third-party gas marketing revenues), higher pigment production
costs of $51 million and 2003 shutdown provisions of $42 million associated with
the closure of Chemical's Mobile facility and forest products operations. These
increases were partially offset by lower lease operating expense of $114 million
mainly due to oil and gas property divestitures. Costs and operating expenses
increased $192 million in 2002 from the 2001 level, resulting principally from
higher gas marketing, gathering and pipeline costs of $74 million (full year of
Rocky Mountain operations in 2002 versus five months in 2001), higher lease
operating expenses of $80 million (full year of Rocky Mountain operations and
new natural gas production brought online in the Gulf of Mexico region), and
higher pigment production cost of $91 million (increased pigment production
volumes).
(Millions of dollars) 2003 2002 2001
- ------------------------------------------- ---- ---- ----
Selling, General and Administrative Expenses $371 $313 $228
For 2003, selling, general and administrative expenses increased $58 million
over the prior year, resulting primarily from provisions totaling $58 million
associated with the 2003 work-force reduction plan and other transition and
severance-related costs, together with additional compensation expense of $17
million resulting from loan prepayments required to release shares from the
company's employee stock ownership plan. Also contributing to the increase were
higher corporate and exploration and production general and administrative costs
of $24 million and $14 million, respectively, partially offset by lower
litigation provisions of $63 million (prior-year forest products litigation).
The 2003 increase in corporate general and administration was principally due to
higher compensation-related costs of $16 million related mostly to 2003
performance bonus and amortization of restricted stock compensation, along with
higher general and auto liability costs of $5 million. The increase in general
and administrative costs for the exploration and production operations of $14
million is due primarily to lower 2003 billings of costs on operated properties
to partners, which were partially offset by lower cost for contract services and
direct labor. Selling, general and administrative expenses for 2002 increased
$85 million primarily as a result of the $72 million reserve for litigation
established mainly in connection with certain forest products litigation in
Mississippi, Louisiana and Pennsylvania. This litigation is discussed in Note 16
to the financial statements.
Shipping and handling expenses for 2003, 2002 and 2001 were $140 million, $125
million and $111 million, respectively. The increase in 2003 is primarily due to
higher costs for transportation from new deepwater fields in the Gulf of Mexico,
including Nansen, Boomvang and Navajo, and increased costs in the U.K. North
Sea, as well as higher pigment shipping costs. The increase in pigment shipping
costs is primarily related to higher ocean freight prices due to supply
constraints on the availability of vessels. The 2002 increase was also due to
higher transportation for new deepwater fields in the Gulf of Mexico, combined
with higher costs in the Rocky Mountain region due to a full year of costs
related to the former HS Resources operations.
Abandonment expense of $40 million and $34 million associated with the company's
exploration and production operations has been reclassified from costs and
operating expenses to depreciation and depletion for 2002 and 2001 to be
consistent with the 2003 presentation after adoption of FAS 143.
(Millions of dollars) 2003 2002 2001
- -------------------------- ---- ---- ----
Depreciation and Depletion $745 $814 $747
Depreciation and depletion expense totaled $745 million in 2003, $814 million in
2002 and $747 million in 2001. The decrease for 2003 is due to lower depletion
expense for divested or held-for-sale properties of $49 million and lower
depletion on the Leadon field of $36 million, partially offset by higher
depletion expense in the Gulf of Mexico region of $24 million mainly due to
higher production from the Nansen, Boomvang and Navajo fields which began
producing in 2002. The 2002 increase was due to higher depletion expense for the
Rocky Mountain region of $75 million (full year of ownership) and for the U.K.
region of $11 million. Partially offsetting these increases was lower expense in
the Gulf of Mexico region of $24 million due to normal declines in production
and held-for-sale properties, which more than offset the impact of new
production from the Nansen, Boomvang and Navajo fields.
Impairment losses on held-for-use assets totaled $14 million in 2003, $652
million in 2002 and $76 million in 2001. These impairments were related to
assets with remaining investments that were no longer expected to be recovered
through future cash flows. Impairments in 2003 were related primarily to various
mature oil and gas fields in the U.S. onshore and Gulf of Mexico shelf areas.
The impairments in 2002 included $541 million for the Leadon field in the North
Sea, $82 million for certain nonoperated fields in the North Sea, $23 million
for several older Gulf of Mexico shelf properties, and $6 million related to the
company's planned shutdown of the forest products operations. The 2001
impairments were comprised of $47 million associated with the shut-down of the
North Sea Hutton field and $29 million for certain chemical facilities in
Belgium and the U.S.
During 2003, the company selectively marketed its 100%-owned Leadon field to
third parties. Although no divestiture negotiations are currently under way, the
company continues to review its options with respect to the field and,
particularly, the associated floating production, storage and offloading (FPSO)
facility. Management presently intends to continue operating and producing the
field until such time as the operating cash flow generated by the field does not
support continued production or until a higher value option is identified. Given
the significant value associated with the FPSO relative to the size of the
entire project, the company will continue to pursue a long-term solution that
achieves maximum value for Leadon - which may include disposing of the field,
monetizing the FPSO by selling it as a development option for a third-party
discovery, or redeployment in other company operations. As of December 31, 2003,
the carrying value of the Leadon field assets totaled $374 million. Given the
uncertainty concerning possible outcomes, it is reasonably possible that the
company's estimate of future cash flows from the Leadon field and associated
fair value could change in the near term due to, among other things, (i)
unfavorable changes in commodity prices or operating costs, (ii) a production
profile that declines more rapidly than currently anticipated, and/or (iii)
unsuccessful results of continued marketing activities or failure to locate a
strategic buyer (or suitable redeployment opportunity). Accordingly, management
anticipates that the Leadon field will be subject to periodic impairment review
until such time as the field is abandoned or sold. If future cash flows or fair
value decrease from that presently estimated, an additional write-down of the
Leadon field could occur in the future.
In connection with the company's divestiture program initiated in 2002, certain
oil and gas properties were identified for disposal and classified as
held-for-sale properties. Upon classification as held-for-sale, the carrying
value of the related properties is analyzed in relation to the estimated fair
value less costs to sell, and losses are recognized, if necessary. Upon ultimate
disposal of the properties, any gain or additional loss on sale is recognized.
Losses of $23 million and gains of $68 million were recognized in 2003 upon
conclusion of the divestiture program in the U.S. and North Sea, and for the
sale of the company's interest in the South China Sea (Liuhua field) and other
noncore U.S. properties (onshore and Gulf of Mexico shelf areas). The company
recognized losses of $176 million in 2002 associated with oil and gas properties
held for sale in the U.S. (onshore and Gulf of Mexico shelf areas), the U.K.
North Sea and Ecuador. Proceeds realized from these disposals totaled $119
million in 2003 and $374 million in 2002. The proceeds from the sale of such
properties have been used to reduce long-term debt. From time to time, other oil
and gas properties may be identified for disposal when such properties are
considered noncore or nearing the end of their productive lives.
(Millions of dollars) 2003 2002 2001
- --------------------- ---- ---- ----
Exploration Expense $354 $273 $210
Exploration costs were $354 million, $273 million and $210 million for 2003,
2002 and 2001, respectively. The 2003 increase was due to higher dry hole costs
of $68 million, primarily exploratory drilling in the deepwater Gulf of Mexico,
and higher exploration department costs of $11 million. The 2002 increase was
due to higher dry hole costs of $41 million, mainly exploratory drilling in the
deepwater Gulf of Mexico and in the North Sea, higher nonproducing leasehold
amortization of $11 million, and higher geophysical costs of $5 million.
Interest and debt expense totaled $251 million in 2003, $275 million in 2002 and
$195 million in 2001. The $24 million decrease in 2003 was due to lower average
borrowings under revolving credit facilities and commercial paper of
approximately $570 million and slightly lower average interest rates on the
company's long-term debt. The $80 million increase in 2002 was due to an annual
average debt balance that was approximately $1.4 billion higher than 2001 due to
the acquisition of HS Resources in August 2001 and capitalized interest that was
lower by $23 million, partially offset by overall average interest rates that
were approximately 1% lower than in the prior year.
Other income (expense) includes the following for each of the years in the
three-year period ended December 31, 2003:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Foreign currency translation gain (loss) $(41) $(38) $ 3
Loss from equity affiliates (33) (25) (5)
Gain on sale of Devon stock 17 - -
Unrealized gain on Devon stock reclassified to
"trading" category of investments - - 181
Exchangeable debt embedded options and Devon
stock revaluations 8 27 17
Gains (losses) on non-hedge natural gas derivatives (4) 8 27
Other (6) (7) 1
---- ---- ----
Other income (expense) $(59) $(35) $224
==== ==== ====
The majority of the 2003 and 2002 foreign currency losses resulted from the
company's U.K. operations, where the company has experienced unfavorable changes
in the U.S. dollar/British pound sterling exchange rates. The loss from equity
affiliates for 2003, 2002 and 2001 was primarily the result of the investment in
the AVESTOR joint venture formed in 2001 to develop new lithium-metal-polymer
batteries. The 2003 gain on sale of Devon stock resulted from the sale of
approximately 1 million shares that were in excess of the total shares the
company believes will be required to extinguish the debt exchangeable for common
stock due in August 2004. The company sold its remaining Devon shares in January
2004 for a pretax gain of $9 million. All other Devon shares will be held
through August 2004 in connection with the maturity of the debt exchangeable for
common stock.
The effective tax rate for 2003 was 42.7%, compared with (7.0)% in 2002 and
36.7% in 2001. The 2003 effective rate is higher than the U.S. statutory rate
primarily due to the impact of taxation on foreign operations. The 2002 tax
benefit was reduced from the U.S. statutory rate due to the deferred tax effect
of $132 million for the 33% increase in the U.K. corporate tax rate for oil and
gas companies, together with the impact of taxation on foreign operations.
- --------------------------------------------------------------------------------
Segment Operations
Operating profit (loss) from each of the company's segments is summarized in the
following table:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Operating profit (loss) -
Exploration and production $1,002 $(140) $922
------ ----- ----
Chemicals -
Pigment (13) 24 (22)
Other (35) (23) (17)
------ ----- ----
Total Chemicals (48) 1 (39)
------ ----- ----
Operating profit (loss) $ 954 $(139) $883
====== ===== ====
Exploration and Production
Revenues - Revenues, production statistics and average prices received from
sales of crude oil, condensate and natural gas are shown in the following table:
(Millions of dollars, except per-unit amounts) 2003 2002 2001
- --------------------------------------------------------------------------------
Revenues -
Crude oil and condensate sales $1,426 $1,531 $1,560
Natural gas sales 1,156 819 833
Gas marketing activities 298 70 22
Other 43 30 13
------ ------ ------
Total $2,923 $2,450 $2,428
====== ====== ======
Production -
Crude oil and condensate (thousands
of barrels per day) 150 191 189
Natural gas (MMcf per day) 726 760 596
Total equivalent barrels of oil (thousands
of barrels per day) 271 318 288
Average Prices -
Crude oil and condensate (per barrel) (1) $26.04 $22.04 $22.60
Natural gas (per Mcf) (1) $ 4.37 $ 2.95 $ 3.83
(1) Includes the results of the company's oil and gas commodity hedging
program, which began in 2002. In 2003, hedges reduced the average sales
price of crude oil and natural gas sold by $2.46 per barrel and $.55 per
Mcf, respectively. In 2002, hedge activity reduced the average sales price
of crude oil and natural gas sold by $1.13 per barrel and $.01 per Mcf,
respectively.
Oil sales revenues declined $105 million in 2003 compared with 2002, primarily
as a result of lower production due to the divestiture of various properties.
This 21% decrease in oil production was partially offset by higher realized
prices. The average realized price for oil increased $4 per barrel, adding $220
million to oil revenues, while lower oil production reduced revenues by $325
million.
The 2003 oil production decline was primarily due to the sale of various noncore
properties during 2003 and 2002. The company began a divestiture program in
mid-2002 to improve the overall quality of its asset portfolio, targeting
high-operating-cost, noncore assets. The program was completed in 2003. Property
sales were concentrated in the U.S. onshore region, Gulf of Mexico shelf and the
U.K. North Sea, as well as Ecuador and the South China Sea. After adjusting for
divestitures, 2003 oil production was approximately the same as 2002.
Oil sales revenues for 2002 declined $29 million compared with 2001, primarily
driven by lower realized prices of $.56 per barrel. The 2002 oil production
volumes remained relatively flat compared with 2001.
Natural gas sales revenues increased $337 million in 2003, primarily as a result
of a $1.42 per Mcf increase in the average realized price for natural gas,
partially offset by a 5% decline in production volumes. Higher realized prices
increased revenue by $374 million, while lower gas production reduced revenues
by $37 million. Production declines resulted primarily from property
divestitures concentrated mainly in the U.S onshore and Gulf of Mexico shelf
areas. After adjusting for divestitures, 2003 gas production volumes declined by
2% compared with 2002.
Natural gas sales revenue decreased $14 million in 2002 compared with 2001.
Lower 2002 realized prices of $.88 per Mcf resulted in a revenue decline of $243
million that was partially offset by an increase of $229 million due to higher
sales volumes. In 2002, gas sales volumes increased 28% or 164 MMcf/day over the
2001 levels, primarily due to a full year of gas production from the Wattenberg
field in Colorado, which was acquired in August 2001.
The variances in revenues from gas marketing activities are discussed in the Gas
Marketing Activities section below.
Operating Costs and Expenses - Operating costs and expenses relating to the sale
of crude oil, condensate and natural gas are shown in the following table.
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Lease operating expense $ 334 $ 448 $ 368
Production taxes 52 67 74
------ ------ ------
Total lifting costs 386 515 442
Transportation expense 94 84 71
Depreciation, depletion and amortization 609 690 619
Accretion expense (abandonment obligations) 25 - -
General and administrative expense 127 87 72
Exploration expense 354 273 210
Impairments on assets held for use 14 646 47
Loss (gain) associated with assets held for sale (45) 176 -
Gas gathering, pipeline and other 66 61 28
------ ------ ------
Total operating cost and expenses $1,630 $2,532 $1,489
====== ====== ======
Lease Operating Expense - During 2003, lease operating expense decreased 25% or
$114 million compared with 2002. On a per-unit basis, lease operating expense
decreased by about 13% to $3.37 per barrel of oil equivalent (BOE) sold in 2003
from $3.87 per BOE in 2002. Lower costs were primarily related to the
divestiture of noncore, high-operating-cost properties. Lease operating expense
increased $80 million in 2002 compared with 2001, resulting in costs of $3.87
and $3.50 per BOE, respectively. Higher lease operating expense in 2002 was the
result of new production from the Nansen and Boomvang fields in the deepwater
Gulf of Mexico and from a full year of production from the Leadon field in the
U.K. North Sea, which commenced production in late 2001. A full year of
operating expenses from the Wattenberg field (acquired in August 2001) also
contributed to the increase.
Production Taxes - During 2003, production taxes decreased by $15 million,
primarily due to the elimination of royalty payments in the U.K. North Sea area
and lower production volumes. These factors were partially offset by higher
commodity prices as production taxes are generally based on sales revenue.
Production taxes in 2002 decreased by $7 million compared with 2001 as a result
of lower commodity prices (primarily natural gas prices), partially offset by
higher sales volumes.
Transportation Expense - Transportation costs, representing the costs paid to
third-party providers to transport oil and gas production, increased $10 million
during 2003. Transportation costs in 2002 reflected a $13 million increase over
2001 levels. The increase for both periods resulted from transportation costs
associated with new deepwater Gulf of Mexico producing fields such as Boomvang,
Nansen and Navajo as well as increased costs in the U.K North Sea area. In
addition, 2002 transportation costs include a full year of costs associated with
the Wattenberg field.
Depreciation, Depletion and Amortization - Depreciation, depletion and
amortization (DD&A) expense decreased $81 million in 2003, representing a 12%
decline compared with 2002. The decrease in DD&A expense is primarily the result
of production declines associated with the divestiture program that began in
mid-2002 and asset impairments that were recorded in 2002 (primarily the Leadon
field). On a per-unit basis, DD&A increased 3% to $6.16 per BOE in 2003 from
$5.97 per BOE in 2002. Although total DD&A expense was lower, higher unit costs
resulted from the company's divestiture activity and the overall mix of
producing properties between 2003 and 2002. In accordance with accounting
standards, depreciation was not recorded for various assets that were designated
as held-for-sale in 2003 and 2002, although production quantities for these
properties continued to be included in the calculation of total unit DD&A.
DD&A expense in 2002 was $71 million higher than in 2001. This increase was
primarily due to higher production in 2002. On a per-unit basis, DD&A expense
increased to $5.97 per BOE in 2002 from $5.89 per BOE in 2001. The increase in
unit costs was due primarily to higher DD&A rates for various new fields that
were brought on production in late 2002 and 2001, including the Nansen and
Boomvang fields in the Gulf of Mexico as well as the Leadon field in the U.K.
North Sea. In addition, a full year of production from the Wattenberg field
(acquired in August 2001) contributed to the increase.
Accretion Expense - Accretion expense of $25 million in 2003 is related to the
company's discounted abandonment liability recognized in 2003 as a result of
implementing FAS 143.
General and Administrative Expenses - General and administrative (G&A) expenses
were $40 million higher in 2003 compared with 2002. This resulted from $27
million of nonrecurring employee severance and related costs in 2003 associated
with the company's work-force reduction plan. Additionally, the company incurred
higher costs associated with employee benefits and the pension plan, as well as
lower billings of costs on operated properties to partners. These costs were
partially offset by lower costs for direct labor and contract services.
G&A expense in 2002 was $15 million higher than in 2001, primarily as a result
of higher contract services and increased labor and benefits costs.
Exploration Expense - Exploration expense in 2003 was $81 million higher than in
2002 primarily as a result of higher dry hole costs from increased exploration
activity during the year. In addition, staffing levels were increased during
2003 to support the company's worldwide exploration efforts and continued
development of the company's high-potential prospect inventory.
Exploration expense in 2002 increased $63 million compared with the prior year
primarily as a result of higher dry hole costs from increased exploration
activity during the year. In addition, higher amortization expense for
nonproducing leaseholds and increased costs for geological and geophysical
projects contributed to the increase.
Impairments on held-for-use assets and the gain or loss on assets held for sale
have been discussed in the Statement of Operations Comparisons section above.
Gas Marketing Activities - In the Rocky Mountain region, Kerr-McGee purchases
third-party natural gas for aggregation and sale with the company's own
production from the Wattenberg field in Colorado. In addition, Kerr-McGee has
purchased transportation capacity to markets in the Midwest to facilitate sale
of its natural gas outside the immediate vicinity of its production. This
activity began with the company's acquisition of HS Resources in August 2001 and
has increased since that time. Revenues (from sale of third-party gas) and
associated gas purchase cost relating to gas marketing activities are shown in
the following table.
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Gas marketing revenues $ 298 $ 70 $ 22
Gas purchase costs (including transportation) (291) (58) (17)
------ ------ -----
Net marketing margin $ 7 $ 12 $ 5
====== ====== =====
Marketing volumes (thousand MMBtu/day) 178 77 29
------ ------ -----
Marketing revenues increased $228 million in 2003 compared with 2002 primarily
due to higher purchase and resale of natural gas in the Rocky Mountain area and
higher natural gas prices. Gas purchase costs increased proportionately for the
same period, an increase of $233 million.
Marketing revenues increased $48 million in 2002 compared with 2001, primarily
as a result of a full year of marketing activity in the Rocky Mountain area
after the HS Resources acquisition. Gas purchase costs also increased in 2002 by
$41 million in proportion to the higher level of marketing activity.
Chemicals
Chemical revenues, operating profit (loss) and pigment production volumes are
shown in the following table:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Revenues -
Pigment $1,079 $ 995 $ 931
Other 183 201 196
------ ------ ------
Total $1,262 $1,196 $1,127
====== ====== ======
Operating profit (loss) -
Pigment $ (13) $ 24 $ (22)
Other (35) (23) (17)
------ ------ ------
Total $ (48) $ 1 $ (39)
====== ====== ======
Titanium dioxide pigment production
(thousands of tonnes) 532 508 483
Pigment - Revenues increased $84 million, or 8%, in 2003 to $1.079 billion from
$995 million in 2002. Of the total increase, $94 million resulted from an
increase in average sales prices, partially offset by a $10 million decrease due
to lower sales volumes. The increase in average sales prices in 2003 was largely
due to the effect of foreign currency exchange rates. Excluding the effect of
foreign currency exchange rates, average selling prices in local currencies for
2003 were 3% higher than in 2002. Sales volumes for 2003 were approximately 1%
lower than in the prior year.
Titanium dioxide pigment revenues for 2002 increased $64 million, or 7%, over
2001, resulting from a $149 million increase due to higher sales volume,
combined with an offsetting decrease of $85 million resulting from weaker sales
prices in 2002, of which $13 million was due to the effect of foreign currency
exchange rates. While poor overall market conditions persisted through the first
quarter of 2002, product demand increased through the remainder of the year. As
demand accelerated, the company announced multiple price increases through the
second half of 2002.
The chemical - pigment operating unit recorded an operating loss of $13 million
in 2003, compared with operating profit of $24 million in 2002. The $94 million
increase in revenues due to higher sales prices was partially offset by an
increase in average product costs of $51 million and an increase in shipping and
handling costs and selling, general and administrative costs of $18 million over
2002. Additionally, operating results in 2003 were impacted by $47 million in
plant closure provisions related to the synthetic rutile plant in Mobile,
Alabama, together with a $23 million charge for work-force reduction and other
compensation costs. The $47 million shutdown provision for the Mobile operations
included $6 million for curtailment costs related to pension and postretirement
benefits. The 2002 operating profit included $12 million in charges for
abandoned chemical engineering projects, $3 million for severance and other
costs and a $5 million reversal of environmental reserves associated with the
Savannah operations.
Operating profit for 2002 improved $46 million over 2001. Higher 2002 sales
volume, combined with lower average per-unit production costs, increased
operating profit by $57 million, offset by reductions due to lower sales prices
of $85 million. Shipping and handling costs and selling, general and
administrative costs decreased $5 million from 2001. In addition, the 2002
operating profit included a provision of $12 million related to abandoned
chemical engineering projects, a $5 million reversal of environmental reserves,
and $3 million for severance and other costs, compared with provisions in 2001
for closure of a pigment plant in Belgium, asset impairments, severance and
other costs totaling $79 million.
Other - Operating loss for 2003 was $35 million on revenues of $183 million,
compared with operating loss of $23 million on revenues of $201 million in 2002.
Of the decrease in sales, $27 million resulted from lower forest products sales,
partially offset by a $9 million increase in electrolytic operations sales
volumes. The increased volumes were predominantly achieved in sodium chlorate
and boron products, 17% and 37%, respectively. The $12 million increase in
operating loss for 2003 was primarily due to 2003 work-force reduction and other
compensation charges of $8 million and higher electrolytic product costs of $8
million, partially offset by lower environmental costs of $5 million.
Environmental provisions in both 2003 and 2002 related primarily to ammonium
perchlorate remediation associated with the company's Henderson, Nevada,
operations (See Note 16). The 2003 operating results were also negatively
affected by an operating loss of $12 million from the forest products
operations, which includes shutdown provisions of $14 million, compared with a
2002 operating loss of $10 million, which included $23 million for shutdown and
impairment provisions. The 2003 forest products shutdown provision of $14
million included $8 million for curtailment costs related to pension and
postretirement benefits.
Operating loss for 2002 was $23 million on revenues of $201 million, compared
with operating loss of $17 million on revenues of $196 million in 2001. The
increase in operating loss was primarily due to 2002 provisions for the shutdown
and impairment of the forest products business of $23 million and environmental
provisions of $15 million, compared with 2001 provisions of $25 million for the
termination of manganese metal production and $5 million for severance and asset
impairment charges.
During the third quarter of 2003, Kerr-McGee Chemical LLC placed its
electrolytic manganese dioxide (EMD) manufacturing operation in Henderson,
Nevada, on standby to reduce inventory levels because of the harmful effect of
low-priced imports on the company's EMD business. In response to the pricing
activities of importing companies, Kerr-McGee Chemical LLC filed a petition for
the imposition of anti-dumping duties with the U.S. Department of Commerce
International Trade Administration and the U.S. International Trade Commission
on July 31, 2003. In its petition, the company alleged that manufacturers in
certain countries export EMD to the United States in violation of the U.S.
anti-dumping laws and requested that the U.S. Department of Commerce apply
anti-dumping duties to the EMD imported from such countries. The Department of
Commerce found probable cause to believe that manufacturers in the specified
countries engaged in dumping and initiated an anti-dumping investigation with
respect to such manufacturers. Partly as a result of the anti-dumping petition,
demand for U.S. EMD product increased, and the plant resumed operations in
December 2003. The company withdrew its anti-dumping petition in February 2004
but will continue to monitor market conditions.
- --------------------------------------------------------------------------------
Financial Condition
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Current ratio 0.8 to 1 0.8 to 1 1.2 to 1
Total debt $3,655 $3,904 $4,574
Total debt less cash (net debt) 3,513 3,814 4,483
Total debt less cash and DECS 3,187 3,496 4,173
Stockholders' equity $2,636 $2,536 $3,174
Net debt to total capitalization 57% 60% 59%
Total debt less cash and DECS to total
capitalization 55% 58% 57%
Floating-rate debt to total debt (including
fixed-rate debt with interest rate swap to
variable rate) 14% 16% 28%
The negative working capital at the end of 2003 and 2002 is not indicative of a
lack of liquidity as the company maintains sufficient current assets to settle
current liabilities when due. Current asset balances are minimized as one way to
finance capital expenditures and lower borrowing costs. If needed, the company
also has unused lines of credit and revolving credit facilities as discussed in
the Liquidity section that follows.
Kerr-McGee operates with the philosophy that over a five-year plan period the
company's capital expenditures and dividends should be paid from cash generated
by operations. On a cumulative basis, the cash generated from operations for the
past five years has exceeded the company's capital expenditures and dividend
payments. Debt and equity transactions are utilized for acquisition
opportunities and short-term needs due to timing of cash flow.
(Percentages) 2003 2002 2001
- -------------------------------- ---- ---- ----
Net Debt to Total Capitalization 57% 60% 59%
(Net debt to total capitalization is total debt less cash divided by total debt
less cash plus stockholders' equity.)
A reduction in net debt of $301 million from 2002, combined with an increase in
stockholders' equity of $100 million resulted in a 3% improvement in the
percentage of net debt to total capitalization as compared to 2002. The
company's goal is to reduce its percentage of net debt to total capitalization
to 50% or below by the end of 2004. Although debt was reduced $670 million from
2001 to 2002, a decrease in equity resulting primarily from the 2002 net loss
and dividends declared resulted in a slightly higher percentage of net debt to
total capitalization in 2002 compared with 2001.
Cash Flow
(Millions of dollars) 2003 2002 2001
- ----------------------------------- ------ ------ ------
Cash Flow from Operating Activities $1,518 $1,448 $1,143
(Cash flow from operating activities has increased significantly over the past
two years.)
Cash flow from operating activities increased $70 million, from $1.448 billion
in 2002 to $1.518 billion in 2003, primarily due to an increase in income
excluding noncash items, partially offset by changes in various working capital
items. Year-end 2003 cash was $142 million, compared with $90 million at
December 31, 2002.
The company invested $1.2 billion in its 2003 capital program, which included
$181 million of unsuccessful exploratory drilling costs. The capital program for
2003 was $110 million lower than in the prior year, resulting primarily from
lower capital expenditures in the North Sea, Rocky Mountain and U.S. onshore
regions, partially offset by higher capital expenditures in the Gulf of Mexico
and China and higher dry hole costs. During 2003, the company completed the
divestiture of several oil and gas properties and other assets, generating
proceeds of $304 million. These proceeds were used primarily to pay down debt.
The company also invested $110 million in selected oil and gas property
acquisitions related to the acquisition of an additional interest in the U.K.
Gryphon and South Gryphon fields and an onshore property acquisition in South
Texas. Cash outlays for investing activities include a $34 million investment by
the chemical unit in AVESTOR, its lithium-metal-polymer battery joint venture in
Canada. Other investing cash inflows included $47 million in proceeds related to
the sale of Devon stock.
(Millions of dollars) 2003 2002 2001
- ----------------------------------- ------ ------ ------
Total Debt $3,655 $3,904 $4,574
(From year-end 2001 to 2003, the company reduced total debt by more than $900
million.)
During 2003, the company reduced its variable interest rate commercial paper by
$68 million. Other debt was reduced $301 million, which included repayment of
current year borrowings on revolving credit facilities of $31 million. Included
in the total 2003 repayments of $301 million is $64 million related to
open-market repurchases of long-term debt issuances on which the company
recorded a loss of $7 million for early extinguishment in other expense in the
Consolidated Statement of Operations. However, by executing the open-market
repurchases, the company will avoid approximately $10 million in future interest
expense. The company added $75 million in debt at December 31, 2003, due to the
consolidation of the Kerr-McGee Gunnison Trust. This synthetic lease arrangement
was restructured to an operating lease arrangement in January 2004, and the
related debt will no longer be reflected on the company's balance sheet. The
consolidation, which resulted in a noncash increase in debt and property, is
discussed in more detail in the Off-Balance Sheet Arrangements section below.
Cash flow was used to pay the company's dividends of $181 million in 2003.
As of December 31, 2003, the company's senior unsecured debt was rated BBB by
Standard & Poor's and Fitch and Baa3 by Moody's. See Note 9 for details of the
company's debt. At December 31, 2001, the company's outstanding debt had
increased significantly from prior-year levels to fund the acquisition of HS
Resources and major development projects in the Gulf of Mexico and the North
Sea. Throughout 2002 and 2003, the company aggressively pursued its strategy of
divesting noncore, high-cost assets, the proceeds from which have been used
primarily to reduce the company's outstanding debt. The company expects to
further reduce debt by approximately $550 million during 2004 by using excess
cash flows and by using Devon common stock to repay the $330 million face amount
of debt exchangeable for Devon common stock (DECS) owned by the company.
Liquidity
The company believes that it has the ability to provide for its operational
needs and its long- and short-term capital programs through its operating cash
flow (partially protected by the company's hedging program), borrowing capacity
and ability to raise capital. The company's primary source of funds has been
from operating cash flow, which could be adversely affected by declines in oil,
natural gas and pigment prices, all of which can be volatile as discussed in the
preceding Outlook section. Should operating cash flows decline, the company may
reduce its capital expenditures program, borrow under its commercial paper
program, draw upon revolving credit facilities and/or consider selective
long-term borrowings or equity issuances. Kerr-McGee's commercial paper programs
are backed by the revolving credit facilities currently in place. Should the
company's commercial paper or debt rating be downgraded, borrowing costs will
increase, and the company may experience loss of investor interest in its debt
instruments as evidenced by a reduction in the number of investors and/or
amounts they are willing to invest.
At December 31, 2003, the company had unused lines of credit and committed
amounts under revolving credit agreements totaling $1.4 billion. The company
maintains two revolving credit agreements consisting of a five-year $650 million
facility signed January 12, 2001, and a 364-day $700 million facility renewed on
November 14, 2003. In addition, the company had other unused credit facilities
of $50 million at December 31, 2003. Of the total of $1.4 billion, $870 million
and $490 million can be used to support commercial paper borrowings in the U.S.
and Europe, respectively, by certain wholly owned subsidiaries and are
guaranteed by the parent company. The borrowings can be made in U.S. dollars,
British pound sterling, euros or local European currencies. Interest for each of
the revolving credit facilities and lines of credit is payable at varying rates.
The company holds derivative financial instruments that require margin deposits
if unrealized losses exceed limits established with individual counterparty
institutions. From time to time, the company may be required to advance cash to
its counterparties to satisfy margin deposit requirements. No margin deposits
were outstanding at December 31, 2003. Between January 1, 2004, and March 5,
2004, margin calls totaled $7 million; however, these amounts have since been
refunded to the company.
At December 31, 2002, the company classified $68 million of its short-term
obligations as long-term debt. The company has the intent and the ability, as
evidenced by committed credit agreements, to refinance this type of debt on a
long-term basis. The company's practice has been to continually refinance its
commercial paper or draw on its backup facilities, while maintaining borrowing
levels believed to be appropriate.
The company issued 5 1/2% notes exchangeable for common stock in August 1999,
which allow each holder to receive between .85 and 1.0 share of Devon common
stock or, at the company's option, an equivalent amount of cash at maturity in
August 2004. As of February 27, 2004, Devon common stock was trading at $56.78
per share. Embedded options in the DECS provide the company a floor price on
Devon's common stock of $33.19 per share (the put option). The company also has
the right to retain up to 15% of the shares if Devon's stock price is greater
than $39.16 per share (the DECS holders have an embedded call option on 85% of
the shares). If Devon's stock price at maturity is greater than $33.19 per share
but less than $39.16 per share, the company's right to retain Devon stock will
be reduced proportionately. The company is not entitled to retain any Devon
stock if the price of Devon stock at maturity is less than or equal to $33.19
per share. Using the Black-Scholes valuation model, the company recognizes any
gains or losses resulting from changes in the fair value of the put and call
options in other income. The fluctuation in the value of the put and call
derivative financial instruments will generally offset the increase or decease
in the market value of the Devon stock classified as trading. The remaining
Devon shares, accounted for as available-for-sale securities, were partially
liquidated in December 2003, with the remaining shares sold in January 2004. The
available-for-sale Devon shares were in excess of the number of shares the
company believes will be required to extinguish the DECS; however, should the
price of the stock fall below $39.16 per share at the maturity of the DECS, the
company would be required to either purchase additional Devon shares to settle
the DECS or settle a portion of the DECS with cash.
The company also has available, to issue and sell, a total of $1.65 billion of
debt securities, common or preferred stock, or warrants under its shelf
registration with the Securities and Exchange Commission, which was last updated
in February 2002.
Off-Balance Sheet Arrangements
During 2001 and 2000, the company identified certain financing needs that it
determined would be best handled by off-balance sheet arrangements with
unconsolidated, special-purpose entities. Three leasing arrangements were
entered into for financing the company's working interest obligations for
production platforms and related equipment at three company-operated fields in
the Gulf of Mexico. Also, the company entered into an accounts receivable
monetization program to sell its receivables from certain pigment customers.
Each of these transactions has provided specific financing for the company's
business needs and/or projects and does not expose the company to significant
additional risks or commitments. The leases have provided a tax-efficient method
of financing a portion of these major development projects, and the sale of the
pigment receivables offers an attractive low-cost source of liquidity.
During 2001, the company entered into a leasing arrangement for its interest in
the production platform and related equipment for the Gunnison field in the
Garden Banks area of the Gulf of Mexico. This leasing arrangement is similar to
two arrangements entered into in 2000 for the Nansen and Boomvang fields in the
East Breaks area of the Gulf of Mexico. In each of these three arrangements, the
company entered into lease commitments with separate business trusts that were
created to construct independent spar production platforms for each field
development. Under the terms of the agreements, the company's share of
construction costs for the platforms was initially financed by synthetic lease
credit facilities between the trust and groups of financial institutions for
$149 million, $137 million and $78 million for Gunnison, Nansen and Boomvang,
respectively, with the company making lease payments sufficient to pay interest
at varying rates on the financings. Upon completion of the construction phase,
separate business trusts with third-party equity participants acquired the
assets and became the lessor/owner of the platforms and related equipment. The
company and these trusts have entered into operating leases for the use of the
spar platform and related equipment. During 2002, the Nansen and Boomvang
synthetic leases were converted to operating lease arrangements upon completion
of construction of the respective production platforms. Completion of the
Gunnison platform occurred in December 2003, at which time a portion of the
Gunnison synthetic lease was converted to an operating lease. The remaining
portion of the Gunnison synthetic lease was converted to an operating lease on
January 15, 2004. Under this type of financing structure, the company leases the
platforms under operating lease agreements, and neither the platform assets nor
the related debt is recognized in the company's Consolidated Balance Sheet.
