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, 2002
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. [X]
---
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 $5.4 billion computed by
reference to the price at which the common equity was last sold as of June 28,
2002, the last business day of the registrant's most recently completed second
fiscal quarter.
The number of shares of common stock outstanding as of February 28, 2003, was
100,373,811.
DOCUMENTS INCORPORATED BY REFERENCE
The definitive Proxy Statement for the 2003 Annual Meeting of Stockholders,
which will be filed with the Securities and Exchange Commission within 120 days
after December 31, 2002, 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 and Danish sectors of the
North Sea, China, Australia, Benin, Brazil, Gabon, Morocco, Canada, 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 information as to business segments of the company, reference is made to
Note 27 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 subsidiaries.
- ----------------------
Except for information or data specifically incorporated herein by reference
under Items 10 through 13, other information and data appearing in the company's
2003 Proxy Statement are not deemed to be filed as part of this annual report on
Form 10-K.
Kerr-McGee's offshore oil and gas exploration and/or production activities are
conducted in the Gulf of Mexico, U.K. and Danish sectors of the North Sea,
Australia, Benin, Brazil, China, Canada, Morocco, and Gabon. Onshore exploration
and/or production operations are conducted in the United States, the United
Kingdom, and Yemen. The company also has oil and gas operations in Kazakhstan
that are classified as held for disposal and are presented as discontinued
operations at year-end 2002.
Kerr-McGee's average daily oil production from continuing operations for 2002
was 191,300 barrels, a 1% increase from 2001. Kerr-McGee's average oil price was
$22.04 per barrel for 2002, including the impact of the hedging program,
compared with $22.60 per barrel for 2001.
During 2002, natural gas sales averaged 760 million cubic feet per day, up 28%
from 2001 sales. The 2002 average natural gas price was $2.95 per thousand cubic
feet, compared with $3.83 per thousand cubic feet for 2001.
Worldwide gross acreage at year-end 2002 was 66 million acres, a decrease of 22%
compared with year-end 2001. The decrease resulted primarily from the
divestiture of certain properties in the North Sea, U.S. onshore, Australia,
Indonesia and Ecuador, as well as relinquishment of certain acreage in Gabon,
Brazil, Thailand and Yemen.
Discontinued Operations and Asset Disposals
- -------------------------------------------
During the first and second quarters of 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. In conjunction with the planned disposals, the related assets were
evaluated and impairment losses were recorded for any difference between the
estimated sales price for the operations, less costs to sell, and the
operations' carrying value. Sales of the company's interests in the Bayu-Undan
project and the Sumatra operations were completed during 2002, and an agreement
for the sale of the Kazakhstan operations was announced in February 2003. The
impairment losses and gains on sale are reported as part of discontinued
operations. See Note 20 to the Consolidated Financial Statements included in
Item 8. of this Form 10-K for a discussion of impairment losses and/or gains on
sale of these assets.
Revenues applicable to the discontinued operations totaled $36 million, $72
million and $58 million for 2002, 2001 and 2000, respectively. Pretax income for
the discontinued operations totaled $104 million (including the gains on sale of
$107 million and the impairment loss of $35 million), $52 million and $45
million for the years ended 2002, 2001 and 2000, respectively.
During late 2001 and 2002, certain U.S., North Sea and Ecuador exploration and
production segment assets were identified for disposal as part of the company's
plan to divest noncore properties, as discussed above. In connection with this
recharacterization, the assets were evaluated and determined to be impaired. The
impairment losses reflect the difference between the estimated sales prices for
the individual properties or group of properties, less the costs to sell, and
the carrying amount of the net assets. See Note 20 to the Consolidated Financial
Statements included in Item 8. of this Form 10-K.
Costs Incurred, Results of Operations, Sales Prices, Production Costs and
Capitalized Costs
- -------------------------------------------------------------------------------
Reference is made to Notes 28, 29 and 30 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, and
production 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, 2002 and 2001.
Reserves
- --------
Kerr-McGee's estimated proved crude oil, condensate, natural gas liquids and
natural gas reserves at December 31, 2002, and the changes in net quantities of
such reserves for the three years then ended are shown in Note 31 to the
Consolidated Financial Statements included in Item 8. of this Form 10-K.
Undeveloped Acreage
- -------------------
As of December 31, 2002, 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 and Danish sectors of the
North Sea, and onshore and offshore in other international areas as follows:
Gross Net
Location Acreage Acreage
- -------- --------- ---------
United States -
Offshore 2,780,839 1,524,035
Onshore 1,242,198 875,177
--------- ---------
4,023,037 2,399,212
--------- ---------
North Sea 1,678,991 870,675
--------- ---------
Other international -
Morocco 30,245,687 28,021,741
Australia 10,511,119 4,576,271
Yemen 6,037,418 1,911,849
Canada 3,021,825 2,292,834
Gabon 2,471,052 617,763
Benin 2,459,439 2,459,439
Kazakhstan 1,474,296 1,474,296
China 1,245,162 1,045,699
Brazil 534,981 160,494
---------- ----------
58,000,979 42,560,386
---------- ----------
Total 63,703,007 45,830,273
========== ==========
Developed Acreage
- -----------------
At December 31, 2002, the company had leases and concessions in developed oil
and gas acreage in the Gulf of Mexico, onshore United States, the United Kingdom
sector of the North Sea, and onshore and offshore in other international areas
as follows:
Gross Net
Location Acreage Acreage
- -------- --------- ---------
United States -
Offshore 572,012 267,829
Onshore 1,579,634 997,661
--------- ---------
2,151,646 1,265,490
--------- ---------
North Sea 406,399 109,490
--------- ---------
Other international -
China 70,005 17,151
Kazakhstan 1,000 1,000
--------- ---------
71,005 18,151
--------- ---------
Total 2,629,050 1,393,131
========= =========
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, 2002, are
as follows:
Net Exploratory (1) Net Development (1)
------------------------------ -----------------------------
Productive Dry Holes Total Productive Dry Holes Total Total
---------- --------- ----- ---------- --------- ----- -----
2002 (2)
United States 4.78 11.10 15.88 186.90 1.37 188.27 204.15
North Sea - 1.84 1.84 8.57 - 8.57 10.41
Other international - 4.23 4.23 .85 - .85 5.08
---- ----- ----- ------ ---- ------ ------
Total 4.78 17.17 21.95 196.32 1.37 197.69 219.64
==== ===== ===== ====== ==== ====== ======
2001
United States 2.39 4.60 6.99 107.29 6.30 113.59 120.58
North Sea - 2.40 2.40 16.08 - 16.08 18.48
Other international - 4.43 4.43 5.25 .30 5.55 9.98
---- ----- ----- ------ ---- ------ ------
Total 2.39 11.43 13.82 128.62 6.60 135.22 149.04
==== ===== ===== ====== ==== ====== ======
2000
United States 1.25 2.75 4.00 34.85 3.09 37.94 41.94
North Sea - 4.66 4.66 8.44 1.85 10.29 14.95
Other international - 3.13 3.13 4.50 .50 5.00 8.13
---- ----- ----- ----- ---- ----- -----
Total 1.25 10.54 11.79 47.79 5.44 53.23 65.02
==== ===== ===== ===== ==== ===== =====
(1) Net wells represent the company's fractional working interest in gross
wells expressed as the equivalent number of full-interest wells.
(2) The 2002 net exploratory well count does not include 2.16 successful net
wells drilled in the United States in 2002 that are currently suspended,
nor does it include 2.45 successful net wells drilled in China or .75
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 waiting on completion as of December 31, 2002:
Wells in Process of Wells Suspended or
Drilling Waiting on Completion
--------------------------- ---------------------------
Exploration Development Exploration Development
----------- ----------- ----------- -----------
United States
Gross 5.00 35.00 23.00 9.00
Net 3.04 27.97 11.49 4.46
North Sea
Gross - 1.00 - 2.00
Net - .07 - .22
China
Gross - 1.00 1.00 -
Net - .25 .82 -
Total ---- ----- ----- -----
Gross 5.00 37.00 24.00 11.00
Net 3.04 28.29 12.31 4.68
==== ===== ===== ====
Gross and Net Wells
- -------------------
The number of productive oil and gas wells in which the company had an interest
at December 31, 2002, is shown in the following table. These wells include 422
gross or 335 net wells associated with improved recovery projects and 2,282
gross or 2,156 net wells that have multiple completions but are included as
single wells.