However, since only a portion of the Gunnison synthetic lease had been converted
to an operating lease structure as of year-end, the remaining assets and
liabilities of the synthetic lessor trust are consolidated in the company's
Consolidated Balance Sheet at December 31, 2003, which includes $83 million in
property, plant and equipment, $4 million in accrued liabilities, $75 million in
long-term debt and $4 million in minority interest. The consolidation of the
synthetic lessor trust occurred in connection with the adoption of a new
accounting standard as discussed in the New/Revised Accounting Standards section
below. Since the remaining portion of the Gunnison synthetic lease was converted
to an operating lease structure in January, the related property and debt will
not be reflected in the company's Consolidated Balance Sheet in 2004.
In conjunction with the operating lease agreements, the company has guaranteed
that the residual values of the Nansen, Boomvang and Gunnison platforms at the
end of the operating leases shall be equal to at least 10% of their fair market
value at the inception of the lease. For Nansen and Boomvang, the guaranteed
values are $14 million and $8 million, respectively, in 2022, and for Gunnison
the guaranteed value is $15 million in 2024. Estimated future minimum annual
rentals under these leases and the residual value guarantees are shown in the
table of contractual obligations below.
In December 2000, the company began an accounts receivable monetization program
for its pigment business through the sale of selected accounts receivable with a
three-year, credit-insurance-backed asset securitization program. On July 30,
2003, the company restructured the existing accounts receivable monetization
program to include the sale of receivables originated by the company's European
chemical operations. The maximum available funding under the amended program is
$165 million. In addition, certain other terms of the program have been modified
as part of the restructuring. Under the terms of the program, selected
qualifying customer accounts receivable may be sold monthly to a special-purpose
entity (SPE), which in turn sells an undivided ownership interest in the
receivables to a third-party multi-seller commercial paper conduit sponsored by
an independent financial institution. The company sells, and retains an interest
in, excess receivables to the SPE as over-collateralization for the program. The
company's retained interest in the SPE's receivables is recorded in trade
accounts receivable in the Consolidated Balance Sheet. The retained interest is
subordinate to, and provides credit enhancement for, the conduit's ownership
interest in the SPE's receivables, and is available to the conduit to pay
certain fees or expenses due to the conduit, and to absorb credit losses
incurred on any of the SPE's receivables in the event of termination. However,
the company believes that the risk of credit loss is very low since its bad-debt
experience has historically been insignificant. The company also holds
preference stock in the special-purpose entity equal to 3.5% of the receivables
sold. The preference stock is essentially a retained deposit to provide further
credit enhancements, if needed, but is otherwise recoverable by the company at
the end of the program. The company records a loss on the receivable sales equal
to the difference in the cash received plus the fair value of the retained
interests and the carrying value of the receivables sold. The fair value of the
retained interests (servicing fees, excess receivables and preference stock of
the SPE) is based on the discounted present value of future cash flows. At
year-end 2003 and 2002, the outstanding balance on receivables sold under the
program totaled $165 million and $111 million, respectively.
During 2003 and 2002, the company entered into sale-leaseback arrangements with
General Electric Capital Corporation (GECC) covering assets associated with a
gas-gathering system in the Rocky Mountain region. The lease agreements were
entered into for the purpose of monetizing the related assets. The sales price
for the 2003 equipment was $6 million. The sales price for the 2002 equipment
was $71 million; however, an $18 million settlement obligation existed for
equipment previously covered by the lease agreement, resulting in net cash
proceeds of $53 million in 2002. The 2002 operating lease agreements have an
initial term of five years, with two 12-month renewal options, and the company
may elect to purchase the equipment at specified amounts after the end of the
fourth year. The 2003 operating lease agreement has an initial term of four
years, with two 12-month renewal options. In the event the company does not
purchase the equipment and it is returned to GECC, the company guarantees a
residual value ranging from $35 million at the end of the initial terms to $27
million at the end of the last renewal option. The company recorded no gain or
loss associated with the GECC sale-leaseback agreements. Estimated future
minimum annual rentals under this agreement and the residual value guarantee are
shown in the table of contractual obligations below.
In conjunction with the company's 2002 sale of its Ecuadorean assets, which
included the company's nonoperating interest in the Oleoducto de Crudos Pesados
Ltd. (OCP) pipeline, the company has entered into a performance guarantee
agreement with the buyer for the benefit of OCP. Under the terms of the
agreement, the company guarantees payment of any claims from OCP against the
buyer upon default by the buyer and its parent company. Claims would generally
be for the buyer's proportionate share of construction costs of OCP; however,
other claims may arise in the normal operations of the pipeline. Accordingly,
the amount of any such future claims cannot be reasonably estimated. In
connection with this guarantee, the buyer's parent company has issued a letter
of credit in favor of the company up to a maximum of $50 million, upon which the
company can draw in the event it is required to perform under the guarantee
agreement. The company will be released from this guarantee when the buyer
obtains a specified credit rating as stipulated under the guarantee agreement.
In addition, the company enters into certain indemnification agreements related
to title claims, environmental matters, litigation and other claims. The company
has recorded no material obligations in connection with its indemnification
agreements.
Obligations and Commitments
In the normal course of business, the company enters into purchase obligations,
contracts, leases and borrowing arrangements. The company has no debt guarantees
for unrelated parties. As part of the company's project-oriented exploration and
production business, Kerr-McGee routinely enters into contracts for certain
aspects of a project, such as engineering, drilling, subsea work, etc. These
contracts are generally not unconditional obligations; thus, the company accrues
for the value of work done at any point in time, a portion of which is billed to
partners. Kerr-McGee's commitments and obligations as of December 31, 2003, are
summarized in the following table:
(Millions of dollars) Payments due by period
- --------------------------------------------------------------------------------
2005 2007 After
Type of Obligation Total 2004 -2006 -2008 2008
- ------------------ ------ ---- ------ ---- ------
Long-term debt (1) $3,580 $574 $ 767 $150 $2,089
Operating leases for Nansen,
Boomvang and Gunnison 599 17 51 54 477
All other operating leases 342 33 80 66 163
Drilling rig commitments 9 9 - - -
Purchase obligations -
Ore contracts 477 168 235 74 -
Gas purchase and transportation
contracts 112 49 21 17 25
Other purchase obligations 405 128 158 67 52
Leased equipment residual value
guarantees 72 - - 35 37
------ ---- ------ ---- ------
Total $5,596 $978 $1,312 $463 $2,843
====== ==== ====== ==== ======
(1) Excludes the $75 million of debt associated with the Gunnison Trust. As
discussed above, the synthetic lease was restructured to an operating lease
in January 2004. The related future minimum lease payments are included
with operating leases for Gunnison.
- --------------------------------------------------------------------------------
Capital Spending
Capital expenditures are summarized as follows:
(Millions of dollars) Est. 2004 2003 2002 2001
- --------------------------------------------------------------------------------
Exploration and production, including
dry hole costs $ 920 $1,050 $1,101 $1,629
Chemicals 95 97 86 153
Other, including discontinued operations 20 15 85 82
------ ------ ------ ------
Total $1,035 $1,162 $1,272 $1,864
====== ====== ====== ======
Capital spending, excluding acquisitions, totaled $4.3 billion in the three-year
period ended December 31, 2003, and dividends paid totaled $535 million in the
same three-year period, which compares with $4.1 billion of net cash provided by
operating activities during the same period. During the three-year period, the
company made one major acquisition -- the 2001 acquisition of HS Resources for
$955 million cash plus common stock and assumed debt.
Kerr-McGee has budgeted approximately $1.035 billion for its capital program in
2004. Management anticipates that the 2004 capital program, dividends and debt
reduction can be provided for through internally generated funds. The available
capacity for borrowings may be used for selective acquisitions that support the
company's growth strategy or to support the company's capital expenditure
program should internally generated cash flow fall short in any one measurement
period.
Oil and Gas
The company's exploration and production capital spending continues to be
focused on global growth and deepwater projects. Successful exploration and
appraisal drilling in the deepwater Gulf of Mexico has resulted in the
development of three major projects during the last two years - Nansen (50%
working interest), Boomvang (30%), and Gunnison (50%). The Red Hawk (50%) and
Constitution (100%) projects currently under development are also in the
deepwater Gulf of Mexico. Constitution will be developed with a truss spar,
capitalizing on the success of the truss spar technology introduced at the
Nansen, Boomvang and Gunnison fields, while Red Hawk is being developed using
innovative cell spar technology. Red Hawk is expected to reach initial
production in mid-2004, while Constitution is expected to reach first production
by mid-2006. The company expects initial production at its Bohai Bay development
by the end of 2004. Two Bohai Bay discoveries are being developed with a
centrally located floating production, storage and offloading vessel, along with
fixed platforms for dry wellheads. Kerr-McGee operates this development with a
40% working interest. Of the $920 million total budget for 2004, $330 million is
allocated to the Gulf of Mexico, $180 million to the North Sea, $155 million to
U.S. onshore, $125 million to other international projects, $10 million to
technology enhancements and $120 million for dry hole costs. In addition, the
company has budgeted approximately $130 million (excluding noncash amortization
of nonproducing leasehold costs) for other exploration program expenses in 2004.
The company's exploration program is expected to fund approximately 50 wells,
with emphasis on balancing risks and potential rewards in both shallow and deep
waters and U.S. onshore.
Chemicals
Capital expenditures for chemical operations are budgeted at $95 million for
2004. Process and technology improvements that increase productivity and enhance
product quality will account for approximately 30% of the 2004 capital budget.
This includes the remaining estimated expenditures related to the
high-productivity oxidation line that began production in January 2004 at the
Savannah, Georgia, chloride-process pigment plant. Chemical has also budgeted
$38 million of additional investment in AVESTOR for 2004.
- --------------------------------------------------------------------------------
Market Risks
The company is exposed to a variety of market risks, including credit risks, the
effects of movements in foreign currency exchange rates, interest rates and
certain commodity prices. The company addresses its risks through a controlled
program of risk management that includes the use of insurance and derivative
financial instruments. See Notes 1 and 18 for additional discussions of the
company's financial instruments, derivatives and hedging activities.
Foreign Currency Exchange Rate Risk
The U.S. dollar is the functional currency for the company's international
operations, except for its European chemical operations, for which the euro is
the functional currency. Periodically, the company enters into forward contracts
to buy and sell foreign currencies. Certain of these contracts (purchases of
Australian dollars and British pound sterling, and sales of euro) have been
designated and have qualified as cash flow hedges of the company's anticipated
future cash flow needs for a portion of its capital expenditures, raw material
purchases and operating costs. These contracts generally have durations of less
than three years. The resulting changes in fair value of these contracts are
recorded in accumulated other comprehensive income.
Selected pigment receivables have been sold in an asset securitization program
at their equivalent U.S. dollar value at the date the receivables were sold. The
company is collection agent and retains the risk of foreign currency rate
changes between the date of sale and collection of the receivables. Under the
terms of the asset securitization agreement, the company is required to enter
into forward contracts for the value of the euro-denominated receivables sold
into the program to mitigate its foreign currency risk. Gains or losses on the
forward contracts are recognized currently in earnings. The company has entered
into other forward contracts to sell foreign currencies, which will be collected
as a result of pigment sales denominated in foreign currencies, primarily in
European currencies. These contracts have not been designated as hedges even
though they do protect the company from changes in foreign currency rates.
Following are the notional amounts at the contract exchange rates,
weighted-average contractual exchange rates and estimated contract values for
open contracts at year-end 2003 and 2002 to purchase (sell) foreign currencies.
Contract values are based on the estimated forward exchange rates in effect at
year-end. All amounts are U.S. dollar equivalents.
Estimated
(Millions of dollars, Notional Weighted-Average Contract
except average contract rates) Amount Contract Rate Value
- --------------------------------------------------------------------------------------------------------------------
Open contracts at December 31, 2003 -
Maturing in 2004 -
British pound sterling $139 1.6372 $148
Australian dollar 38 .5366 51
Euro (113) 1.1358 (106)
British pound sterling (1) 1.6876 (1)
Japanese yen (2) .0092 (2)
New Zealand dollar (1) .6121 (1)
Maturing in 2005 -
British pound sterling 77 1.5995 82
Open contracts at December 31, 2002 -
Maturing in 2003 -
British pound sterling 113 1.5454 115
Australian dollar 63 .5606 62
Euro (10) .9833 (10)
British pound sterling (1) 1.5432 (1)
Japanese yen (1) .0080 (1)
New Zealand dollar (1) .4807 (1)
Maturing in 2004 -
Australian dollar 38 .5366 38
Interest Rate Risk
The company's exposure to changes in interest rates relates primarily to
long-term debt obligations. The table below presents principal amounts and
related weighted-average interest rates by maturity date for the company's
long-term debt obligations outstanding at year-end 2003. All borrowings are in
U.S. dollars.
There- Fair Value
(Millions of dollars) 2004 2005 2006 2007 2008 after Total 12/31/03
- ----------------------------------------------------------------------------------------------------------------------
Fixed-rate debt -
Principal amount $474 $110 $307 $150 $ - $2,089 $3,130 $3,550
Weighted-average
interest rate 6.41% 8.15% 5.88% 6.63% - 6.67% 6.61%
Variable-rate debt - (1)
Principal amount $100 $350 $ 75 $ - $ - $ - $ 525 $ 525
Weighted-average
interest rate 1.92% 2.03% 1.93% - - - 1.99%
(1) Includes fixed-rate debt with interest rate swap to variable rate.
At December 31, 2002, long-term debt included fixed-rate debt of $3.286 billion
(fair value - $3.706 billion) with a weighted-average interest rate of 6.67% and
$618 million of variable-rate debt, which approximated fair value, with a
weighted-average interest rate of 2.56%.
In connection with the issuance of $350 million 5.375% notes due April 15, 2005,
the company entered into an interest rate swap arrangement in 2002. The terms of
the agreement effectively change the interest the company will pay on the debt
until maturity from the fixed rate to a variable rate of LIBOR plus .875%. The
company considers the swap to be a hedge against the change in fair value of the
debt as a result of interest rate changes. The estimated fair value of the
interest rate swap was $15 million at December 31, 2003.
During February 2004, the company reviewed the composition of its outstanding
debt and entered into additional interest rate swaps, converting an aggregate of
$566 million in fixed-rate debt to variable-rate debt. Under the interest rate
swaps, $150 million of 6.625% notes due October 15, 2007, will pay a variable
rate of LIBOR plus 3.35%; $109 million of 8.125% notes due October 15, 2005,
will pay a variable rate of LIBOR plus 5.86%; and $307 million of 5.875% notes
due September 15, 2006, will pay a variable rate of LIBOR plus 3.1%. The
interest rate swaps have been designated as hedges against changes in the fair
value of the related debt resulting from interest rate changes. The estimated
fair value of the interest rate swaps, including the original swap outstanding
at December 31, 2003, totaled $21 million as of February 29, 2004.
Commodity Price Risk
The company is exposed to market risk from fluctuations in crude oil and natural
gas prices. To increase the predictability of its cash flows and to support
capital projects, the company initiated a hedging program in 2002 and
periodically enters into financial derivative instruments that generally fix the
commodity prices to be received for a portion of its oil and gas production in
the future. At December 31, 2003, the outstanding commodity-related derivatives
accounted for as hedges had a liability fair value of $168 million, which is
recorded as a current liability. The fair value of these derivative instruments
at December 31, 2003, was determined based on prices actively quoted, generally
NYMEX and Dated Brent prices. At December 31, 2003, the company had after-tax
deferred losses of $106 million in accumulated other comprehensive income
associated with these contracts. The company expects to reclassify the entire
amount of these losses into earnings during the next 12 months, assuming no
further changes in fair market value of the contracts. During 2003, the company
realized a $71 million loss on U.S. oil hedging, a $64 million loss on North Sea
oil hedging and a $144 million loss on U.S. natural gas hedging. During 2002,
the company realized a $28 million loss on U.S. oil hedging, a $50 million loss
on North Sea oil hedging and a $2 million loss on U.S. natural gas hedging. The
losses offset the higher oil and natural gas prices realized on the physical
sale of crude oil and natural gas. Losses for hedge ineffectiveness are
recognized as a reduction of revenue in the Consolidated Statement of Operations
and were not material for 2003 or 2002.
At December 31, 2003, the following commodity-related derivative contracts were
outstanding:
Daily Average
Contract Type (1) Period Volume Price
- --------------------------------------------------------------------------------
Natural Gas MMBtu $/MMBtu
- ----------- ------- -------
Fixed-price swaps (NYMEX) Q1 - 2004 195,000 $5.33
Q2 - 2004 565,000 $4.74
Q3,4 - 2004 575,000 $4.75
Costless collars (NYMEX) Q1 - 2004 360,000 $4.79 - $6.47
Basis swaps (CIG and Northwest) Q1 - 2004 135,000 $0.57
Q2,3 - 2004 55,000 $0.47
Q4 - 2004 41,739 $0.38
Crude Oil Bbl $/Bbl
- --------- ------ ------
Fixed-price swaps (WTI) Q1 - 2004 48,000 $28.57
Q2 - 2004 48,000 $27.65
Q3 - 2004 45,000 $27.29
Q4 - 2004 30,000 $26.96
Fixed-price swaps (Brent) Q1 - 2004 45,000 $26.38
Q2 - 2004 46,500 $25.86
Q3 - 2004 39,750 $25.98
Q4 - 2004 32,000 $25.65
(1) These contracts may be subject to margin calls above certain limits
established with individual counterparty institutions.
After December 31, 2003, the following derivative contacts were added to the
company's 2004 hedging program and, combined with the hedges outstanding at
December 31, 2003, cover approximately 80% of expected 2004 worldwide crude oil
and condensate production, and 75% of the U.S. natural gas production.
Daily Average
Contract Type (1) Period Volume Price
- --------------------------------------------------------------------------------
Crude Oil Bbl $/Bbl
- --------- ------ ------
Fixed-price swaps (WTI) Q1 - 2004 4,352 $34.13
Q2 - 2004 6,300 $32.67
Q3 - 2004 5,915 $31.18
Q4 - 2004 20,015 $30.28
Fixed-price swaps (Brent) Q1 - 2004 4,286 $30.77
Q2 - 2004 5,300 $29.92
Q3 - 2004 7,100 $29.07
Q4 - 2004 20,000 $28.41
(1) These contracts may be subject to margin calls above certain limits
established with individual counterparty institutions.
In addition to the company's hedging program, Kerr-McGee Rocky Mountain Corp.
holds certain gas basis swaps settling between 2004 and 2008. Through December
2003, the company treated these gas basis swaps as non-hedge derivatives, and
changes in fair value were recognized in earnings. On December 31, 2003, the
company designated those swaps settling in 2004 as hedges since the basis swaps
have been coupled with natural gas fixed-price swaps, while the remainder
settling between 2005 and 2008 will continue to be treated as non-hedge
derivatives. At December 31, 2003, these derivatives are recorded at their fair
value of $23 million, of which $8 million is recorded as a current asset and $15
million is recorded in investments - other assets. At December 31, 2002, these
derivatives were recorded at their fair value of $21 million in investments -
other assets. The net gains associated with these non-hedge derivatives were $2
million, $8 million and $27 million in 2003, 2002 and 2001, respectively, and
are included in other income in the Consolidated Statement of Operations.
The company's marketing subsidiary, Kerr-McGee Energy Services (KMES), markets
natural gas (primarily equity gas) in the Denver area. Existing contracts for
the physical delivery of gas at fixed prices have not been designated as hedges
and are marked to market in accordance with FAS 133. KMES has also entered into
natural gas swaps and basis swaps that offset its fixed-price risk on physical
contracts. These derivative contracts lock in the margins associated with the
physical sale. The company believes that risk associated with these derivatives
is minimal due to the credit-worthiness of the counterparties. The net asset
fair value of these derivative instruments was not material at year-end 2003 and
2002. The fair values of the outstanding derivative instruments at December 31,
2003, were based on prices actively quoted. During 2003, the net loss associated
with these derivative contracts totaled $12 million, of which $7 million is
included as a reduction of revenue and $5 million is included in other income.
For 2002 and 2001, the net loss associated with these derivative contracts
totaled $20 million and $24 million, respectively, and is included as a
reduction of revenue in the Consolidated Statement of Operations. The losses on
the derivative contracts are substantially offset by the fixed prices realized
on the physical sale of the natural gas.
- --------------------------------------------------------------------------------
Critical Accounting Policies
Preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates,
judgments and assumptions regarding matters that are inherently uncertain and
that ultimately affect the reported amounts of assets, liabilities, revenues and
expenses, and the disclosure of contingent assets and liabilities. However, the
accounting principles used by the company generally do not impact the company's
reported cash flows or liquidity. Generally, accounting rules do not involve a
selection among alternatives, but involve a selection of the appropriate
policies for applying the basic principles. Interpretation of the existing rules
must be done and judgments made on how the specifics of a given rule apply to
the company.
The more significant reporting areas impacted by management's judgments and
estimates are assessment of unproved oil and gas properties for impairment,
crude oil and natural gas reserve estimation, site dismantlement and asset
retirement obligations, recoverability of assets, environmental remediation,
derivative instruments, litigation, tax accruals, and benefit plans.
Management's judgments and estimates in these areas are based on information
available from both internal and external sources, including engineers, legal
counsel, actuaries, environmental studies and historical experience in similar
matters. Actual results could differ materially from those estimates as
additional information becomes known.
Successful Efforts Method of Accounting
The company has elected to use the successful efforts method of accounting for
its oil and gas exploration and development activities. Exploration expenses,
including geological and geophysical costs, rentals, and exploratory dry holes,
are charged against income as incurred. Costs of successful wells and related
production equipment and developmental dry holes are capitalized and amortized
by field using the unit-of-production method as oil and gas is produced. The
successful efforts method reflects the inherent volatility in exploring for and
producing oil and gas. The accounting method may yield significantly different
operating results than the full-cost method.
Under the successful efforts method, the costs of drilling an exploratory well
are capitalized pending determination of whether proved reserves can be
attributed to the discovery. In the case of onshore wells and offshore wells in
relatively shallow water, that determination usually can be made upon or shortly
after cessation of drilling operations. However, such determination may take
longer depending on, among other things, the amount of hydrocarbons encountered,
results of future appraisal drilling and proximity to existing infrastructure -
especially in the case of deepwater and international exploration. As a
consequence, the company has capitalized costs associated with exploratory wells
on its balance sheet at any point in time that may be charged to earnings in a
future period if management determines that commercial quantities of
hydrocarbons have not been discovered. At December 31, 2003, the company had
capitalized costs of approximately $143 million associated with such ongoing
exploration activities, primarily in the deepwater Gulf of Mexico and China.
Oil and Gas Reserves and Standardized Measure of Future Cash Flows
The estimates of oil and gas reserves and associated future net cash flows are
prepared by the company's geologists and engineers. Only proved oil and gas
reserves are included in any financial statement disclosure. The U.S. Securities
and Exchange Commission has defined proved reserves as the estimated quantities
of crude oil, natural gas and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Even though the company's geologists and engineers are knowledgeable
and follow authoritative guidelines for estimating reserves, they must make a
number of subjective assumptions based on professional judgments in developing
the reserve estimates. Reserve estimates are updated at least annually and
consider recent production levels and other technical information about each
field. Revisions in the estimated reserves and future cash flows may be
necessary due to a number of factors, including reservoir performance, new
drilling, oil and gas prices and cost changes, technological advances, new
geological or geophysical data, or other economic factors. See Notes 32 and 33
to the Consolidated Financial Statements for information concerning historical
changes in reserve estimates and standardized measure of future cash flows for
each of the last three years. The company cannot predict the amounts or timing
of future reserve revisions.
Depreciation and depletion rates are calculated using both reserve quantity
estimates and the capitalized costs of producing properties. As the estimated
reserves are adjusted, the depreciation and depletion expense for a property
will change, assuming no change in production volumes or the costs capitalized.
Estimated reserves also are used as the basis for calculating the expected
future cash flows from a property, which are further used to analyze a property
for potential impairment. In addition, reserves are used to estimate the
company's supplemental disclosure of the standardized measure of discounted
future net cash flows relating to its oil and gas producing activities. Changes
in estimated reserves are considered changes in estimates for accounting
purposes and are reflected on a prospective basis.
Site Dismantlement and Asset Retirement Obligations
The company has significant obligations for the dismantlement and removal of its
oil and gas production and related facilities. Estimating future asset removal
costs is difficult and requires management to make estimates and judgments since
most of the removal activities will occur several years in the future. Asset
removal technologies and costs are constantly changing, as are political,
environmental, safety and public relations considerations that may ultimately
impact the amount of the obligation. In June 2001, the FASB issued FAS 143,
"Accounting for Asset Retirement Obligations," which the company adopted on
January 1, 2003. The impact of this new standard is discussed below in the
New/Revised Accounting Standards section.
Impairment of Assets
All long-lived assets are assessed for potential impairment when events or
changes in circumstances indicate that the carrying value of the asset may be
greater than its future net cash flows. The evaluations involve a significant
amount of judgment since the results are based on estimated future events, such
as future sales prices for oil, gas or chemicals; future costs to produce these
products; estimates of future oil and gas reserves to be recovered; development
costs and the timing thereof; the economic and regulatory climates; and other
factors. The need to test a property for impairment may result from significant
declines in sales prices, unfavorable adjustments to oil and gas reserves,
increases in operating costs, and changes in environmental or abandonment
regulations. Assets held for sale are reviewed for potential loss on sale when
the company approves the plan to sell and thereafter while the asset is held for
sale. Losses are measured as the difference between fair value less costs to
sell, and the assets' carrying value. Estimates of anticipated sales prices are
highly judgmental and subject to material revision in future periods. Goodwill
is tested annually for impairment, or more frequently if impairment indicators
arise. The company completed its annual test for impairment of goodwill and
indefinite-lived intangible assets as of June 30, 2003, with no impairment loss
indicated. The company cannot predict when or if future impairment charges for
held-for-use assets, goodwill or intangibles, or losses associated with
held-for-sale properties will be recorded.
Derivative Instruments
The company is exposed to risk from fluctuations in crude oil and natural gas
prices, foreign currency exchange rates, and interest rates. To reduce the
impact of these risks on earnings and to increase the predictability of its cash
flow, from time to time the company enters into certain derivative contracts,
primarily swaps and collars for a portion of its oil and gas production, forward
contracts to buy and sell foreign currencies, and interest rate swaps. The
company accounts for all its derivative instruments, including hedges, in
accordance with FAS 133, "Accounting for Derivative Instruments and Hedging
Activities." The commodity, foreign currency and interest rate contracts are
measured at fair value and recorded as assets or liabilities in the Consolidated
Balance Sheet. When available, quoted market prices are used in determining fair
value; however, if quoted market prices are not available, the company estimates
fair value using either quoted market prices of financial instruments with
similar characteristics or other valuation techniques. The counterparties to
these contractual arrangements generally are limited to major institutions.
Environmental Remediation, Litigation and Other Contingency Reserves
Kerr-McGee management makes judgments and estimates in accordance with
applicable accounting rules when it establishes reserves for environmental
remediation, litigation and other contingent matters. Provisions for such
matters are charged to expense when it is probable that a liability has been
incurred and reasonable estimates of the liability can be made. It is not
possible for management to reliably estimate the amount and timing of all future
expenditures related to environmental, legal or other contingent matters because
of continually changing laws and regulations, inherent uncertainties associated
with court and regulatory proceedings as well as cleanup requirements and
related work, the possible existence of other potentially responsible parties,
and the changing political and economic environment. For these reasons, actual
environmental, litigation and other contingency costs can vary significantly
from the company's estimates. For additional information about contingencies,
refer to the Environmental Matters section that follows and Note 16.
Tax Accruals
The company has operations in several countries around the world and is subject
to income and other similar taxes in these countries. The estimation of the
amounts of income tax to be recorded by the company involves interpretation of
complex tax laws and regulations, evaluation of tax audit findings, and
assessment of how the foreign taxes affect domestic taxes. Although the
company's management believes its tax accruals are adequate, differences may
occur in the future, depending on the resolution of pending and new tax matters.
Benefit Plans
The company provides defined benefit retirement plans and certain nonqualified
benefits for employees in the U.S., U.K., Germany and the Netherlands and
accounts for these plans in accordance with FAS 87, "Employers' Accounting for
Pensions." The various assumptions used and the attribution of the costs to
periods of employee service are fundamental to the measurement of net periodic
cost and pension obligations associated with the retirement plans.
One of the significant assumptions used to account for the company's pension
plans is the expected long-term rate of return on plan assets. The expected
long-term rate of return forecasting methodology is based on a capital asset
pricing model using historical data. Based on this information, the company
selected 8.5% for 2003 and 2004 for U.S. pension plans.
Another significant assumption for pension plan accounting is the discount rate.
The company selects a discount rate as of December 31 each year for U.S. plans
to reflect average rates available on high-quality fixed income debt instruments
during December of that year. The average Moody's Long-Term AA Corporate Bond
Yield for December is used as a guide in the selection of the discount rate for
U.S. pension plans. For December 2002, the average Moody's Long-Term AA
Corporate Bond Yield was 6.63%, and the company chose 6.75% as its discount rate
at the end of 2002. For December 2003, the average Moody's Long-Term AA
Corporate Bond Yield was 6.04%, and the company chose 6.25% as its discount rate
at the end of 2003. This decrease in the discount rate effective December 31,
2003, is expected to increase 2004 net periodic pension cost by $5 million but
not affect expected contributions to fund the pension plans.
The rate of compensation increase is another significant assumption used in the
development of accounting information for pension plans. The company determines
this assumption based on its long-term plans for compensation increases and
current economic conditions. Based on this information, the company selected
4.5% at December 31, 2002 and 2003, for U.S. pensions plans.
The net effect the U.S. pension plans had on results of operations for 2003 was
$32 million of income due to the expected return on assets exceeding other
pension charges. The total expected return on assets of the U.S. pension plans
for 2003 was $117 million, compared with an actual return of $189 million.
During 2003, the company's contributions to the retirement plans totaled $5
million for certain U.S. nonqualified plans and foreign plans.
When calculating expected return on plan assets for U.S. pension plans, the
company uses a market-related value of assets that spreads asset gains and
losses (differences between actual return and expected return) over five years.
As of January 1, 2004, the amount of unrecognized losses on U.S. pension assets
was $188 million. As these losses are recognized during future years in the
market-related value of assets, they will result in cumulative increases in net
periodic pension cost of $16 million in 2005 through 2008.
A 25 basis point increase/decrease in the company's expected long-term rate of
return assumption as of the beginning of 2004 would decrease/increase net
periodic pension cost for U.S. pension plans for 2004 by $3 million. The change
would not affect expected contributions to fund the company's U.S. pension
plans.
The company also provides certain postretirement health care and life insurance
benefits and accounts for the related plans in accordance with FAS 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions." The
postretirement benefit cost and obligation are also dependent on the company's
assumptions used in the actuarially determined amounts. These assumptions
include discount rates (discussed above), health care cost trend rates,
inflation rates, retirement rates, mortality rates and other factors. The health
care cost trend assumptions are developed based on historical cost data, the
near-term outlook and an assessment of likely long-term trends. Assumed
inflation rates are based on an evaluation of external market indicators.
Retirement and mortality rates are based primarily on actual plan experience.
See Note 24 for a discussion of the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 as it relates to the company's postretirement health
care plan.
The above description of the company's critical accounting policies is not
intended to be an all-inclusive discussion of the uncertainties considered and
estimates made by management in applying accounting principles and policies.
Results may vary significantly if different policies were used or required and
if new or different information becomes known to management.
- --------------------------------------------------------------------------------
Environmental Matters
The company's affiliates are subject to various environmental laws and
regulations in the United States and in foreign countries in which they operate.
Under these laws, the company's affiliates are or may be required to obtain or
maintain permits and/or licenses in connection with their operations. In
addition, under these laws, the company's affiliates are or may be required to
remove or mitigate the effects on the environment due to the disposal or release
of certain chemical, petroleum, low-level radioactive and other substances at
various sites. Environmental laws and regulations are becoming increasingly
stringent, and compliance costs are significant and will continue to be
significant in the foreseeable future. There can be no assurance that such laws
and regulations or any environmental law or regulation enacted in the future
will not have a material effect on the company's operations or financial
condition.
Sites at which the company's affiliates have environmental responsibilities
include sites that have been designated as Superfund sites by the U.S.
Environmental Protection Agency (EPA) pursuant to the Comprehensive
Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), as
amended, and that are included on the National Priority List (NPL). As of
December 31, 2003, the company's affiliates had received notices that they had
been named potentially responsible parties (PRP) with respect to 13 existing EPA
Superfund sites on the NPL that require remediation. The company does not
consider the number of sites for which its affiliates have been named a PRP to
be the determining factor when considering the company's overall environmental
liability. Decommissioning and remediation obligations, and the attendant costs,
vary substantially from site to site and depend on unique site characteristics,
available technology and the regulatory requirements applicable to each site.
Additionally, the company's affiliates may share liability at some sites with
numerous other PRPs, and the law currently imposes joint and several liability
on all PRPs under CERCLA. The company's affiliates are also obligated to perform
or have performed remediation or remedial investigations and feasibility studies
at sites that have not been designated as Superfund sites by EPA. Such work is
frequently undertaken pursuant to consent orders or other agreements.
Current Businesses
The company's oil and gas affiliates are subject to numerous international,
federal, state and local laws and regulations relating to environmental
protection. In the United States, these include the Federal Water Pollution
Control Act, commonly known as the Clean Water Act, the Clean Air Act and the
Resource Conservation and Recovery Act (RCRA). These laws and regulations
govern, among other things, the amounts and types of substances and materials
that may be released into the environment; the issuance of permits in connection
with exploration, drilling and production activities; the release of emissions
into the atmosphere; and the discharge and disposition of waste materials.
Environmental laws and regulations also govern offshore oil and gas operations,
the implementation of spill prevention plans, the reclamation and abandonment of
wells and facility sites, and the remediation and monitoring of contaminated
sites. The company's chemical affiliates are subject to a broad array of
international, federal, state and local laws and regulations relating to
environmental protection, including the Clean Water Act, the Clean Air Act,
CERCLA and RCRA. These laws require the company's affiliates to undertake
various activities to reduce air emissions, eliminate the generation of
hazardous waste, decrease the volume of wastewater discharges and increase the
efficiency of energy use.
Discontinued Businesses
The company's affiliates historically have held interests in various businesses
in which they are no longer engaged or which they intend to exit. Such
businesses include the refining and marketing of oil and gas and associated
petroleum products, the mining and processing of uranium and thorium, the
production of ammonium perchlorate, and other activities. Additionally, the
company expects to complete its exit from the forest products business by the
end of 2004. Although the company's affiliates are no longer engaged in certain
businesses or have announced their intention to exit certain businesses,
residual obligations may still exist, including obligations related to
compliance with environmental laws and regulations, including the Clean Water
Act, the Clean Air Act, CERCLA and RCRA. These laws and regulations require
company affiliates to undertake remedial measures at sites of current or former
operations or at sites where waste was disposed. For example, company affiliates
are required to conduct decommissioning and environmental remediation at certain
refineries, distribution facilities and service stations they owned and/or
operated before exiting the refining and marketing business in 1995. Company
affiliates also are required to conduct decommissioning and remediation
activities at sites where they were involved in the exploration, production,
processing and/or sale of uranium or thorium. Additionally, the company's
chemical affiliate may be required to decommission and remediate its
wood-treatment facilities as part of its plan to exit the forest products
business.
Environmental Costs
Expenditures for environmental protection and cleanup for each of the last three
years and for the three-year period ended December 31, 2003, are as follows:
(Millions of dollars) 2003 2002 2001 Total
- --------------------------------------------------------------------------------
Charges to environmental reserves $104 $128 $142 $374
Recurring expenses 19 37 57 113
Capital expenditures 18 22 21 61
---- ---- ---- ----
Total $141 $187 $220 $548
==== ==== ==== ====
In addition to past expenditures, reserves have been established for the
remediation and restoration of active and inactive sites where it is probable
that future costs will be incurred and the liability is reasonably estimable.
For environmental sites, the company considers a variety of matters when setting
reserves, including the stage of investigation; whether EPA or another relevant
agency has ordered action or quantified cost; whether the company has received
an order to conduct work; whether the company participates as a PRP in the
Remedial Investigation/Feasibility Study (RI/FS) process and, if so, how far the
RI/FS has progressed; the status of the record of decision by the relevant
agency; the status of site characterization; the stage of the remedial design;
evaluation of existing remediation technologies; the number and financial
condition of other potential PRPs; and whether the company reasonably can
evaluate costs based upon a remedial design and/or engineering plan.
After the remediation work has begun, additional accruals or adjustments to
costs may be made based on any number of developments, including revisions to
the remedial design; unanticipated construction problems; identification of
additional areas or volumes of contamination; inability to implement a planned
engineering design or to use planned technologies and excavation methods;
changes in costs of labor, equipment and/or technology; any additional or
updated engineering and other studies; and weather conditions.
As of December 31, 2003, the company's financial reserves for all active and
inactive sites totaled $259 million. This includes $105 million added in 2003
for active and inactive sites. In the Consolidated Balance Sheet, $161 million
of the total reserve is classified as a deferred credit, and the remaining $98
million is included in current liabilities. Management believes that currently
the company has reserved adequately for the reasonably estimable costs of known
environmental contingencies. However, additional reserves may be required in the
future due to the previously noted uncertainties. Additionally, there may be
other sites where the company has potential liability for environmental-related
matters but for which the company does not have sufficient information to
determine that the liability is probable and/or reasonably estimable. The
company has not established reserves for such sites.
The following table reflects the company's portion of the known estimated costs
of investigation and/or remediation that are probable and estimable. The table
summarizes EPA Superfund NPL sites where the company and/or its affiliates have
been notified it is a PRP under CERCLA and other sites for which the company had
some ongoing financial involvement in investigation and/or remediation at
year-end 2003. In the table, aggregated information is presented for certain
sites that are individually not significant (having a remaining reserve balance
of less than $10 million) or for which the company has not recorded a reserve
because the liability is not probable and/or reasonably estimable. Amounts
reported in the table for the West Chicago sites are not reduced for actual or
expected reimbursement from the U.S. government under Title X of the Energy
Policy Act of 1992 (Title X), described in Note 16 to the Consolidated Financial
Statements, which financial statements are included in Item 8. of this Form
10-K.
Remaining
Reserve
Total Balance at
Expenditures December 31,
Through 2003 2003 Total
-----------------------------------------
Location of Site Stage of Investigation/Remediation (Millions of dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
EPA Superfund sites on
National Priority List (NPL)
West Chicago, Ill.
Vicinity areas Remediation of thorium tailings at
Residential Areas and Reed-Keppler Park
is substantially complete. An agreement
in principle for cleanup of thorium
tailings at Kress Creek and Sewage
Treatment Plant has been reached with
relevant agencies; court approval
expected in 2004. $ 113 $ 84 $ 197
Milwaukee, Wis. Completed soil cleanup at former wood-
treatment facility and began cleanup of
offsite tributary creek. Groundwater
remediation is continuing. 31 11 42
Other sites Sites where the company has been named a
PRP, including landfills, wood-treating
sites, a mine site and an oil recycling
refinery. These sites are in various
stages of investigation/remediation. 33 12 45
------ ---- ------
177 107 284
------ ---- ------
Sites under consent order, license
or agreement, not on EPA Superfund
NPL
West Chicago, Ill.
Former manufacturing Excavation of contaminated soils at
facility former thorium mill is substantially
complete, and soil removal is expected to
be substantially completed in 2004.
Groundwater monitoring and/or remediation
will continue. 424 12 436
Cushing, Okla. Remediation of thorium and uranium re-
siduals is expected to be substantially
completed in 2004. Investigation and
remediation addressing hydrocarbon con-
tamination is continuing. 123 22 145
Henderson, Nev. Groundwater treatment to address per-
chlorate contamination is being conducted
under consent order with Nevada
Department of Environmental Protection. 106 23 129
Mobile, Ala. Groundwater treatment in compliance with
NPDES permit and closure of surface
impoundments is ongoing. - 11 11
Other sites Sites related to wood-treatment, chemical
production, landfills, mining, oil and
gas production, and petroleum refining,
distribution and marketing. These sites
are in various stages of investigation/
remediation. 297 84 381
------ ---- ------
950 152 1,102
------ ---- ------
Total $1,127 $259 $1,386
- ------------------------------------------------------------------------------------------------------------------------------------
The company has not recorded in the financial statements potential
reimbursements from governmental agencies or other third parties, except for
amounts due from the U.S. government under Title X for costs incurred by the
company on its behalf and recoveries under certain insurance policies. If
recoveries from third parties, other than recovery from the U.S. government
under Title X and recoveries under certain insurance policies, become probable,
they will be disclosed but will not generally be recorded in the financial
statements until received.
Sites specifically identified in the table above are discussed in Note 16 to the
Consolidated Financial Statements, which financial statements are included in
Item 8. of this Form 10-K. Any discussion in Note 16 of the West Chicago,
Illinois; Henderson, Nevada; Milwaukee, Wisconsin; Cushing, Oklahoma; and
Mobile, Alabama, sites is incorporated herein by reference and made fully a part
hereof.
- --------------------------------------------------------------------------------
New/Revised Accounting Standards
In June 2001, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (FAS) No. 143, "Accounting for Asset
Retirement Obligations." FAS 143 requires that an asset retirement obligation
(ARO) associated with the retirement of a tangible long-lived asset be
recognized as a liability in the period in which it is incurred or becomes
determinable (as defined by the standard), with an associated increase in the
carrying amount of the related long-lived asset. The cost of the tangible asset,
including the initially recognized asset retirement cost, is depreciated over
the useful life of the asset. The ARO is recorded at fair value, and accretion
expense will be recognized over time as the discounted liability is accreted to
its expected settlement value. The fair value of the ARO is measured using
expected future cash outflows discounted at the company's credit-adjusted
risk-free interest rate.
The company adopted FAS 143 on January 1, 2003, which resulted in an increase in
net property of $108 million, an increase in abandonment liabilities of $161
million and a decrease in deferred income tax liabilities of $18 million. The
net impact of these changes resulted in an after-tax charge to earnings of $35
million to recognize the cumulative effect of retroactively applying the new
accounting principle. In accordance with the provisions of FAS 143, Kerr-McGee
accrues an abandonment liability associated with its oil and gas wells and
platforms when those assets are placed in service, rather than its past practice
of accruing the expected abandonment costs on a unit-of-production basis over
the productive life of the associated oil and gas field. No market risk premium
has been included in the company's calculation of the ARO for oil and gas wells
and platforms since no reliable estimate can be made by the company. In
connection with the change in accounting principle, abandonment expense of $40
million in 2002 and $34 million in 2001 has been reclassified from costs and
operating expenses to depreciation and depletion in the Consolidated Statement
of Operations to be consistent with the 2003 presentation. In January 2003, the
company announced its plan to close the synthetic rutile plant in Mobile,
Alabama, and closed the plant in June 2003. Since the plant had a determinate
closure date, the company accrued an abandonment liability of $18 million
associated with its plans to decommission the Mobile facility in connection with
the adoption of FAS 143.
In November 2002, the FASB issued FASB Interpretation (FIN) No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others - an Interpretation of FASB Statements No.
5, 57, and 107 and Rescission of FASB Interpretation No. 34." For certain
guarantees, FIN 45 requires recognition at the inception of a guarantee of a
liability for the fair value of the obligation assumed in issuing the guarantee.
FIN 45 also requires expanded disclosures for outstanding guarantees, even if
the likelihood of the guarantor having to make any payments under the guarantee
is considered remote. The recognition provisions of FIN 45 were effective for
guarantees issued or modified after December 31, 2002. The company has not
issued or modified any material guarantees within the scope of FIN 45 during
2003; therefore, implementation of this new standard has not impacted its
consolidated financial condition or results of operations.
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest
Entities - an Interpretation of ARB No. 51." This interpretation clarifies the
application of ARB 51, "Consolidated Financial Statements," to certain entities
in which equity investors do not have the characteristics of a controlling
financial interest or do not have sufficient equity at risk for the entity to
finance its activities without additional subordinated financial support from
other parties. Because application of the majority voting interest requirement
in ARB 51 may not identify the party with a controlling financial interest in
situations where controlling financial interest is achieved through arrangements
not involving voting interests, this interpretation introduces the concept of
variable interests and requires consolidation by an enterprise having variable
interests in a previously unconsolidated entity if the enterprise is considered
the primary beneficiary, meaning the enterprise will absorb a majority of the
variable interest entity's expected losses or residual returns. For variable
interest entities in existence as of February 1, 2003, FIN 46, as originally
issued, required consolidation by the primary beneficiary in the third quarter
of 2003. In October 2003, the FASB deferred the effective date of FIN 46 to the
fourth quarter.
In accordance with the provisions of FIN 46, the company has consolidated the
business trust created to construct and finance the Gunnison production
platform. Accordingly, the assets and liabilities of the trust are reflected in
the company's Consolidated Balance Sheet at December 31, 2003, which includes
$83 million in property, plant and equipment, $4 million in accrued liabilities,
$75 million in long-term debt and $4 million in minority interest (See Notes 1
and 9). The company has reviewed the effects of FIN 46 relative to its other
relationships with possible variable interest entities, such as the lessor
trusts that are party to the Nansen and Boomvang operating leases and certain
joint-venture arrangements, and has determined that consolidation of these
entities is not required.
The company applies the provisions of FAS No. 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies," for the accounting of oil and gas
mineral rights held by lease or contract and accordingly classifies these assets
as property, plant and equipment. This classification is the long standing and
current industry standard and is consistent with most mineral rights case law
(that is, mineral rights generally are treated as interests in real property and
real property laws are used to interpret the leases). However, the SEC has asked
that the Emerging Issues Task Force (EITF) consider whether mineral rights are
intangible assets under the guidance provided by FAS No. 141, "Business
Combinations," and FAS No. 142, "Goodwill and Other Intangible Assets." If such
interests are deemed to be intangible assets by the EITF, mineral rights to
extract oil and gas for both undeveloped and developed leaseholds may be
reclassified separately as intangible assets.
Even though management believes the company's current balance sheet
classification is required under generally accepted accounting principles,
reclassification may be necessary in the future when further guidance is
provided by the EITF. However, it is not currently clear which mineral rights
might have to be reclassified as intangible assets - all producing and
nonproducing leaseholds, only nonproducing leaseholds or only leaseholds
acquired in business combinations since the effective date of FAS No. 141. Any
such reclassification would not affect the company's total assets, net worth,
cash flows or results of operations. A reclassification could negatively impact
one of the company's debt covenants and certain contractual obligations that
require the company to maintain a certain level of tangible net worth, absent
waiver or amendment of such provisions. These mineral rights would continue to
be amortized in accordance with FAS No. 19. At December 31, 2003 and 2002, the
company had total producing leasehold costs for mineral interests of
approximately $1.6 billion, net of accumulated depletion and amortization, and
nonproducing leasehold costs of approximately $.5 billion, net of accumulated
depletion and amortization. Of these amounts, leasehold costs, net of
accumulated depletion and amortization, acquired in business combinations since
the effective date of FAS No. 141 were approximately $1.3 billion and $1.4
billion of producing leasehold costs at December 31, 2003 and 2002,
respectively, and $.1 billion of nonproducing leasehold costs at both December
31, 2003 and 2002.
Item 7a. Quantitative and Qualitative Disclosure about Market Risk
For information required under this section, reference is made to the "Market
Risks" section of Management's Discussion and Analysis, which discussion is
included in Item 7. of this Form 10-K.
Item 8. Financial Statements and Supplementary Data
Index to the Consolidated Financial Statements PAGE
- ---------------------------------------------- ----
Responsibility for Financial Reporting 57
Report of Independent Auditors 58
Consolidated Statement of Operations for the years ended
December 31, 2003, 2002 and 2001 59
Consolidated Statement of Comprehensive Income
and Stockholders' Equity for the years ended
December 31, 2003, 2002 and 2001 60
Consolidated Balance Sheet at December 31, 2003 and 2002 61
Consolidated Statement of Cash Flows for the years ended
December 31, 2003, 2002 and 2001 62
Notes to Financial Statements 63
Index to Supplementary Data
- ---------------------------
Ten-Year Financial Summary 117
Ten-Year Operating Summary 118
Index to the Financial Statement Schedules
- ------------------------------------------
Schedule II - Valuation Accounts and Reserves 126
All other schedules are omitted because they are either not required, not
significant, not applicable or the information is presented in the financial
statements or the notes to the financial statements.
- --------------------------------------------------------------------------------
Responsibility for Financial Reporting
The company's management is responsible for the integrity and objectivity of the
financial data contained in the financial statements. These financial statements
have been prepared in conformity with generally accepted accounting principles
appropriate under the circumstances and, where necessary, reflect informed
judgments and estimates of the effects of certain events and transactions based
on currently available information at the date the financial statements were
prepared.
The company's management depends on the company's system of internal accounting
controls to assure itself of the reliability of the financial statements. The
internal control system is designed to provide reasonable assurance, at
appropriate cost, that assets are safeguarded and transactions are executed in
accordance with management's authorizations and are recorded properly to permit
the preparation of financial statements in accordance with generally accepted
accounting principles. Periodic reviews are made of internal controls by the
company's staff of internal auditors, and corrective action is taken if needed.
The Board of Directors reviews and monitors financial statements through its
audit committee, which is composed solely of directors who are not officers or
employees of the company and who satisfy the independence requirements of the
Securities and Exchange Commission and the New York Stock Exchange. The audit
committee meets regularly with the independent auditors, internal auditors and
management to review internal accounting controls, auditing and financial
reporting matters.
The independent auditors are engaged to provide an objective and independent
review of the company's financial statements and to express an opinion thereon.
Their audits are conducted in accordance with generally accepted auditing
standards, and their report is included below.
- --------------------------------------------------------------------------------
Report of Independent Auditors
The Board of Directors and Stockholders
Kerr-McGee Corporation
We have audited the accompanying consolidated balance sheets of Kerr-McGee
Corporation as of December 31, 2003 and 2002, and the related consolidated
statements of operations, comprehensive income and stockholders' equity, and
cash flows for each of the three years in the period ended December 31, 2003.
Our audits also included the financial statement schedule listed in the Index in
Item 8. These financial statements and schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Kerr-McGee
Corporation at December 31, 2003 and 2002, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2003, in conformity with accounting principles generally accepted
in the United States. Also, in our opinion, the related financial statement
schedule, when considered in relation to the basic financial statements taken as
a whole, presents fairly in all material respects the information set forth
therein.
As discussed in Notes 1 and 13 to the consolidated financial statements,
effective January 1, 2003, the Company adopted Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement Obligations. As discussed in
Notes 1, 9 and 17 to the consolidated financial statements, effective December
31, 2003, the Company adopted FASB Interpretation No. 46, Consolidation of
Variable Interest Entities. As discussed in Notes 1 and 18 to the consolidated
financial statements, effective January 1, 2001, the Company adopted Statement
of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities.
/s/ ERNST & YOUNG LLP
Oklahoma City, Oklahoma
March 3, 2004
Consolidated Statement of Operations
- -------------------------------------------------------------------------------------------------------------------------------
(Millions of dollars,
except per-share amounts) 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------------
Revenues $4,185 $3,646 $3,555
------ ------ ------
Costs and Expenses
Costs and operating expenses 1,668 1,456 1,264
Selling, general and administrative expenses 371 313 228
Shipping and handling expenses 140 125 111
Depreciation and depletion 745 814 747
Accretion expense 25 - -
Impairments on assets held for use 14 652 76
Loss (gain) associated with assets held for sale (45) 176 -
Exploration, including dry holes and
amortization of undeveloped leases 354 273 210
Taxes, other than income taxes 98 104 114
Provision for environmental remediation and restoration,
net of reimbursements 62 80 82
Interest and debt expense 251 275 195
------ ------ ------
Total Costs and Expenses 3,683 4,268 3,027
------ ------ ------
502 (622) 528
Other Income (Expense) (59) (35) 224
------ ------ ------
Income (Loss) from Continuing Operations
before Income Taxes 443 (657) 752
Benefit (Provision) for Income Taxes (189) 46 (276)
------ ------ ------
Income (Loss) from Continuing Operations 254 (611) 476
Income from Discontinued Operations, including tax expense
(benefit) of $(22) in 2002 and $22 in 2001 - 126 30
Cumulative Effect of Change in Accounting Principle,
including tax benefit of $18 in 2003 and $11 in 2001 (35) - (20)
------ ------ ------
Net Income (Loss) $ 219 $ (485) $ 486
====== ====== ======
Income (Loss) per Common Share
Basic -
Continuing operations $ 2.52 $(6.09) $ 4.91
Discontinued operations - 1.25 .31
Cumulative effect of accounting change (.34) - (.21)
------ ------ ------
Net income (loss) $ 2.18 $(4.84) $ 5.01
====== ====== ======
Diluted -
Continuing operations $ 2.48 $(6.09) $ 4.65
Discontinued operations - 1.25 .28
Cumulative effect of accounting change (.31) - (.19)
------ ------ ------
Net income (loss) $ 2.17 $(4.84) $ 4.74
====== ====== ======
The accompanying notes are an integral part of this statement.
Consolidated Statement of Comprehensive Income and Stockholders' Equity
- ------------------------------------------------------------------------------------------------------------------------------------
Accumulated
Capital in Other Deferred Total
Comprehensive Common Excess of Retained Comprehensive Treasury Compensation Stockholders'
(Millions of dollars) Income (Loss) Stock Par Value Earnings Income (Loss) Stock and Other Equity
- ------------------------------------------------------------------------------------------------------------------------------------
Balance December 31, 2000 $101 $1,660 $1,233 $ 113 $(383) $(91) $2,633
Net income $ 486 - - 486 - - - 486
Unrealized losses on securities,
net of $12 tax benefit (22) - - - (22) - - (22)
Reclassification of unrealized
gains on securities to net
income, net of $63 tax provision (118) - - - (118) - - (118)
Record fair value of cash flow
hedges, net of $1 tax benefit (3) - - - (3) - - (3)
Change in fair value of cash
flow hedges, net of $5 tax benefit (15) - - - (15) - - (15)
Foreign currency translation
adjustment (17) - - - (17) - - (17)
Minimum pension liability
adjustment, net of $1 tax benefit (2) - - - (2) - - (2)
Shares issued - 6 382 - - - - 388
Treasury stock cancelled - (7) (371) - - 378 - -
Dividends declared ($1.80 per share) - - - (176) - - - (176)
Other - - 5 - - 5 10 20
----- ---- ------ ------ ----- ----- ----- -------
Total $ 309
=====
Balance December 31, 2001 100 1,676 1,543 (64) - (81) 3,174
Net loss $(485) - - (485) - - - (485)
Unrealized gains on securities,
net of $4 tax provision 7 - - - 7 - - 7
Change in fair value of cash
flow hedges, net of $23 tax benefit (39) - - - (39) - - (39)
Foreign currency translation
adjustment 48 - - - 48 - - 48
Minimum pension liability
adjustment, net of $9 tax benefit (14) - - - (14) - - (14)
Shares issued - - 5 - - - - 5
Dividends declared ($1.80 per share) - - - (181) - - - (181)
Other - - 6 9 - - 6 21
----- ---- ------ ------ ----- ----- ----- -------
Total $(483)
=====
Balance December 31, 2002 100 1,687 886 (62) (1) - (75) 2,536
Net income $ 219 - - 219 - - - 219
Unrealized gains on securities of $6
and reclassification of realized
gains of $(7), net of tax provision (1) - - - (1) - - (1)
Change in fair value of cash
flow hedges, net of $35 tax benefit (31) - - - (31) - - (31)
Foreign currency translation
adjustment 56 - - - 56 - - 56
Minimum pension liability
adjustment, net of $5 tax benefit (7) - - - (7) - - (7)
Shares issued - - 1 - - - - 1
Restricted stock activity - 1 21 - - (1) (10) 11
ESOP deferred compensation - - - - - - 32 32
Dividends declared ($1.80 per share) - - - (182) - - - (182)
Other - - (1) 4 - (1) - 2
----- ---- ------ ------ ----- ----- ----- -------
Total $ 236
=====
Balance December 31, 2003 $101 $1,708 $ 927 $ (45) (1) $ (2) $ (53) $2,636
==== ====== ====== ===== ===== ===== ======
(1) The balance of the items in Accumulated Other Comprehensive Income (Loss)
at December 31, 2003 and 2002, includes - unrealized gains on securities,
$5 million and $6 million; fair value of cash flow hedges, $(88) million
and $(57) million; foreign currency translation adjustments, $62 million
and $6 million; and minimum pension liability, $(24) million and $(17)
million, respectively.
The accompanying notes are an integral part of this statement.
Consolidated Balance Sheet
- ------------------------------------------------------------------------------------------------------
(Millions of dollars) 2003 2002
- ------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash $ 142 $ 90
Accounts receivable, net of allowance for doubtful
accounts of $10 in 2003 and 2002 583 608
Inventories 394 402
Investment in equity securities 510 -
Deposits, prepaid expenses and other assets 127 133
Current assets associated with properties held for disposal 1 57
------- ------
Total Current Assets 1,757 1,290
Investments
Equity affiliates 123 123
Investment in equity securities - 457
Other assets 125 127
Property, Plant and Equipment - Net 7,467 7,036
Deferred Charges 317 328
Goodwill 357 356
Long-Term Assets Associated with Properties
Held for Disposal 28 192
------- ------
Total Assets $10,174 $9,909
======= ======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 735 $ 772
Long-term debt due within one year 574 106
Taxes on income 127 170
Taxes, other than income taxes 37 40
Accrued liabilities 759 520
Current liabilities associated with properties held for disposal - 2
------- ------
Total Current Liabilities 2,232 1,610
------- ------
Long-Term Debt 3,081 3,798
------- ------
Deferred Credits and Reserves
Income taxes 1,259 1,145
Asset retirement obligations 401 222
Other 565 582
------- ------
Total Deferred Credits and Reserves 2,225 1,949
------- ------
Long-Term Liabilities Associated with Properties
Held for Disposal - 16
------- ------
Stockholders' Equity
Common stock, par value $1.00 - 300,000,000 shares authorized,
100,892,354 shares issued in 2003
and 100,391,054 shares issued in 2002 101 100
Capital in excess of par value 1,708 1,687
Preferred stock purchase rights 1 1
Retained earnings 927 886
Accumulated other comprehensive loss (45) (62)
Common stock in treasury, at cost - 31,924 shares
in 2003 and 7,299 shares in 2002 (2) -
Deferred compensation (54) (76)
------- ------
Total Stockholders' Equity 2,636 2,536
------- ------
Total Liabilities and Stockholders' Equity $10,174 $9,909
======= ======
The "successful efforts" method of accounting for oil and gas exploration and
production activities has been followed in preparing this balance sheet.
The accompanying notes are an integral part of this balance sheet.
Consolidated Statement of Cash Flows
- -------------------------------------------------------------------------------------------------------------------------------
(Millions of dollars) 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------------
Cash Flow from Operating Activities
Net income (loss) $ 219 $ (485) $ 486
Adjustments to reconcile to net cash
provided by operating activities -
Depreciation, depletion and amortization 814 884 813
Accretion expense 25 - -
Deferred income taxes 156 (112) 205
Dry hole costs 181 113 72
Impairments on assets held for use 14 652 76
(Gain) loss associated with assets held for sale (39) 210 -
Cumulative effect of change in accounting principle 35 - 20
Provision for environmental remediation
and restoration, net of reimbursements 62 89 82
Gains on asset retirements and sales (1) (110) (12)
Noncash items affecting net income 144 100 (189)
Changes in current assets and liabilities
and other, net of effects of operations acquired-
(Increase) decrease in accounts receivable 60 (104) 278
(Increase) decrease in inventories 22 37 (51)
(Increase) decrease in deposits,
prepaids and other assets 12 185 (201)
Increase (decrease) in accounts
payable and accrued liabilities (89) 137 (131)
Increase (decrease) in taxes payable 66 49 (132)
Other (163) (197) (173)
------ ------ ------
Net cash provided by operating activities 1,518 1,448 1,143
------ ------ ------
Cash Flow from Investing Activities
Capital expenditures (981) (1,159) (1,792)
Dry hole costs (181) (113) (72)
Acquisitions (110) (24) (978)
Purchase of long-term investments (39) (65) (92)
Proceeds from sale of long-term investments 50 12 18
Proceeds from sale of assets 304 756 19
Other investing activities 6 - -
------ ------ ------
Net cash used in investing activities (951) (593) (2,897)
------ ------ ------
Cash Flow from Financing Activities
Issuance of long-term debt 31 418 2,513
Issuance of common stock - 5 32
Decrease in short-term borrowings - (8) (9)
Repayment of long-term debt (369) (1,093) (661)
Dividends paid (181) (181) (173)
Other financing activities (1) - -
------ ------ ------
Net cash provided by (used in) financing activities (520) (859) 1,702
------ ------ ------
Effects of Exchange Rate Changes on Cash and Cash Equivalents 5 3 (1)
------ ------ ------
Net Increase (Decrease) in Cash and Cash Equivalents 52 (1) (53)
Cash and Cash Equivalents at Beginning of Year 90 91 144
------ ------ ------
Cash and Cash Equivalents at End of Year $ 142 $ 90 $ 91
====== ====== ======
The accompanying notes are an integral part of this statement.
Notes to Financial Statements
- --------------------------------------------------------------------------------
1. The Company and Significant Accounting Policies
Kerr-McGee is an energy and chemical company with worldwide operations. It
explores for, develops, produces and markets crude oil and natural gas, and its
chemical operations primarily produce and market titanium dioxide pigment. The
exploration and production unit produces and explores for oil and gas in the
United States, the United Kingdom sector of the North Sea and China. Exploration
efforts also extend to Australia, Benin, Bahamas, Brazil, Gabon, Morocco,
Western Sahara, Canada, Yemen and the Danish and Norwegian sectors of the North
Sea. The chemical unit has production facilities in the United States,
Australia, Germany and the Netherlands.
On August 1, 2001, the company completed the acquisition of all the outstanding
shares of common stock of HS Resources, Inc., an independent oil and gas
exploration and production company. To accomplish the acquisition, the company
reorganized and formed a new holding company, Kerr-McGee Holdco, which later
changed its name to Kerr-McGee Corporation. All the outstanding shares of the
former Kerr-McGee Corporation were canceled and the same number of shares was
issued by the new holding company. The former Kerr-McGee Corporation was renamed
and is now a wholly owned subsidiary.
Basis of Presentation
The consolidated financial statements include the accounts of all subsidiary
companies that are more than 50% owned, the proportionate share of joint
ventures in which the company has an undivided interest and variable interest
entities for which the company is considered the primary beneficiary.
Investments in affiliated companies that are 20% to 50% owned are carried as
investments - equity affiliates in the Consolidated Balance Sheet at cost
adjusted for equity in undistributed earnings. Except for dividends and changes
in ownership interest, changes in equity in undistributed earnings are included
in the Consolidated Statement of Operations. All material intercompany
transactions have been eliminated.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial statements, and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates as additional information
becomes known.
Discontinued operations in the consolidated financial statements represent the
company's former oil and gas operations in Kazakhstan, Indonesia and Australia
(see Note 21).
Variable Interest Entities
In January 2003, the Financial Accounting Standards Board (FASB) issued FASB
Interpretation (FIN) No. 46, "Consolidation of Variable Interest Entities - an
Interpretation of ARB No. 51." This interpretation clarifies the application of
Accounting Research Bulletin (ARB) 51, "Consolidated Financial Statements," to
certain entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. Because application of the majority voting interest
requirement in ARB 51 may not identify the party with a controlling financial
interest in situations where controlling financial interest is achieved through
arrangements not involving voting interests, this interpretation introduces the
concept of variable interests. Consolidation is required by an enterprise having
variable interests in a previously unconsolidated entity if the enterprise is
considered the primary beneficiary, meaning the enterprise will absorb a
majority of the variable interest entity's expected losses or residual returns.
For variable interest entities in existence as of February 1, 2003, FIN 46, as
originally issued, required consolidation by the primary beneficiary in the
third quarter of 2003. In October 2003, the FASB deferred the effective date of
FIN 46 to December 31, 2003.
In accordance with the provisions of FIN 46, the company has consolidated the
business trust created to construct and finance the Gunnison production
platform. Accordingly, the assets and liabilities of the trust are reflected in
the company's Consolidated Balance Sheet at December 31, 2003, which includes
$83 million in property, plant and equipment, $4 million in accrued liabilities,
$75 million in long-term debt and $4 million in minority interest (See Notes 9
and 17). The company has reviewed the effects of FIN 46 relative to its other
relationships with possible variable interest entities, such as the lessor
trusts that are party to the Nansen and Boomvang operating leases and certain
joint-venture arrangements, and has determined that consolidation of these
entities is not required.
Reclassifications
Certain prior year amounts have been reclassified to conform with the current
year presentation.
In 2003, the company began reporting the net marketing fee received from sales
of nonequity North Sea crude oil marketed on behalf of other partners in
revenues. Prior to 2003, the company reported purchases and sales of nonequity
crude oil on a gross basis. The company believes this change in reporting, which
has no impact on net income, better reflects the economic substance of its North
Sea marketing arrangements. For 2002 and 2001, the company has reclassified $54
million and $11 million, respectively, from costs and operating expenses to
reduce revenues in the Consolidated Statement of Operations to conform with the
2003 presentation.
In connection with the adoption of the Statement of Financial Accounting
Standards (FAS) No. 143, "Accounting for Asset Retirement Obligations,"
abandonment expense of $40 million for 2002 and $34 million for 2001 has been
reclassified from costs and operating expenses to depreciation and depletion in
the Consolidated Statement of Operations. This new standard is discussed in more
detail below.
Foreign Currencies
The U.S. dollar is considered the functional currency for each of the company's
international operations, except for its European chemical operations. Foreign
currency transaction gains or losses are recognized in the period incurred and
are included in other income (expense) in the Consolidated Statement of
Operations. The company recorded net foreign currency transaction gains (losses)
of $(41) million, $(38) million and $3 million in 2003, 2002 and 2001,
respectively.
The euro is the functional currency for the European chemical operations.
Translation adjustments resulting from translating the functional currency
financial statements into U.S. dollar equivalents are reported separately in
accumulated other comprehensive income in the Consolidated Statement of
Comprehensive Income and Stockholders' Equity.
Cash Equivalents
The company considers all investments with a maturity of three months or less to
be cash equivalents. Cash equivalents totaling $72 million in 2003 and $23
million in 2002 were comprised of time deposits, certificates of deposit and
U.S. government securities.
Accounts Receivable and Receivable Sales
Accounts receivable are reflected at their net realizable value, reduced by an
allowance for doubtful accounts to allow for expected credit losses. The
allowance is estimated by management based on factors such as age of the related
receivables and historical experience, giving consideration to customer
profiles. The company does not generally charge interest on accounts receivable;
however, certain operating agreements have provisions for interest and penalties
that may be invoked if deemed necessary. Accounts receivable are aged in
accordance with contract terms and are written off when deemed uncollectible.
Any subsequent recoveries of amounts written off are credited to the allowance
for doubtful accounts.
Under an asset securitization program, Kerr-McGee sells selected pigment
customers' accounts receivable to a variable interest entity (VIE). The company
does not own any of the common stock of the VIE. When the receivables are sold,
Kerr-McGee retains an interest in excess receivables that serve as
over-collateralization for the program and retains interests for servicing and
in preference stock of the VIE. The interest in the preference stock is
essentially a deposit to provide further credit enhancement to the
securitization program, if needed, but is otherwise recoverable by the company
at the end of the program. The servicing fee received is estimated by management
to be adequate compensation and is equal to what would otherwise be charged by
an outside servicing agent. The company records the loss associated with the
receivable sales by comparing cash received and fair value of the retained
interests to the carrying amount of the receivables sold. The estimate of fair
value of the retained interests is based on the present value of future cash
flows discounted at rates estimated by management to be commensurate with the
risks.
Inventories
Inventories are stated at the lower of cost or market. The costs of the
company's product inventories are determined by the first-in, first-out (FIFO)
method. Inventory carrying values include material costs, labor and associated
indirect manufacturing expenses. Costs for materials and supplies, excluding
ore, are determined by average cost to acquire. Ore inventories are carried at
actual cost.
Property, Plant and Equipment
Exploration and Production - Exploration expenses, including geological and
geophysical costs, rentals and exploratory dry holes, are charged against income
as incurred. Costs of drilling exploratory wells are capitalized pending
determination of whether proved reserves can be attributed to the discovery.
Capitalized costs associated with exploratory wells may be charged to earnings
in a future period if management determines that commercial quantities of
hydrocarbons have not been discovered. At December 31, 2003, the company had
capitalized costs of approximately $143 million associated with such ongoing
exploration activities, primarily in the deepwater Gulf of Mexico and China.
Costs of successful wells and related production equipment and developmental dry
holes are capitalized and amortized by field using the unit-of-production method
as the oil and gas are produced.
Undeveloped acreage costs are capitalized and amortized at rates that provide
full amortization on abandonment of unproductive leases. Costs of abandoned
leases are charged to the accumulated amortization accounts, and costs of
productive leases are transferred to the developed property accounts.
Other - Property, plant and equipment is stated at cost less reserves for
depreciation, depletion and amortization. Maintenance and repairs are expensed
as incurred, except that costs of replacements or renewals that improve or
extend the lives of existing properties are capitalized.
Depreciation and Depletion - Property, plant and equipment is depreciated or
depleted over its estimated life by the unit-of-production or the straight-line
method. Capitalized exploratory drilling and development costs are amortized
using the unit-of-production method based on total estimated proved developed
oil and gas reserves. Amortization of producing leasehold, platform costs, asset
retirement costs and acquisition costs of proved properties is based on the
unit-of-production method using total estimated proved reserves. In arriving at
rates under the unit-of-production method, the quantities of recoverable oil,
gas and other minerals are established based on estimates made by the company's
geologists and engineers. Non-oil and gas assets are depreciated using the
straight-line method over the estimated useful lives.
Retirements and Sales - The cost and related depreciation, depletion and
amortization reserves are removed from the respective accounts upon retirement
or sale of property, plant and equipment. The resulting gain or loss is included
in other income (expense) in the Consolidated Statement of Operations.
Interest Capitalized - The company capitalizes interest costs on major projects
that require an extended length of time to complete. Interest capitalized in
2003, 2002 and 2001 was $10 million, $8 million and $31 million, respectively.
Impairments on Assets Held for Use
Proved oil and gas properties are reviewed for impairment on a field-by-field
basis when facts and circumstances indicate that their carrying amounts may not
be recoverable. In performing this review, future cash flows are estimated by
applying future oil and gas prices to future production quantities, less future
expenditures necessary to develop and produce the reserves. If the sum of these
estimated future cash flows (undiscounted and without interest charges) is less
than the carrying amount of the property, an impairment loss is recognized for
the excess of the carrying amount over the estimated fair value of the property
based on estimated discounted future cash flows.