Location Crude Oil Natural Gas Total
- -------- --------- ----------- -----
United States
Gross 2,129 2,928 5,057
Net 1,858 2,259 4,117
North Sea
Gross 273 5 278
Net 46 - 46
China
Gross 24 - 24
Net 6 - 6
Kazakhstan
Gross 15 - 15
Net 8 - 8
Total ----- ----- -----
Gross 2,441 2,933 5,374
Net 1,918 2,259 4,177
===== ===== =====
Crude Oil and Natural Gas Sales
- -------------------------------
The following table summarizes the sales of the company's crude oil and natural
gas production from continuing operations for each of the three years in the
period ended December 31, 2002:
(Millions) 2002 2001(1) 2000(1)
-------- -------- --------
Crude oil and condensate - barrels
United States 29.7 28.4 27.0
North Sea 37.2 37.3 43.1
Other international 2.6 3.4 3.3
-------- -------- --------
69.5 69.1 73.4
======== ======== ========
Crude oil and condensate
United States $ 639.6 $ 625.5 $ 742.6
North Sea 832.8 865.6 1,205.0
Other international 58.4 68.9 85.5
-------- -------- --------
$1,530.8 $1,560.0 $2,033.1
======== ======== ========
Natural gas - Mcf
United States 240.8 194.9 168.9
North Sea 36.7 22.8 25.4
-------- -------- --------
277.5 217.7 194.3
======== ======== ========
Natural gas
United States $ 732.7 $ 777.2 $ 693.7
North Sea 86.4 56.2 58.8
-------- -------- --------
$ 819.1 $ 833.4 $ 752.5
======== ======== ========
(1) Years 2001 and 2000 have been restated to exclude discontinued operations.
Sales of Production
- -------------------
All of the company's crude oil and natural gas is sold at market prices, and the
realized revenue on the physical sale is adjusted for any gains or losses on
hedging contracts. Kerr-McGee has contracted with several energy marketing
companies to sell substantially all of its domestic crude oil and natural gas
production. International crude oil and natural gas are sold both under contract
and through spot market sales in the geographic area of production.
Kerr-McGee's single largest purchaser of natural gas is Cinergy Marketing &
Trading LP, whose purchases are guaranteed by its parent company, Cinergy
Corporation. Additionally, Kerr-McGee maintains a cap on single-customer
exposure through a credit risk insurance policy.
Kerr-McGee's single largest purchaser of crude oil is Texon L.P., whose payments
are guaranteed by letters of credit.
Improved Recovery
- -----------------
As part of the company's strategic plan to rationalize noncore assets,
Kerr-McGee's improved-recovery projects in West Texas and Oklahoma were sold
during 2002. As of December 31, 2002, the company is participating in 22 active
improved-recovery projects located principally in Texas and the United Kingdom
sector of the North Sea. Most of the company's improved-recovery operations
incorporate water injection.
Exploration and Development Activities
- --------------------------------------
Gulf of Mexico:
Since 1947, the Gulf of Mexico has been a focal area for Kerr-McGee and
represented 28% of Kerr-McGee's worldwide crude oil and condensate production
and 36% of its gas sales in 2002. Kerr-McGee is one of the largest independent
producers in the Gulf of Mexico and has significantly expanded its deepwater
exploration, exploitation and production activities in that area as part of its
growth plan. Kerr-McGee's strategy is focused on generating growth from
exploration in deepwater basins, where the company has developed a competitive
advantage through the use of innovative and cost-effective technology.
In 2002, Kerr-McGee was among the most active companies bidding at federal lease
sales. Through its participation in the Central and Western Gulf of Mexico lease
sales, Kerr-McGee acquired an interest in 60 deepwater blocks, or 257,280 net
deepwater acres. Additionally, Kerr-McGee, BHP Billiton and Ocean Energy, Inc.
(Ocean) completed an exploration joint venture in Atwater Valley that added 34
additional blocks to Kerr-McGee's inventory.
During 2002, Kerr-McGee continued drilling under terms of a joint-venture
agreement with Ocean, which covers an area comprised of 181 blocks. Kerr-McGee
and Ocean drilled three exploratory wells in 2002, with Ocean paying a
disproportionate share of the drilling costs to earn its equity interest in the
venture. This arrangement will continue for approximately three additional
years.
In total, Kerr-McGee participated in the drilling of 17 gross exploration and
appraisal wells during 2002 in the deepwater Gulf of Mexico, of which three
exploratory wells were still drilling at year-end. As a result of these efforts,
three new fields were discovered - West Navajo, Northwest Navajo and Vortex.
Appraisal drilling included a successful follow-up well on the Vortex discovery,
as well as two successful appraisal wells at Merganser, a 2001 discovery. The
exploration program continued to include a mix of satellites near existing core
operating areas and larger prospects that would support the development of new
core areas. Exploration drilling activity will continue to increase into 2003.
Kerr-McGee's development activity in the deepwater Gulf of Mexico also continued
at a high level during 2002 in terms of capital outlays, wells drilled and
construction activity. Installations of truss spars were completed at Nansen and
Boomvang during 2002, and significant progress was made on the Gunnison truss
spar. Development drilling for the Gunnison project continued during 2002 and
was completed in January 2003. In addition, Kerr-McGee commissioned construction
of a new spar for the Red Hawk project, and significant drilling and completion
activities occurred at the Nansen, Boomvang, Navajo, Pompano and Northwestern
fields. A summary of these and other major producing fields 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 2002 gross production was 17,800 barrels of oil per day
and 73 million cubic feet of gas per day. During the fourth quarter of 2002,
gross production increased to an average of approximately 23,000 barrels of oil
per day and 138 million cubic feet of gas per day from seven producing wells.
Ultimately, a total of 12 development wells are expected to be utilized to
produce this field, with nine wells produced from the spar and three wells
produced from a subsea cluster. The remaining five wells are expected to be
completed and begin production during 2003. The capacity of the Nansen spar is
40,000 barrels of oil per day and 200 million cubic feet of gas per day.
Boomvang field, East Breaks 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 2002 gross production was 6,400 barrels of oil per day and
76 million cubic feet of gas per day. During the fourth quarter of 2002, gross
production increased to an average of approximately 20,500 barrels of oil per
day and 148 million cubic feet of gas per day from three subsea wells and four
dry-tree wells. The field is being developed with five producing wells located
at the Boomvang spar in block 643 and two subsea clusters to produce the
reserves located in blocks 642 and 688. Completion operations on the remaining
dry-tree well were finished in January 2003. Similar to Nansen, the Boomvang
spar has a capacity of 40,000 barrels of oil per day and 200 million cubic feet
of gas per day.
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 tied back
to the Nansen spar located approximately 5 miles to the north. First production
for Navajo was achieved in June 2002, and gross production averaged 48 million
cubic feet of gas per day for the remainder of 2002. Early in 2002, two
additional discoveries, West and Northwest Navajo, were made in the Navajo area.
The two wells will be connected through the Navajo subsea system to the Nansen
spar, and production is expected to commence in the first half of 2003.
Gunnison field, Garden Banks block 668 area (50%): The Gunnison field,
sanctioned for development in October 2001, will incorporate a 98-foot-diameter
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 is
expected to include seven dry-tree wells and three subsea wells. The Gunnison
spar, located in 3,100 feet of water, will be Kerr-McGee's third truss spar in
the deepwater Gulf of Mexico. At year-end, spar construction was 84% complete,
and topsides fabrication was 55% complete. Additional construction activities
were under way for the subsea systems, moorings, risers and export pipelines.
Development drilling activities continued during 2002, and the final development
well was completed in January 2003. First production is anticipated in the first
quarter of 2004.
Red Hawk field, Garden Banks block 877 (50%): Red Hawk, discovered in 2001, was
the first deepwater prospect drilled under the exploration joint venture with
Ocean Energy. Development of Red Hawk was sanctioned in July 2002 utilizing a
new spar design referred to as a cell spar. The cell spar utilizes a smaller
production facility, and lowers the reserve threshold for economic development
of deepwater reservoirs. Located in approximately 5,300 feet of water, the field
will be developed utilizing two subsea development wells that will be tied back
to the cell spar. Development drilling began in the fourth quarter of 2002.
First production is anticipated in the second quarter of 2004, with peak gross
production rates of 120 million cubic feet of gas per day.
Conger field, Garden Banks block 215 (25%): Average 2002 gross production from
the Conger field was 24,600 barrels of oil per day and 95 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 location, a sidetrack of the Garden Banks 215
#6 well, is currently planned for late 2003.
Northwestern field, Garden Banks blocks 200 and 201 (25%): Average 2002 gross
production from the Northwestern field was 66 million cubic feet of gas per day
and 1,500 barrels of oil per day. First production from the Northwestern field
began in November 2000. The field was developed with two subsea wells tied back
to the Kerr-McGee-operated East Cameron 373 platform. In early 2002, drilling of
an additional development well was completed on Garden Banks block 201. The
Garden Banks 201 #1 well was completed and tied back to the existing subsea
system, and production commenced in November 2002.
Baldpate field, Garden Banks block 260 (50%): Average 2002 gross production from
the Baldpate field, including the Penn State subsea satellite wells (50%), was
26,800 barrels of oil per day and 83 million cubic feet of gas per day. The
field is located in 1,690 feet of water and is producing from an articulated
compliant tower. Decline in field production stabilized during 2002, following
anticipated water breakthrough in 2001.
Neptune field, Viosca Knoll block 826 area (50%): Average 2002 gross production
from the Neptune field was 15,700 barrels of oil per day and 25 million cubic
feet of gas per day. The Neptune field was developed utilizing the world's first
production spar.
Pompano field, Viosca Knoll block 989 area (25%): Average 2002 gross production
from the Pompano field was 34,300 barrels of oil per day and 100 million cubic
feet of gas per day. An active completion program in 2002 resulted in production
from two wells, the A-31 well in Viosca Knoll block 989 and the TB-9 well, which
extended field reserves into Mississippi Canyon block 29. Gross production from
the A-31 well peaked in 2002 at 73 million cubic feet of gas per day and 3,200
barrels of oil per day, and the well is currently producing 39 million cubic
feet of gas per day and 1,300 barrels of oil per day. Gross production from the
TB-9 well peaked in 2002 at 5.6 million cubic feet of gas per day and 5,000
barrels of oil per day, and the well is currently producing 3.3 million cubic
feet of gas per day and 1,600 barrels of oil per day.
North Sea:
Kerr-McGee has been active in the North Sea area since 1976. As of December 31,
2002, Kerr-McGee had interests in 20 producing fields in the United Kingdom
sector. In 2002, North Sea production represented 54% of the company's worldwide
crude oil and condensate production and 13% of its gas sales.
Key events for the U.K. operations in 2002 include first production from the
100% Kerr-McGee-operated Tullich field. The field was developed using a subsea
tieback to the Kerr-McGee-operated Gryphon facility, with first oil occurring in
August 2002. First production was also achieved from the nonoperated Maclure
field (33.3%). The field was developed as a subsea tieback to the Gryphon
facility, with first oil occurring in August 2002.
Oil production from both the Tullich and Maclure fields is exported by shuttle
tanker from the Gryphon floating production, storage and offloading (FPSO)
vessel. Gas is piped to the Leadon facility for fuel usage and/or sold from the
St. Fergus terminal.
Kerr-McGee's U.K. operations conducted a significant divesture program in 2002
that covered the northern North Sea assets and various high-cost, low-volume
nonoperated properties. Divestiture of company-operated fields included Ninian,
Murchison, Lyell and Columba. The purchaser assumed all decommissioning
liabilities associated with the divested fields.
In December 2002, after an extensive review and evaluation, an after-tax,
noncash impairment of $335 million was made to the Leadon field. The field had
been producing lower volumes than initially anticipated because of early water
breakthrough and reservoir compartmentalization. To maximize cash flow from the
Leadon field, the company is considering various alternatives, including
continued production using existing infrastructure, a subsea tieback to another
host structure, such as the Kerr-McGee-operated Gryphon facility, or sale of the
asset. The subsea tieback option would allow for redeployment or sale of the
Kerr-McGee Global Producer III, an FPSO vessel launched at Leadon in 2001.
Leadon has produced approximately 8 million barrels of oil equivalent (BOE)
through 2002, and remaining reserves are estimated at about 30 million BOE.
The company's North Sea exploration program included one wildcat well in 2002.
No discoveries were made.
The following is a summary of the company's five key developments in the North
Sea, which contributed approximately 57% of the region's total net production
(Kerr-McGee-operated unless stated otherwise):
Leadon field, block 9/14a, 9/14b (100%): Average 2002 gross production from the
Leadon field was 18,200 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%): An additional 5% equity interest in the
nonoperated Harding field was acquired as part of a northern North Sea asset
sale. Average 2002 gross production from the Harding field was 60,600 barrels of
oil per day. The Harding field provides Kerr-McGee with additional
infrastructure in the strategically important Quad 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 started production in December
2001. Average 2002 gross field production was 144 million cubic feet of gas per
day and 8,200 barrels of oil per day. The Skene field is being produced by 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.
Janice field, block 30/17a (75.3%): Average 2002 gross production from the
Janice field was 14,900 barrels of oil per day and more than 1.5 million cubic
feet of gas per day. An additional equity interest of 24.4% was acquired in
2002.
Gryphon area, blocks 9/18a, 9/18b, 9/19 and 9/23a (33.3% - 100%): Average 2002
gross production from the Gryphon area was 20,500 barrels of oil per day and 2.1
million cubic feet of gas per day. The Maclure and Tullich satellites began
production in August 2002. The Gryphon area is produced into an FPSO vessel,
with oil exported via shuttle tanker. Gas is exported to the Leadon facility for
fuel usage and/or sold from 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 2002, onshore production
represented 51% of the company's worldwide gas production and 15% of its oil
production. A major focus in 2002 was the exploitation of undeveloped gas
reserves acquired from HS Resources in 2001. In addition, the company completed
a divestiture program of high-cost, low-margin waterflood properties in 2002.
Following is a summary of key U.S. onshore developments:
Wattenberg field (94%): The Wattenberg gas field is located in the
Denver-Julesberg (D-J) Basin in northeast Colorado. Kerr-McGee gained interest
in the field with the acquisition of HS Resources in 2001. Kerr-McGee's 2002 net
production from this field was 10,450 barrels of oil per day and 178 million
cubic feet of gas per day. In 2002, the company completed nearly 550 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 connection with the large number of operational activities,
the company reengineered its stimulation design program and, together with
internal supply-chain initiatives, reduced stimulation costs by as much as 50%.
In addition to the ongoing D-J Basin exploitation program, the company continued
the successful integration of the Wattenberg Gathering System (WGS) into its
operating activities. Kerr-McGee operates more than 3,000 wells in the D-J
Basin, nearly 1,800 of which are connected to WGS. The company-operated
production represents about 70% of the total system throughput of approximately
260 million cubic feet of natural gas per day, 30 million cubic feet of which is
processed at the company's new Ft. Lupton plant.
Flores and Jeffress fields, Starr and Hidalgo counties, Texas (80%): The company
completed 14 new wells and an additional 14 workover projects during 2002. Over
the past three years, a total of 55 wells have been drilled. Kerr-McGee's net
production from both fields for 2002 averaged 2,200 barrels of oil per day and
43 million cubic feet of gas per day.
Chambers County, Texas (75%): Seven new wells and an additional six workover
projects were completed in 2002. Kerr-McGee's net production from the area
during 2002 averaged 900 barrels of oil per day and 20 million cubic feet of gas
per day.
Mocane-Laverne field, Harper and Beaver counties, Oklahoma (60%): Development of
properties acquired from trades in 2000 and 2001 continued. Since 1998, a total
of 54 wells have been drilled, and a 10-well drilling program is currently under
way. In addition, nine workover projects were completed in 2002. Kerr-McGee's
net production for 2002 from the field was 17 million cubic feet of gas per day.
Other International:
In 2002, Kerr-McGee continued its exploration and production efforts in selected
international areas and successfully completed the divestiture of its noncore
interests in Ecuador, Indonesia and the Bayu-Undan project in Australia. The
company currently has an executed purchase and sale agreement in place for the
sale of its operations in Kazakhstan. The sale is expected to close in March
2003.
China
Liuhua 11-1 field, South China Sea (24.5%): Gross production for 2002 was 14,450
barrels of oil per day. One sidetrack and one extended-reach well were completed
in 2002. Two sidetracks and a second extended-reach well are planned for 2003.
Bohai Bay block 04/36 (81.8%): During 2002, Kerr-McGee submitted development
plans to the Chinese government for the CFD 11-1 and 11-2 fields. These plans
are now under consideration for formal project sanction. The project schedule
anticipates first oil in 2004, with development drilling due to start in the
third quarter of 2003. No additional appraisal wells were drilled in 2002 on CFD
11-1 and 11-2 following the two successful appraisal wells completed in 2001.
A new wildcat discovery, CFD 11-3-1, was followed by a successful appraisal well
three miles east of the CFD 11-1 development area, and additional appraisal
drilling is planned for the area. Another discovery well was drilled at CFD
16-1-1 that will be appraised in 2003.
Bohai Bay block 05/36 (50%): During 2002, Kerr-McGee evaluated potential
development options for the CFD 12-1 and 12-1S discoveries, including options to
tie back to the CFD 11-1 discovery in the 04/36 block. Additional exploration
drilling is planned for 2003.
Bohai Bay block 09/18 (100%): This block includes more than 535,000 gross acres
and is located south of Kerr-McGee-operated blocks 04/36 and 05/36. Block 09/18
has similar play concepts as the company's fields and discoveries on blocks
04/36 and 05/36. Seismic data has been acquired, and three exploration wells are
planned for 2003.
Indonesia
The company completed the divestiture of the Jabung block to Petronas Carigali
Overseas Sdn Bhd., a subsidiary of Petroliam Nasional Bhd (PETRONAS), in June
2002.
Ecuador
The company completed the divestiture of its entire equity ownership in Ecuador
to Perenco Ecuador Limited, a subsidiary of Perenco S.A., and Burlington
Resources Oriente Limited, in September 2002. The assets consisted of one
producing license and one license under development.
Kazakhstan
The company executed an agreement with Shell Kazakhstan Development in 2002 for
the sale of its operations in Kazakhstan. The assets consist of one producing
license, one exploration license and an equity ownership in the Caspian Pipeline
Consortium. The sale is expected to close in March 2003.