Other assets are reviewed for impairment by asset group for which the lowest
level of independent cash flows can be identified and impaired in a similar
manner as proved oil and gas properties.
Gain or Loss on Assets Held for Sale
Assets are classified as held for sale when management approves a plan of sale
that is expected to be completed within one year. Upon transfer to the
held-for-sale category, long-lived assets are no longer depreciated. Losses are
measured at the time of transfer, and subsequently thereafter, as the difference
between fair value less costs to sell and the assets' carrying value. Losses may
be reversed up to the original carrying value as estimates are revised; however,
any gain above the assets' carrying value at the date of transfer is only
recognized upon disposition.
Revenue Recognition
Revenue is recognized when title passes to the customer. Natural gas sales
revenues involving gas-balancing arrangements with partners are recognized when
the gas is sold using the entitlements method of accounting and are based on the
company's net working interests. At December 31, 2003 and 2002, both the
quantity and dollar amount of gas-balancing arrangements were immaterial.
Income Taxes
Deferred income taxes are provided to reflect the future tax consequences of
differences between the tax basis of assets and liabilities and their reported
amounts in the financial statements.
Remediation, Restoration and Site Dismantlement Costs
As sites of environmental concern are identified, the company assesses the
existing conditions, claims and assertions, generally related to former
operations, and records an estimated undiscounted liability when environmental
assessments and/or remedial efforts are probable and the associated costs can be
reasonably estimated.
In June 2001, the FASB issued FAS No. 143, "Accounting for Asset Retirement
Obligations." FAS 143 requires that an asset retirement obligation (ARO)
associated with the retirement of a tangible long-lived asset be recognized as a
liability in the period in which it is incurred or becomes determinable (as
defined by the standard), with an associated increase in the carrying amount of
the related long-lived asset. The cost of the tangible asset, including the
initially recognized asset retirement cost, is depreciated over the useful life
of the asset. The ARO is recorded at fair value, and accretion expense will be
recognized over time as the discounted liability is accreted to its expected
settlement value. The fair value of the ARO is measured using expected future
cash outflows discounted at the company's credit-adjusted risk-free interest
rate.
The company adopted FAS 143 on January 1, 2003, which resulted in an increase in
net property of $108 million, an increase in abandonment liabilities of $161
million and a decrease in deferred income tax liabilities of $18 million. The
net impact of these changes resulted in an after-tax charge to earnings of $35
million to recognize the cumulative effect of adopting the new accounting
standard. In addition, accretion expense of $25 million was recorded during
2003. In accordance with the provisions of FAS 143, Kerr-McGee accrues an
abandonment liability associated with its oil and gas wells and platforms when
those assets are placed in service, rather than its past practice of accruing
the expected abandonment costs on a unit-of-production basis over the productive
life of the associated oil and gas field. No market risk premium has been
included in the company's calculation of the ARO for oil and gas wells and
platforms since no reliable estimate can be made by the company. Additionally,
in January 2003, the company announced its plan to close the synthetic rutile
plant in Mobile, Alabama, and closed the plant in June 2003. Since the plant had
a determinate closure date, the company accrued an abandonment liability of $18
million as of January 1, 2003, associated with its plans to decommission the
Mobile facility. Otherwise, the company has not recognized an asset retirement
obligation associated with its operating chemical facilities, since there is
either no legal obligation or the life of such facilities is indeterminate.
If the provisions of FAS 143 had been applied retroactively, pro forma net loss
for 2002 would have been $492 million, with basic and diluted loss per share of
$4.91. Pro forma net income for 2001 would have been $484 million, with basic
and diluted earnings per share of $4.98 and $4.72, respectively.
Employee Stock Option Plan
FAS 123, "Accounting for Stock-Based Compensation," prescribes a fair-value
method of accounting for employee stock options under which compensation expense
is measured based on the estimated fair value of stock options at the grant date
and recognized over the period that the options vest. The company, however,
chooses to account for its stock option plans under the optional intrinsic-value
method of Accounting Principles Board Opinion (APB) No. 25, "Accounting for
Stock Issued to Employees," whereby no compensation expense is generally
recognized for fixed-price stock options.
If compensation expense for stock option grants had been determined in
accordance with FAS 123, the resulting expense would have affected stock-based
compensation expense, net income and per-share amounts as shown in the following
table. These amounts may not be representative of future compensation expense
using the fair-value method of accounting for employee stock options as the
number of options granted in a particular year may not be indicative of the
number of options granted in future years, and the fair-value method of
accounting has not been applied to options granted prior to January 1, 1995.
(Millions of dollars,
except per-share amounts) 2003 2002 2001
- --------------------------------------------------------------------------------
Net income (loss) as reported $ 219 $ (485) $ 486
Less stock-based compensation
expense determined using a
fair-value method, net of taxes (16) (15) (8)
----- ------ -----
Pro forma net income (loss) $ 203 $ (500) $ 478
===== ====== =====
Net income (loss) per share -
Basic -
As reported $2.18 $(4.84) $5.01
Pro forma 2.03 (4.99) 4.92
Diluted -
As reported 2.17 (4.84) 4.74
Pro forma 2.03 (4.99) 4.66
The fair value of each option granted in 2003, 2002 and 2001 was estimated as of
the date of the grant using the Black-Scholes option pricing model with the
following weighted-average assumptions:
Assumptions
------------------------------------------------------------------------------- Weighted-Average
Risk-Free Expected Expected Expected Fair Value of
Interest Rate Dividend Yield Life (years) Volatility Options Granted
- -------------------------------------------------------------------------------------------------------------------
2003 3.6% 3.3% 5.8 32.7% $11.09
2002 4.8 3.4 5.8 36.0 16.97
2001 5.0 3.3 5.8 42.9 22.54
Financial Instruments
Investments in marketable securities are classified as either "trading" or
"available for sale," depending on management's intent. Unrecognized gains or
losses on trading securities are recognized in earnings, while unrecognized
gains or losses on available-for-sale securities are recorded as a component of
other comprehensive income (loss) within stockholders' equity.
The company accounts for all its derivative financial instruments in accordance
with FAS 133, "Accounting for Derivative Instruments and Hedging Activities."
Derivative financial instruments are recorded as assets or liabilities in the
Consolidated Balance Sheet, measured at fair value. When available, quoted
market prices are used in determining fair value; however, if quoted market
prices are not available, the company estimates fair value using either quoted
market prices of financial instruments with similar characteristics or other
valuation techniques.
The company uses futures, forwards, options, collars and swaps to reduce the
effects of fluctuations in crude oil, natural gas, foreign currency exchange
rates and interest rates. Gains or losses due to changes in the fair value of
instruments that are designated as cash flow hedges and that qualify for hedge
accounting under the provisions of FAS 133 are recorded in accumulated other
comprehensive income (loss). These hedging gains or losses will be recognized in
earnings in the periods during which the hedged forecasted transactions affect
earnings. The ineffective portion of the change in fair value of such hedges, if
any, is included in current earnings. Instruments that are not designated as
hedges or that do not meet the criteria for hedge accounting and those
designated as fair-value hedges under FAS 133 are recorded at fair value with
gains or losses reported currently in earnings (together with offsetting gains
or losses on the hedged item for fair value hedges).
On January 1, 2001, the company adopted FAS 133 by recording the fair value of
the options associated with the company's debt exchangeable for stock (DECS) of
Devon Energy Corporation (Devon). In adopting the standard, the company
recognized an expense of $20 million as a cumulative effect of the accounting
change and a $3 million reduction in equity (other comprehensive income) for the
foreign currency contracts designated as hedges. Also, in accordance with FAS
133, the company chose to reclassify 85% of the Devon shares owned to "trading"
from the "available for sale" category of investments as of January 1, 2001, and
recognized after-tax income of $118 million for the unrealized appreciation on
these shares.
Shipping and Handling Fees and Costs
All amounts billed to a customer in a sales transaction related to shipping and
handling represent revenues earned and are reported as revenue. Costs incurred
by the company for shipping and handling, including transportation costs paid to
third-party shippers to transport oil and gas production, are reported as an
expense.
Goodwill and Intangible Assets
In accordance with FAS 142, "Goodwill and Other Intangible Assets," which the
company adopted on January 1, 2002, goodwill and certain indefinite-lived
intangibles are not amortized but are reviewed annually for impairment, or more
frequently if impairment indicators arise. The annual test for impairment was
completed in the second quarter of 2003, with no impairment indicated for the
$357 million of goodwill ($346 million, exploration and production; $11 million,
chemical - pigment) or the $55 million of indefinite-lived intangible assets
(chemical - pigment) associated with patented technology and other intellectual
property. The company's net income for 2001 would not have been materially
different had the indefinite-lived intangibles and goodwill not been amortized
prior to adoption of FAS 142. Additionally, the company had immaterial amounts
of intangibles subject to amortization ($19 million gross carrying value at
December 31, 2003 and 2002; $9 million and $14 million net of accumulated
amortization at December 31, 2003 and 2002, respectively).
2. Cash Flow Information
Net cash provided by operating activities reflects cash payments for income
taxes and interest as follows:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Income tax payments $115 $ 89 $434
Less refunds received (49) (268) (19)
---- ----- ----
Net income tax payments (refunds) $ 66 $(179) $415
==== ===== ====
Interest payments $237 $ 258 $189
==== ===== ====
Noncash items affecting net income included in the reconciliation of net income
to net cash provided by operating activities include the following:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Increase (decrease) in fair value of
embedded options in the DECS (1) $ 88 $ 34 $(205)
(Increase) decrease in fair value of
trading securities (1) (96) (61) 7
Performance incentive provisions 33 16 27
Compensation expense for ESOP shares
allocated to participants 32 14 14
Net periodic postretirement expense 30 21 18
Net losses on equity method investments 33 25 5
Litigation reserve provisions 7 72 -
Net periodic pension credit for qualified plan (2) - (48) (53)
All other (3) 17 27 (2)
---- ---- -----
Total $144 $100 $(189)
==== ==== =====
Details of other changes in current assets and liabilities and other within the
operating section of the Consolidated Statement of Cash Flows are as follows:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Environmental expenditures $(104) $(107) $(94)
Cash abandonment expenditures - exploration
and production (17) (48) (29)
Employer contributions to postretirement plan (24) (18) (20)
All other (3) (18) (24) (30)
----- ----- -----
Total $(163) $(197) $(173)
===== ===== =====
Information about noncash investing and financing activities not reflected in
the Consolidated Statement of Cash Flows follows:
(Millions of dollars) 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------
Noncash investing activities
Increase (decrease) in fair value of securities available for sale (1) $ 9 $11 $ (34)
Increase (decrease) in fair value of trading securities (1) 96 61 (188)
Investment in equity affiliate - 2 -
Increase in property related to consolidation of Gunnison trust (4) 83 - -
Noncash financing activities
Common stock issued in HS Resources acquisition - - 355
Debt assumed in HS Resources acquisition - - 506
Debt assumed in relation to consolidation of Gunnison Trust (4) 75 - -
Increase in the valuation of the DECS (1) 8 8 8
Increase (decrease) in fair value of embedded options in
the DECS (1) 88 34 (205)
Dividends declared but not paid - - 3
(1) See Notes 1 and 18 for discussion of FAS 133 adoption.
(2) Net periodic pension credit for 2003 of $(38) million is reflected net of
curtailment losses of $38 million.
(3) No other individual item is material to total cash flows from operations.
(4) See Note 1 for a discussion of the adoption of FIN 46.
3. Inventories
Major categories of inventories at year-end 2003 and 2002 are:
(Millions of dollars) 2003 2002
- --------------------------------------------------------------------------------
Chemicals and other products $307 $306
Materials and supplies 80 89
Crude oil and natural gas liquids 7 7
---- ----
Total $394 $402
==== ====
4. Investments - Other Assets
Investments in other assets consist of the following at December 31, 2003 and
2002:
(Millions of dollars) 2003 2002
- --------------------------------------------------------------------------------
Long-term receivables, net of allowance for
doubtful notes of $9 in both 2003 and 2002 $101 $ 94
Derivatives (fixed-price and basis swap
commodity contracts) 17 22
Other 7 11
---- ----
Total $125 $127
==== ====
5. Property, Plant and Equipment
Property, plant and equipment and related reserves at December 31, 2003 and
2002, are as follows:
Reserves for
Depreciation and
Gross Property Depletion Net Property
---------------------- ------------------- ---------------------
(Millions of dollars) 2003 2002 2003 2002 2003 2002
- --------------------------------------------------------------------------------------------------------------------
Exploration and production $12,087 $11,585 $5,719 $5,632 $6,368 $5,953
Chemicals 2,082 1,963 1,068 965 1,014 998
Other 184 176 99 91 85 85
------- ------- ------ ------ ------ ------
Total $14,353 $13,724 $6,886 $6,688 $7,467 $7,036
======= ======= ====== ====== ====== ======
The company applies the provisions of FAS No. 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies," for the accounting of oil and gas
mineral rights held by lease or contract and accordingly classifies these assets
as property, plant and equipment. This classification is the long standing and
current industry standard and is consistent with most mineral rights case law
(that is, mineral rights generally are treated as interests in real property and
real property laws are used to interpret the leases). However, the U.S.
Securities and Exchange Commission has asked that the Emerging Issues Task Force
(EITF) consider whether mineral rights are intangible assets under the guidance
provided by FAS No. 141, "Business Combinations," and FAS No. 142, "Goodwill and
Other Intangible Assets." If such interests are deemed to be intangible assets
by the EITF, mineral rights to extract oil and gas for both undeveloped and
developed leaseholds may be reclassified separately as intangible assets.
Even though management believes the company's current balance sheet
classification is required under generally accepted accounting principles,
reclassification may be necessary in the future when further guidance is
provided by the EITF. However, it is not currently clear which mineral rights
might have to be reclassified as intangible assets - all producing and
nonproducing leaseholds, only nonproducing leaseholds or only leaseholds
acquired in business combinations since the effective date of FAS No. 141. Any
such reclassification would not affect the company's total assets, net worth,
cash flows or results of operations. A reclassification could negatively impact
one of the company's debt covenants and certain contractual obligations that
require the company to maintain a certain level of tangible net worth, absent
waiver or amendment of such provisions. These mineral rights would continue to
be amortized in accordance with FAS No. 19. At December 31, 2003 and 2002, the
company had total producing leasehold costs for mineral interests of
approximately $1.6 billion, net of accumulated depletion and amortization, and
nonproducing leasehold costs of approximately $.5 billion, net of accumulated
depletion and amortization. Of these amounts, leasehold costs, net of
accumulated depletion and amortization, acquired in business combinations since
the effective date of FAS No. 141 were approximately $1.3 billion and $1.4
billion of producing leasehold costs at December 31, 2003 and 2002,
respectively, and $.1 billion of nonproducing leasehold costs at both December
31, 2003 and 2002.
6. Deferred Charges
Deferred charges are as follows at year-end 2003 and 2002:
(Millions of dollars) 2003 2002
- --------------------------------------------------------------------------------
Pension plan prepayments $243 $240
Nonqualified benefit plans deposits 35 35
Unamortized debt issue costs 22 27
Amounts pending recovery from third parties 8 13
Other 9 13
---- ----
Total $317 $328
==== ====
7. Accrued Liabilities
Accrued liabilities at year-end 2003 and 2002 are as follows:
(Millions of dollars) 2003 2002
- --------------------------------------------------------------------------------
Derivatives (1) $354 $135
Employee-related costs and benefits 141 103
Interest payable 109 105
Current environmental reserves 98 100
Asset retirement obligations (current portion) 20 -
Litigation reserves 5 43
North Sea royalties - 13
Other 32 21
---- ----
Total $759 $520
==== ====
(1) Balance at December 31, 2003, includes the call option associated with the
DECS of $155 million (See Note 18).
8. Work Force Reduction, Restructuring Provisions and Exit Activities
In September 2003, the company announced a program to reduce its U.S.
nonbargaining work force through both voluntary retirements and involuntary
terminations. As a result of the program, the company's eligible U.S.
nonbargaining work force was reduced by approximately 9%, or 271 employees.
Qualifying employees terminated under this program are eligible for enhanced
benefits under the company's pension and postretirement plans, along with
severance payments. The program was substantially completed by the end of 2003,
with certain retiring employees staying into the first half of 2004 for
transition purposes. In connection with the work force reduction, the company
took a pretax charge of $56 million during 2003, of which $34 million was for
curtailment and special termination benefits associated with the company's
retirement plans and $22 million was for severance-related costs. The provision
for severance-related costs is included in the restructuring reserve balance
below. Of the severance-related provision of $22 million, $5 million has been
paid through December 31, 2003, with $17 million remaining in the accrual to be
paid in 2004.
The company closed its synthetic rutile plant in Mobile, Alabama, during June
2003. During the year, the company's chemical - pigment operating unit provided
$24 million for costs associated with the closure of this facility. Included in
this amount were $14 million recorded as a cumulative effect of change in
accounting principle related to the recognition of an asset retirement
obligation and $10 million for the accrual of severance benefits. The provision
for severance benefits is included in the restructuring reserve balance below.
See Note 1 for a discussion of the asset retirement obligation. Of the total
severance provision of $10 million, $8 million was paid through the end of the
year and $2 million remained in the accrual at December 31, 2003. Approximately
135 employees will ultimately be terminated in connection with this plant
closure, of which 117 had been terminated as of December 31, 2003. Additionally,
during 2003, the company recognized $15 million in accelerated depreciation on
the plant assets, $6 million for curtailment costs and special termination
benefits related to pension and postretirement plans, $8 million for cleanup and
decommissioning costs associated with the plant, and $8 million for other
shutdown costs.
During 2002, the company's chemical - other operating unit provided $17 million
for costs associated with exiting its forest products business. During 2003, the
company provided an additional $5 million associated with exiting the forest
products business. Included in the total provision of $22 million were $16
million for dismantlement and closure costs, and $6 million for severance costs.
These costs are reflected in costs and operating expenses in the Consolidated
Statement of Operations. Of the total provision, $8 million was paid through
December 31, 2003, and $14 million remained in the accrual as of year-end 2003.
Of its five remaining forest products-treating plants, one has been closed, and
three have ceased operations and are in the process of being dismantled. The
company will continue to operate its fifth plant, a leased facility located in
The Dalles, Oregon, through the term of the lease, which runs through November
30, 2004. In connection with the plant closures, 252 employees will be
terminated, of which 163 were terminated as of year-end 2003. Additionally,
during 2003, the company recognized $9 million for other shutdown related costs,
including accelerated depreciation on plant assets, curtailment costs and
special termination benefits related to pension and postretirement plans.
In 2001, the company's chemical - pigment operating unit provided $32 million
related to the closure of a plant in Antwerp, Belgium. The provision consisted
of $12 million for severance costs, $12 million for dismantlement costs, $7
million for contract settlement costs and $1 million for other plant closure
costs. Of this total accrual, $5 million and $9 million remained in the
restructuring accrual at the end of 2003 and 2002, respectively. As a result of
this plant closure, 121 employees were identified for termination and all have
been terminated as of December 31, 2003.
Also in 2001, the company's chemical - other operating unit provided $12 million
for the discontinuation of manganese metal production at its Hamilton,
Mississippi, facility. The provision consisted of $7 million for pond-closure
costs, $2 million for severance costs and $3 million for other plant-closure
costs. Of this total accrual, $1 million and $2 million remained in the
restructuring accrual at the end of 2003 and 2002, respectively. As a result of
this plant closure, 42 employees were terminated and all related severance costs
were paid in 2001. Completion of the remaining action of pond closure may take
from three to 10 years, depending on environmental constraints.
The provisions, payments, adjustments and reserve balances for 2003 and 2002 are
included in the table below.
2003 2002
--------------------------------------- --------------------------------------
Dismantlement Dismantlement
Personnel and Personnel and
(Millions of dollars) Total Costs Closure Total Costs Closure
- ---------------------------------------------------------------------------------------------------------------------
Beginning balance $ 27 $ 4 $23 $ 28 $ 12 $ 16
Provisions 37 37 - 17 1 16
Payments (1) (22) (16) (6) (20) (10) (10)
Adjustments (2) (3) 2 (5) 2 1 1
---- ---- --- ---- ---- ----
Ending balance $ 39 $ 27 $12 $ 27 $ 4 $ 23
==== ==== === ==== ==== ====
(1) Includes amounts in total provision that were charged directly to expense.
(2) Includes foreign-currency translation adjustments related to Antwerp,
Belgium, accrual.
9. Debt
Lines of Credit
At year-end 2003, the company had available unused bank lines of credit and
revolving credit facilities of $1.4 billion. Of this amount, $870 million can be
used to support commercial paper borrowing arrangements of Kerr-McGee Credit
LLC, and $490 million can be used to support European commercial paper
borrowings of Kerr-McGee (G.B.) PLC, Kerr-McGee Chemical GmbH, Kerr-McGee
Pigments (Holland) B.V. and Kerr-McGee International ApS.
The company has arrangements to maintain compensating balances with certain
banks that provide credit. At year-end 2003, the aggregate amount of such
compensating balances was immaterial, and the company was not legally restricted
from withdrawing all or a portion of such balances at any time during the year.
Long-Term Debt
The company's policy is to classify certain borrowings under revolving credit
facilities and commercial paper as long-term debt since the company has the
ability under certain revolving credit agreements and the intent to maintain
these obligations for longer than one year. At year-end 2003 and 2002, debt
totaling nil and $68 million, respectively, was classified as long-term
consistent with this policy.
Long-term debt consisted of the following at year-end 2003 and 2002:
(Millions of dollars) 2003 2002
- --------------------- ------ ------
Debentures -
7.125% Debentures due October 15, 2027
(7.01% effective rate) $ 150 $ 150
7% Debentures due November 1, 2011, net of
unamortized debt discount of $84 in 2003
and $90 in 2002 (14.25% effective rate) 166 160
5-1/4% Convertible subordinated debentures due
February 15, 2010 (convertible at $61.08 per
share, subject to certain adjustments) 600 600
Notes payable -
5-7/8% Notes due September 15, 2006 (5.89% effective rate) 307 325
6-7/8% Notes due September 15, 2011,
net of unamortized debt discount of $1
in both 2003 and 2002 (6.90% effective rate) 674 674
7-7/8% Notes due September 15, 2031,
net of unamortized debt discount of $2
in both 2003 and 2002 (7.91% effective rate) 498 498
5-1/2% Exchangeable Notes (DECS) due August 2, 2004, net
of unamortized debt discount of $4 in 2003 and
$12 in 2002 (5.60% effective rate) (See Note 18) 326 318
6.625% Notes due October 15, 2007 150 150
8.375% Notes due July 15, 2004 145 150
8.125% Notes due October 15, 2005 109 150
8% Notes due October 15, 2003 - 100
5.375% Notes due April 15, 2005 350 350
Floating rate notes due June 28, 2004 (1.92% average
interest rate at December 31, 2003) 100 200
Euro Commercial paper (2.10% average effective
interest rate at December 31, 2002) - 68
Guaranteed Debt of Employee Stock Ownership Plan 9.61%
Notes due in installments through January 2, 2005 5 11
Gunnison Trust floating rate notes due November 8, 2006
(1.93% average interest rate at December 31, 2003) 75 -
------ ------
3,655 3,904
Long-term debt due within one year (574) (106)
------ ------
Total $3,081 $3,798
====== ======
Future maturities of long-term debt as of December 31, 2003, are as follows:
There-
(Millions of dollars) 2004 2005 2006 2007 2008 after Total
- ---------------------------------------------------------------------------------------------------------------------
Long-term debt $574 (1) $460 $382 $150 $ - $2,089 $3,655
(1) Of this amount, $326 million may be a noncash settlement of the DECS with
distribution of the Devon stock.
The company's long-term debt agreements do not contain subjective acceleration
clauses (commonly referred to as material adverse change clauses); however,
certain of the company's long-term debt agreements contain restrictive
covenants, including a minimum tangible net worth requirement and a maximum
total debt to total capitalization ratio, as defined in the agreements. At
December 31, 2003, the company was in compliance with its debt covenants. Except
for the Gunnison Trust floating rate notes payable discussed below, all
outstanding notes and debentures are unsecured.
During 2001, the company entered into a leasing arrangement with Kerr-McGee
Gunnison Trust (Gunnison Trust) for the construction of the company's share of a
platform to be used in the development of the Gunnison field, in which the
company has a 50% working interest. Under the terms of the agreement, the
company's share of construction costs for the platform has been financed under a
five-year synthetic lease credit facility between the trust and groups of
financial institutions for up to $157 million, with the company making lease
payments sufficient to pay interest at varying rates on the notes. Construction
of the platform was completed in December 2003, with the company's share of
construction costs totaling $149 million. On December 31, 2003, $66 million of
the synthetic lease facility was converted to a leveraged lease structure,
whereby the company leases an interest in the platform under an operating lease
agreement from a separate business trust.
Both the Gunnison Trust and the new operating lease trust are considered
variable interest entities under the provisions of FIN 46. As such, the company
is required to analyze its relationship with each trust to determine whether the
company is the primary beneficiary, and thus required to consolidate the trusts.
Based on the analyses performed, the company is not the primary beneficiary of
the operating lease trust; however, the company is considered the primary
beneficiary of the Gunnison Trust. Accordingly, the remaining assets and
liabilities of the Gunnison Trust are reflected in the company's Consolidated
Balance Sheet at December 31, 2003, which includes $83 million in property,
plant and equipment, $4 million in accrued liabilities, $75 million in long-term
debt, and $4 million in minority interest. The Gunnison Trust floating rate
notes payable are secured by the platform assets of $83 million included in
property and an assignment of the company's lease agreement with the Gunnison
Trust. The $66 million of platform assets and related debt that was converted to
the leveraged lease structure in December 2003 is not recognized in the
company's Consolidated Balance Sheet at December 31, 2003. On January 15, 2004,
the remaining $83 million of the synthetic lease facility was converted to the
leveraged lease structure, and the related lessor trust will not be subject to
consolidation. As a result, the related property and debt will not be reflected
in the company's Consolidated Balance Sheet in 2004. The operating lease
commitment is included in the Note 17 disclosure.
10. Asset Securitization
In December 2000, the company began an accounts receivable monetization program
for its pigment business through the sale of selected accounts receivable with a
three-year, credit-insurance-backed asset securitization program. On July 30,
2003, the company restructured the existing accounts receivable monetization
program to include the sale of receivables originated by the company's European
chemical operations. The maximum available funding under the amended program is
$165 million. In addition, certain other terms of the program have been modified
as part of the restructuring. Under the terms of the program, selected
qualifying customer accounts receivable may be sold monthly to a special-purpose
entity (SPE), which in turn sells an undivided ownership interest in the
receivables to a third-party multi-seller commercial paper conduit sponsored by
an independent financial institution. The company sells, and retains an interest
in, excess receivables to the SPE as over-collateralization for the program. The
company's retained interest in the SPE's receivables is classified in trade
accounts receivable in the accompanying Consolidated Balance Sheet. The retained
interest is subordinate to, and provides credit enhancement for, the conduit's
ownership interest in the SPE's receivables, and is available to the conduit to
pay certain fees or expenses due to the conduit, and to absorb credit losses
incurred on any of the SPE's receivables in the event of termination. However,
the company believes that the risk of credit loss is very low since its bad-debt
experience has historically been insignificant. The company retains servicing
responsibilities and receives a servicing fee of 1.07% of the receivables sold
for the period of time outstanding, generally 60 to 120 days. Servicing fees
collected were $2 million in 2003 and $1 million in both 2002 and 2001. No
recourse obligations were recorded since the company has no obligations for any
recourse actions on the sold receivables. The company also holds preference
stock in the special-purpose entity equal to 3.5% of the receivables sold. The
preference stock is essentially a retained deposit to provide further credit
enhancements, if needed, but otherwise recoverable by the company at the end of
the program.
During 2003, 2002 and 2001, the company sold $836 million, $609 million and $597
million, respectively, of its pigment receivables, resulting in pretax losses of
$5 million, $5 million and $8 million, respectively. The losses are equal to the
difference in the book value of the receivables sold and the total of cash and
the fair value of the deposit retained by the special-purpose entity. At
year-end 2003 and 2002, the outstanding balance on receivables sold, net of the
company's retained interest in receivables serving as over-collateralization,
totaled $165 million and $111 million, respectively. The outstanding balance for
receivables serving as over-collateralization totaled $36 million at December
31, 2003. There were no delinquencies as of year-end 2003.
11. Income Taxes
The 2003, 2002 and 2001 income tax provisions (benefits) from continuing
operations are summarized below:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
U.S. Federal -
Current $ 9 $ 12 $(70)
Deferred 19 (104) 219
---- ----- ----
28 (92) 149
---- ----- ----
International -
Current 58 36 130
Deferred 100 10 (8)
---- ----- ----
158 46 122
---- ----- ----
State 3 - 5
---- ----- ----
Total $189 $ (46) $276
==== ===== ====
In the following table, the U.S. Federal income tax rate is reconciled to the
company's effective tax rates for income or loss from continuing operations as
reflected in the Consolidated Statement of Operations.
2003 2002 2001
- --------------------------------------------------------------------------------
U.S. statutory rate - provision (benefit) 35.0% (35.0)% 35.0%
Increases (decreases) resulting from -
Adjustment of deferred tax balances due
to tax rate changes - 19.9 (.1)
Taxation of foreign operations 8.6 12.1 1.7
Federal income tax credits - (1.8) -
State income taxes .5 - .6
Other - net (1.4) (2.2) (.5)
---- ---- ----
Total 42.7% (7.0)% 36.7%
==== ==== ====
Net deferred tax liabilities at December 31, 2003 and 2002, are composed of the
following:
(Millions of dollars) 2003 2002
- --------------------------------------------------------------------------------
Net deferred tax liabilities -
Accelerated depreciation $1,100 $1,088
Exploration and development 406 192
Undistributed earnings of foreign subsidiaries 28 28
Postretirement benefits (76) (89)
Dismantlement, remediation, restoration and
other reserves (109) (34)
U.S. and foreign operating loss carryforward (126) (92)
AMT credit carryforward (47) (47)
Other 83 99
------ ------
Total $1,259 $1,145
====== ======
The taxation of a company that has operations in several countries involves many
complex variables, such as tax structures that differ from country to country
and the effect on U.S. taxation of international earnings. These complexities do
not permit meaningful comparisons between the U.S. and international components
of income before income taxes and the provision for income taxes, and
disclosures of these components do not necessarily provide reliable indicators
of relationships in future periods. Income (loss) from continuing operations
before income taxes is comprised of the following:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
United States $145 $(116) $524
International 298 (541) 228
---- ----- ----
Total $443 $(657) $752
==== ===== ====
On July 24, 2002, the United Kingdom government made certain changes to its
existing tax laws. Under one of these changes, companies are required to pay a
supplementary corporate tax charge of 10% on profits from their U.K. oil and gas
production, in addition to the required 30% corporate tax on these profits. The
U.K. government also accelerated tax depreciation for capital investments in
U.K. upstream activities and abolished North Sea royalty. The deferred income
tax liability was adjusted to reflect these changes, causing a net increase in
the 2002 international deferred provision for income taxes of $132 million.
At December 31, 2003, the company had foreign operating loss carryforwards
totaling $272 million. Of this amount, $3 million expires in 2004, $13 million
in 2006, $1 million in 2007 and $255 million has no expiration date. Realization
of these operating loss carryforwards depends on generating sufficient taxable
income in future periods. A valuation allowance of $9 million has been recorded
to reduce deferred tax assets associated with loss carryforwards that the
company does not expect to fully realize prior to expiration.
Undistributed earnings of certain consolidated foreign subsidiaries totaled $710
million at December 31, 2003. No provision for deferred U.S. income taxes has
been made for these earnings because they are considered to be indefinitely
invested outside the U.S. The distribution of these earnings in the form of
dividends or otherwise, may subject the company to U.S. income taxes. However,
because of the complexities of U.S. taxation of foreign earnings, it is not
practicable to estimate the amount of additional tax that might be payable on
the eventual remittance of these earnings.
The Internal Revenue Service has completed its examination of the Kerr-McGee
Corporation and subsidiaries' Federal income tax returns for all years through
1998 and is conducting an examination of the years 1999 through 2002. The years
through 1994 have been closed. The Oryx income tax returns have been examined
through 1997, and the years through 1978 have been closed, as have the years
1988 through 1997. The company believes that it has made adequate provision for
income taxes that may be payable with respect to open years.
12. Taxes, Other than Income Taxes
Taxes, other than income taxes, as shown in the Consolidated Statement of
Operations for the years ended December 31, 2003, 2002 and 2001, are comprised
of the following:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Production/severance $46 $ 58 $ 67
Payroll 30 21 27
Property 19 20 15
Other 3 5 5
--- ---- ----
Total $98 $104 $114
=== ==== ====
13. Asset Retirement Obligations
As discussed in Note 1, the company adopted FAS 143 on January 1, 2003. At
December 31, 2002, the comparable balance of $222 million reflected in the
company's Consolidated Balance Sheet represents the non-current portion of the
company's site dismantlement reserve prior to the adoption of FAS 143. A summary
of the changes in asset retirement obligations since the date of adoption is
included in the table below.
(Millions of dollars)
- --------------------------------------------------------------------------------
January 1, 2003, balance upon adoption of FAS 143 $395
Obligations incurred 11
Accretion expense 25
Abandonment expenditures (17)
Abandonment obligations settled through property divestitures (15)
Changes in estimates, including timing 22
----
December 31, 2003 421
Less current asset retirement obligation (20)
----
Non-current asset retirement obligation $401
====
14. Deferred Credits and Reserves - Other
Other deferred credits and reserves consist of the following at year-end 2003
and 2002:
(Millions of dollars) 2003 2002
- --------------------------------------------------------------------------------
Postretirement benefit obligations $215 $210
Reserves for remediation and restoration 152 165
Pension plan liabilities 73 54
Derivatives (1) 2 67
Litigation reserves 32 30
Accrued rent expense - spar operating leases 32 9
Ad valorem taxes 31 21
Other 28 26
---- ----
Total $565 $582
==== ====
(1) Options associated with exchangeable debt of $67 million at December 31,
2002, were reclassified from other deferred credits and reserves to accrued
liabilities during 2003 in connection with the maturity of the DECS in
August 2004 (see Note 18).
The company provided for environmental remediation and restoration, net of
authorized reimbursements, during each of the years 2003, 2002 and 2001, as
follows:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Provision, net of authorized reimbursements $62 $ 80 $90
Reimbursements received 15 9 11
Authorized reimbursements accrued 32 113 -
The reimbursements pertain to the former facility in West Chicago, Illinois, and
the Henderson, Nevada, facility. The West Chicago reimbursements are authorized
pursuant to Title X of the Energy Policy Act of 1992 and the Henderson
reimbursements represent amounts recoverable under an environmental cost cap
insurance policy (see Note 16).
15. Other Income (Expense)
Other income (expense) included the following during each of the years in the
three-year period ended December 31, 2003:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Gain (loss) on foreign currency exchange $(41) $(38) $ 3
Loss from unconsolidated affiliates (33) (25) (5)
Gain on sale of Devon stock 17 - -
Derivatives and Devon stock revaluation (1) 4 35 225
Interest income 5 5 10
Other (11) (12) (9)
---- ---- ----
Total $(59) $(35) $224
==== ==== ====
(1) See Note 18.