Australia
Bayu-Undan field (11.2%): The company divested its entire equity ownership in
the Bayu-Undan field in May 2002.
WA 278 (39%): A retention lease application is currently being negotiated with
the Australian government for the areas around Kerr-McGee's Prometheus and
Rubicon successful but presently noncommercial gas discoveries in 2000.
WA 295 (50%): Kerr-McGee operates this 3.5 million-acre block in the Carnarvon
basin. Acquisition of 4,800 kilometers of 2-D seismic data was completed in
2001. A two-well drilling program was initiated in late 2002. The Wigmore
prospect was the first drilled and was unsuccessful. Drilling of a second well
is planned in mid-2003.
WA 301 and 304 (50%), WA 302, 303 and 305 (33.3%): Kerr-McGee has an interest in
6.4 million acres in the deepwater Browse basin. Seismic and geological studies
have been ongoing for two years, in preparation for the initial exploration
well, Maginnis, which began drilling in early 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 commenced in late 2002 and both wells were dry.
Additional 2-D seismic data is planned for 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.
Brazil
BS-1 (40%): A second exploration well, the Ana prospect, was drilled in 2002.
The well failed to find commercial hydrocarbons, and data collected in the well
condemned several other prospects on the block. As a result, Kerr-McGee elected
to relinquish the acreage in 2002. Kerr-McGee was operator of this 2.2 million
gross acre block.
BM-S-3 (30%): This deepwater Santos basin block covers 1.6 million acres.
Additional analysis was conducted on this block subsequent to the drilling in
BS-1, which is a direct offsetting block. The plays in BM-S-3 became
noncommercial as a result of the drilling activity, and Kerr-McGee elected to
relinquish the acreage in 2002.
BM-ES-9 (30%): 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.
Gabon
Anton and Astrid Marin blocks (14%): Located offshore along the southern coast
of Gabon, the Anton and Astrid Marin blocks total 3.1 million acres. A four-well
drilling program was completed in late 2001. After evaluating all of the well
and seismic data, Kerr-McGee elected to relinquish the acreage in 2002.
Olonga Marin block (25%): Kerr-McGee and partners plan to conduct seismic
operations after 2003.
Morocco
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 from 650 feet to 6,500 feet. A 3-D seismic acquisition
was completed in 2002 and is currently being evaluated.
Boujdour block (100%): In October 2001, Kerr-McGee acquired a reconnaissance
permit covering approximately 27 million acres offshore Morocco from the
shoreline to a water depth of more than 10,000 feet. A reconnaissance permit
allows Kerr-McGee to perform seismic and related activities for evaluation
purposes. Kerr-McGee completed its acquisition of a large 2-D seismic grid in
January 2003, and the data is currently being evaluated.
Nova Scotia, Canada
EL2383, EL2386, EL2393 and EL 2396 (50%): Kerr-McGee is operator of four
deepwater blocks covering approximately 1.5 million acres located 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, EL2399 and EL2404 (100%): These 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 is planned
for 2003.
Thailand
Block W7/38, Andaman Sea (85%): Kerr-McGee was the operator of this 4.9
million-acre block. The license for this block expired in March 2002, and the
company no longer has an interest in Thailand.
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 call for Petronas
to pay a disproportionate share of costs for seismic data and an exploratory
well, which will be drilled in 2003. Upon completion of the farm-in obligation,
Kerr-McGee's interest will be reduced to 31.7%.
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 subsidiaries Kerr-McGee Chemical LLC,
KMCC Western Australia Pty. Ltd., Kerr-McGee Pigments GmbH, Kerr-McGee Pigments
International GmbH, Kerr-McGee Pigments Limited, Kerr-McGee Pigments (Holland)
B.V. and Kerr-McGee Pigments (Savannah) Inc. Many of these products are
manufactured using proprietary technology developed by the company.
Industrial chemicals include titanium dioxide, synthetic rutile, manganese
dioxide 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. The company took an after-tax charge of $15 million for plant
and equipment impairment and decommissioning expenses.
In January 2003, Kerr-McGee announced a plan to close its synthetic rutile plant
in Mobile, Alabama, by year-end 2003. This plant closure is another step in the
company's plan to enhance its operating profitability. The Mobile plant
processes and supplies a portion of the feedstock for the company's titanium
dioxide pigment plants in the United States. Through Kerr-McGee's ongoing
supply-chain initiatives, the company now can purchase the feedstock more
economically than it can be manufactured at the Mobile plant. As a result of
these steps, the company anticipates significant savings.
During March 2003, the company announced the temporary shutdown of the Mobile
synthetic rutile plant due to imposition of a new, much lower limit for one
effluent impurity effective March 1, 2003. This limit did not exist previously
under the plant's operating permit. The synthetic rutile plant will remain shut
down until Kerr-McGee is confident it can meet this new permit condition.
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 and paper. 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 over the past 20 years.
The chloride process currently makes up about 60% of total industry 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 chloride process accounts for approximately 74% of the
company's production capacity. The following table outlines the company's
production capacity by location and process.
TiO2 Capacity
As of January 1, 2003
(Gross tonnes per year)
Facility Capacity Process
- -------- -------- -------
Hamilton, Mississippi 200,000 Chloride
Savannah, Georgia 91,000 Chloride
Kwinana, Western Australia (1) 95,000 Chloride
Botlek, Netherlands 62,000 Chloride
Uerdingen, Germany 105,000 Sulfate
Savannah, Georgia 54,000 Sulfate
-------
Total 607,000
=======
(1) The Kwinana facility is part of the Tiwest Joint Venture, in which the
company owns a 50% interest.
The company owns a 50% 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 mineral separation facility, a synthetic
rutile facility and a titanium dioxide plant.
Heavy minerals are mined from 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 5.7 million tonnes of heavy minerals contained in 195
million tonnes of sand averaging 2.9% heavy minerals. The valuable heavy
minerals are composed of 61% ilmenite, 10.3% zircon, 4.5% natural rutile and
3.4% leucoxene, with the remaining 20.8% of heavy minerals presently having no
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 200,000 tonnes per year.
Synthetic rutile is a high-grade titanium dioxide feedstock. Synthetic rutile
from the Tiwest Joint Venture provides feedstock to a 95,000 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 purchased by Kerr-McGee as part of the feedstock
requirement for its TiO2 business 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, 2002, 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) 2002 2001 2000
- ---------------------------- ----- ----- -----
Proven and probable reserves 5,700 5,800 6,700
Production 289 280 293
Average market price (per tonne) $150 $143 $145
The company also operates a synthetic rutile production facility located in
Mobile, Alabama. This facility, with an annual production capacity of 200,000
tonnes per year, provides a portion of the feedstock for the company's titanium
dioxide business. As previously noted, the company has announced its plans to
close the Mobile facility by the end of 2003, and the plant is temporarily shut
down due to a new operating permit restriction.
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 and Ukraine. Ores are generally purchased under multi-year
agreements.
The global market in which the company's titanium dioxide business operates is
highly competitive. The company actively markets its 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. World demand for
titanium dioxide is expected to increase 4% in 2003.
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.
Applications for this battery include telecommunications stand-by power, utility
peak shaving, electric vehicles and hybrid electric vehicles. The first
commercial LMP battery is specifically designed for the telecommunications
market and is superior to lead-acid battery technology in both performance and
life. In 2002, a 120-megawatt-hour LMP production facility was built and
commissioned at Boucherville, Quebec. Production rates are expected to increase
throughout 2003 to the rated capacity.
Other Products
- --------------
The chemical - other operating unit consists of the company's electrolytic
operations and forest products business.
Electrolytic Products - Plants at the company's Hamilton, Mississippi, complex
include a 130,000 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's
share of the U.S. market is about 8%.
The company operates facilities at Henderson, Nevada, producing electrolytic
manganese dioxide and boron trichloride. Annual production capacity is 26,500
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.
Increased 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. The company's six wood-treating plants are
located along major railways in Madison, Illinois; Indianapolis, Indiana;
Columbus, Mississippi; Springfield, Missouri; The Dalles, Oregon; and Texarkana,
Texas. In October 2002, the Indianapolis, Indiana, plant ceased operations, and
plant dismantlement was initiated. The company has announced the planned closing
of the Madison, Columbus, Springfield and Texarkana plants by the end of 2003.
The Dalles plant is a leased facility, and the company's options at the site
include continuation of operations for the term of the lease or sale. The lease
expires November 30, 2004.
For more information regarding the company's plan to exit the forest products
business and for information as to the chemical - other operating unit's
revenues and operating profit (loss) for the three-year period ended December
31, 2002, reference is made to Notes 10 and 27 to the Consolidated Financial
Statements included in Item 8. of this Form 10-K.
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 electrolytic businesses.
Employees
- ---------
On December 31, 2002, the company and its affiliates had 4,470 employees.