16. Contingencies
West Chicago, Illinois
In 1973, the company's chemical affiliate (Chemical) closed a facility in West
Chicago, Illinois, that processed thorium ores for the federal government and
for certain commercial purposes. Historical operations had resulted in low-level
radioactive contamination at the facility and in surrounding areas. The original
processing facility is regulated by the State of Illinois (the State), and four
vicinity areas are designated as Superfund sites on the National Priorities List
(NPL).
Closed Facility - Pursuant to agreements reached in 1994 and 1997 among
Chemical, the City of West Chicago (the City) and the State regarding the
decommissioning of the closed West Chicago facility, Chemical has substantially
completed the excavation of contaminated soils and has shipped the bulk of those
soils to a licensed disposal facility. Removal of the remaining materials is
expected to be substantially completed by the end of 2004, leaving principally
surface restoration and groundwater monitoring and/or remediation for subsequent
years. Surface restoration is expected to be completed in 2004, except for areas
designated for use in connection with the Kress Creek and Sewage Treatment Plant
remediation discussed below. The long-term scope, duration and cost of
groundwater monitoring and/or remediation are uncertain because it is not
possible to reliably predict how groundwater conditions have been affected by
the excavation and removal work.
Vicinity Areas - The Environmental Protection Agency (EPA) has listed four areas
in the vicinity of the closed West Chicago facility on the NPL and has
designated Chemical as a Potentially Responsible Party (PRP) in these four
areas. Chemical has substantially completed remedial work for two of the areas
(known as the Residential Areas and Reed-Keppler Park). The other two NPL sites,
known as Kress Creek and the Sewage Treatment Plant, are contiguous and involve
low levels of insoluble thorium residues, principally in streambanks and
streambed sediments, virtually all within a floodway. Chemical has reached an
agreement in principle with the appropriate federal and state agencies and local
communities regarding the characterization and cleanup of the sites, past and
future government response costs, and the waiver of natural resource damage
claims. The agreement in principle is expected to be incorporated in a consent
decree, which must be agreed to by the appropriate federal and state agencies
and local communities and then entered by a federal court. Court approval is
expected in 2004. Chemical has already conducted an extensive characterization
of Kress Creek and the Sewage Treatment Plant and, at the request of EPA,
Chemical is conducting limited additional characterization that is expected to
be completed in 2004. The cleanup work, which is expected to take about four
years to complete following entry of the consent decree, will require excavation
of contaminated soils and stream sediments, shipment of excavated materials to a
licensed disposal facility and restoration of affected areas.
Financial Reserves - As of December 31, 2003, the company had remaining reserves
of $96 million for costs related to West Chicago. This includes $19 million
added to the reserve in 2003 because of an increase in soil volumes experienced
at the Closed Facility and related post-cleanup demolition, city infrastructure
replacement, and additional support and oversight costs. Although actual costs
may exceed current estimates, the amount of any increases cannot be reasonably
estimated at this time. The amount of the reserve is not reduced by
reimbursements expected from the federal government under Title X of the Energy
Policy Act of 1992 (Title X) (discussed below).
Government Reimbursement - Pursuant to Title X, the U.S. Department of Energy
(DOE) is obligated to reimburse Chemical for certain decommissioning and cleanup
costs incurred in connection with the West Chicago sites in recognition of the
fact that about 55% of the facility's production was dedicated to U.S.
government contracts. The amount authorized for reimbursement under Title X is
$365 million plus inflation adjustments. That amount is expected to cover the
government's full share of West Chicago cleanup costs. Through December 31,
2003, Chemical had been reimbursed approximately $171 million under Title X. In
March 2004, Chemical received an additional reimbursement of $44 million,
bringing the total reimbursement received to date to about $215 million.
Reimbursements under Title X are provided by congressional appropriations.
Historically, congressional appropriations have lagged Chemical's cleanup
expenditures. As of December 31, 2003, the government's share of costs incurred
by Chemical but not yet reimbursed by the DOE totaled approximately $109
million, which was reduced to $65 million in March 2004 following receipt of the
additional reimbursement of $44 million. The company believes receipt of the
remaining arrearage in due course following additional congressional
appropriations is probable and has reflected the arrearage as a receivable in
the financial statements. The company expects to receive reimbursement for the
remainder of this receivable by the end of 2006, and will recognize recovery of
the government's share of future remediation costs for the West Chicago sites as
Chemical incurs the costs.
Henderson, Nevada
In 1998, Chemical decided to exit the ammonium perchlorate business. At that
time, Chemical curtailed operations and began preparation for the shutdown of
the associated production facilities in Henderson, Nevada, that produced
ammonium perchlorate and other related products. Manufacture of perchlorate
compounds began at Henderson in 1945 in facilities owned by the U.S. government.
The U.S. Navy expanded production significantly in 1953 when it completed
construction of a plant for the manufacture of ammonium perchlorate. The Navy
continued to own the ammonium perchlorate plant as well as other associated
production equipment at Henderson until 1962, when the plant was purchased by a
predecessor of Chemical. The ammonium perchlorate produced at the Henderson
facility was used primarily in federal government defense and space programs.
Perchlorate has been detected in nearby Lake Mead and the Colorado River.
Chemical began decommissioning the facility and remediating associated
perchlorate contamination, including surface impoundments and groundwater when
it decided to exit the business in 1998. In 1999 and 2001, Chemical entered into
consent orders with the Nevada Division of Environmental Protection that require
Chemical to implement both interim and long-term remedial measures to capture
and remove perchlorate from groundwater.
In 1999, Chemical initiated the interim measures required by the consent orders.
In June 2003, construction began on a long-term remediation system. It is
anticipated that this system will be operational in early 2004. The scope and
duration of groundwater remediation will be driven in the long term by drinking
water standards, which to date have not been formally established by state or
federal regulatory authorities. EPA and other federal and state agencies
currently are evaluating the health and environmental risks associated with
perchlorate as part of the process for ultimately setting a drinking water
standard. The resolution of these issues could materially affect the scope,
duration and cost of the long-term groundwater remediation that Chemical is
required to perform.
Financial Reserves - In 2003, the company added $32 million to its reserves for
groundwater remediation at Henderson for the construction and operation of the
long-term remediation system and the continued operation of the interim system
during the construction and startup period for the long-term system. Remaining
reserves for Henderson totaled $23 million as of December 31, 2003. As noted
above, the long-term scope, duration and cost of groundwater remediation are
uncertain and, therefore, additional costs may be incurred in the future.
However, the amount of any additional costs cannot be reasonably estimated at
this time.
Government Litigation - In 2000, Chemical initiated litigation against the
United States seeking contribution for response costs. The suit is based on the
fact that the government owned the plant in the early years of its operation,
exercised significant control over production at the plant and the sale of
products produced at the plant, and was the largest consumer of products
produced at the plant. The litigation is in the discovery stage. Although the
outcome of the litigation is uncertain, Chemical believes it is likely to
recover a portion of its costs from the government. The amount and timing of any
recovery cannot be estimated at this time and, accordingly, the company has not
recorded a receivable or otherwise reflected in the financial statements any
potential recovery from the government.
Insurance - In 2001, Chemical purchased a 10-year, $100 million environmental
cost cap insurance policy for groundwater and other remediation at Henderson.
The insurance policy provides coverage only after Chemical exhausts a
self-insured retention of approximately $61 million and covers only those costs
incurred to achieve a cleanup level specified in the policy. As noted above,
federal and state agencies have not established a drinking water standard and,
therefore, it is possible that Chemical may be required to achieve a cleanup
level more stringent than that covered by the policy. If so, the amount
recoverable under the policy could be affected. Through December 31, 2003,
Chemical has incurred expenditures of about $59 million that it believes can be
applied to the self-insured retention. The company believes that the remaining
reserve of $23 million at December 31, 2003, also will qualify under the
insurance policy, which would exhaust the self-insured retention and leave about
$21 million for recovery under the policy. The company believes that
reimbursement of the $21 million under the insurance policy is probable and,
accordingly, the company has recorded a $21 million receivable in the financial
statements. The company expects to be reimbursed for this receivable by the end
of 2007.
Milwaukee, Wisconsin
In 1976, Chemical closed a wood-treatment facility it had operated in Milwaukee,
Wisconsin. Operations at the facility prior to its closure had resulted in the
contamination of soil and groundwater at and around the site with creosote and
other substances used in the wood-treatment process. In 1984, EPA designated the
Milwaukee wood-treatment facility as a Superfund site under CERCLA, listed the
site on the NPL and named Chemical a PRP. Chemical executed a consent decree in
1991 that required it to perform soil and groundwater remediation at and below
the former wood-treatment area and to address a tributary creek of the Menominee
River that had become contaminated as a result of the wood-treatment operations.
Actual remedial activities were deferred until after the decree was finally
entered in 1996 by a federal court in Milwaukee.
Groundwater treatment was initiated in 1996 to remediate groundwater
contamination below and in the vicinity of the former wood-treatment area. It is
not possible to reliably predict how groundwater conditions will be affected by
the ongoing soil remediation and groundwater treatment; therefore, it is not
known how long groundwater treatment will continue. Soil cleanup of the former
wood-treatment area began in 2000 and was completed in 2002. Also in 2002, terms
for addressing the tributary creek were agreed upon with EPA, after which
Chemical began the implementation of a remedy to reroute the creek and to
remediate associated sediment and stream bank soils, which is expected to take
about four more years.
As of December 31, 2003, the company had remaining reserves of $11 million for
the costs of the remediation work described above. Although actual costs may
exceed current estimates, the amount of any increases cannot be reasonably
estimated at this time.
Cushing, Oklahoma
In 1972, an affiliate of the company closed a petroleum refinery it had operated
near Cushing, Oklahoma. Prior to closing the refinery, the affiliate also had
produced uranium and thorium fuel and metal at the site pursuant to licenses
issued by the Atomic Energy Commission (AEC). The uranium and thorium operations
commenced in 1962 and were shut down in 1966, at which time the affiliate
decommissioned and cleaned up the portion of the facility related to uranium and
thorium operations to applicable standards. The refinery also was cleaned up to
applicable standards at the time of closing.
Subsequent regulatory changes required more extensive remediation at the site.
In 1990, the affiliate entered into a consent agreement with the State of
Oklahoma to investigate the site and take appropriate remedial actions related
to petroleum refining and uranium and thorium residuals. Investigation and
remediation of hydrocarbon contamination is being performed with oversight of
the Oklahoma Department of Environmental Quality. Soil remediation to address
hydrocarbon contamination is expected to continue for about four more years. The
long-term scope, duration and cost of groundwater remediation are uncertain and,
therefore, additional costs may be incurred in the future. Additionally, in
1993, the affiliate received a decommissioning license from the Nuclear
Regulatory Commission (NRC), the successor to AEC's licensing authority, to
perform certain cleanup of uranium and thorium residuals. This work is expected
to be substantially completed in 2004.
As of December 31, 2003, the company had remaining reserves of $22 million for
the costs of the ongoing remediation and decommissioning work described above.
This includes $17 million added to the reserve in 2003 as a result of the
increase in uranium and thorium residuals experienced at the site, which
required excavation, transportation and disposal, as well as additional
characterization of petroleum hydrocarbons, and extended support costs. Although
actual costs may exceed current estimates, the amount of any increases cannot be
reasonably estimated at this time.
Mobile, Alabama
In June 2003, Chemical ceased operations at its facility in Mobile, Alabama,
which Chemical had used to produce feedstock for its titanium dioxide plants.
Operations prior to closure had resulted in minor contamination of the
groundwater adjacent to surface impoundments. A groundwater recovery system was
installed prior to closure and continues in operation as required under
Chemical's National Pollutant Discharge Elimination System (NPDES) permit.
Future remediation work, including groundwater recovery, closure of the
impoundments and other minor work, is expected to be substantially completed in
about five years. Reserves of $11 million were provided for the remediation in
2003 and remain outstanding as of December 31, 2003. Although actual costs may
exceed current estimates, the amount of any increases cannot be reasonably
estimated at this time.
New Jersey Wood-Treatment Site
In 1999, EPA notified Chemical and its parent company that they were potentially
responsible parties at a former wood-treatment site in New Jersey that has been
listed by EPA as a Superfund site. At that time, the company knew little about
the site as neither Chemical nor its parent had ever owned or operated the site.
A predecessor of Chemical had been the sole stockholder of a company that owned
and operated the site. The company that owned the site already had been
dissolved and the site had been sold to a third party before Chemical became
affiliated with the former stockholder in 1964. EPA has preliminarily estimated
that cleanup costs may reach $120 million or more.
There are substantial uncertainties about Chemical's responsibility for the
site, and Chemical is evaluating possible defenses to any claim by EPA for
response costs. EPA has not articulated the factual and legal basis on which EPA
notified Chemical and its parent that they are potentially responsible parties.
The EPA notification may be based on a successor liability theory premised on
the 1964 transaction pursuant to which Chemical became affiliated with the
former stockholder of the company that had owned and operated the site. Based on
available historical records, it is uncertain whether and, if so, under what
terms, the former stockholder assumed liabilities of the dissolved company.
Moreover, as noted above, the site had been sold to a third party and the
company that owned and operated the site had been dissolved before Chemical
became affiliated with that company's stockholder. In addition, there appear to
be other potentially responsible parties, though it is not known whether the
other parties have received notification from EPA. EPA has not ordered Chemical
or its parent to perform work at the site and is instead performing the work
itself. The company has not recorded a reserve for the site as it is not
possible to reliably estimate whatever liability Chemical or its parent may have
for the cleanup because of the aforementioned uncertainties and the existence of
other potentially responsible parties.
Forest Products Litigation
Between 1999 and 2001, Kerr-McGee Chemical LLC (Chemical) and its parent company
were named in 22 lawsuits in three states (Mississippi, Louisiana and
Pennsylvania) in connection with present and former forest products operations
located in those states (in Columbus, Mississippi; Bossier City, Louisiana; and
Avoca, Pennsylvania). The lawsuits sought recovery under a variety of common law
and statutory legal theories for personal injuries and property damages
allegedly caused by exposure to and/or release of creosote and other substances
used in the wood-treatment process.
Having earlier set a reserve of $70 million for liabilities associated with
these matters, Chemical executed settlement agreements, which are expected to
resolve substantially all of the Louisiana, Pennsylvania and Columbus,
Mississippi, lawsuits described above. About 90% of approximately 10,400
identified claimants and about 2,500 class members pursuant to a class action
settlement have released Chemical and its parent from liability related to the
former forest products operations in exchange for settlement payments totaling
approximately $66 million (leaving approximately $4 million in the reserve).
Accordingly most of the suits have been, or are expected to be, dismissed. The
settlements do not resolve two of the Columbus, Mississippi, lawsuits, which
together involve 27 plaintiffs. The settlements also do not resolve the claims
of plaintiffs who did not sign releases, class members who opted out of the
class settlement, or class members whose claims may arise in the future for
currently unmanifested personal injuries.
Chemical and its affiliates believe that lawsuits and claims not resolved
pursuant to the settlements described above are without substantial merit, and
Chemical and its affiliates are vigorously defending against them. However,
there is no assurance that the company will not be required to adjust the
reserve in the future in light of the uncertainties of litigation. The company
believes that the resolution of the claims that remain outstanding with respect
to forest products operations in Columbus, Mississippi; Bossier City, Louisiana;
and Avoca, Pennsylvania, will not have a material adverse effect on the company.
Following the adoption by the Mississippi legislature of tort reform,
plaintiffs' lawyers filed many new lawsuits across the state of Mississippi in
advance of the reform's effective date. On December 31, 2002, approximately 245
lawsuits were filed against Chemical and its affiliates on behalf of
approximately 4,600 claimants in connection with Chemical's Columbus,
Mississippi, operations, seeking recovery on legal theories substantially
similar to those advanced in the litigation described above. Substantially all
of these lawsuits have been removed to the U.S. District Court for the Northern
District of Mississippi, and the company is seeking to consolidate these
lawsuits for pretrial and discovery purposes. Chemical and its affiliates
believe the lawsuits are without substantial merit and are vigorously defending
against them. The company has not provided a reserve for the lawsuits because it
cannot reasonably determine the probability of a loss, and the amount of loss,
if any, cannot be reasonably estimated.
On December 31, 2002, and June 13, 2003, two lawsuits were filed against
Chemical in connection with a former wood-treatment plant located in
Hattiesburg, Mississippi, and the plaintiffs' lawyers also have asserted similar
claims on behalf of other persons not named in the lawsuits. The lawsuits and
other claims seek recovery on legal theories substantially similar to those
advanced in the litigation described above. Chemical resolved the majority of
these claims pursuant to a settlement reached in April 2003, which has resulted
in aggregate payments by Chemical of approximately $600,000. Chemical and its
affiliates believe that claims not resolved pursuant to the Hattiesburg
settlements are without substantial merit and are vigorously defending against
such claims.
The company believes that the resolution of the claims that remain outstanding
with respect to the follow-on litigation will not have a material adverse effect
on the company's financial condition or results of operations.
Other Matters
The company and/or its affiliates are parties to a number of legal and
administrative proceedings involving environmental and/or other matters pending
in various courts or agencies. These include proceedings associated with
facilities currently or previously owned, operated or used by the company's
affiliates and/or their predecessors, some of which include claims for personal
injuries and property damages. Current and former operations of the company's
affiliates also involve management of regulated materials and are subject to
various environmental laws and regulations. These laws and regulations will
obligate the company's affiliates to clean up various sites at which petroleum
and other hydrocarbons, chemicals, low-level radioactive substances and/or other
materials have been contained, disposed of or released. Some of these sites have
been designated Superfund sites by EPA pursuant to CERCLA. Similar environmental
regulations exist in foreign countries in which the company's affiliates
operate.
The company provides for costs related to contingencies when a loss is probable
and the amount is reasonably estimable. It is not possible for the company to
reliably estimate the amount and timing of all future expenditures related to
environmental and legal matters and other contingencies because, among other
reasons:
o some sites are in the early stages of investigation, and other sites may be
identified in the future;
o remediation activities vary significantly in duration, scope and cost from
site to site depending on the mix of unique site characteristics,
applicable technologies and regulatory agencies involved;
o cleanup requirements are difficult to predict at sites where remedial
investigations have not been completed or final decisions have not been
made regarding cleanup requirements, technologies or other factors that
bear on cleanup costs;
o environmental laws frequently impose joint and several liability on all
potentially responsible parties, and it can be difficult to determine the
number and financial condition of other potentially responsible parties and
their respective shares of responsibility for cleanup costs;
o environmental laws and regulations, as well as enforcement policies, are
continually changing, and the outcome of court proceedings and discussions
with regulatory agencies are inherently uncertain;
o some legal matters are in the early stages of investigation or proceeding
or their outcomes otherwise may be difficult to predict, and other legal
matters may be identified in the future;
o unanticipated construction problems and weather conditions can hinder the
completion of environmental remediation;
o the inability to implement a planned engineering design or use planned
technologies and excavation methods may require revisions to the design of
remediation measures, which delay remediation and increase costs; and
o the identification of additional areas or volumes of contamination and
changes in costs of labor, equipment and technology generate corresponding
changes in environmental remediation costs.
As of December 31, 2003, the company had reserves totaling $259 million for
cleaning up and remediating environmental sites, reflecting the reasonably
estimable costs for addressing these sites. This includes $96 million for the
West Chicago sites, $23 million for the Henderson, Nevada, site and $35 million
for forest products sites. Additionally, as of December 31, 2003, the company
had litigation reserves totaling approximately $37 million for the reasonably
estimable losses associated with litigation. Management believes, after
consultation with general counsel, that currently the company has reserved
adequately for the reasonably estimable costs of environmental matters and other
contingencies. However, additions to the reserves may be required as additional
information is obtained that enables the company to better estimate its
liabilities, including liabilities at sites now under review, though the company
cannot now reliably estimate the amount of future additions to the reserves.
17. Commitments
Lease Obligations and Guarantees
Total lease rental expense was $65 million in 2003, $61 million in 2002 and $38
million in 2001.
The company has various commitments under noncancelable operating lease
agreements, principally for office space, production and gathering facilities,
and drilling and other equipment. The company has also entered into operating
lease agreements for the use of the Nansen, Boomvang and Gunnison platforms
located in the Gulf of Mexico. Aggregate minimum annual rentals under all
operating leases (including the platform leases in effect at December 31, 2003,
and the Gunnison operating lease which closed January 15, 2004), total $941
million, of which $50 million is due in 2004, $66 million in 2005, $65 million
in 2006, $59 million in 2007, $61 million in 2008 and $640 million thereafter.
During 2001, the company entered into a synthetic lease arrangement with
Kerr-McGee Gunnison Trust for the construction of the company's share of a
platform to be used in the development of the Gulf of Mexico Gunnison field, in
which the company has a 50% working interest. The construction of the company's
portion of the platform was financed with a $149 million synthetic lease between
the trust and a group of financial institutions. Completion of the Gunnison
platform occurred in December 2003, at which time a portion of the platform
assets was acquired by a separate business trust and the company entered into an
operating lease for the use of the assets. The remaining portion of the Gunnison
synthetic lease was converted to an operating lease on January 15, 2004. In
accordance with the provisions of FIN 46, the company has consolidated the
remaining synthetic lessor trust as of December 31, 2003, as discussed in Note
1.
The company has guaranteed that the Nansen, Boomvang and Gunnison platforms will
have residual values at the end of the operating leases equal to at least 10% of
the fair-market value of the platform at the inception of the lease. For Nansen
and Boomvang, the guaranteed values are $14 million and $8 million,
respectively, in 2022, and for Gunnison the guarantee is $15 million in 2024.
During 2003 and 2002, the company entered into sale-leaseback arrangements with
General Electric Capital Corporation (GECC) covering assets associated with a
gas-gathering system in the Rocky Mountain region. The lease agreements were
entered into for the purpose of monetizing the related assets. The sales price
for the 2003 equipment was $6 million. The sales price for the 2002 equipment
was $71 million; however, an $18 million settlement obligation existed for
equipment previously covered by the lease agreement, resulting in net cash
proceeds of $53 million in 2002. The 2002 operating lease agreements have an
initial term of five years, with two 12-month renewal options, and the company
may elect to purchase the equipment at specified amounts after the end of the
fourth year. The 2003 operating lease agreement has an initial term of four
years, with two 12-month renewal options. In the event the company does not
purchase the equipment and it is returned to GECC, the company guarantees a
residual value ranging from $35 million at the end of the initial terms to $27
million at the end of the last renewal option. The company recorded no gain or
loss associated with the GECC sale-leaseback agreements. The future minimum
annual rentals due under noncancelable operating leases shown above include
payments related to these agreements.
In conjunction with the company's sale of its Ecuadorean assets, which included
the company's nonoperating interest in the Oleoducto de Crudos Pesados Ltd.
(OCP) pipeline, the company has entered into a performance guarantee agreement
with the buyer for the benefit of OCP. Under the terms of the agreement, the
company guarantees payment of any claims from OCP against the buyer upon default
by the buyer and its parent company. Claims would generally be for the buyer's
proportionate share of construction costs of OCP; however, other claims may
arise in the normal operations of the pipeline. Accordingly, the amount of any
such future claims cannot be reasonably estimated. In connection with this
guarantee, the buyer's parent company has issued a letter of credit in favor of
the company up to a maximum of $50 million, upon which the company can draw in
the event it is required to perform under the guarantee agreement. The company
will be released from this guarantee when the buyer obtains a specified credit
rating as stipulated under the guarantee agreement.
In connection with certain contracts and agreements, the company enters into
indemnifications related to title claims, environmental matters, litigation and
other claims. The company has recorded no material obligations in connection
with its indemnification agreements.
Purchase Obligations
In the normal course of business, the company enters into contractual agreements
to purchase raw materials, pipeline capacity, utilities and other services.
Aggregate future payments under these contracts total $994 million, of which
$345 million is expected to be paid in 2004, $414 million between 2005 and 2006,
$158 million between 2007 and 2008, and $77 million thereafter.
Drilling Rig Commitments
During 1999, the company entered into lease agreements to participate in the use
of various drilling rigs. The total commitment with respect to these
arrangements ranges from nil to $9 million, depending on partner utilization.
These agreements extend through 2004.
18. Financial Instruments and Derivative Activities
Investments in Certain Debt and Equity Securities
The company has certain investments that are considered to be available for
sale. These financial instruments are carried in the Consolidated Balance Sheet
at fair value, which is based on quoted market prices. The company had no
securities classified as held to maturity at December 31, 2003 or 2002. At
December 31, 2003 and 2002, available-for-sale securities for which fair value
can be determined are as follows:
2003 2002
----------------------------------- ----------------------------------
Gross Gross
Unrealized Unrealized
Fair Holding Fair Holding
(Millions of dollars) Value Cost Gains Value Cost Gains
- ---------------------------------------------------------------------------------------------------------------------
Equity securities $27 $10 $8(1) $70 $32 $10(1)
U.S. government obligations 4 4 - 4 4 -
-- ---
Total $8 $10
== ===
(1) This amount includes $9 million and $28 million at December 31, 2003 and
2002, respectively, of gross unrealized hedging losses on 15% of the
exchangeable debt at the time of adoption of FAS 133.
The equity securities represent the company's investment in Devon Energy
Corporation common stock. The company also holds debt exchangeable for stock
(DECS) that may be repaid with the Devon stock currently owned by Kerr-McGee.
Prior to the beginning of 2001, the stock and the debt were marked to market
each month, with the offset recognized in accumulated other comprehensive
income. On January 1, 2001, the company adopted the provisions of FAS 133 and in
accordance with that standard chose to reclassify 85% of the Devon shares owned
at that time to "trading" from the "available for sale" category of investments.
As a result of the reclassification, the company recognized after-tax income
totaling $118 million ($181 million before taxes) for the unrealized
appreciation on 85% of the Devon shares. Additionally, with adoption of FAS 133,
the DECS and its embedded option features were separated. The debt is now
recorded in the Consolidated Balance Sheet at face value less unamortized
discount, and the options associated with the exchangeable feature of the debt
have been recorded at fair value on the balance sheet in accrued liabilities.
(See further discussion on derivatives below.)
During December 2003, the company sold a portion of its Devon shares classified
as available for sale resulting in a pretax gain of $17 million. The remaining
shares were sold in January 2004 for a pretax gain of $9 million. Proceeds from
the December sales totaled $59 million ($47 million received in 2003 and $12
million received in 2004) and proceeds from the January sales totaled $27
million. The cost of the shares sold and the amount of the gain reclassified
from accumulated other comprehensive income were determined using the average
cost of the shares held. The Devon securities are carried in the Consolidated
Balance Sheet as current assets. U.S. government obligations are carried as
current assets or as investments - other assets, depending on their maturities.
The change in unrealized holding gains (losses), net of income taxes, as shown
in accumulated other comprehensive income for the years ended December 31, 2003,
2002 and 2001, is as follows:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Beginning balance $ 6 $(1) $ 139
Net unrealized holding gains (losses) 6 7 (22)
Reclassification of gains included in net income (7) - (118)
--- --- -----
Ending balance $ 5 $ 6 $ (1)
=== === =====
Trading Securities
As discussed above, the company has recorded 85% of its Devon shares as trading
securities and marks this investment to market through income. At December 31,
2003, the market value of 8.4 million shares of Devon was $483 million, and $96
million in unrealized pretax gains was recognized during 2003 in other income
(expense) in the Consolidated Statement of Operations. However, this gain was
substantially offset by an $88 million unrealized loss on the embedded options
associated with the DECS. See the discussion of these derivatives below. At
year-end 2002, the market value of 8.4 million shares of Devon was $387 million,
and $61 million in unrealized pretax gains were recognized during 2002. This
gain was partially offset by a $34 million unrealized loss on the embedded
options associated with the DECS.
Financial Instruments for Other than Trading Purposes
In addition to the financial instruments previously discussed, the company holds
or issues financial instruments for other than trading purposes. At December 31,
2003 and 2002, the carrying amount and estimated fair value of these instruments
for which fair value can be determined are as follows:
2003 2002
----------------------- -------------------------
Carrying Fair Carrying Fair
(Millions of dollars) Amount Value Amount Value
- -------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents $ 142 $ 142 $ 90 $ 90
Long-term receivables 95 82 88 73
Contracts to purchase and sell foreign currencies 17 17 2 2
Debt exchangeable for stock, excluding options 326 330 318 330
Long-term debt, except DECS 3,329 3,761 3,586 4,013
The carrying amount of cash and cash equivalents approximates fair value of
those instruments due to their short maturity. The fair value of long-term
receivables is based on discounted cash flows. The fair value of foreign
currency forward contracts represents the aggregate replacement cost based on
financial institutions' quotes. The fair value of the company's long-term debt
is based on the quoted market prices for the same or similar debt issues or on
the current rates offered to the company for debt with the same remaining
maturity.
Derivatives
The company is exposed to market risk from fluctuations in crude oil and natural
gas prices. To increase the predictability of its cash flows and to support
capital projects, the company initiated a hedging program in 2002 and
periodically enters into financial derivative instruments that generally fix the
commodity prices to be received for a portion of its oil and gas production in
the future. At December 31, 2003, the outstanding commodity-related derivatives
accounted for as hedges had a liability fair value of $168 million, which is
recorded as a current liability. At December 31, 2002, the outstanding
commodity-related derivatives accounted for as hedges had a net liability fair
value of $83 million, of which $27 million was recorded as a current asset and
$110 million was recorded as a current liability. The fair value of these
derivative instruments was determined based on prices actively quoted, generally
NYMEX and Dated Brent prices. At December 31, 2003, the company had after-tax
deferred losses of $106 million in accumulated other comprehensive income
associated with these contracts. The company expects to reclassify the entire
amount of these losses into earnings during the next 12 months, assuming no
further changes in fair market value of the contracts. During 2003, the company
realized a $71 million loss on U.S. oil hedging, a $64 million loss on North Sea
oil hedging and a $144 million loss on U.S. natural gas hedging. During 2002,
the company realized a $28 million loss on U.S. oil hedging, a $50 million loss
on North Sea oil hedging and a $2 million loss on U.S. natural gas hedging. The
losses offset the higher oil and natural gas prices realized on the physical
sale of crude oil and natural gas. Losses for hedge ineffectiveness are
recognized as a reduction of revenue in the Consolidated Statement of Operations
and were not material for 2003 or 2002.
In addition to the company's hedging program, Kerr-McGee Rocky Mountain Corp.
holds certain gas basis swaps settling between 2004 and 2008. Through December
2003, the company treated these gas basis swaps as nonhedge derivatives, and
changes in fair value were recognized in earnings. On December 31, 2003, the
company designated those swaps settling in 2004 as hedges since the basis swaps
have been coupled with natural gas fixed-price swaps, while the remainder
settling between 2005 and 2008 will continue to be treated as non-hedge
derivatives. At December 31, 2003, these derivatives are recorded at their fair
value of $23 million, of which $8 million is recorded as a current asset and $15
million is recorded in investments - other assets. At December 31, 2002, these
derivatives were recorded at their fair value of $21 million in investments -
other assets. The net gains associated with these non-hedge derivatives were $2
million, $8 million and $27 million in 2003, 2002 and 2001, respectively, and
are included in other income in the Consolidated Statement of Operations.
The company's marketing subsidiary, Kerr-McGee Energy Services Corporation
(KMES) markets natural gas (primarily equity gas) in the Denver area. Existing
contracts for the physical delivery of gas at fixed prices have not been
designated as hedges and are marked to market in accordance with FAS 133. KMES
also has entered into natural gas swaps and basis swaps that offset its
fixed-price risk on physical contracts. These derivative contracts lock in the
margins associated with the physical sale. The company believes that risk
associated with these derivatives is minimal due to the creditworthiness of the
counterparties. The net asset fair value of these derivative instruments was not
material at year-end 2003 or 2002. The fair values of the outstanding derivative
instruments at December 31, 2003, were based on prices actively quoted. During
2003, the net loss associated with these derivative contracts totaled $12
million, of which $7 million is included as a reduction of revenue and $5
million is included in other income. For 2002 and 2001, the net loss associated
with these derivative contracts totaled $20 million and $24 million,
respectively, and is included as a reduction of revenue in the Consolidated
Statement of Operations. The losses on the derivative contracts are
substantially offset by the fixed prices realized on the physical sale of the
natural gas.
From time to time, the company enters into forward contracts to buy and sell
foreign currencies. Certain of these contracts (purchases of Australian dollars
and British pound sterling, and sales of euro) have been designated and have
qualified as cash flow hedges of the company's anticipated future cash flow
needs for a portion of its capital expenditures, raw material purchases and
operating costs. These forward contracts generally have durations of less than
three years. At December 31, 2003, the outstanding foreign exchange derivative
contracts accounted for as hedges had a net asset fair value of $21 million, of
which $28 million was recorded in current assets and $7 million was recorded in
current liabilities. Changes in the fair value of these contracts are recorded
in accumulated other comprehensive income and will be recognized in earnings in
the periods during which the hedged forecasted transactions affect earnings
(i.e., when hedged assets are depreciated in the case of a hedge of capital
expenditures, when finished inventory is sold in the case of a hedged raw
material purchase and when the forward contracts close in the case of a hedge of
operating costs). At December 31, 2003 and 2002, the company had after-tax
deferred gains of $17 million and deferred losses of $7 million, respectively,
in accumulated other comprehensive income. In 2003, the company reclassified $11
million of gains on forward contracts from accumulated other comprehensive
income to operating expenses in the Consolidated Statement of Operations. In
2002 and 2001, the company reclassified $5 million and $9 million, respectively,
of losses on forward contracts from accumulated other comprehensive income to
operating expenses in the Consolidated Statement of Operations. Of the existing
unrealized net gains at December 31, 2003, approximately $9 million in gains
will be reclassified into earnings during the next 12 months, assuming no
further changes in fair value of the contracts. No hedges were discontinued
during 2003, and no ineffectiveness was recognized.
Selected pigment receivables have been sold in an asset securitization program
at their equivalent U.S. dollar value at the date the receivables were sold. The
company is collection agent and retains the risk of foreign currency rate
changes between the date of sale and collection of the receivables. Under the
terms of the asset securitization agreement restructured in 2003, the company is
required to enter into forward contracts for the value of the euro-denominated
receivables sold into the program to mitigate its foreign currency risk. Gains
or losses on the forward contracts are recognized currently in earnings. During
2003, the company recognized losses of $7 million associated with these
contracts.
The company has entered into other forward contracts to sell foreign currencies,
which will be collected as a result of pigment sales denominated in foreign
currencies, primarily in European currencies. These contracts have not been
designated as hedges even though they do protect the company from changes in
foreign currency rates. The estimated fair value of these contracts was
immaterial at December 31, 2003 and 2002.
The company issued 5 1/2% notes exchangeable for common stock (DECS) in August
1999, which allow each holder to receive between .85 and 1.0 share of Devon
common stock or, at the company's option, an equivalent amount of cash at
maturity in August 2004. Embedded options in the DECS provide the company a
floor price on Devon's common stock of $33.19 per share (the put option). The
company also has the right to retain up to 15% of the shares if Devon's stock
price is greater than $39.16 per share (the DECS holders have an imbedded call
option on 85% of the shares). If Devon's stock price at maturity is greater than
$33.19 per share but less than $39.16 per share, the company's right to retain
Devon stock will be reduced proportionately. The company is not entitled to
retain any Devon stock if the price of Devon stock at maturity is less than or
equal to $33.19 per share. Using the Black-Scholes valuation model, the company
recognizes any gains or losses resulting from changes in the fair value of the
put and call options in other income. At December 31, 2003 and 2002, the net
liability fair value of the embedded put and call options was $155 million and
$67 million, respectively. The company recorded losses of $88 million, $34
million and $205 million during 2003, 2002 and 2001, respectively, in other
income for the changes in the fair values of the put and call options. The
fluctuation in the value of the put and call derivative financial instruments
will generally offset the increase or decease in the market value of the Devon
stock classified as trading. The remaining Devon shares, which are classified as
available-for-sale securities, were partially liquidated in December 2003, with
the remaining shares sold in January 2004 as discussed above. The
available-for-sale Devon shares were in excess of the number of shares the
company believes will be required to extinguish the DECS; however, should the
price of the stock fall below $39.16 per share at the maturity of the DECS, the
company would be required to either purchase additional Devon shares to settle
the DECS or settle a portion of the DECS with cash. The DECS and the derivative
liability associated with the call option have been classified as current
liabilities in the Consolidated Balance Sheet as of December 31, 2003.
In connection with the issuance of $350 million 5.375% notes due April 15, 2005,
the company entered into an interest rate swap arrangement in April 2002. The
terms of the agreement effectively change the interest the company will pay on
the debt until maturity from the fixed rate to a variable rate of LIBOR plus
..875%. The company considers the swap to be a hedge against the change in fair
value of the debt as a result of interest rate changes. The estimated fair value
of the interest rate swap was $15 million and $21 million at December 31, 2003
and 2002, respectively. Any gain or loss on the swap is offset by a comparable
gain or loss resulting from recording changes in the fair value of the related
debt. The critical terms of the swap match the terms of the debt; therefore, the
swap is considered highly effective and no hedge ineffectiveness has been
recorded. The company recognized an $11 million reduction in interest expense in
2003 and a $6 million reduction in interest expense in 2002 from the swap
arrangement.
19. Acquisition and Merger Reserves
During 2002, the company recorded an accrual of $3 million representing
additional severance and other acquisition-related costs related to its 2001
acquisition of HS Resources. In 2001, the company recorded an accrual of $42
million for items associated with this acquisition, which included transaction
costs, severance and other employee-related costs, contract termination costs,
and other acquisition-related costs. Of the total accrual of $45 million, $11
million was paid in 2002 and $34 million was paid during 2001, leaving no
remaining reserve balance at December 31, 2002.
20. Business Combination
On August 1, 2001, the company completed the acquisition of all of the
outstanding shares of common stock of HS Resources, Inc., an independent oil and
gas exploration and production company with active projects in the
Denver-Julesburg Basin, Gulf Coast, Mid-Continent and Northern Rocky Mountain
regions of the U.S. The acquisition added approximately 250 million cubic feet
equivalent of daily gas production and 1.3 trillion cubic feet equivalent of
proved gas reserves, primarily in the Denver, Colorado, area. The addition of
these primarily natural gas reserves provided the company a more balanced
portfolio, geographic diversity and production mix, while also providing
low-risk exploitation drilling opportunities from identified projects based on
HS Resources' seismic inventory. The acquisition price totaled $1.8 billion in
cash, company stock and assumption of debt. The company reflected the assets and
liabilities acquired at fair value in its balance sheet effective August 1,
2001, and the company's results of operations include HS Resources beginning
August 1, 2001. The purchase price was allocated to specific assets and
liabilities based on their estimated fair value at the date of acquisition. The
allocations included $348 million recorded as goodwill, which is not deductible
for income tax purposes. The cash portion of the acquisition totaled $955
million, including direct expenses, and was ultimately financed through issuance
of long-term debt. A total of 5,057,273 shares of Kerr-McGee common stock were
issued in connection with the acquisition. The shares were valued at $70.33 per
share, the average price two days before and after the purchase was announced.
Debt totaling $506 million was assumed.
The following unaudited pro forma condensed information has been prepared to
give effect to the HS Resources acquisition as if it had occurred at the
beginning of 2001, including purchase accounting adjustments.
(Millions of dollars, except per-share amounts) 2001
- --------------------------------------------------------------------------------
Revenues $3,787
Income from continuing operations 490
Net income 499
Earnings per share-
Basic 4.99
Diluted 4.73
21. Discontinued Operations, Asset Impairments and Asset Disposals
During 2002, the company approved a plan to dispose of its exploration and
production operations in Kazakhstan, its interest in the Bayu-Undan project in
the East Timor Sea offshore Australia and its interest in the Jabung block of
Sumatra, Indonesia. These divestiture decisions were made as part of the
company's strategic plan to rationalize noncore oil and gas properties. The
results of these operations have been reported separately as discontinued
operations in the accompanying Consolidated Statement of Operations for all
years presented. In conjunction with the disposals, the related assets were
evaluated and losses were recorded for the Kazakhstan operations, calculated as
the difference between the estimated sales price for the operation, less costs
to sell, and the operations' carrying value. The losses totaled $6 million in
2003 and $35 million in 2002 and are reported as part of discontinued
operations. On March 31, 2003, the company completed the sale of its Kazakhstan
operations for $169 million. In 2002, the company completed the sale of its
interest in the Bayu-Undan project for $132 million in cash, resulting in a
pretax gain of $35 million. The company also completed the sale of its Sumatra
operations in 2002 for $171 million in cash with an $11 million contingent
purchase price pending government approval of an LPG project. The sale resulted
in a pretax gain of $72 million (excluding the contingent purchase price). The
net proceeds received by the company from these sales were used to reduce
outstanding debt.
Revenues applicable to the discontinued operations totaled $6 million, $36
million and $72 million for 2003, 2002 and 2001, respectively. Pretax income for
the discontinued operations totaled nil (including the loss on sale of $6
million), $104 million (including the gains on sale of $107 million and the loss
on sale of $35 million) and $52 million for the years 2003, 2002 and 2001,
respectively.
Impairment losses on held-for-use assets totaled $14 million in 2003, and were
primarily related to oil and gas fields in the U.S. onshore and Gulf of Mexico
shelf areas with remaining investments that were no longer expected to be
recovered through future cash flows. Pretax impairment losses totaling $652
million were recorded in 2002, of which $646 million related to the exploration
and production operating unit and $6 million related to the chemical - other
operating unit. For the exploration and production operating unit, the
impairment charge included $541 million for the Leadon field in the U.K. North
Sea, $82 million for certain other North Sea fields and $23 million for several
older Gulf of Mexico shelf properties. Negative reserve revisions stemming from
additional performance analysis for these properties during 2002 resulted in
revised estimates of future cash flows from the properties that were less than
the carrying values of the related assets. For the chemical - other operating
unit, the $6 million impairment related to the company's decision to exit the
forest products business. In addition, the chemical - pigment operating unit
recorded a $12 million pretax write-down of property, plant and equipment in
2002 related to abandoned chemical engineering projects, which is reflected in
depreciation and depletion in the Consolidated Statement of Operations.
During 2003, the company selectively marketed its 100% owned Leadon field to
third parties. Although no divestiture negotiations are currently under way, the
company continues to review its options with respect to the field and,
particularly, the associated floating production, storage and offloading (FPSO)
facility. Management presently intends to continue operating and producing the
field until such time as the operating cash flow generated by the field does not
support continued production or until a higher value option is identified. Given
the significant value associated with the FPSO relative to the size of the
entire project, the company will continue to pursue a long-term solution that
achieves maximum value for Leadon - which may include disposing of the field,
monetizing the FPSO by selling it as a development option for a third-party
discovery, or redeployment in other company operations. As of December 31, 2003,
the carrying value of the Leadon field assets totaled $374 million. Given the
uncertainty concerning possible outcomes, it is reasonably possible that the
company's estimate of future cash flows from the Leadon field and associated
fair value could change in the near term due to, among other things, (i)
unfavorable changes in commodity prices or operating costs, (ii) a production
profile that declines more rapidly than currently anticipated, and/or (iii)
unsuccessful results of continued marketing activities or failure to locate a
strategic buyer (or suitable redeployment opportunity). Accordingly, management
anticipates that the Leadon field will be subject to periodic impairment review
until such time as the field is abandoned or sold. If future cash flows or fair
value decrease from that presently estimated, an additional write-down of the
Leadon field could occur in the future.
Impairment losses in 2001 were comprised of a $47 million write-down associated
with the shut-down of the North Sea Hutton field and $29 million for certain
chemical facilities in Belgium and the U.S. In 2001, the company's exploration
and production operating unit suspended production from the Hutton field in the
North Sea due to concerns about the amount of corrosion present in the pipeline,
which would have ultimately required replacement of the pipeline for production
to resume. Due to the small amount of remaining field reserves, the company, as
operator, and the other partners entered into a plan to decommission the field,
which was completed during 2003.
At the end of 2001, the company's chemical - pigment operating unit ceased
production at its titanium dioxide pigment plant in Antwerp, Belgium, as part of
its strategy to improve efficiencies and enhance margins by rationalizing assets
within the chemical unit. A $14 million impairment loss was recognized in
connection with the Antwerp shutdown. Also during 2001, the company's chemical -
other operating unit ceased production at its manganese metal production plant
in Hamilton, Mississippi, due to low-priced imports and softening prices that
made the product no longer profitable. A $13 million impairment loss was
recognized in connection with the Hamilton shutdown. Additionally, the loss of
its only major customer led to a $2 million impairment charge for the shutdown
of a wood-preserving plant in Indianapolis, Indiana.
In connection with the company's divestiture program initiated in 2002, certain
oil and gas properties were identified for disposal and classified as
held-for-sale properties. Upon classification as held-for-sale, the carrying
value of the related properties is analyzed in relation to the estimated fair
value less costs to sell, and losses are recognized if necessary. Upon ultimate
disposal of the properties, any gain or additional loss on sale is recognized.
Losses of $23 million and gains of $68 million were recognized in 2003 upon
conclusion of the divestiture program in the U.S. and North Sea, and for the
sale of the company's interest in the South China Sea (Liuhua field) and other
noncore U.S. properties (onshore and Gulf of Mexico shelf areas). The company
recognized losses of $176 million in 2002 associated with oil and gas properties
held for sale in the U.S. (onshore and Gulf of Mexico shelf areas), the U.K.
North Sea and Ecuador. Proceeds realized from these disposals totaled $119
million in 2003 and $374 million in 2002. The proceeds from the sale of these
properties have been used to reduce long-term debt.
The chemical - pigment operating unit began production through a new
high-productivity oxidation line at the Savannah, Georgia, chloride process
pigment plant in January 2004. This new technology results in low-cost,
incremental capacity increases through modification of existing chloride
oxidation lines and allows for improved operating efficiencies through
simplification of hardware configurations and reduced maintenance requirements.
Based on the future outcome of these technological advancements, the company may
need to review its existing configuration at the Savannah plant to optimize the
plant's resources in relation to capacity requirements. The company will
evaluate the performance of the new high-productivity line, analyze the
implications on the capacity of existing assets and have a plan for
reconfiguration, if any, by the latter part of 2004. If the new
high-productivity line performs as expected, the outcome of this review may
result in the deployment of certain assets to alternate uses and/or the need to
idle certain other assets. If this occurs, the future useful life of such assets
may be adjusted, resulting in the acceleration of depreciation expense.
The assets and liabilities of discontinued operations and other assets held for
sale have been reclassified as Assets/Liabilities Associated with Properties
Held for Disposal in the Consolidated Balance Sheet. The company recognized a
net gain on disposal of property, excluding discontinued operations and assets
held for sale, of $1 million in 2003, $1 million in 2002 and $12 million in
2001, which is reflected in Other Income in the Consolidated Statement of
Operations.
22. Common Stock
Changes in common stock issued and treasury stock held for 2003, 2002 and 2001
are as follows:
Common Treasury
(Thousands of shares) Stock Stock
- --------------------------------------------------------------------------------
Balance December 31, 2000 101,417 6,933
Exercise of stock options and stock appreciation rights 533 -
Cancellation of outstanding shares of Kerr-McGee
Operating Corporation (formerly Kerr-McGee
Corporation) (95,118) -
Issuance of stock by Kerr-McGee Corporation
(new holding company) 95,118 -
Shares issued to purchase HS Resources 5,057 -
Cancellation of treasury stock (6,838) (6,838)
Issuance of restricted stock 16 (102)
Forfeiture of restricted stock - 8
Issuance of shares for achievement awards 1 -
------- ------
Balance December 31, 2001 100,186 1
Exercise of stock options 112 -
Issuance of restricted stock 94 (5)
Forfeiture of restricted stock (2) 11
Issuance of shares for achievement awards 1 -
------- ------
Balance December 31, 2002 100,391 7
Exercise of stock options 18 -
Issuance of restricted stock 483 -
Forfeiture of restricted stock - 25
------- ------
Balance December 31, 2003 100,892 32
======= ======
The company has 40 million shares of preferred stock without par value
authorized, and none is issued.
There are 1,107,692 shares of the company's common stock registered in the name
of a wholly owned subsidiary of the company. These shares are not included in
the number of shares shown in the preceding table or in the Consolidated Balance
Sheet. These shares are not entitled to be voted.
Under the 2002 Long-Term Incentive Plan (Plan), the company may grant incentive
opportunities to key employees. The Plan includes provisions for stock, stock
options and performance-related awards. A maximum of 7,000,000 shares of common
stock was authorized for issuance under the Plan in connection with stock
options, stock appreciation rights, restricted stock and performance awards. Of
the total 7,000,000 shares, a maximum of 1,750,000 shares of common stock are
authorized for issuance under the Plan in connection with awards of restricted
stock and performance awards. Restricted stock is awarded in the name of the
employee and, except for the right of disposal, holders have full shareholders'
rights during the period of restriction, including voting rights and the right
to receive dividends. Under the Plan, certain key employees in Europe and
Australia have received stock opportunity grants giving them the opportunity to
earn unrestricted stock in the future provided that certain conditions are met.
These stock opportunity grants do not carry voting privileges or dividend rights
since the related shares are not issued until vested. Restricted stock and stock
opportunity grants generally vest between three and five years. Compensation
expense is recognized over the vesting period and was $10 million, $6 million
and $4 million in 2003, 2002 and 2001, respectively. The company granted
483,000, 99,000 and 118,000 shares of restricted common stock in 2003, 2002 and
2001, respectively, for which the weighted average fair value at the date of
grant was $20 million, $4 million and $7 million, respectively. The company
granted 9,000 stock opportunity shares in 2003 for which the weighted average
fair value at the date of grant was $.4 million. There were no stock opportunity
grants issued in 2002 or 2001.
The company has had a stockholders-rights plan since 1986. The current rights
plan is dated July 26, 2001, and replaced the previous plan prior to its
expiration. Rights were distributed as a dividend at the rate of one right for
each share of the company's common stock and continue to trade together with
each share of common stock. Generally, the rights become exercisable the earlier
of 10 days after a public announcement that a person or group has acquired, or a
tender offer has been made for, 15% or more of the company's then-outstanding
stock. If either of these events occurs, each right would entitle the holder
(other than a holder owning more than 15% of the outstanding stock) to buy the
number of shares of the company's common stock having a market value two times
the exercise price. The exercise price is $215. Generally, the rights may be
redeemed at $.01 per right until a person or group has acquired 15% or more of
the company's stock. The rights expire in July 2006.
23. Employee Stock Option Plans
The 2002 Long-Term Incentive Plan (2002 Plan) authorizes the issuance of shares
of the company's common stock any time prior to May 13, 2012, in the form of
stock options, restricted stock or performance awards. The options may be
accompanied by stock appreciation rights. A total of 7,000,000 shares of the
company's common stock is authorized to be issued under the 2002 Plan.
In January 1998, the Board of Directors approved a broad-based stock option plan
(BSOP) that provides for the granting of options to purchase the company's
common stock to full-time, nonbargaining-unit employees, except officers. A
total of 1,500,000 shares of common stock is authorized to be issued under the
BSOP.
The 1987 Long-Term Incentive Program (1987 Program), the 1998 Long-Term
Incentive Plan (1998 Plan) and the 2000 Long-Term Incentive Plan (2000 Plan)
authorized the issuance of shares of the company's stock in the form of stock
options, restricted stock or long-term performance awards. The 1987 Program was
terminated when the stockholders approved the 1998 Plan, the 1998 Plan was
terminated with the approval of the 2000 Plan, and the 2000 Plan was terminated
with the approval of the 2002 Plan. No options could be granted under the 1987
Program, the 1998 Plan or the 2000 Plan after each plan's respective termination
date, although options and any accompanying stock appreciation rights
outstanding may be exercised prior to their expiration dates.
The company's employee stock options are fixed-price options granted at the fair
market value of the underlying common stock on the date of the grant. Generally,
one-third of each grant vests and becomes exercisable over a three-year period
immediately following the grant date and expires 10 years after the grant date.
The following table summarizes the stock option transactions under the plans
described above.
2003 2002 2001
---------------------- --------------------- ---------------------
Weighted- Weighted- Weighted-
Average Average Average
Exercise Exercise Exercise
Price per Price per Price per
Options Option Options Option Options Option
- ---------------------------------------------------------------------------------------------------------------------
Outstanding, beginning of year 5,406,424 $59.27 3,433,745 $61.18 3,036,605 $59.66
Options granted 1,353,100 42.93 2,544,562 57.08 1,024,530 65.19
Options exercised (18,500) 44.55 (111,411) 46.78 (532,260) 59.55
Options surrendered upon exercise
of stock appreciation rights - - - - (1,900) 42.63
Options forfeited (189,638) 55.35 (141,116) 58.42 (62,539) 62.78
Options expired (132,667) 57.78 (319,356) 67.09 (30,691) 63.74
--------- --------- ---------
Outstanding, end of year 6,418,719 56.02 5,406,424 59.27 3,433,745 61.18
========= ========= =========
Exercisable, end of year 3,382,550 59.81 2,179,960 59.60 1,935,880 59.32
========= ========= =========
The following table summarizes information about stock options issued under the
plans described above that are outstanding and exercisable at December 31, 2003:
Options Outstanding Options Exercisable
-------------------------------------------------------------------- ------------------------------
Weighted- Weighted- Weighted-
Average Average Average
Range of Exercise Remaining Exercise Exercise
Prices per Contractual Price per Price per
Options Option Life (years) Option Options Option
- ----------------------------------------------------------------------------------------------------------------
9,457 $30.00 - $39.99 1.5 $34.19 9,457 $34.19
1,587,178 40.00 - 49.99 7.9 42.88 278,603 42.63
1,950,998 50.00 - 59.99 6.4 55.10 1,105,917 55.82
2,751,442 60.00 - 69.99 6.5 63.57 1,868,929 63.98
119,644 70.00 - 79.99 2.2 73.41 119,644 73.41
- --------- ---------
6,418,719 30.00 - 79.99 6.7 56.02 3,382,550 59.81
- ----------------------------------------------------------------------------------------------------------------
24. Employee Benefit Plans
The company has both noncontributory and contributory defined-benefit retirement
plans and company-sponsored contributory postretirement plans for health care
and life insurance. Most employees are covered under the company's retirement
plans, and substantially all U.S. employees may become eligible for the
postretirement benefits if they reach retirement age while working for the
company. Kerr-McGee uses a December 31 measurement date for its plans. In 2003,
the company recognized a curtailment loss with respect to pension and
postretirement benefits in connection with its work-force reduction program and
other plant closures and recognized special termination benefits associated with
its work-force reduction program. These losses have been reflected in the
disclosures below.
In December 2003, the FASB issued FAS 132 (revised 2003), "Employers'
Disclosures about Pensions and Other Postretirement Benefits," (FAS 132). FAS
132 does not change the measurement or recognition of those plans; however,
certain additional disclosures are required by the new standard and are included
herein. Additional disclosures for the company's foreign plans will be delayed
for one year as permitted by the new standard.
Following are the changes in the benefit obligations during the past two years:
Postretirement
Retirement Plans Health and Life Plans
----------------------- ---------------------
(Millions of dollars) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------
Benefit obligation, beginning of year $1,147 $1,075 $327 $271
Service cost 25 24 3 3
Interest cost 74 76 17 19
Plan amendments (3) - 10 -
Net actuarial loss (gain) 84 60 (28) 53
Foreign exchange rate changes 17 12 - -
Contributions by plan participants - - 9 6
Special termination benefits and
curtailment losses 28 - 9 -
Benefits paid (122) (100) (33) (25)
------ ------ ---- ----
Benefit obligation, end of year $1,250 $1,147 $314 $327
====== ====== ==== ====
The benefit amount that can be covered by the retirement plans that qualify
under the Employee Retirement Income Security Act of 1974 (ERISA) is limited by
both ERISA and the Internal Revenue Code. Therefore, the company has unfunded
supplemental plans designed to maintain benefits for all employees at the plan
formula level and to provide senior executives with benefits equal to a
specified percentage of their final average compensation. The projected benefit
obligation and accumulated benefit obligation for the U.S and certain foreign
unfunded retirement plans, excluding the under-funded U.K. plan discussed below,
were $60 million and $51 million, respectively, at December 31, 2003, and $58
million and $47 million, respectively, at December 31, 2002. Although not
considered plan assets, a grantor trust was established from which payments for
certain of these U.S. supplemental plans are made. The trust had a balance of
$37 million at year-end 2003 and at year-end 2002. The postretirement plans are
also unfunded. In addition, the company has an under-funded foreign pension plan
covering employees in the United Kingdom. The projected benefit obligation and
accumulated benefit obligation for that plan at year-end 2003 were $75 million
and $63 million, respectively, and were $50 million and $45 million,
respectively, at year-end 2002. The market value of plan assets for the U.K.
plan was $44 million at December 31, 2003, resulting in an under-funded status
for the plan of $31 million.
Following are the changes in the fair value of plan assets during the past two
years and the reconciliation of the plans' funded status to the amounts
recognized in the financial statements at December 31, 2003 and 2002:
Postretirement
Retirement Plans Health and Life Plans
------------------------- -----------------------
(Millions of dollars) 2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------------------
Fair value of plan assets, beginning of year $ 1,190 $ 1,364 $ - $ -
Actual return on plan assets 198 (90) - -
Employer contributions (1) 5 6 24 18
Participant contributions - - 9 7
Foreign exchange rate changes 12 10 - -
Benefits paid (122) (100) (33) (25)
------- ------- ----- -----
Fair value of plan assets, end of year (2) 1,283 1,190 - -
Benefit obligation (1,250) (1,147) (314) (327)
------- ------- ----- -----
Funded status of plans - over (under) 33 43 (314) (327)
Amounts not recognized in the
Consolidated Balance Sheet -
Prior service costs 58 79 12 3
Net actuarial loss 106 83 68 96
------- ------- ----- -----
Prepaid expense (accrued liability) $ 197 $ 205 $(234) $(228)
======= ======= ===== =====
Accumulated benefit obligation $(1,147) $(1,046)
======= =======
(1) No contributions are expected in 2004 for the U.S. qualified retirement
plan. Kerr-McGee Corporation expects to contribute $2 million to its U.S.
nonqualified retirement plans in 2004.
(2) The fair value of plan assets for the U.S. qualified retirement plan was
$1.188 billion at December 31, 2003.
Following is the classification of the amounts recognized in the Consolidated
Balance Sheet at December 31, 2003 and 2002:
Postretirement
Retirement Plans Health and Life Plans
---------------------- -----------------------
(Millions of dollars) 2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------------------
Prepaid benefits expense $230 $240 $ - $ -
Accrued benefit liability (72) (62) (234) (228)
Additional minimum liability -
intangible asset 1 1 - -
Accumulated other comprehensive
income (before tax) 38 26 - -
---- ---- ----- -----
Total $197 $205 $(234) $(228)
==== ==== ===== =====
For 2003, 2002 and 2001, the company had after-tax losses of $7 million, $14
million and $2 million, respectively, included in other comprehensive income
resulting from changes in the additional minimum pension liability.
Total costs recognized for employee retirement and postretirement benefit plans
for each of the years ended December 31, 2003, 2002 and 2001, were as follows:
Postretirement
Retirement Plans Health and Life Plans
------------------------------- -------------------------------
(Millions of dollars) 2003 2002 2001 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Net periodic cost -
Service cost $ 25 $ 24 $ 22 $ 3 $ 3 $ 2
Interest cost 73 76 73 17 19 17
Expected return on plan assets (122) (130) (124) - - -
Special termination benefits,
curtailment loss 38 - - 10 - -
Net amortization -
Transition asset - - (1) - - -
Prior service cost 9 10 9 - 1 1
Net actuarial (gain) loss (9) (16) (23) - 1 -
----- ----- ----- --- --- ---
Total $ 14 $ (36) $ (44) $30 $24 $20
===== ===== ===== === === ===
The following assumptions were used in estimating the net periodic expense:
2003 2002 2001
-------------------------- --------------------------- -----------------------
United United United
States International States International States International
- --------------------------------------------------------------------------------------------------------------------------
Discount rate 6.75% 5.5 - 5.75% 7.25% 5.75% 7.75% 5.5 - 6.5%
Expected return on 8.5 5.25 - 7.25 9.0 5.75 - 7.0 9.0 7.0
plan assets
Rate of compensation 4.5 2.5 - 6.5 5.0 2.5 - 7.5 5.0 3.0 - 5.0
increases
The following assumptions were used in estimating the actuarial present value of
the plans' benefit obligations:
2003 2002 2001
--------------------------- --------------------------- ------------------------
United United United
States International States International States International
- --------------------------------------------------------------------------------------------------------------------------
Discount rate 6.25% 5.25 - 5.5% 6.75% 5.5 - 5.75% 7.25% 5.75%
Rate of compensation 4.5 2.75 - 5.0 4.5 2.5 - 6.5 5.0 2.5 - 7.5
increases
The health care cost trend rates used to determine the year-end 2003
postretirement benefit obligation were 10% in 2004, gradually declining to 5% in
the year 2009 and thereafter. A 1% increase in the assumed health care cost
trend rate for each future year would increase the postretirement benefit
obligation at December 31, 2003, by $15 million and increase the aggregate of
the service and interest cost components of net periodic postretirement expense
for 2003 by $1 million. A 1% decrease in the trend rate for each future year
would reduce the benefit obligation at year-end 2003 by $15 million and decrease
the aggregate of the service and interest cost components of the net periodic
postretirement expense for 2003 by $1 million.
Asset categories for the company's U.S. funded retirement plan (the Plan) and
the weighted-average asset allocations at December 31, 2003 and 2002, by asset
category are as follows:
Plan Assets
at December 31,
-------------------------
2003 2002
- --------------------------------------------------------------------------------
Equity securities 55% 42%
Debt securities 41% 56%
Cash 4% 2%
---- ----
Total 100% 100%
==== ====
The Plan is administered by a board appointed committee that maintains a well
developed investment policy stating the guidelines for the performance and
allocation of plan assets, performance review procedures, and updating of the
policy itself. The committee adheres to traditional capital market pricing
theory, recognizing that over the long term the risk of owning equity securities
is generally rewarded with a greater return than available from fixed-income
investments. However, the committee also recognizes that the avoidance of large
risks is desirable and may forego certain higher return opportunities in order
to preserve a lower-risk investment profile. At least annually, the Plan's asset
allocation guidelines are reviewed in light of evolving risk and return
expectations. Current guidelines permit the committee to manage the allocation
of funds between equity and debt securities at its discretion; however,
throughout 2002 and 2003, the committee has maintained an allocation of assets
in the range of 40-60% equity securities and 40-60% debt securities. The
long-term return forecasting methodology for both equity and fixed-income
securities is based on a capital asset pricing model using historical data.
Based on the asset allocation at the end of 2003, the expected long-term rate of
return of plan assets is forecasted to be 8.5%.
Substantially all of the plan's assets are invested with eight select equity
fund managers and six fixed-income fund managers. At year-end 2003 and 2002,
equity securities held by the plan included $2 million of Kerr-McGee stock, or
50,737 shares. Dividends paid on these shares were less than $100,000 in 2003
and 2002. To control risk, equity fund managers are prohibited from investing in
commodities, including all futures contracts, purchasing letter stock, short
selling, option trading, margin and Kerr-McGee securities, but are permitted to
invest in U.S. common stock, U.S. preferred stock, U.S. securities convertible
into common stock, common stock of foreign companies listed on major U.S.
exchanges, common stock of foreign companies listed on foreign exchanges,
covered call writing, and cash and cash equivalents. Fixed-income fund managers
are prohibited from investing in foreign debt securities, direct real estate
mortgages or commingled real estate funds, private placements, purchase of
guaranteed investment contracts, and Kerr-McGee securities, but are permitted to
invest in debt securities issued by the U.S. government, its agencies or
instrumentalities, corporate bonds, debentures and other forms of corporate debt
obligations, commercial paper rated A1/P1, certificates of deposit or bankers
acceptances in amounts of $100,000 or less of U.S. banks insured by the FDIC,
and financial futures contracts on U.S. Treasury obligations and options on such
contracts where these investments are for the sole purpose of hedging. Some
exceptions to the plan's investment restrictions are granted to equity and fixed
income mutual funds. As long as a mutual fund remains in compliance with its own
prospectus with regard to investment restrictions it is deemed to be in
compliance with plan policy. All securities held in fixed-income fund manager
accounts must be rated no less than Baa3 or its equivalent and each fund
manager's portfolio should have an average credit rating that is A or better.
On December 8, 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 ("the Act") was signed into law. The Act expanded
Medicare to include, for the first time, coverage for prescription drugs.
Kerr-McGee expects that this legislation will eventually reduce the cost
associated with its retiree medical programs. However, at this point,
Kerr-McGee's investigation into its options in response to the legislation is
preliminary and guidance from various governmental and regulatory agencies
concerning the requirements that must be met to obtain these cost reductions, as
well as the manner in which such savings should be measured, has not yet been
issued.
Because of various uncertainties surrounding Kerr-McGee's response to this
legislation and the appropriate accounting methodology for this event, the
company has elected to defer financial recognition of the impact of this
legislation until the FASB issues final accounting guidance. When issued, the
final guidance could require the company to change previously reported
information. This one-time deferral election is permitted under FASB Staff
Position No. 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003."
25. Employee Stock Ownership Plan
In 1989, the company's Board of Directors approved a leveraged Employee Stock
Ownership Plan (ESOP) into which is paid the company's matching contribution for
the employees' contributions to the Kerr-McGee Corporation Savings Investment
Plan (SIP). The ESOP was amended in 2001 to provide matching contributions for
the employees' contributions made to the Kerr-McGee Pigments (Savannah) Inc.,
Employees' Savings Plan, a savings plan for the bargaining-unit employees at the
company's Savannah, Georgia, pigment plant (Savannah Plan). Most of the
company's employees are eligible to participate in both the ESOP and the SIP or
Savannah Plan. Although the ESOP, SIP and Savannah Plan are separate plans,
matching contributions to the ESOP are contingent upon participants'
contributions to the SIP or Savannah Plan. Additionally, HS Resources had a
savings plan at the time of acquisition, which had only discretionary cash
contributions by the employer. Kerr-McGee paid $1 million into this plan in
December 2001. Beginning January 1, 2002, the remaining HS Resources employees
became eligible to participate in the Kerr-McGee ESOP and SIP.
In 1989, the ESOP trust borrowed $125 million from a group of lending
institutions and used the proceeds to purchase approximately three million
shares of the company's treasury stock. The company used the $125 million in
proceeds from the sale of the stock to acquire shares of its common stock in
open-market and privately negotiated transactions. In 1996, a portion of the
third-party borrowings was replaced with a note payable to the company (sponsor
financing), which was fully paid in 2003. The third-party borrowings are
guaranteed by the company and are reflected in the Consolidated Balance Sheet as
Long-Term Debt (see Note 9).
The Oryx Capital Accumulation Plan (CAP) was a combined stock bonus and
leveraged employee stock ownership plan available to substantially all U.S.
employees of the former Oryx operations. In 1989, Oryx privately placed $110
million of notes pursuant to the provisions of the CAP. Oryx loaned the proceeds
to the CAP, which used the funds to purchase Oryx common stock that was placed
in a trust. This loan was sponsor financing and does not appear in the
accompanying balance sheet. The remaining balance of the sponsor financing is
$33 million at year-end 2003. During 1999, the company merged the Oryx CAP into
the ESOP and SIP.
The company stock owned by the ESOP trust is held in a loan suspense account.
Deferred compensation, representing the unallocated ESOP shares, is reflected as
a reduction of stockholders' equity. The company's matching contribution and
dividends on the shares held by the ESOP trust are used to repay the loan, and
stock is released from the loan suspense account as the principal and interest
are paid. The expense is recognized and stock is then allocated to participants'
accounts at market value as the participants' contributions are made to the SIP.
Long-term debt is reduced as payments are made on the third-party financing.
Dividends paid on the common stock held in participants' accounts are also used
to repay the loans, and stock with a market value equal to the amount of
dividends is allocated to participants' accounts.
Shares of stock allocated to the ESOP participants' accounts and in the loan
suspense account are as follows:
(Thousands of shares) 2003 2002
- --------------------------------------------------------------------------------
Participants' accounts 1,496 1,448
Loan suspense account 315 630
The shares in the loan suspense account at December 31, 2003, included
approximately 5,000 released shares that were allocated to participants'
accounts in January 2004. At December 31, 2002, the shares in the loan suspense
account included approximately 6,000 released shares that were allocated to
participants' accounts in January 2003.
All ESOP shares are considered outstanding for net income per-share
calculations. Dividends on ESOP shares are charged to retained earnings.
Compensation expense related to the plan was $33 million, $19 million and $12
million in 2003, 2002 and 2001, respectively. These amounts include interest
expense incurred on the third-party ESOP debt, which was not material for 2003,
2002 or 2001. The company contributed $42 million, $27 million and $22 million
to the ESOP in 2003, 2002 and 2001, respectively. Included in the respective
contributions were $37 million, $19 million and $12 million for principal and
interest payments on the sponsor financings. The cash contributions are net of
$4 million, $5 million and $4 million for the dividends paid on the company
stock held by the ESOP trust in 2003, 2002 and 2001, respectively.
26. Earnings Per Share
Basic earnings per share includes no dilution and is computed by dividing income
or loss from continuing operations available to common stockholders by the
weighted-average number of common shares outstanding for the period. Diluted
earnings per share reflects the potential dilution that could occur if security
interests were exercised or converted into common stock.
The following table sets forth the computation of basic and diluted earnings per
share for the years ended December 31, 2003, 2002 and 2001.
2003 2002 2001
---------------------------- ---------------------------- ------------------------------
(Millions of dollars, Income Loss Income
except from Per- from Per- from Per-
per-share amounts and Continuing share Continuing share Continuing share
thousands of shares) Operations Shares Income Operations Shares Loss Operations Shares Income
- -------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share $254 100,145 $2.52 $(611) 100,330 $(6.09) $476 97,106 $4.91
Effect of dilutive securities:
5-1/4% convertible
debentures 21 9,824 - - 22 9,824
Restricted stock - 697 - - - -
Employee stock options - 17 - - - 181
---- ------- ----- ----- ------- ------ ---- ------- -----
Diluted earnings per share $275 110,683 $2.48 $(611) 100,330 $(6.09) $498 107,111 $4.65
==== ======= ===== ===== ======= ====== ==== ======= =====
Not included in the calculation of the denominator for diluted earnings per
share were 4,866,144, 4,688,853 and 2,219,858 employee stock options outstanding
at year-end 2003, 2002 and 2001, respectively. The inclusion of these options
would have been antidilutive since they were not "in the money" at the end of
the respective years. Since the company incurred a loss from continuing
operations for 2002, no dilution of the loss per share would result from an
additional 330,003 stock options that were "in the money" at year-end 2002 or
the assumed conversion of the convertible debentures, discussed below.
The company has reserved 9,823,778 shares of common stock for issuance to the
owners of its 5-1/4% Convertible Subordinated Debentures due 2010. These
debentures are convertible into the company's common stock at any time prior to
maturity at $61.08 per share of common stock.
27. Condensed Consolidating Financial Information
In connection with the acquisition of HS Resources in 2001, a holding company
structure was implemented. The company formed a new holding company, Kerr-McGee
Holdco, which then changed its name to Kerr-McGee Corporation. The former
Kerr-McGee Corporation's name was changed to Kerr-McGee Operating Corporation.