Approximately 984, or 22% 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 over 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 the ISO 9002 for quality management and ISO 14001 for environmental
management standards developed by the International Organization for
Standardization, a nongovernmental organization that promotes the development of
standards and related activities 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. 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 2002, direct capital and operating expenditures related to environmental
protection and cleanup of existing sites totaled $59 million. Additional
expenditures totaling $128 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
2003 it will incur $33 million in direct capital expenditures, $35 million in
operating expenditures and $100 million in expenditures charged to reserves.
Additionally, the company estimates that in 2004 it will incur $17 million in
direct capital expenditures, $20 million in operating expenditures and $100
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, and 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 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 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 are continually changing, and court
proceedings 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 a reserve 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 upon 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 are dependent upon numerous factors that are beyond its
control. These factors include, but are not limited to, 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, and the overall economic environment. Any significant
decline in prices for oil and gas could have a material adverse effect on the
company's financial condition, results of operations and quantities of reserves
recoverable on an economic basis. Demand for titanium dioxide is dependent on
the demand for ultimate products utilizing titanium dioxide pigment. This demand
is generally dependent on the condition of the economy. The profitability of the
company's products is dependent on the price realized for them, the efficiency
of manufacturing costs, 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.
State and Local Regulation of Oil and Gas Development and Surface Development
Conflicts Could Adversely Affect Results
- -------------------------------------------------------------------------------
State regulatory authorities have established rules and regulations governing,
among other things, 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,
taxation, and environmental and conservation matters. In general, these measures
make oil and gas development more difficult, and their application to the
company's operations could adversely affect its results of operations.
Failure to Fund Continued Capital Expenditures Could Adversely Affect Results
- -----------------------------------------------------------------------------
The company expects that it will 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
otherwise, 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, and its future cash generation may be
materially adversely affected as a result of the failure to find and develop
reserves.
Oil and Gas Reserve Information Is Estimated
- --------------------------------------------
The proved oil and gas reserve information included in this Form 10-K represents
estimates. These estimates are based primarily on reports prepared by the
company's geologists and engineers. Petroleum engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
measured in an exact manner. Estimates of economically recoverable oil and gas
reserves and of future net cash flows necessarily depend on a number of variable
factors and assumptions, including:
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 SEC, the estimated discounted future
net cash flows from proved reserves are generally 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.
In addition, 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.
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 favorably disposed towards U.S.
exploration and production companies.
Oil and Gas Operations Involve Substantial Costs and Are Subject to Various
Economic Risks
- -------------------------------------------------------------------------------
The company's oil and gas operations are subject to the economic risks typically
associated with exploration, development and production activities. In
conducting exploration and development activities, the presence of unanticipated
pressure or irregularities in formations, miscalculations or accidents may cause
the company's exploration, development and production activities to be
unsuccessful. This could result in a total loss of the company's investment in a
particular property. If exploration efforts in a country are unsuccessful in
establishing proved reserves and exploration activities cease, the amounts
accumulated as unproved costs would be charged against earnings as impairments.
In addition, the cost and timing of drilling, completing and operating wells is
often uncertain.
Competition is Intense
- ----------------------
The exploration and production business and the titanium dioxide pigment
business are each highly competitive. 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.
AVAILABILITY OF REPORTS
Effective January 1, 2003, Kerr-McGee made 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 Securities and Exchange Commission (SEC).
Interested parties should refer to the Investor Relations link on the company's
website. Reports on Forms 10-Q and 10-K are available for all 2001 and 2002
filings and Current Reports on Form 8-K are available for all filings subsequent
to January 1, 2003.
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 December 2001, Kerr-McGee North Sea (U.K.) Limited received a notice of
violation of the Prevention of Oil Pollution Act 1971 and of the Merchant
Shipping (Oil Pollution Preparedness, Response and Cooperation Convention)
Regulations 1998 from authorities in Scotland. This matter is currently pending
in the Sheriff Court, Aberdeen, Scotland, and concerns a subsea pipeline leak
associated with the company's North Sea Hutton facility. The company is
vigorously defending the matter and believes that any fines and penalties will
not have a material adverse effect on the company.
C. 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 is vigorously defending the proceeding, which is
pending in the Court of Petty Sessions, Perth, Western Australia. 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.
D. 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 2002.
Executive Officers of the Registrant
The following is a list of executive officers, their ages, and their positions
and offices as of March 15, 2003:
Name Age Office
- ------------------ --- -------------------------------------------------
Luke R. Corbett 56 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 59 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 46 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 46 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, Executive Vice President and
General Manager for Atlanta office of Edelman
Worldwide and Executive Vice President of Cohn &
Wolfe, a division of Young & Rubicam, Inc.
Robert M. Wohleber 52 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 54 Senior Vice President since 1997. Senior Vice
President of Marketing for Kerr-McGee Chemical
from 1996 to 1997.
George D. Christiansen 58 Vice President, Safety and Environmental Affairs,
since 1998. Vice President, Environmental
Assessment and Remediation, from 1996 to 1998.
Fran G. Heartwell 56 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 53 Vice President since 1987. Controller since
January 2002. Treasurer from 1996 to 2002.
John F. Reichenberger 50 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 45 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 U.S. Private Securities
Litigation Reform Act of 1995. 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, 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 33 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 2002,
2001 and 2000. Cash dividends have been paid continuously since 1941 and totaled
$181 million in 2002, $173 million in 2001 and $166 million in 2000.
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 "Nine-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's assets total approximately
$10 billion, and proved oil and gas reserves are approximately 1 billion barrels
of oil equivalent. The equity production capacity for titanium dioxide pigment
is 560,000 tonnes per year. For 2002, revenues from continuing operations
totaled $3.7 billion, of which $2.5 billion (68%) was generated by the company's
oil and gas exploration and production operations and $1.2 billion (32%) was
generated by the company's chemical operations.
- --------------------------------------------------------------------------------
Operating Environment and Outlook
Oil and Gas Exploration and Production
While the 2002 financial results are disappointing, Kerr-McGee has started 2003
in a stronger position as a result of its program to sell noncore and
higher-cost oil and gas assets. These sales yielded proceeds of approximately
$760 million during 2002, and completion of additional transactions is expected
in 2003. The proceeds have enabled the company to reduce total debt by 15% from
the 2001 year-end level. Kerr-McGee's goal is to reduce its
debt-to-capitalization ratio below 50%. As the company benefits from the sale of
the higher-cost fields and ramps up production from efficient new deepwater
projects, lifting costs are expected to decline by approximately 20% per barrel
of oil equivalent.
The volatility of crude oil and natural gas prices has a significant impact on
the profitability of Kerr-McGee's oil and gas exploration and production
business. While financial instruments and marketing arrangements have the
potential to dampen this volatility in certain circumstances, the uncertainty
surrounding commodity markets, directly affected by geopolitical issues and
global economies, must be analyzed in projecting future sales environments. To
provide greater predictability of cash flow necessary to fund exploration and
capital programs, the company hedged about 40% of its 2002 production and
currently has hedged approximately half of its 2003 production.
The oil and gas industry operated in an environment of uncertainty during 2002.
The effects of the September 2001 terrorist attack still lingered in the global
economy, with discernible global consequences. Concerns about possible military
action in the Middle East set in early in the year. Venezuela dealt with
political strife that began in 2001 and led to a general strike in 2002. Despite
early expectations, the U.S. economy did not experience the recovery anticipated
early in the year, and financial markets were impacted by a series of corporate
scandals. The resulting commercial environment and price volatility profoundly
impacted investment decisions by the oil and gas industry.
The U.S. petroleum market began the year with ample inventories carried over
from 2001. The price of crude oil hovered near $20 per barrel. Reacting to weak
prices due to sluggish demand, OPEC and significant non-OPEC producers cut back
production effective January 1, 2002. Geopolitical uncertainties, combined with
the surprisingly high quota compliance by OPEC and non-OPEC producers (and their
agreement to extend the quota reduction into the second quarter) supported oil
price recovery. By the end of the first quarter, the well-referenced West Texas
Intermediate (WTI) spot price for crude oil had surpassed $25 per barrel.
After reaching the top of the average range during the first quarter, crude oil
inventories in the U.S. began to slide in April, reflecting the effect of the
production cuts. As the U.S. entered the summer driving season, a self-imposed
30-day delivery cutoff by Iraq increased market tension. Crude oil stocks began
a steep decline, reaching the lower level of the historical average range by the
end of August. Tightening of demand/supply market fundamentals as well as
geopolitical events caused late-year upward pressure on the crude oil market.
Tropical storms also influenced crude oil markets, causing U.S. crude oil stocks
to briefly decline to historically low levels. The spot price of WTI soared
above $30 per barrel. U.S. crude oil stocks increased in the fourth quarter,
tracking at the lower end of the historical average range. By the end of the
year, when crude oil imports declined again due to the strike in Venezuela, the
WTI spot price briefly climbed over $32 per barrel.
Reacting to an economy characterized by uncertainty, caution and concern over
investment risk, U.S. oil consumption rose only slightly on the strength of
continued increases in transportation sector use. OPEC discipline, a perceived
premium associated with the possibility of war in the Middle East and low levels
of crude oil stocks (the lowest in five years) added near-term upward pressure
to cyclical demand.
Natural gas pricing also demonstrated strong upward movement during the year.
Natural gas prices are driven by weather, pipeline capacity, storage (capacity
and management) and supply reliability. The increase in natural gas prices was
partially due to the competitive fuel prices and the evident decline of
production in North America. Market signals require time to develop a supply
response. Strong downward pressure on natural gas prices through 2001, plus the
relatively full levels of natural gas storage at the end of the heating season,
contributed to uncertainty that translated into unexpectedly low drilling
activity as the year progressed. Reference New York Mercantile Exchange (NYMEX)
gas prices began the year at $2.75 per million British thermal units (MMBtu),
declined to about $2/MMBtu during February when storage levels were relatively
high, and rose to $3.50/MMBtu by the end of the first quarter. After trending
lower through the summer, prices began to reflect anticipated heating season
loads and declining deliverability, climbing steadily to $4.80/MMBtu by
year-end.
The upstream oil and gas environment at the end of 2002 was nearly the reverse
of that which characterized the beginning of the year. Oil prices were
relatively high, natural gas prices were extremely strong and natural gas demand
appeared to be rising, but drilling activity, which increased slowly during the
year, did not yet reflect levels that historically have been characteristic of
periods during which there is investment in new supply. Due to global economic
conditions, mixed signals from the marketplace, and numerous regulatory and
financial uncertainties, the level of concern that permeated the early part of
the year progressed to an investment climate of extreme caution. Diligence in
investment - choosing only the most value-added opportunities - replaced an
industry quest for increased exploration investment. In this environment of
market volatility and uncertainty, budget discipline and flexibility in
near-term spending are high priorities.
Kerr-McGee's growth strategy for its exploration and production operating unit
is focused primarily on the deepwater Gulf of Mexico and selected international
basins. In addition, the company will continue to pursue opportunities in the
U.K. North Sea, U.S. onshore, Gulf of Mexico shelf and China. The company
expects to build growth through the drill bit and to seek strategic partnerships
and acquisitions.
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 and plastics industries. In early 2003, chloride
technology accounted for about 74% of the company's pigment production capacity.
The remaining capacity is sulfate-process production.
Titanium dioxide is a "quality-of-life" product, and its consumption follows
general economic trends. Since a low point in the business cycle was experienced
in the winter of 2001, economic growth indicators associated with pigment demand
improved at a moderate pace. This strengthening demand for the company's pigment
products supported price increases throughout 2002.
Modest growth in the U.S. economy is expected to continue in 2003, bolstered by
strong automotive and construction markets. Further supporting this outlook are
recent early signals of a rebound in business confidence. Outside the U.S.,
moderate growth in the Euro-zone and Japanese gross domestic products is
expected to continue. In Southeast Asia, where growth is well in excess of other
regions, significant progress has been made toward trade facilitation in the
area of customs and through elimination of technical barriers.
The Kerr-McGee chemical operating unit's strategy focuses on technology
improvements and cost control. This includes an integrated portfolio of supply
chain initiatives, continuous improvement and technology-based efficiency
programs. Accordingly, operating results should improve with the success of
these initiatives as well as the price increases that began in 2002 and are
expected to continue through 2003. During 2003, the company will continue its
low-cost plant capacity expansions in line with market growth. The company also
remains focused on exiting noncore businesses within its chemical operations,
while growing new opportunities aligned with its core competencies.
New opportunities for capitalizing on the company's experience are carefully
considered. One such opportunity is AVESTOR. This joint venture with
Hydro-Quebec, one of North America's largest utilities, was formed in 2001 to
produce a revolutionary lithium-metal-polymer battery. Commercial sales will
begin in 2003 with batteries that increase the reliability of telecommunication
networks during power outages. Work is under way on future applications,
including peak-power shaving and use in electric and hybrid electric vehicles.
The company is committed to growing this business and expects to invest an
additional $50 million in the joint venture in 2003.
In January 2003, Kerr-McGee announced a plan to close its synthetic rutile plant
in Mobile, Alabama, by year-end 2003. This plant closure is another step in the
company's plan to enhance its operating profitability. The Mobile plant
processes and supplies a portion of the feedstock for the company's titanium
dioxide pigment plants in the United States. Through Kerr-McGee's ongoing supply
chain initiatives, the company now can purchase the feedstock more economically
than it can be manufactured at the Mobile plant. As a result of these steps, the
company anticipates significant savings.
During March 2003, the company announced the temporary shutdown of the Mobile
synthetic rutile plant due to imposition of a new, much lower limit for one
effluent impurity effective March 1, 2003. This limit did not exist previously
under the plant's operating permit. The synthetic rutile plant will remain shut
down until Kerr-McGee is confident it can meet this new permit condition.
- --------------------------------------------------------------------------------
Results of Consolidated Operations
Net income (loss) and per-share amounts for each of the years in the three-year
period ended December 31, 2002, were as follows:
(Millions of dollars,
except per-share amounts) 2002 2001 2000
- ------------------------- ----- ---- ----
Net income (loss) $(485) $486 $842
Net income (loss) per share -
Basic (4.84) 5.01 9.01
Diluted (4.84) 4.74 8.37
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
------------------------
2002 2001
Versus Versus
(Millions of dollars) 2001 2000
- --------------------- ----- -----
Exploration and production net operating profit $(850) $(346)
Chemical - pigment net operating profit 25 (82)
Chemical - other net operating profit (4) (22)
Net interest expense (56) 4
Other income/expense (202) 105
Discontinued operations 96 5
Cumulative effect of accounting change 20 (20)
----- -----
Net income $(971) $(356)
===== =====
The majority of the 2002 decline in exploration and production net operating
profit resulted from asset impairments of $561 million and the deferred tax
effect of $132 million for the 33% increase in the U.K. corporate tax rate for
oil and gas companies. The remaining $157 million decrease is due principally to
higher lease operating expense, shipping and handling expense, depreciation and
depletion, and exploration expense.
The improvement in chemical's pigment net operating profit in 2002 is
principally the result of higher pigment sales volumes and lower average
per-unit production costs. Higher interest expense in 2002 is due to
significantly higher average debt outstanding and lower capitalized interest,
partially offset by a lower overall average interest rate.
The negative variance for other income/expense is mainly due to the 2001
adoption of the Financial Accounting Standards Board's (FASB) Statement No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (FAS 133), as
amended, that allowed the company to reclassify 85% of the Devon Energy
Corporation (Devon) shares owned to "trading" from the "available for sale"
category of investments. This resulted in a $118 million net unrealized gain on
the stock being recognized in income as of January 1, 2001, with a corresponding
reduction in other comprehensive income where the unrealized gain had previously
been recorded. 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.
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. All
periods presented have been restated to reflect these interests as discontinued
operations in the financial statements.
The cumulative effect of the change in accounting principle is the result of 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 stock (DECS) of Devon presently 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.
The 2001 decrease in exploration and production net operating profit primarily
was due to significantly lower average sales prices and volumes for crude oil
and natural gas, the Hutton U.K. North Sea asset impairment in 2001 and higher
exploration, gas gathering, pipeline and transportation expenses. The decline in
2001 net operating profit from chemicals resulted mainly from lower pigment
sales prices and volumes, the 2001 provisions for closure of the pigment plant
in Belgium, asset impairments, severance and other costs. The 2001 other
income/expense variance was mainly the result of the $118 million unrealized
gain on Devon stock reclassified to the "trading" category of investments,
discussed above.
- --------------------------------------------------------------------------------
Statement of Operations Comparisons
Sales (Billions of dollars) 2002 2001 2000
- --------------------------- ---- ---- ----
Oil and gas and pigment sales $3.7 $3.6 $4.1
increased in 2002 compared
with 2001.
The increase in 2002 sales primarily was 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. The decrease in 2001 revenues compared
with 2000 was due primarily to a decrease in crude oil and pigment sales prices
and volumes, partially offset by five months of revenues from the Rocky Mountain
region. These variances are discussed in more detail in the segment discussion
that follows.
Costs and operating expenses increased $241 million in 2002 from the 2001 level,
resulting principally from higher gas marketing and pipeline costs of $105
million (full year of Rocky Mountain operations in 2002 versus five months in
2001), higher lease operating expenses of $80 million (higher crude oil and
natural gas production volumes) and higher pigment production cost of $91
million (increased pigment production volumes). The 2001 costs and operating
expenses increased $44 million over 2000, principally due to costs for closing
the pigment plant in Belgium, discontinuation of manganese metal production at
Hamilton, Mississippi, and the write-down of certain pigment inventories.
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. These lawsuits are discussed in Note 16 to the
financial statements. The 2001 selling, general and administrative expenses
increased $31 million over the 2000 expenses. This increase resulted principally
from the acquisition of HS Resources in August 2001, completion of the
integration of the two chemical plants acquired in the second quarter of 2000,
higher costs for information technology projects, higher incentive compensation
based on 2000 performance and higher chemical warehousing costs due to higher
inventory levels.