At the end of 2002, another reorganization took place whereby among other
changes, Kerr-McGee Operating Corporation distributed its investment in certain
subsidiaries (primarily the oil and gas operating subsidiaries) to a newly
formed intermediate holding company, Kerr-McGee Worldwide Corporation.
Kerr-McGee Operating Corporation formed a new subsidiary, Kerr-McGee Chemical
Worldwide LLC, and merged into it.
On October 3, 2001, Kerr-McGee Corporation issued $1.5 billion of long-term
notes in a public offering. The notes are general, unsecured obligations of the
company and rank in parity with all of the company's other unsecured and
unsubordinated indebtedness. Kerr-McGee Chemical Worldwide LLC (formerly
Kerr-McGee Operating Corporation, which was previously the original Kerr-McGee
Corporation) and Kerr-McGee Rocky Mountain Corporation have guaranteed the
notes. Additionally Kerr-McGee Corporation has guaranteed all indebtedness of
its subsidiaries, including the indebtedness assumed in the purchase of HS
Resources. As a result of these guarantee arrangements, the company is required
to present condensed consolidating financial information. The top holding
company is Kerr-McGee Corporation. The guarantor subsidiaries include Kerr-McGee
Chemical Worldwide LLC in 2003 and 2002, its predecessor, Kerr-McGee Operating
Corporation in 2001, along with Kerr-McGee Rocky Mountain Corporation in 2003,
2002 and 2001.
The following tables present condensed consolidating financial information for
(a) Kerr-McGee Corporation, the parent company, (b) the guarantor subsidiaries,
and (c) the non-guarantor subsidiaries on a consolidated basis.
Condensed Consolidating Statement of Operations for the Year Ended December 31, 2003
- ----------------------------------------------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------
Revenues $ - $694 $3,491 $ - $4,185
----- ---- ------ ----- ------
Costs and Expenses
Costs and operating expenses - 351 1,319 (2) 1,668
Selling, general and administrative
expenses - 14 357 - 371
Shipping and handling expenses - 9 131 - 140
Depreciation and depletion - 122 623 - 745
Accretion expense - 2 23 - 25
Impairments on assets held for use - - 14 - 14
Loss (gain) associated with assets
held for sale - 1 (46) - (45)
Exploration, including dry holes and
amortization of undeveloped leases - 15 339 - 354
Taxes, other than income taxes - 25 73 - 98
Provision for environmental remediation
and restoration, net of reimbursements - 31 31 - 62
Interest and debt expense 116 36 277 (178) 251
----- ---- ------ ----- ------
Total Costs and Expenses 116 606 3,141 (180) 3,683
----- ---- ------ ----- ------
(116) 88 350 180 502
Other Income (Expense) 506 (9) 65 (621) (59)
----- ---- ------ ----- ------
Income from Continuing Operations
before Income Taxes 390 79 415 (441) 443
Benefit (Provision) for Income Taxes (189) 23 (171) 148 (189)
----- ---- ------ ----- ------
Income from Continuing Operations 201 102 244 (293) 254
Income (Loss) from Discontinued Operations,
net of taxes - 12 (10) (2) -
Cumulative Effect of Change in Accounting
Principle, net of taxes - (1) (34) - (35)
----- ---- ------ ----- ------
Net Income $ 201 $113 $ 200 $(295) $ 219
===== ==== ====== ===== ======
Condensed Consolidating Statement of Operations for the Year Ended December 31, 2002
- ----------------------------------------------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------
Revenues $ - $351 $3,554 $(259) $3,646
----- ---- ------ ----- ------
Costs and Expenses
Costs and operating expenses - 105 1,611 (260) 1,456
Selling, general and administrative
expenses - 4 309 - 313
Shipping and handling expenses - 9 116 - 125
Depreciation and depletion - 121 693 - 814
Impairments on assets held for use - 3 649 - 652
Loss (gain) associated with assets
held for sale - - 176 - 176
Exploration, including dry holes and
amortization of undeveloped leases - 12 261 - 273
Taxes, other than income taxes - 16 88 - 104
Provision for environmental remediation
and restoration, net of reimbursements - - 80 - 80
Interest and debt expense 115 36 323 (199) 275
----- ---- ------ ----- ------
Total Costs and Expenses 115 306 4,306 (459) 4,268
----- ---- ------ ----- ------
(115) 45 (752) 200 (622)
Other Income (Expense) (438) 484 (127) 46 (35)
----- ---- ------ ----- ------
Income (Loss) from Continuing Operations
before Income Taxes (553) 529 (879) 246 (657)
Benefit (Provision) for Income Taxes 68 (26) 44 (40) 46
----- ---- ------ ----- ------
Income (Loss) from Continuing Operations (485) 503 (835) 206 (611)
Income from Discontinued Operations,
net of taxes - - 126 - 126
----- ---- ------ ----- ------
Net Income (Loss) $(485) $503 $ (709) $ 206 $ (485)
===== ==== ====== ===== ======
Condensed Consolidating Statement of Operations for the Year Ended December 31, 2001
- ----------------------------------------------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------
Revenues $ - $ 122 $3,790 $ (357) $3,555
----- ------ ------ ------- ------
Costs and Expenses
Costs and operating expenses - 47 1,574 (357) 1,264
Selling, general and administrative
expenses - 69 159 - 228
Shipping and handling expenses - 2 109 - 111
Depreciation and depletion - 57 690 - 747
Impairments on assets held for use - - 76 - 76
Exploration, including dry holes and
amortization of undeveloped leases - 15 195 - 210
Taxes, other than income taxes - 13 101 - 114
Provision for environmental remediation
and restoration, net of reimbursements - 82 - - 82
Interest and debt expense 36 202 121 (164) 195
----- ------ ------ ------- ------
Total Costs and Expenses 36 487 3,025 (521) 3,027
----- ------ ------ ------- ------
(36) (365) 765 164 528
Other Income 809 1,205 150 (1,940) 224
----- ------ ------ ------- ------
Income from Continuing Operations
before Income Taxes 773 840 915 (1,776) 752
Provision for Income Taxes (287) (209) (362) 582 (276)
----- ------ ------ ------- ------
Income from Continuing Operations 486 631 553 (1,194) 476
Income from Discontinued Operations,
net of taxes - - 30 - 30
Cumulative Effect of Change in Accounting
Principle, net of taxes - (21) 1 - (20)
----- ------ ------ ------- ------
Net Income $ 486 $ 610 $ 584 $(1,194) $ 486
===== ====== ====== ======= ======
Condensed Consolidating Balance Sheet as of December 31, 2003
- -------------------------------------------------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- -------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash $ 2 $ - $ 140 $ - $ 142
Accounts receivable - 125 458 - 583
Intercompany receivables 795 (26) 2,110 (2,879) -
Inventories - 6 388 - 394
Deposits, prepaid expenses and other assets - 18 619 - 637
Current assets associated with properties
held for disposal - - 1 - 1
------ ------ ------ ------- -------
Total Current Assets 797 123 3,716 (2,879) 1,757
Investments in and Advances to Subsidiaries 3,949 519 (20) (4,448) -
Investments and Other Assets 10 96 538 (79) 565
Property, Plant and Equipment - Net - 1,975 5,492 - 7,467
Goodwill - 346 11 - 357
Long-Term Assets Associated with Properties
Held for Disposal - - 28 - 28
------ ------ ------ ------- -------
Total Assets $4,756 $3,059 $9,765 $(7,406) $10,174
====== ====== ====== ======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 45 $ 81 $ 609 $ - $ 735
Intercompany borrowings 69 563 2,183 (2,815) -
Long-term debt due within one year - - 574 - 574
Other current liabilities 37 132 754 - 923
------ ------ ------ ------- -------
Total Current Liabilities 151 776 4,120 (2,815) 2,232
Investments by and Advances from Parent - - 598 (598) -
Long-Term Debt 1,829 - 1,252 - 3,081
Deferred Credits and Reserves (6) 678 1,555 (2) 2,225
Stockholders' Equity 2,782 1,605 2,240 (3,991) 2,636
------ ------ ------ ------- -------
Total Liabilities and Stockholders' Equity $4,756 $3,059 $9,765 $(7,406) $10,174
====== ====== ====== ======= =======
Condensed Consolidating Balance Sheet as of December 31, 2002
- -------------------------------------------------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- -------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash $ 3 $ - $ 87 $ - $ 90
Accounts receivable - 73 535 - 608
Intercompany receivables 956 46 1,641 (2,643) -
Inventories - 6 396 - 402
Deposits, prepaid expenses and other assets - 60 75 (2) 133
Current assets associated with properties
held for disposal - - 57 - 57
------ ------ ------ ------- ------
Total Current Assets 959 185 2,791 (2,645) 1,290
Investments in and Advances to Subsidiaries 3,673 695 80 (4,448) -
Investments and Other Assets 12 118 986 (81) 1,035
Property, Plant and Equipment - Net - 1,956 5,080 - 7,036
Goodwill - 347 9 - 356
Long-Term Assets Associated with Properties
Held for Disposal - - 187 5 192
------ ------ ------ ------- ------
Total Assets $4,644 $3,301 $9,133 $(7,169) $9,909
====== ====== ====== ======= ======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 45 $ 78 $ 649 $ - $ 772
Intercompany borrowings 68 842 1,732 (2,642) -
Long-term debt due within one year - - 106 - 106
Other current liabilities 18 195 491 26 730
Current liabilities associated with properties
held for disposal - - 2 - 2
------ ------ ------ ------- ------
Total Current Liabilities 131 1,115 2,980 (2,616) 1,610
Long-Term Debt 1,847 - 1,951 - 3,798
Investments by and Advances from Parent - - 729 (729) -
Deferred Credits and Reserves - 675 1,298 (24) 1,949
Long-Term Liabilities Associated with Properties
Held for Disposal - - 16 - 16
Stockholders' Equity 2,666 1,511 2,159 (3,800) 2,536
------ ------ ------ ------- ------
Total Liabilities and Stockholders' Equity $4,644 $3,301 $9,133 $(7,169) $9,909
====== ====== ====== ======= ======
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2003
- --------------------------------------------------------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- --------------------------------------------------------------------------------------------------------------------------------
Cash Flow from Operating Activities
Net income $ 201 $ 113 $ 200 $(295) $ 219
Adjustments to reconcile to net cash provided
by operating activities -
Depreciation, depletion and amortization - 127 687 - 814
Accretion expense - 2 23 - 25
Deferred income taxes (6) (8) 170 - 156
Dry hole costs - - 181 - 181
Impairments on assets held for use - - 14 - 14
Gain associated with assets held for sale - - (39) - (39)
Cumulative effect of change in accounting principle - 1 34 - 35
Equity in loss (earnings) of subsidiaries (227) 65 - 162 -
Provision for environmental remediation and
restoration, net of reimbursements - 31 31 - 62
(Gains) losses on asset retirements and sales - (12) 11 - (1)
Noncash items affecting net income 1 34 109 - 144
Other net cash provided by (used in) operating
activities 3 (157) 62 - (92)
----- ----- ------ ----- ------
Net cash provided by (used in) operating
activities (28) 196 1,483 (133) 1,518
----- ----- ------ ----- ------
Cash Flow from Investing Activities
Capital expenditures - (129) (852) - (981)
Dry hole costs - - (181) - (181)
Acquisitions - - (110) - (110)
Proceeds from sales of assets - 8 296 - 304
Other investing activities - - 17 - 17
----- ----- ------ ----- ------
Net cash used in investing
activities - (121) (830) - (951)
----- ----- ------ ----- ------
Cash Flow from Financing Activities
Issuance of long-term debt - - 31 - 31
Increase (decrease) in intercompany notes payable 226 (75) (152) 1 -
Repayment of long-term debt (18) - (351) - (369)
Dividends paid (181) - (134) 134 (181)
Other financing activities - - 1 (2) (1)
----- ----- ------ ----- ------
Net cash provided by (used in) financing
activities 27 (75) (605) 133 (520)
----- ----- ------ ----- ------
Effects of Exchange Rate Changes on Cash and Cash
Equivalents - - 5 - 5
----- ----- ------ ----- ------
Net Increase (Decrease) in Cash and Cash Equivalents (1) - 53 - 52
Cash and Cash Equivalents at Beginning of Year 3 - 87 - 90
----- ----- ------ ----- ------
Cash and Cash Equivalents at End of Year $ 2 $ - $ 140 $ - $ 142
===== ===== ====== ===== ======
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2002
- --------------------------------------------------------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- --------------------------------------------------------------------------------------------------------------------------------
Cash Flow from Operating Activities
Net income (loss) $(485) $ 503 $ (709) $ 206 $ (485)
Adjustments to reconcile to net cash provided by
operating activities -
Depreciation, depletion and amortization - 124 760 - 884
Deferred income taxes - 9 (121) - (112)
Dry hole costs - - 113 - 113
Impairments on assets held for use - 3 649 - 652
Loss associated with assets held for sale - - 210 - 210
Equity in loss (earnings) of subsidiaries 465 (25) - (440) -
Provision for environmental remediation and
restoration, net of reimbursements - - 89 - 89
Gains on asset retirements and sales - - (110) - (110)
Noncash items affecting net income - (13) 113 - 100
Other net cash provided by (used in) operating
activities (16) 328 (205) - 107
----- ----- ------ ----- ------
Net cash provided by (used in) operating
activities (36) 929 789 (234) 1,448
----- ----- ------ ----- ------
Cash Flow from Investing Activities
Capital expenditures - (179) (980) - (1,159)
Dry hole costs - - (113) - (113)
Acquisitions - - (24) - (24)
Other investing activities - (639) 1,342 - 703
----- ----- ------ ----- ------
Net cash provided by (used in) investing
activities - (818) 225 - (593)
----- ----- ------ ----- ------
Cash Flow from Financing Activities
Issuance of long-term debt 350 - 68 - 418
Issuance of common stock 5 - - - 5
Increase (decrease) in intercompany notes payable (135) (112) 248 (1) -
Decrease in short-term borrowings - - (8) - (8)
Repayment of long-term debt - - (1,093) - (1,093)
Dividends paid (181) - (235) 235 (181)
----- ----- ------ ----- ------
Net cash provided by (used in) financing
activities 39 (112) (1,020) 234 (859)
----- ----- ------ ----- ------
Effects of Exchange Rate Changes on Cash and Cash
Equivalents - - 3 - 3
----- ----- ------ ----- ------
Net Increase (Decrease) in Cash and Cash Equivalents 3 (1) (3) - (1)
Cash and Cash Equivalents at Beginning of Year - 1 90 - 91
----- ----- ------ ----- ------
Cash and Cash Equivalents at End of Year $ 3 $ - $ 87 $ - $ 90
===== ===== ====== ===== ======
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2001
- --------------------------------------------------------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- --------------------------------------------------------------------------------------------------------------------------------
Cash Flow from Operating Activities
Net income $ 486 $ 610 $ 584 $(1,194) $ 486
Adjustments to reconcile to net cash provided by
operating activities -
Depreciation, depletion and amortization - 60 753 - 813
Deferred income taxes - 166 39 - 205
Dry hole costs - - 72 - 72
Impairments on assets held for use - - 76 - 76
Cumulative effect of change in accounting principle - 21 (1) - 20
Equity in earnings of subsidiaries (520) (586) - 1,106 -
Provision for environmental remediation and
restoration, net of reimbursements - 82 - - 82
Gains on asset retirements and sales - (3) (9) - (12)
Noncash items affecting net income - (222) 33 - (189)
Other net cash provided by (used in) operating
activities (463) 656 (700) 97 (410)
------ ------- ------- ------- -------
Net cash provided by (used in) operating
activities (497) 784 847 9 1,143
------ ------- ------- ------- -------
Cash Flow from Investing Activities
Capital expenditures - (95) (1,697) - (1,792)
Dry hole costs - - (72) - (72)
Acquisitions (955) - (23) - (978)
Other investing activities - 6 (61) - (55)
------ ------- ------- ------- -------
Net cash used in investing activities (955) (89) (1,853) - (2,897)
------ ------- ------- ------- -------
Cash Flow from Financing Activities
Issuance of long-term debt 1,497 (10) 1,026 - 2,513
Issuance of common stock - 32 - - 32
Increase (decrease) in intercompany notes payable - 1,009 - (1,009) -
Increase (decrease) in short-term borrowings - (11) 2 - (9)
Repayment of long-term debt - (586) (75) - (661)
Dividends paid (45) (1,128) - 1,000 (173)
------ ------- ------- ------- -------
Net cash provided by (used in) financing
activities 1,452 (694) 953 (9) 1,702
------ ------- ------- ------- -------
Effects of Exchange Rate Changes on Cash and Cash
Equivalents - - (1) - (1)
------ ------- ------- ------- -------
Net Increase (Decrease) in Cash and Cash Equivalents - 1 (54) - (53)
Cash and Cash Equivalents at Beginning of Year - 3 141 - 144
------ ------- ------- ------- -------
Cash and Cash Equivalents at End of Year $ - $ 4 $ 87 $ - $ 91
====== ======= ======= ======= =======
28. Reporting by Business Segments and Geographic Locations
The company has three reportable segments: oil and gas exploration and
production, production and marketing of titanium dioxide pigment, and production
and marketing of other chemicals. The exploration and production unit explores
for and produces oil and gas in the United States, the United Kingdom sector of
the North Sea and China. Exploration efforts also extend to Australia, Benin,
Bahamas, Brazil, Gabon, Morocco, Western Sahara, Canada, Yemen and the Danish
and Norwegian sectors of the North Sea. The chemical unit primarily produces and
markets titanium dioxide pigment and has production facilities in the United
States, Australia, Germany and the Netherlands. Other chemicals include the
company's electrolytic manufacturing and marketing operations and forest
products treatment business. All of these operations are in the United States.
Crude oil sales to individually significant customers totaled $446 million to BP
PLC and subsidiaries (BP) in 2003; $408 million to Texon L.P. and $450 million
to BP in 2002; and $408 million to Texon L.P. and $401 million to BP in 2001. In
addition, natural gas sales totaled $103 million to BP and $782 million to
Cinergy Marketing & Trading LP (Cinergy) in 2003; $72 million to BP and $496
million to Cinergy in 2002; and $682 million to Cinergy in 2001. Sales to
subsidiary companies are eliminated as described in Note 1.
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Revenues -
Exploration and production $2,923 $2,450 $2,428
------ ------ ------
Chemicals -
Pigment 1,079 995 931
Other 183 201 196
------ ------ ------
Total Chemicals 1,262 1,196 1,127
------ ------ ------
Total $4,185 $3,646 $3,555
====== ====== ======
Operating profit (loss) -
Exploration and production $1,002 $ (140) $ 922
------ ------ ------
Chemicals -
Pigment (13) 24 (22)
Other (35) (23) (17)
------ ------ ------
Total Chemicals (48) 1 (39)
------ ------ ------
Total 954 (139) 883
------ ------ ------
Net interest expense (246) (270) (185)
Net nonoperating income (expense) (265) (248) 54
Benefit (provision) for income taxes (189) 46 (276)
Discontinued operations, net of taxes - 126 30
Cumulative effect of change in accounting
principle, net of taxes (35) - (20)
------ ------ ------
Net income (loss) $ 219 $ (485) $ 486
====== ====== ======
Depreciation, depletion and amortization -
Exploration and production (1) $ 678 $ 758 $ 675
------ ------ ------
Chemicals -
Pigment 110 97 103
Other 18 20 17
------ ------ ------
Total Chemicals 128 117 120
------ ------ ------
Other 8 6 8
Discontinued operations - 3 10
------ ------ ------
Total $ 814 $ 884 $ 813
====== ====== ======
(1) Includes amortization of nonproducing leasehold costs that is reported in
exploration expense in the Consolidated Statement of Operations.
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Capital expenditures -
Exploration and production
(excludes Gunnison lease of $83) $ 869 $ 988 $ 1,557
------- ------ -------
Chemicals -
Pigment 90 78 139
Other 7 8 14
------- ------ -------
Total Chemicals 97 86 153
------- ------ -------
Other 15 58 15
Discontinued operations - 27 67
------- ------ -------
Total 981 1,159 1,792
------- ------ -------
Exploration expenses -
Exploration and production -
Dry hole costs 181 113 72
Amortization of undeveloped leases 69 67 56
Other 104 93 82
------- ------ -------
Total 354 273 210
------- ------ -------
Total capital expenditures
and exploration expenses $ 1,335 $1,432 $ 2,002
======= ====== =======
Total assets -
Exploration and production $ 7,324 $7,030 $ 8,076
------- ------ -------
Chemicals -
Pigment 1,521 1,413 1,391
Other 212 247 245
------- ------ -------
Total Chemicals 1,733 1,660 1,636
------- ------ -------
Total 9,057 8,690 9,712
Corporate and other assets 1,117 1,038 1,010
Discontinued operations - 181 354
------- ------ -------
Total $10,174 $9,909 $11,076
======= ====== =======
Revenues -
U.S. operations $ 2,860 $2,190 $ 2,125
------- ------ -------
International operations -
North Sea - exploration and production 791 936 935
China - exploration and production 23 30 31
Other - exploration and production - 28 39
Europe - pigment 313 294 258
Australia - pigment 198 168 167
------- ------ -------
1,325 1,456 1,430
------- ------ -------
Total $ 4,185 $3,646 $ 3,555
======= ====== =======
Operating profit (loss) -
U.S. operations $ 622 $ 322 $ 647
------- ------ -------
International operations -
North Sea - exploration and production 353 (412) 318
China - exploration and production 1 7 6
Other - exploration and production (66) (59) (66)
Europe - pigment 14 (21) (53)
Australia - pigment 30 24 31
------- ------ -------
332 (461) 236
------- ------ -------
Total $ 954 $ (139) $ 883
======= ====== =======
Net property, plant and equipment -
U.S. operations $ 5,021 $4,631 $ 4,483
------- ------ -------
International operations -
North Sea - exploration and production 1,874 1,912 2,427
China - exploration and production 165 115 93
Other - exploration and production 4 13 27
Europe - pigment 301 255 226
Australia - pigment 102 110 122
------- ------ -------
2,446 2,405 2,895
------- ------ -------
Total $ 7,467 $7,036 $ 7,378
======= ====== =======
29. Costs Incurred in Crude Oil and Natural Gas Activities
Total expenditures, both capitalized and expensed, for crude oil and natural gas
property acquisition, exploration and development activities for the three years
ended December 31, 2003, are reflected in the following table:
Property
Acquisition Exploration Development
(Millions of dollars) Costs(1) Costs(2) Costs(3) Total
- -------------------------------------------------------------------------------------------------------------------
2003 -
United States $ 121 $357 $ 473 $ 951
North Sea 46 43 55 144
China 1 31 45 77
Other international 1 49 - 50
------ ---- ------ ------
Total finding, development and
acquisition costs incurred 169 480 573 1,222
Asset retirement costs (4) 9 - 2 11
------ ---- ------ ------
Total costs incurred $ 178 $480 $ 575 $1,233
====== ==== ====== ======
2002 -
United States $ 89 $206 $ 426 $ 721
North Sea 55 14 296 365
China - 14 16 30
Other international 2 44 - 46
------ ---- ------ ------
Total continuing operations 146 278 738 1,162
Discontinued operations 2 1 5 8
------ ---- ------ ------
Total costs incurred $ 148 $279 $ 743 $1,170
====== ==== ====== ======
2001 -
United States $1,420 $225 $ 457 $2,102
North Sea - 71 695 766
China - 45 4 49
Other international 3 54 17 74
------ ---- ------ ------
Total continuing operations 1,423 395 1,173 2,991
Discontinued operations - 4 64 68
------ ---- ------ ------
Total costs incurred $1,423 $399 $1,237 $3,059
====== ==== ====== ======
(1) Includes $95 million, $69 million and $1.128 billion applicable to
purchases of reserves in place in 2003, 2002 and 2001, respectively.
(2) Exploration costs include delay rentals, exploratory dry holes, dry hole
and bottom hole contributions, geological and geophysical costs, costs of
carrying and retaining properties, and capital expenditures, such as costs
of drilling and equipping successful exploratory wells.
(3) Development costs include costs incurred to obtain access to proved
reserves (surveying, clearing ground, building roads), to drill and equip
development wells, and to acquire, construct and install production
facilities and improved-recovery systems. Development costs also include
costs of developmental dry holes.
(4) Asset retirement costs represent the noncash increase in property, plant
and equipment recognized when initially recording a liability for
abandonment obligations (discounted) associated with the company's oil and
gas wells and platforms. Asset retirement costs are depleted on a
unit-of-production basis over the useful life of the related field. See
further discussion in Note 1 regarding the 2003 adoption of FAS 143.
30. Results of Operations from Crude Oil and Natural Gas Activities
The results of operations from crude oil and natural gas activities for the
three years ended December 31, 2003, consist of the following:
Loss (Gain) on
Held for Sale Income Results of
Production Depreciation, Properties Tax Operations,
(Lifting) Other Exploration Depletion and and Asset Expense Producing
(Millions of dollars) Revenues Costs Costs Expenses Accretion Impairments (Benefit) Activities
- ------------------------------------------------------------------------------------------------------------------------------------
2003 -
United States $1,775 $235 $149 $249 $400 $ (4) $255 $ 491
North Sea 783 146 60 27 220 (15) 147 198
China 23 5 8 19 2 (12) 1 -
Other international - - 6 59 1 - (22) (44)
------ ---- ---- ---- ---- ---- ---- -----
Total crude oil and
natural gas activities 2,581 386 223 (1) 354 623 (31) 381 645
Other (2) 342 - 355 - 11 - (8) (16)
------ ---- ---- ---- ---- ---- ---- -----
Total from continuing
operations 2,923 386 578 354 634 (31) 373 629
Discontinued operations 6 1 2 - - 6 - (3)
------ ---- ---- ---- ---- ---- ---- -----
Total $2,929 $387 $580 $354 $634 $(25) $373 $ 626
====== ==== ==== ==== ==== ==== ==== =====
2002 -
United States $1,367 $254 $106 $159 $389 $111 $116 $ 232
North Sea 920 244 60 48 288 706 33 (459)
China 30 10 5 5 3 - 2 5
Other international 29 7 14 61 - 5 (17) (41)
------ ---- ---- ---- ---- ---- ---- -----
Total crude oil and
natural gas activities 2,346 515 185 (1) 273 680 822 134 (263)
Other (2) 104 - 105 - 10 - (4) (7)
------ ---- ---- ---- ---- ---- ---- -----
Total from continuing
operations 2,450 515 290 273 690 822 130 (270)
Discontinued operations 36 4 14 1 3 35 - (21)
------ ---- ---- ---- ---- ---- ---- -----
Total $2,486 $519 $304 $274 $693 $857 $130 $(291)
====== ==== ==== ==== ==== ==== ==== =====
2001 -
United States $1,402 $217 $ 69 $100 $331 $ - $248 $ 437
North Sea 922 207 61 29 273 47 120 185
China 30 10 5 6 4 - 2 3
Other international 39 8 14 74 7 - (21) (43)
------ ---- ---- ---- ---- ---- ---- -----
Total crude oil and
natural gas activities 2,393 442 149 (1) 209 615 47 349 582
Other (2) 35 - 39 1 4 - (7) (2)
------ ---- ---- ----- ---- ---- ---- -----
Total from continuing 2,428 442 188 210 619 47 342 580
operations
Discontinued operations 72 7 17 1 10 - 17 20
------ ---- ---- ---- ---- ---- ---- -----
Total $2,500 $449 $205 $211 $629 $ 47 $359 $ 600
====== ==== ==== ==== ==== ==== ==== =====
(1) Includes transportation, general and administrative expense, and taxes
other than income taxes associated with oil and gas producing activities.
(2) Includes gas marketing activities, gas processing plants, pipelines and
other items that do not fit the definition of crude oil and natural gas
producing activities but have been included above to reconcile to the
segment presentations.
The table below presents the company's average per-unit sales price of crude oil
and natural gas and lifting costs (lease operating expense and production taxes)
per barrel of oil equivalent from continuing operations for each of the past
three years. Natural gas production has been converted to a barrel of oil
equivalent based on approximate relative heating value (6 Mcf equals 1 barrel).
2003 2002 2001
- --------------------------------------------------------------------------------
Average price of crude oil sold (per barrel) -
United States $26.14 $21.56 $22.05
North Sea 25.82 22.41 23.23
China 29.66 24.84 21.94
Other international - 20.28 19.14
Average(1) 26.04 22.04 22.60
Average price of natural gas sold (per Mcf) -
United States $4.56 $3.04 $3.99
North Sea 3.09 2.35 2.46
Average(1) 4.37 2.95 3.83
Lifting costs (per barrel of oil equivalent) -
United States $3.57 $3.64 $3.56
North Sea 4.52 5.64 5.03
China 6.02 8.08 7.15
Other international - 5.05 4.54
Average 3.90 4.45 4.20
(1) Includes the results of the company's 2003 and 2002 hedging program, which
reduced the average price of crude oil sold by $2.46 and $1.13 per barrel,
respectively, and natural gas sold by $.55 and $.01 per Mcf, respectively.
31. Capitalized Costs of Crude Oil and Natural Gas Activities
Capitalized costs of crude oil and natural gas activities and the related
reserves for depreciation, depletion and amortization at the end of 2003 and
2002 are set forth in the table below.
(Millions of dollars) 2003 2002
- --------------------------------------------------------------------------------
Capitalized costs -
Proved properties $10,875 $10,442
Unproved properties 837 782
Other 375 361
------- -------
Total 12,087 11,585
Assets held for disposal 467 782
Discontinued operations - 63
------- -------
Total 12,554 12,430
------- -------
Reserves for depreciation, depletion and amortization -
Proved properties 5,403 5,384
Unproved properties 206 155
Other 110 93
------- -------
Total 5,719 5,632
Assets held for disposal 439 746
Discontinued operations - 17
------- -------
Total 6,158 6,395
------- -------
Net capitalized costs $ 6,396 $ 6,035
======= =======
32. Crude Oil, Condensate, Natural Gas Liquids and Natural Gas Net Reserves
(Unaudited)
The estimates of proved reserves have been prepared by the company's geologists
and engineers in accordance with the Securities and Exchange Commission
definitions. Such estimates include reserves on certain properties that are
partially undeveloped and reserves that may be obtained in the future by
improved-recovery operations now in operation or for which successful testing
has been demonstrated. The company has no proved reserves attributable to
long-term supply agreements with governments or consolidated subsidiaries in
which there are significant minority interests. Natural gas liquids and natural
gas volumes are determined using a gas pressure base of 14.73 psia.
The following table summarizes the changes in the estimated quantities of the
company's crude oil, condensate, natural gas liquids and natural gas proved
reserves for the three years ended December 31, 2003.
Continuing Operations
---------------------------------------------------
Total
Crude Oil, Condensate and Natural Gas Liquids United North Other Continuing Discontinued
(Millions of barrels) States Sea China International Operations Operations Total
- ----------------------------------------------------------------------------------------------------------------------------
Proved developed and undeveloped reserves -
Balance December 31, 2000 228 355 12 40 635 65 700
Revisions of previous estimates 27 (4) - 1 24 - 24
Purchases of reserves in place 45 - - - 45 - 45
Sales of reserves in place (4) - - - (4) - (4)
Extensions, discoveries and other
additions 49 74 25 - 148 - 148
Production (28) (37) (2) (2) (69) (3) (72)
----- ---- -- --- ----- ---- -----
Balance December 31, 2001 317 388 35 39 779 62 841
Revisions of previous estimates 8 (101) 1 - (92) - (92)
Purchases of reserves in place 1 13 - - 14 - 14
Sales of reserves in place (62) (61) - (37) (160) (51) (211)
Extensions, discoveries and other
additions 6 1 - - 7 - 7
Production (29) (38) (1) (2) (70) (2) (72)
----- ---- -- --- ----- ---- -----
Balance December 31, 2002 241 202 35 - 478 9 487
Revisions of previous estimates 7 (7) 2 - 2 - 2
Purchases of reserves in place 3 12 - - 15 - 15
Sales of reserves in place (16) - (3) - (19) (9) (28)
Extensions, discoveries and other
additions 55 14 6 - 75 - 75
Production (28) (26) (1) - (55) - (55)
----- ---- -- --- ----- ---- -----
Balance December 31, 2003 262 195 39 - 496 - 496
===== ==== == === ===== ==== =====
Natural Gas (Billions of cubic feet)
--------------------------------------------------------------------------------------------------------------------------
Proved developed and undeveloped reserves -
Balance December 31, 2000 1,325 467 - - 1,792 535 2,327
Revisions of previous estimates 35 2 - - 37 - 37
Purchases of reserves in place 1,050 5 - - 1,055 - 1,055
Sales of reserves in place (7) - - - (7) - (7)
Extensions, discoveries and other
additions 737 76 - - 813 - 813
Production (195) (23) - - (218) - (218)
----- ---- -- --- ----- ---- -----
Balance December 31, 2001 2,945 527 - - 3,472 535 4,007
Revisions of previous estimates (70) (7) - - (77) - (77)
Purchases of reserves in place 17 16 - - 33 - 33
Sales of reserves in place (76) (9) - - (85) (535) (620)
Extensions, discoveries and other
additions 204 6 - - 210 - 210
Production (241) (37) - - (278) - (278)
----- ---- -- --- ----- ---- -----
Balance December 31, 2002 2,779 496 - - 3,275 - 3,275
Revisions of previous estimates (10) 11 - - 1 - 1
Purchases of reserves in place 57 30 - - 87 - 87
Sales of reserves in place (77) - - - (77) - (77)
Extensions, discoveries and other
additions 152 8 - - 160 - 160
Production (230) (35) - - (265) - (265)
----- ---- -- --- ----- ---- -----
Balance December 31, 2003 2,671 510 - - 3,181 - 3,181
===== ==== == === ===== ==== =====
Continuing Operations
---------------------------------------------------
Total
Crude Oil, Condensate and Natural Gas Liquids United North Other Continuing Discontinued
(Millions of barrels) States Sea China International Operations Operations Total
- ----------------------------------------------------------------------------------------------------------------------------
Proved developed reserves -
December 31, 2001 206 248 2 11 467 11 478
December 31, 2002 147 130 2 - 279 5 284
December 31, 2003 122 125 - - 247 - 247
Natural Gas (Billions of cubic feet)
- ----------------------------------------------------------------------------------------------------------------------------
Proved developed reserves -
December 31, 2001 1,741 208 - - 1,949 13 1,962
December 31, 2002 1,658 168 - - 1,826 - 1,826
December 31, 2003 1,502 113 - - 1,615 - 1,615
The following presents the company's barrel of oil equivalent proved developed
and undeveloped reserves based on approximate heating value (6 Mcf equals 1
barrel).