Shipping and handling expenses for 2002, 2001 and 2000 were $125 million, $111
million and $98 million, respectively. The 2002 increase is primarily due to
higher costs for shipping product from the new deepwater fields in the Gulf of
Mexico, including Nansen, Boomvang and Navajo, and higher costs in the Rocky
Mountain region due to the inclusion of the first full year of costs related to
the former HS Resources operations. The 2001 increase was due to higher natural
gas sales volumes, mainly from five months of Rocky Mountain sales and increased
transportation costs in the North Sea.
Depreciation and depletion expense totaled $774 million in 2002, $713 million in
2001 and $678 million in 2000. The 2002 increase was due to higher depreciation
and depletion for the Rocky Mountain region of $75 million (full year of
expense) and for the U.K. region of $11 million (mainly due to a full year of
expense on the Leadon and Skene fields, partially offset by having no
depreciation on certain assets while they were held for sale). Partially
offsetting these increases was lower expense in the U.S. offshore region of $24
million due to normal declines in production and held-for-sale properties, which
more than offset the impact of production from the Nansen, Boomvang and Navajo
fields. The 2001 increase was due to a $16 million charge for discontinued
capital projects and write-off of certain assets no longer used in the pigment
operations, the acquisition of HS Resources in August 2001, the oil and gas
production mix in the other regions, and a full year of depreciation for the two
chemical plants acquired in the second quarter of 2000.
Asset impairments totaled $828 million in 2002 and $76 million in 2001. These
impairments were due to certain assets that were no longer expected to recover
their net book values through future cash flows. The impairments in 2002
included $541 million for the Leadon field in the North Sea. The field had been
producing lower volumes than initially anticipated due to water breakthrough and
reservoir compartmentalization. The company conducted additional drilling and
field performance analysis during the third and fourth quarters of 2002, and
after considering various alternatives for the field, the asset was written down
to its fair value based on expected future cash flows. The impairment assumes
the tieback of all subsea wells to other fixed infrastructure in the area
(possibly the Kerr-McGee-operated Gryphon field), allowing the company to
monetize the Leadon state-of-the-art floating facility by marketing it as a
development option for another discovery. Should the company be unsuccessful in
marketing the Leadon vessel or unable to tie the field back to other existing
infrastructure, Kerr-McGee would expect to continue with the Leadon vessel in
place and produce from the existing wells until they are fully depleted. In
addition, the company impaired to fair market value certain northern North Sea
and U.S. onshore and offshore noncore exploration and production assets
identified in early 2002 for divestiture totaling $176 million. Impairments
totaling $105 million for several older Gulf of Mexico shelf properties and
certain other North Sea fields were also recorded, primarily due to the
write-down of underlying oil and gas reserves. Additionally, a $6 million asset
impairment was recognized in connection with the company's planned shutdown of
the forest products operations. The 2001 impairments were comprised of a $47
million write-down associated with the shut-in of the North Sea Hutton field and
$29 million for certain chemical facilities in Belgium and the U.S.
Exploration costs were $273 million, $210 million and $169 million for 2002,
2001 and 2000, respectively. The 2002 increase was due to higher dry hole costs
of $41 million, mainly in the deepwater area of the Gulf of Mexico and in the
North Sea, higher nonproducing leasehold amortization of $11 million, and higher
geophysical costs of $5 million. The $41 million increase in 2001 was primarily
the result of higher planned exploratory drilling in Brazil, Gabon, Australia
and China, higher geophysical costs, principally from the HS Resources
acquisition, and higher amortization of nonproducing leaseholds. During 2003,
the company plans to drill additional wells and to continue seismic work on
deepwater blocks offshore Benin, Brazil, Morocco and Nova Scotia. The success of
these projects will impact the company's future exploration costs.
In connection with the company's second-quarter 2000 acquisition of the pigment
plant in Savannah, Georgia, certain incomplete research and development projects
were identified and valued as part of the purchase price. Since these projects
had no alternative future use to the company, $32 million was expensed at the
date of acquisition.
Interest and debt expense totaled $275 million in 2002, $195 million in 2001 and
$208 million in 2000. The $80 million increase in 2002 was due to an annual
average debt balance that was approximately $1.4 billion higher than for 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. The lower expense in 2001 was due to higher levels of interest being
capitalized on major development projects in the Gulf of Mexico and the North
Sea and lower interest rates, partially offset by significantly higher
borrowings resulting from the August 2001 HS Resources acquisition and higher
capital spending.
Other income (loss) includes the following for each of the years in the
three-year period ended December 31, 2002:
(Millions of dollars) 2002 2001 2000
- --------------------- ---- ---- ----
Foreign currency translation gain (loss) $(38) $ 3 $30
Income (loss) from equity affiliates (25) (5) 23
Unrealized gain on Devon stock reclassified to
"trading" category of investments - 181 -
Exchangeable debt derivative options and Devon
stock revaluations 27 17 -
Gains on speculative derivative contracts for gas
basis swaps acquired with HS Resources 8 27 -
All other (7) 1 (3)
---- ---- ---
$(35) $224 $50
==== ==== ===
Most of the 2002 foreign currency loss was a result of the company's U.K.
operations, where the company suffered from the unfavorable U.S. dollar/British
pound sterling exchange rates. The loss from equity affiliates for 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.
- --------------------------------------------------------------------------------
Segment Operations
Operating profit (loss) from each of the company's segments is summarized in the
following table:
(Millions of dollars) 2002 2001 2000
- --------------------- ----- ---- ------
Operating profit (loss) -
Exploration and production $(140) $922 $1,431
----- ---- ------
Chemicals -
Pigment 24 (22) 130
Other (23) (17) 17
----- ---- ------
Total Chemicals 1 (39) 147
----- ---- ------
Operating profit (loss) $(139) $883 $1,578
===== ==== ======
Exploration and Production
Exploration and production sales, operating profit (loss) and certain other
statistics are shown in the following table:
(Millions of dollars,
except per-unit amounts) 2002 2001 2000
- ------------------------ ------ ------ ------
Sales $2,504 $2,439 $2,802
====== ====== ======
Operating profit (loss) $ (140) $ 922 $1,431
====== ====== ======
Exploration expense $ 273 $ 210 $ 169
Net crude oil and condensate produced
(thousands of barrels per day) 191 189 200
Average price of crude oil sold
(per barrel) (1) $22.04 $22.60 $27.69
Natural gas sold (MMcf per day) 760 596 531
Average price of natural gas sold
(per Mcf) (1) $ 2.95 $ 3.83 $ 3.87
Average production costs (per BOE) $ 4.81 $ 4.53 $ 4.54
(1) Includes the results of the company's 2002 hedging program that reduced the
average price of crude oil and natural gas sold by $1.13 per barrel and
$.01 per Mcf, respectively.
Sales increased $65 million in 2002 compared with 2001, primarily driven by a
$108 million increase in Rocky Mountain gas marketing and other operating
income, partially offset by a decrease of $43 million in crude oil and natural
gas sales resulting from lower 2002 average sales prices, partially offset by
higher sales volumes. Average sales prices decreased 2% for crude oil and 23%
for natural gas, resulting in a decrease in total sales of $205 million.
However, a slight increase in crude oil sales volume, combined with a 28%
increase in natural gas sales volume (full year of Rocky Mountain production),
resulted in an offsetting increase in sales of $162 million.
Sales decreased $363 million from 2000 to 2001, of which $473 million was due to
a decrease in crude oil sales, partially offset by increases in natural gas
sales and other operating revenues of $81 million and $29 million, respectively.
The decrease in crude oil sales resulted from an 18% drop in the average
per-barrel sales price, causing year-over-year sales to decline $341 million,
combined with a 6%, or $132 million, decrease in sales volumes. The addition of
the HS Resources Rocky Mountain operations accounted for $62 million of the
increase in natural gas sales over 2000. Natural gas sales for existing
operations increased $24 million due to higher average sales prices, partially
offset by a $5 million decrease resulting from lower sales volumes. Other
operating revenues increased $29 million, primarily due to higher tariff income
and gas marketing income attributable to the HS Resources acquisition.
Operating profit, which decreased from $922 million in 2001 to a loss of $140
million in 2002, was adversely affected by higher asset impairment losses
combined with lower oil and gas sales prices, discussed above, and higher
production, exploration and other operating costs driven in part by higher
production volumes in 2002. In total, $822 million in asset impairment losses
were recorded in 2002, compared with $47 million in 2001, lowering operating
profit by $775 million between years. Assets held for use represented $646
million of the asset impairment loss, of which $541 million related to the
Leadon field in the U.K. area of the North Sea. An additional $82 million was
recorded for certain other U.K. North Sea fields, and $23 million was recorded
for several older Gulf of Mexico shelf properties. During 2002, additional
performance analysis of these fields resulted in downward revisions of reserve
estimates sufficient to lower future cash flow projections for the properties
below the carrying value of the related assets. The remaining $176 million asset
impairment loss related to assets classified as held for disposal in the U.S.,
North Sea and Ecuador. The 2001 asset impairment loss of $47 million was
attributable to the shutdown of the Hutton field in the North Sea.