Continuing Operations
---------------------------------------------------
Total
Barrels of Oil Equivalent United North Other Continuing Discontinued
(Millions of barrels) States Sea China International Operations Operations Total
- ----------------------------------------------------------------------------------------------------------------------------
Proved developed and undeveloped reserves -
Balance December 31, 2000 449 433 12 40 934 154 1,088
Revisions of previous estimates 33 (4) - 1 30 - 30
Purchases of reserves in place 219 1 - - 220 - 220
Sales of reserves in place (5) - - - (5) - (5)
Extensions, discoveries and other additions 172 87 25 - 284 - 284
Production (60) (41) (2) (2) (105) (3) (108)
----- ---- -- --- ----- ---- -----
Balance December 31, 2001 808 476 35 39 1,358 151 1,509
Revisions of previous estimates (4) (102) 1 - (105) - (105)
Purchases of reserves in place 3 16 - - 19 - 19
Sales of reserves in place (74) (63) - (37) (174) (140) (314)
Extensions, discoveries and other additions 40 2 - - 42 - 42
Production (69) (44) (1) (2) (116) (2) (118)
----- ---- -- --- ----- ---- -----
Balance December 31, 2002 704 285 35 - 1,024 9 1,033
Revisions of previous estimates 5 (5) 2 - 2 - 2
Purchases of reserves in place 12 17 - - 29 - 29
Sales of reserves in place (29) - (3) - (32) (9) (41)
Extensions, discoveries and other additions 81 15 6 - 102 - 102
Production (66) (32) (1) - (99) - (99)
----- ---- -- --- ----- ---- -----
Balance December 31, 2003 707 280 39 - 1,026 - 1,026
===== ==== == === ===== ==== =====
Continuing Operations
---------------------------------------------------
Total
United North Other Continuing Discontinued
(Millions of equivalent barrels) States Sea China International Operations Operations Total
- ----------------------------------------------------------------------------------------------------------------------------
Proved developed reserves -
December 31, 2001 496 283 2 11 792 13 805
December 31, 2002 423 158 2 - 583 5 588
December 31, 2003 372 144 - - 516 - 516
33. Standardized Measure of and Reconciliation of Changes in Discounted Future
Net Cash Flows (Unaudited)
The standardized measure of future net cash flows presented in the following
table was computed using year-end prices and costs and a 10% discount factor.
The future income tax expense was computed by applying the appropriate year-end
statutory rates, with consideration of future tax rates already legislated, to
the future pretax net cash flows less the tax basis of the properties involved.
However, the company cautions that actual future net cash flows may vary
considerably from these estimates. Although the company's estimates of total
reserves, development costs and production rates were based on the best
information available, the development and production of the oil and gas
reserves may not occur in the periods assumed. Actual prices realized, costs
incurred and production quantities may vary significantly from those used.
Therefore, such estimated future net cash flow computations should not be
considered to represent the company's estimate of the expected revenues or the
current value of existing proved reserves.
Standardized
Future Measure of
Future Future Future Future Net 10% Discounted
Cash Production Development Income Cash Annual Future Net
(Millions of dollars) Inflows(1) Costs Costs(2) Taxes Flows Discount Cash Flows
- ---------------------------------------------------------------------------------------------------------------------
2003
United States $23,850 $5,002 $2,067 $5,467 $11,314 $4,721 $6,593
North Sea 7,770 2,437 790 1,552 2,991 970 2,021
China 1,114 306 130 178 500 208 292
------- ------ ------ ------ ------- ------ ------
Total $32,734 $7,745 $2,987 $7,197 $14,805 $5,899 $8,906(3)
======= ====== ====== ====== ======= ====== ======
2002
United States $17,195 $4,909 $1,642 $3,372 $7,272 $2,951 $4,321
North Sea 7,332 1,484 602 1,887 3,359 923 2,436
China 1,052 280 154 162 456 214 242
------- ------ ------ ------ ------- ------ ------
Total continuing
operations 25,579 6,673 2,398 5,421 11,087 4,088 6,999(3)
Discontinued
operations 224 84 11 34 95 32 63
------- ------ ------ ------ ------- ------ ------
Total $25,803 $6,757 $2,409 $5,455 $11,182 $4,120 $7,062
======= ====== ====== ====== ======= ====== ======
2001
United States $12,126 $3,952 $1,851 $2,007 $4,316 $1,937 $2,379
North Sea 8,348 2,950 855 1,155 3,388 1,216 2,172
China 541 255 143 40 103 62 41
Other international 535 236 104 58 137 67 70
------- ------ ------ ------ ------- ------ ------
Total continuing
operations 21,550 7,393 2,953 3,260 7,944 3,282 4,662(3)
Discontinued
operations 2,440 748 326 497 869 543 326
------- ------ ------ ------ ------- ------ ------
Total $23,990 $8,141 $3,279 $3,757 $8,813 $3,825 $4,988
======= ====== ====== ====== ======= ====== ======
(1) Future cash inflows from sales of crude oil and natural gas are based on
average year-end prices of $29.05, $28.61 and $17.52 per barrel of oil and
$5.77, $3.63 and $2.31 per Mcf of natural gas for 2003, 2002 and 2001,
respectively.
(2) Future abandonment costs, net of anticipated salvage values, for 2002 and
2001 have been classified in future development costs (rather than
production costs) to conform with the current year presentation.
(3) Estimated future net cash flows before income tax expense, discounted at
10%, totaled approximately $13.2 billion, $10.3 billion and $6.5 billion,
for 2003, 2002 and 2001, respectively.
The changes in the standardized measure of future net cash flows are presented
below for each of the past three years:
(Millions of dollars) 2003 2002 2001
- --------------------------------------------------------------------------------
Net change in sales prices and production costs $ 3,308 $ 6,870 $(5,879)
Sales revenues less production costs (2,383) (1,795) (1,904)
Purchases of reserves in place 344 243 1,117
Extensions, discoveries and other additions 1,183 347 1,232
Revisions in quantity estimates 63 (1,433) 168
Sales of reserves in place (255) (1,920) (87)
Current-period development costs incurred 573 743 1,237
Changes in estimated future development costs (472) (209) (639)
Accretion of discount 1,033 701 1,093
Change in income taxes (978) (1,336) 1,689
Timing and other (572) (137) (265)
------- ------- -------
Net change 1,844 2,074 (2,238)
Total at beginning of year 7,062 4,988 7,226
------- ------- -------
Total at end of year $8,906 $7,062 $ 4,988
======= ======= =======
34. Quarterly Financial Information (Unaudited)
A summary of quarterly consolidated results for 2003 and 2002 is presented
below. The quarterly per-share amounts do not add to the annual amounts due to
the effects of the weighted average of stock issued and the anti-dilutive effect
of convertible debentures in certain quarters.
Income (Loss) from
Income Continuing Operations
(Loss) from Net per Common Share
(Millions of dollars, Operating Continuing Income ---------------------
except per-share amounts) Revenues Profit (Loss) Operations (Loss) Basic Diluted
- -----------------------------------------------------------------------------------------------------------
2003 Quarter Ended -
March 31 $1,100 $ 270 $ 104 $ 70 $ 1.04 $ .99
June 30 1,052 250 70 70 .70 .68
September 30 1,006 226 29 29 .29 .29
December 31 1,027 208 51 50 .50 .50
------ ----- ----- ----- ------ ------
Total $4,185 $ 954 $ 254 $ 219 $ 2.52 $ 2.48
====== ===== ===== ===== ====== ======
2002 Quarter Ended -
March 31 $ 791 $ 111 $ (2) $ 6 $ (.02) $ (.02)
June 30 926 56 (178) (58) (1.77) (1.77)
September 30 965 182 (87) (87) (.86) (.86)
December 31 964 (488) (344) (346) (3.43) (3.43)
------ ----- ----- ----- ------ ------
Total $3,646 $(139) $(611) $(485) $(6.09) $(6.09)
====== ===== ===== ===== ====== ======
The company's common stock is listed for trading on the New York Stock Exchange
and at year-end 2003 was held by approximately 24,500 Kerr-McGee stockholders of
record and Oryx and HS Resources owners who have not yet exchanged their stock.
The ranges of market prices and dividends declared during the last two years for
Kerr-McGee Corporation are as follows:
Market Prices
----------------------------------------------------------- Dividends
2003 2002 per Share
------------------------ ------------------------ ------------------
High Low High Low 2003 2002
- -------------------------------------------------------------------------------------------------------------------
Quarter Ended -
March 31 $44.90 $37.82 $63.29 $50.72 $.45 $.45
June 30 48.59 39.90 63.58 52.80 .45 .45
September 30 45.50 41.08 53.90 39.10 .45 .45
December 31 47.20 40.10 47.51 38.02 .45 .45
Ten-Year Financial Summary
- ------------------------------------------------------------------------------------------------------------------------------------
(Millions of dollars, except
per-share amounts) 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994
- ------------------------------------------------------------------------------------------------------------------------------------
Summary of Net Income (Loss)
Revenues $ 4,185 $ 3,646 $ 3,555 $4,063 $2,712 $2,233 $2,651 $2,779 $2,462 $ 2,389
------------------------------------------------------------------------------------------------
Costs and operating expenses 3,432 3,993 2,832 2,651 2,314 2,626 2,059 2,162 2,343 2,203
Interest and debt expense 251 275 195 208 191 159 141 145 194 210
------------------------------------------------------------------------------------------------
Total costs and expenses 3,683 4,268 3,027 2,859 2,505 2,785 2,200 2,307 2,537 2,413
------------------------------------------------------------------------------------------------
502 (622) 528 1,204 207 (552) 451 472 (75) (24)
Other income (expense) (59) (35) 224 50 36 40 81 109 146 15
Benefit (provision) for income taxes (189) 46 (276) (437) (105) 173 (183) (224) 41 (14)
------------------------------------------------------------------------------------------------
Income (loss) from continuing
operations 254 (611) 476 817 138 (339) 349 357 112 (23)
Income from discontinued
operations - 126 30 25 8 271 35 57 25 47
Extraordinary charge - - - - - - (2) - (23) (12)
Cumulative effect of change in
accounting principle (35) - (20) - (4) - - - - (948)
------------------------------------------------------------------------------------------------
Net income (loss) $ 219 $ (485) $ 486 $ 842 $ 142 $ (68) $ 382 $ 414 $ 114 $ (936)
================================================================================================
Effective Income Tax Rate 42.7% (7.0)% 36.7% 34.8% 43.2% (33.8)% 34.4% 38.6% 57.7% NM
Common Stock Information, per
Share
Diluted net income (loss) -
Continuing operations $ 2.48 $ (6.09) $ 4.65 $ 8.13 $ 1.60 $(3.91) $ 4.00 $ 4.03 $ 1.25 $ (.26)
Discontinued operations - 1.25 .28 .24 .09 3.13 .40 .65 .28 .53
Extraordinary charge - - - - - - (.02) - (.26) (.14)
Cumulative effect of accounting
change (.31) - (.19) - (.05) - - - - (10.82)
------------------------------------------------------------------------------------------------
Net income (loss) $ 2.17 $ (4.84) $ 4.74 $ 8.37 $ 1.64 $ (.78) $ 4.38 $ 4.68 $ 1.27 $(10.69)
================================================================================================
Dividends declared $ 1.80 $ 1.80 $ 1.80 $ 1.80 $ 1.80 $ 1.80 $ 1.80 $ 1.64 $ 1.55 $ 1.52
Stockholders' equity 23.79 23.01 28.83 25.01 17.19 15.58 17.88 14.59 12.47 12.33
Market high for the year 48.59 63.58 74.10 71.19 62.00 73.19 75.00 74.13 64.00 51.00
Market low for the year 37.82 38.02 46.94 39.88 28.50 36.19 55.50 55.75 44.00 40.00
Market price at year-end $ 46.49 $ 44.30 $ 54.80 $66.94 $62.00 $38.25 $63.31 $72.00 $63.50 $ 46.25
Shares outstanding at year-end
(thousands) 100,860 100,384 100,185 94,485 86,483 86,367 86,794 87,032 89,613 90,143
Balance Sheet Information
Working capital $ (475) $ (320) $ 193 $ (34) $ 321 $ (173) $ - $ 161 $ (106) $ (254)
Property, plant and equipment - net 7,467 7,036 7,378 5,240 3,972 4,044 3,844 3,658 3,789 4,493
Total assets 10,174 9,909 11,076 7,666 5,899 5,451 5,339 5,194 5,006 5,918
Long-term debt 3,081 3,798 4,540 2,244 2,496 1,978 1,736 1,809 1,683 2,219
Total debt 3,655 3,904 4,574 2,425 2,525 2,250 1,766 1,849 1,938 2,704
Total debt less cash 3,513 3,814 4,483 2,281 2,258 2,129 1,574 1,719 1,831 2,612
Stockholders' equity 2,636 2,536 3,174 2,633 1,492 1,346 1,558 1,279 1,124 1,112
Cash Flow Information
Net cash provided by operating
activities 1,518 1,448 1,143 1,840 708 418 1,114 1,144 732 693
Capital expenditures 981 1,159 1,792 842 528 1,006 851 829 749 622
Dividends paid 181 181 173 166 138 86 85 83 79 79
Treasury stock purchased $ - $ - $ - $ - $ - $ 25 $ 60 $ 195 $ 45 $ -
Ratios and Percentage
Current ratio .8 .8 1.2 1.0 1.4 .8 1.0 1.2 .9 .8
Average price/earnings ratio 19.9 NM 12.8 6.6 27.6 NM 14.9 13.9 42.5 NM
Total debt less cash to total
capitalization 57% 60% 59% 46% 60% 61% 50% 57% 62% 70%
Employees
Total wages and benefits $ 541 $ 412 $ 369 $ 333 $ 327 $ 359 $ 367 $ 367 $ 402 $ 422
Number of employees at year-end 3,915 4,470 4,638 4,426 3,653 4,400 4,792 4,827 5,176 6,724
- ------------------------------------------------------------------------------------------------------------------------------------
Ten-Year Operating Summary
- ------------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999 1998 1997 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------------
Exploration and Production
Net production of crude oil and condensate -
(thousands of barrels per day)
United States 76.5 81.3 77.7 73.7 79.3 66.2 70.6 73.8 74.8 73.4
North Sea 71.6 102.8 101.9 117.7 102.9 87.4 83.3 86.5 91.9 88.7
China 2.1 3.3 3.8 4.5 5.2 7.6 8.7 3.7 - -
Other international - 3.9 5.5 4.5 4.3 5.7 7.0 11.2 16.4 26.4
------------------------------------------------------------------------------------
Total 150.2 191.3 188.9 200.4 191.7 166.9 169.6 175.2 183.1 188.5
------------------------------------------------------------------------------------
Average price of crude oil sold (per barrel) -
United States $26.14 $21.56 $22.05 $27.50 $16.90 $12.78 $18.45 $19.56 $15.78 $14.25
North Sea 25.82 22.41 23.23 27.92 17.88 12.93 18.93 19.60 16.56 15.33
China 29.66 24.84 21.94 27.54 15.23 11.79 17.71 19.53 - -
Other international - 20.28 19.14 24.55 12.99 7.23 12.60 14.53 14.91 14.58
Average $26.04 $22.04 $22.60 $27.69 $17.30 $12.63 $18.40 $19.26 $16.10 $14.80
Natural gas sales (MMcf per day) 726 760 596 531 580 584 685 781 809 872
Average price of natural gas sold (per Mcf) $ 4.37 $ 2.95 $ 3.83 $ 3.87 $ 2.38 $ 2.13 $ 2.44 $ 2.11 $ 1.63 $ 1.82
Net exploratory wells drilled(1)-
Productive 6.7 4.8 2.4 1.3 1.7 4.4 7.7 6.9 4.7 11.6
Dry 17.0 17.2 11.4 10.5 3.8 14.4 7.4 5.5 11.2 13.5
------------------------------------------------------------------------------------
Total 23.7 22.0 13.8 11.8 5.5 18.8 15.1 12.4 15.9 25.1
------------------------------------------------------------------------------------
Net development wells drilled(1)-
Productive 244.4 196.3 128.6 47.8 46.2 62.3 95.8 143.3 135.9 69.3
Dry 1.1 1.4 6.6 5.4 5.9 9.0 7.0 13.1 11.9 9.6
------------------------------------------------------------------------------------
Total 245.5 197.7 135.2 53.2 52.1 71.3 102.8 156.4 147.8 78.9
------------------------------------------------------------------------------------
Undeveloped net acreage (thousands)(1)-
United States 2,884 2,399 2,382 2,020 1,560 1,487 1,353 1,099 1,280 1,415
North Sea 369 871 932 923 861 908 523 560 570 629
China 1,488 1,046 917 961 346 1,481 2,183 925 341 282
Other international 47,178 41,514 50,450 25,117 18,693 13,235 12,447 3,631 3,690 7,212
------------------------------------------------------------------------------------
Total 51,919 45,830 54,681 29,021 21,460 17,111 16,506 6,215 5,881 9,538
------------------------------------------------------------------------------------
Developed net acreage (thousands)(1)-
United States 1,352 1,266 1,192 729 796 810 830 871 1,190 1,270
North Sea 136 109 149 115 105 115 70 79 58 68
China - 17 17 17 19 19 19 19 19 19
Other international - 1 639 639 766 593 182 179 188 996
------------------------------------------------------------------------------------
Total 1,488 1,393 1,997 1,500 1,686 1,537 1,101 1,148 1,455 2,353
------------------------------------------------------------------------------------
Estimated proved reserves(1)-
(millions of equivalent barrels) 1,026 1,033 1,509 1,088 920 901 892 849 864 1,059
Chemicals
Titanium dioxide pigment
production (thousands of tonnes) 532 508 483 480 320 284 168 155 154 148
- ------------------------------------------------------------------------------------------------------------------------------------
(1) Includes discontinued operations.
Item 9. Change in and Disagreements with Accountants on Accounting and Financial
Disclosure
None.
Item 9A. Controls and Procedures
As of the end of the period covered by this report, an evaluation was carried
out under the supervision and with the participation of the company's
management, including its Chief Executive Officer and Chief Financial Officer,
of the effectiveness of the design and operation of the company's disclosure
controls and procedures pursuant to Exchange Act Rule 13a-15. Based on that
evaluation, the Chief Executive Officer and Chief Financial Officer concluded
that the company's disclosure controls and procedures are effective in alerting
them in a timely manner to material information relating to the company
(including its consolidated subsidiaries) required to be included in the
company's periodic SEC filings. There were no significant changes in the
company's internal controls or in other factors that could significantly affect
these controls subsequent to the date of their evaluation.
PART III
Item 10. Directors and Executive Officers of the Registrant
(a) Identification of directors -
For information required under this section, reference is made to the
"Director Information" section of the company's proxy statement made in
connection with its Annual Stockholders' Meeting to be held on May 11,
2004.
(b) Identification of executive officers -
The information required under this section is set forth in the caption
"Executive Officers of the Registrant" on pages 23 and 24 of this Form
10-K pursuant to Instruction 3 to Item 401(b) of Regulation S-K and
General Instruction G(3) to Form 10-K.
(c) Compliance with Section 16(a) of the 1934 Act -
For information required under this section, reference is made to the
"Section 16(a) Beneficial Ownership Reporting Compliance" section of
the company's proxy statement made in connection with its Annual
Stockholders' Meeting to be held on May 11, 2004.
(d) Code of ethics for the Chief Executive Officer and Principal Financial
Officers -
Information regarding the Code of Ethics for The Chief Executive
Officer and Principal Financial Officers can be found in Item 2. of
this Form 10-K under "Availability of Reports and Governance
Documents."
(e) Audit committee financial expert -
For information required under this section, reference is made to the
"Information About the Board" section of the company's proxy statement
made in connection with its Annual Stockholders' Meeting to be held on
May 11, 2004.
Item 11. Executive Compensation
For information required under this section, reference is made to the executive
compensation sections of the company's proxy statement made in connection with
its Annual Stockholders' Meeting to be held on May 11, 2004.
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
Information regarding Kerr-McGee common stock that may be issued under the
company's equity compensation plans as of December 31, 2003, is included in the
following table:
Number of shares of Number of shares
common stock to be Weighted-average remaining available
issued upon exercise exercise price of for future issuance
of outstanding outstanding under equity
options, warrants options, warrants compensation
and rights and rights plans (1)
- ---------------------------------------------------------------------------------------------------------------------
Equity compensation plans approved
by security holders 5,591,602 $55.68 4,232,453
Equity compensation plans not
approved by security holders 827,117 58.32 531,133
--------- ---------
Total 6,418,719 56.02 4,763,586
========= =========
(1) Excludes shares to be issued upon exercise of outstanding options, warrants
and rights.
The Kerr-McGee Corporation Performance Share Plan was approved by the Board of
Directors in January 1998 but was not approved by the company's stockholders.
This plan is a broad-based stock option plan that provides for the granting of
options to purchase the company's common stock to full-time, nonbargaining-unit
employees, except officers. A total of 1,500,000 shares of common stock were
authorized to be issued under this plan. A copy of the plan document was
attached as exhibit 10.19 to the company's December 31, 2002, Form 10-K and is
incorporated by reference in exhibit 10.14 to the company's December 31, 2003
Form 10-K.
For information required under Item 403 of Regulation S-K, reference is made to
the "Ownership of Stock of the Company" section of the company's proxy statement
made in connection with its Annual Stockholders' Meeting to be held on May 11,
2004.
Item 13. Certain Relationships and Related Transactions
None.
Item 14. Principal Accountant Fees and Services
For information required under this section, reference is made to the "Fees Paid
to the Independent Auditors" section of the company's proxy statement made in
connection with its Annual Stockholders' Meeting to be held on May 11, 2004.
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) 1. Financial Statements - See the Index to the Consolidated Financial
Statements included in Item 8. of this Form 10-K.
(a) 2. Financial Statement Schedules - See the Index to the Financial
Statement Schedules included in Item 8. of this Form 10-K.
(a) 3. Exhibits - The following documents are filed under Commission file
numbers 1-16619 and 1-3939 as part of this report.
Exhibit No.
-----------
3.1 Amended and restated Certificate of Incorporation of
Kerr-McGee Corporation, filed as Exhibit 4.1 to the
company's Registration Statement on Form S-4 dated June 28,
2001, and incorporated herein by reference.
3.2 Amended and restated By Laws of Kerr-McGee Corporation.
4.1 Rights Agreement dated as of July 26, 2001, by and between
the company and UMB Bank, N.A., filed as Exhibit 4.1 to the
company's Registration Statement on Form 8-A filed on July
27, 2001, and incorporated herein by reference.
4.2 First Amendment to Rights Agreement, dated as of July 30,
2001, by and between the company and UMB Bank, N.A., filed
as Exhibit 4.1 to the company's Registration Statement on
Form 8-A/A filed on August 1, 2001, and incorporated herein
by reference.
4.3 Indenture dated as of November 1, 1981, between the company
and United States Trust Company of New York, as trustee,
relating to the company's 7% Debentures due November 1,
2011, filed as Exhibit 4 to Form S-16, effective November
16, 1981, Registration No. 2-772987, and incorporated herein
by reference.
4.4 Indenture dated as of August 1, 1982, filed as Exhibit 4 to
Form S-3, effective August 27, 1982, Registration Statement
No. 2-78952, and incorporated herein by reference, and the
first supplement thereto dated May 7, 1996, between the
company and Citibank, N.A., as trustee, relating to the
company's 6.625% notes due October 15, 2007, and 7.125%
debentures due October 15, 2027, filed as Exhibit 4.1 to the
Current Report on Form 8-K filed July 27, 1999, and
incorporated herein by reference.
4.5 The company agrees to furnish to the Securities and Exchange
Commission, upon request, copies of each of the following
instruments defining the rights of the holders of certain
long-term debt of the company: the Note Agreement dated as
of November 29, 1989, among the Kerr-McGee Corporation
Employee Stock Ownership Plan Trust (the Trust) and several
lenders, providing for a loan guaranteed by the company of
$125 million to the Trust; the $150 million, 8.375% Note
Agreement entered into by Oryx dated as of July 17, 1996,
and due July 15, 2004; the $150 million, 8-1/8% Note
Agreement entered into by Oryx dated as of October 20, 1995,
and due October 15, 2005; the amended and restated Revolving
Credit Agreement dated as of January 11, 2002, between the
company or certain subsidiary borrowers and various banks
providing for revolving credit up to $650 million through
January 12, 2006; the $700 million Credit Agreement dated as
of November 14, 2003, between the company or certain
subsidiary borrowers and various banks providing for a
364-day revolving credit facility; and the $200 million
variable-interest rate Note Agreement dated June 26, 2001,
and due June 28, 2004. The total amount of securities
authorized under each of such instruments does not exceed
10% of the total assets of the company and its subsidiaries
on a consolidated basis.
4.6 Kerr-McGee Corporation Direct Purchase and Dividend
Reinvestment Plan filed on September 9, 2001, pursuant to
Rule 424(b)(2) of the Securities Act of 1933 as the
Prospectus Supplement to the Prospectus dated August 31,
2001, and incorporated herein by reference.
4.7 Second Supplement to the August 1, 1982, Indenture dated as
of August 2, 1999, between the company and Citibank, N.A.,
as trustee, relating to the company's 5-1/2% exchangeable
notes due August 2, 2004, filed as Exhibit 4.11 to the
report on Form 10-K for the year ended December 31, 1999,
and incorporated herein by reference.
4.8 Fifth Supplement to the August 1, 1982, Indenture dated as
of February 11, 2000, between the company and Citibank,
N.A., as trustee, relating to the company's 5-1/4%
Convertible Subordinated Debentures due February 15, 2010,
filed as Exhibit 4.1 to Form 8-K filed February 4, 2000, and
incorporated herein by reference.
4.9 Indenture dated as of August 1, 2001, between the company
and Citibank, N.A., as trustee, relating to the company's
$350 million, 5-3/8% notes due April 15, 2005; $325 million,
5-7/8% notes due September 15, 2006; $675 million, 6-7/8%
notes due September 15, 2011; and $500 million 7-7/8% notes
due September 15, 2031, filed as Exhibit 4.1 to Form S-3
Registration Statement No. 333-68136 Pre-effective Amendment
No. 1, and incorporated herein by reference.
10.1* Kerr-McGee Corporation Deferred Compensation Plan for
Non-Employee Directors as amended and restated effective
January 1, 2003, filed as Exhibit 10.1 to the Form 10-K for
the year ended December 31, 2002, and incorporated herein by
reference.
10.2* Kerr-McGee Corporation Executive Deferred Compensation Plan
as amended and restated effective January 1, 2003, filed as
Exhibit 10.4 to the Form 10-K for the year ended December
31, 2002, and incorporated herein by reference.
10.3* Benefits Restoration Plan as amended and restated effective
May 1, 1999.
10.4* First Supplement to Benefits Restoration Plan as amended and
restated effective January 1, 2000.
10.5* Second Supplement to Benefits Restoration Plan as amended
and restated effective January 1, 2001.
10.6* Kerr-McGee Corporation Supplemental Executive Retirement
Plan as amended and restated effective February 26, 1999,
filed as exhibit 10.6 to the report on Form 10-K for the
year ended December 31, 2001, and incorporated herein by
reference.
10.7* First Supplement to the Kerr-McGee Corporation Supplemental
Executive Retirement Plan as amended and restated effective
February 26, 1999, filed as exhibit 10.7 to the report on
Form 10-K for the year ended December 31, 2001, and
incorporated herein by reference.
10.8* Second Supplement to the Kerr-McGee Corporation Supplemental
Executive Retirement Plan as amended and restated effective
February 26, 1999, filed as exhibit 10.8 to the report on
Form 10-K for the year ended December 31, 2001, and
incorporated herein by reference.
10.9* The Long Term Incentive Program as amended and restated
effective May 9, 1995, filed as Exhibit 10.5 on Form 10-Q
for the quarter ended March 31, 1995, and incorporated
herein by reference.
10.10* The Kerr-McGee Corporation 1998 Long Term Incentive Plan
effective January 1, 1998, filed as Exhibit 10.4 on Form
10-Q for the quarter ended March 31, 1998, and incorporated
herein by reference.
10.11* The Kerr-McGee Corporation 2000 Long Term Incentive Plan
effective May 1, 2000, filed as Exhibit 10.4 on Form 10-Q
for the quarter ended March 31, 2000, and incorporated
herein by reference.
10.12* The 2002 Long Term Incentive Plan effective May 14, 2002,
filed as Exhibit 10.1 on Form 10-Q for the quarter ended
June 30, 2002, and incorporated herein by reference.
10.13* The 2002 Annual Incentive Compensation Plan effective May
14, 2002, filed as Exhibit 10.1 on Form 10-Q for the quarter
ended June 30, 2002, and incorporated herein by reference.
10.14* Kerr-McGee Corporation Performance Share Plan effective
January 1, 1998, filed as Exhibit 10.19 to the Form 10-K for
the year ended December 31, 2002, and incorporated herein by
reference.
10.15* Oryx Energy Company 1992 Long-Term Incentive Plan, as
amended and restated May 1, 1997.
10.16* Oryx Energy Company 1997 Long-Term Incentive Plan, as
amended and restated May 1, 1997.
10.17* Amended and restated Agreement, restated as of January 11,
2000, between the company and Luke R. Corbett filed as
Exhibit 10.10 on Form 10-K for the year ended December 31,
2000, and incorporated herein by reference.
10.18* Amended and restated Agreement, restated as of January 11,
2000, between the company and Kenneth W. Crouch filed as
Exhibit 10.11 on Form 10-K for the year ended December 31,
2000, and incorporated herein by reference.
10.19* Amended and restated Agreement, restated as of January 11,
2000, between the company and Robert M. Wohleber filed as
Exhibit 10.12 on Form 10-K for the year ended December 31,
2000, and incorporated herein by reference.
10.20* Amended and restated Agreement, restated as of January 11,
2000, between the company and William P. Woodward filed as
Exhibit 10.13 on Form 10-K for the year ended December 31,
2000, and incorporated herein by reference.
10.21* Amended and restated Agreement, restated as of January 11,
2000, between the company and Gregory F. Pilcher filed as
Exhibit 10.14 on Form 10-K for the year ended December 31,
2000, and incorporated herein by reference.
10.22* Form of agreement, amended and restated as of January 11,
2000, between the company and certain executive officers not
named in the Summary Compensation Table contained in the
company's definitive Proxy Statement for the 2001 Annual
Meeting of Stockholders filed as Exhibit 10.15 on Form 10-K
for the year ended December 31, 2000, and incorporated
herein by reference.
12 Computation of ratio of earnings to fixed charges.
14 Code of Ethics.
21 Subsidiaries of the Registrant.
23 Consent of Ernst & Young LLP.
24 Powers of Attorney.
31.1 Certification pursuant to Securities Exchange Act Rule
15d-14(a), as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 Certification pursuant to Securities Exchange Act Rule
15d-14(a), as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*These exhibits relate to the compensation plans and arrangements of the
company.
(b) Reports on Form 8-K -
The following Current Reports on Form 8-K were filed by the company during
the quarter ended December 31, 2003:
o Current Report dated October 22, 2003, announcing a conference call to
discuss the company's third-quarter 2003 financial and operating
activities, and expectations for the future.
o Current Report dated October 29, 2003, announcing a security analyst
meeting to discuss the company's financial and operating outlook for 2003
and certain expectations for oil and natural gas production volumes for
the year 2003.
o Current Report dated October 29, 2003, announcing the company had posted
on its website a table containing hedge guidance for 2003 and 2004 oil
and gas derivative instruments.
o Current Report dated October 29, 2003, announcing the company had posted
on its website a table containing a reconciliation of GAAP to Adjusted
Net Income for the year-to-date and quarterly fiscal periods ended
September 30, 2003.
o Current Report dated October 29, 2003, announcing the company's
third-quarter 2003 earnings.
o Current Report dated November 3, 2003, announcing that the company would
present at the Merrill Lynch Global Energy Conference on November 5,
2003.
o Current Report dated November 13, 2003, announcing certain expectations
for oil and natural gas production volumes for the year 2004.
o Current Report dated November 14, 2003, announcing that the company would
present at the Banc of America Securities 2003 Energy & Power Conference
on November 18, 2003.
o Current Report dated November 20, 2003, announcing a conference call to
discuss the company's interim fourth-quarter 2003 financial and operating
activities, and expectations for the future.
o Current Report dated November 25, 2003, announcing the company had posted
on its website a table containing hedge guidance for 2003 and 2004 oil
and gas derivative instruments.
o Current Report dated November 25, 2003, announcing certain expectations
for oil and natural gas production volumes for the year 2003.
o Current Report dated December 1, 2003, announcing that the company would
present at the Friedman, Billings, Ramsey 10th Annual Investor Conference
on December 3, 2003.
o Current Report dated December 9, 2003, announcing certain updates to 2004
oil and gas hedge positions.
o Current Report dated December 17, 2003, announcing a conference call to
discuss the company's interim fourth-quarter 2003 financial and operating
activities, and expectations for the future.
o Current Report dated December 23, 2003, announcing a security analyst
meeting to discuss the company's financial and operating outlook for 2003
and certain expectations for oil and natural gas production volumes for
the year 2003.
o Current Report dated December 23, 2003, announcing a security analyst
meeting to discuss the company's financial and operating outlook for 2003
and certain expectations for oil and natural gas production volumes for
the year 2004.
SCHEDULE II
KERR-McGEE CORPORATION AND SUBSIDIARY COMPANIES
VALUATION ACCOUNTS AND RESERVES
Additions
--------------------------
Balance at Charged to Charged to Deductions Balance at
Beginning Profit and Other from End of
(Millions of dollars) of Year Loss Accounts Reserves Year
- --------------------- ---------- ---------- ---------- ---------- ----------
Year Ended December 31, 2003
Deducted from asset accounts
Allowance for doubtful notes
and accounts receivable $ 19 $ 1 $ - $ 1 $ 19
Warehouse inventory obsolescence 4 6 - 2 8
----- ---- ----- ---- -----
Total $ 23 $ 7 $ - $ 3 $ 27
===== ==== ===== ==== =====
Year Ended December 31, 2002
Deducted from asset accounts
Allowance for doubtful notes
and accounts receivable $ 21 $ - $ - $ 2 $ 19
Warehouse inventory obsolescence 5 1 - 2 4
----- ---- ----- ---- -----
Total $ 26 $ 1 $ - $ 4 $ 23
===== ==== ===== ==== =====
Year Ended December 31, 2001
Deducted from asset accounts
Allowance for doubtful notes
and accounts receivable $ 20 $ 1 $ 2 $ 2 $ 21
Warehouse inventory obsolescence 5 1 - 1 5
----- ---- ----- ---- -----
Total $ 25 $ 2 $ 2 $ 3 $ 26
===== ==== ===== ==== =====
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
KERR-McGEE CORPORATION
By: Luke R. Corbett*
-----------------------------
Luke R. Corbett,
Chief Executive Officer
March 11, 2004 By: (Robert M. Wohleber)
- -------------- -----------------------------
Date Robert M. Wohleber
Senior Vice President and
Chief Financial Officer
By: (John M. Rauh)
-----------------------------
John M. Rauh
Vice President and Controller
and Chief Accounting Officer
* By his signature set forth below, John M. Rauh has signed this Annual
Report on Form 10-K as attorney-in-fact for the officer noted above,
pursuant to power of attorney filed with the Securities and Exchange
Commission.
By: (John M. Rauh)
-----------------------------
John M. Rauh
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons in the capacities and on the date
indicated.
By: Luke R. Corbett*
----------------------------------
Luke R. Corbett, Director
By: William E. Bradford*
----------------------------------
William E. Bradford, Director
By: Sylvia A. Earle*
----------------------------------
Sylvia A. Earle, Director
By: David C. Genever-Watling*
----------------------------------
David C. Genever-Watling, Director
March 11, 2004 By: Martin C. Jischke*
- -------------- ----------------------------------
Date Martin C. Jischke, Director
By: Leroy C. Richie*
----------------------------------
Leroy C. Richie, Director
By: Matthew R. Simmons*
----------------------------------
Matthew R. Simmons, Director
By: Farah M. Walters*
----------------------------------
Farah M. Walters, Director
By: Ian L. White-Thomson*
----------------------------------
Ian L. White-Thomson, Director
* By his signature set forth below, John M. Rauh has signed this Annual
Report on Form 10-K as attorney-in-fact for the directors noted above,
pursuant to the powers of attorney filed with the Securities and Exchange
Commission.
By: (John M. Rauh)
----------------------------------
John M. Rauh