Total 2002 operating expenses increased $352 million compared with 2001, due to
higher gas marketing and pipeline costs of $105 million (primarily an offset to
the increased income of $108 million for gas marketing and other, discussed
above), higher production expenses of $79 million, higher depreciation and
depletion expense of $66 million, higher exploration expense of $63 million,
higher environmental expense of $11 million, higher general and administrative
expenses of $15 million, and higher transportation costs of $13 million. The
higher production costs, depreciation and depletion expense, and transportation
expense resulted primarily from the increased crude oil and natural gas
production volumes. The increase in exploration expense resulted from the
company's expanded exploration program during the second half of 2002.
The decrease in operating profit of $509 million from 2000 to 2001 was primarily
due to the significant decline in average sales prices for crude oil and natural
gas, which resulted in a decrease in comparable sales year over year of $316
million, combined with net sales volume decreases of $76 million. In addition,
when compared with 2000, the 2001 period included the $47 million North Sea
Hutton field impairment, higher exploration expense of $41 million resulting
from the company's planned exploration program, higher gas gathering and
pipeline expenses of $43 million (of which $31 million was directly attributable
to additional costs associated with the acquired HS Resources operations),
higher transportation expense of $16 million, and higher depreciation and
depletion expense of $7 million, offset in part by lower production and general
and administrative costs of $8 million.
Chemicals
Chemical sales, operating profit (loss) and pigment production volumes are shown
in the following table:
(Millions of dollars) 2002 2001 2000
- --------------------- ------ ------ ------
Sales -
Pigment $ 995 $ 931 $1,034
Other 201 196 227
------ ------ ------
Total $1,196 $1,127 $1,261
====== ====== ======
Operating profit (loss) -
Pigment $ 24 $ (22) $ 130
Other (23) (17) 17
------ ------ ------
Total $ 1 $ (39) $ 147
====== ====== ======
Titanium dioxide pigment production
(thousands of tonnes) 508 483 480
Pigment - Titanium dioxide pigment sales for 2002 increased $64 million, or 7%,
over 2001 due to sales volume increases of $149 million, combined with an
offsetting decrease of $85 million resulting from weaker sales prices in 2002.
While poor overall market conditions persisted through the first quarter of
2002, product demand began to increase through the remainder of the year. As
demand accelerated, the company announced multiple price increases through the
second half of the year.
The $103 million, or 10%, decrease in titanium dioxide pigment sales from 2000
to 2001 was due to lower pigment sales prices, resulting in a decrease of $61
million between years and lower sales volumes that caused a drop of $42 million
in comparable sales. The 2001 global economic downturn led to reduced customer
demand and lower pricing.
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.
Operating profit in 2001 declined $152 million compared with 2000 due
principally to lower sales of $103 million, coupled with an $8 million increase
in operating expenses. Additionally, operating profit in 2001 included $79
million in plant closure provisions, asset impairments, severance and other
costs, as discussed above, compared with a 2000 write-off of $32 million for
acquired in-process research and development projects and $6 million in
transition costs incurred in connection with the purchase of two pigment plants.
Other - 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.
Other chemical sales declined $31 million from 2000 to 2001, of which $13
million resulted from the discontinued production of manganese metal, $11
million was due to lower manganese dioxide sales, and $6 million was due to
lower forest products sales. Operating profit decreased $34 million between
periods, primarily due to the $30 million in 2001 charges discussed above,
related to the discontinuation of manganese metal production, severance charges
and asset impairments.
- --------------------------------------------------------------------------------
Financial Condition
(Millions of dollars) 2002 2001 2000
- --------------------- -------- -------- --------
Current ratio 0.8 to 1 1.2 to 1 1.0 to 1
Total debt $3,904 $4,574 $2,425
Total debt less cash 3,814 4,483 2,281
Stockholders' equity $2,536 $3,174 $2,633
Total debt less cash to total
capitalization 60% 59% 46%
Floating-rate debt to total debt 7% 28% 3%
The negative working capital at the end of 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. Additionally, the company has
sufficient unused lines of credit and revolving credit facilities as discussed
in the Liquidity section that follows.
Kerr-McGee operates with a philosophy that over a plan period the company's
capital expenditures and dividends will be paid from cash generated by
operations. On a cumulative basis, the cash generated from operations for the
past four 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.
Net Debt to Total Capitalization
(Percentages) 2002 2001 2000
- ------------- ---- ---- ----
Net debt to total capitalization is total
debt less cash divided by total debt less
cash plus stockholders' equity. 60% 59% 46%
Although debt was reduced $670 million from 2001, the 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 as compared to
2001. The higher percentage of net debt to total capitalization in 2001 resulted
from the debt issued and assumed in conjunction with the acquisition of HS
Resources and the expenditures for major development projects in the Gulf of
Mexico and the North Sea.
Cash Flow
Net Cash Flow from Operating
Activities (Millions of dollars) 2002 2001 2000
- -------------------------------- ------ ------ ------
Net cash flow from operating
activities increased $305 $1,448 $1,143 $1,840
million in 2002.
Net cash flow from operating activities increased $305 million, from $1.1
billion in 2001 to $1.4 billion in 2002, primarily as a result of changes in
various working capital items, partially offset by a decrease in income
excluding noncash items. Year-end 2002 cash was $90 million, compared with $91
million at December 31, 2001.
The company invested $1.3 billion in its 2002 capital program, which included
$113 million of unsuccessful exploratory drilling costs. The capital program for
2002 was $592 million lower than in the prior year, resulting in part from the
completion of the major construction on certain field developments in the North
Sea and the Gulf of Mexico in late 2001 and early 2002. During 2002, the company
completed the divestiture of several oil and gas properties and other assets,
generating proceeds of $756 million. These proceeds were used primarily to lower
debt. The company also invested $24 million to acquire an additional 24%
interest in the Janice field in the U.K. North Sea, bringing its working
interest to 75%. Cash outlays for investing activities include a $47 million
investment by the chemical unit in AVESTOR, its lithium-metal-polymer battery
joint venture in Canada, and an additional $16 million investment for the
company's share of construction costs for the Caspian pipeline by the
exploration and production operating unit. Other investing activities provided
$10 million of net cash.
Total Debt (Millions of dollars) 2002 2001 2000
- -------------------------------- ------ ------ ------
Outstanding debt was reduced
$670 million in 2002. $3,904 $4,574 $2,425
During 2002, the company issued $350 million of 5.375% notes due April 2005. In
connection with this issuance, the company entered into an interest rate swap
agreement, the terms of which effectively change the fixed interest rate on the
notes to a variable rate of LIBOR plus .875%. Variable interest rate commercial
paper and revolving credit borrowings were reduced by $998 million on a net
basis in 2002, and other debt and short-term borrowings were reduced $35
million. Cash flow was used to pay the company's dividends of $181 million in
2002.
As of December 31, 2002, the company's senior unsecured debt was rated BBB by
Standard & Poor's and Fitch and the equivalent by Moody's. See Note 11 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, the company aggressively pursued its strategy of
divesting noncore and 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 during 2003 using proceeds from the divestiture of its
exploration and production operations in Kazakhstan, which are expected to total
approximately $140 million, and from excess cash flow.
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 would 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 flow decline, the company may
reduce its capital expenditures program, borrow under its commercial paper
program 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 as evidenced by a reduction in
the number of investors and/or amounts they are willing to invest.
At December 31, 2002, the company had unused lines of credit and committed
amounts under revolving credit agreements totaling $1.499 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
December 10, 2002. Of the two agreements, $860 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. The company also had a $100
million revolving credit agreement available to its Chinese subsidiary through
March 3, 2003, when the agreement lapsed and was not renewed. In addition, the
company had other unused credit facilities of $49 million and unused,
uncommitted lines of credit of $40 million at December 31, 2002. Interest for
each of the revolving credit facilities and lines of credit is payable at
varying rates.
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 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 (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 retains the right to up to 15% of the shares if Devon's stock price
is greater than $39.16 per share (the DECS holders have a call option on 85% of
the shares). Using the Black-Scholes valuation model, the company recognizes in
Other Income (Loss) any gains or losses resulting from changes in the fair value
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 85% of the Devon stock owned by the company. The
remaining 15% of the Devon shares are accounted for as available-for-sale
securities in accordance with FAS 115, "Accounting for Certain Investments in
Debt and Equity Securities," with changes in market value recorded in
accumulated other comprehensive income.
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 the
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 results in lowering the company's overall financing costs as
the subject discount rate is lower than the company's short-term borrowing rate.
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 five-year 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 has been financed by synthetic lease credit
facilities between the trust and groups of financial institutions for up to $157
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,
different trusts with third-party equity participants become the lessor/owner of
the platforms and related equipment. The company and these trusts have entered
into operating leases or, where construction is not yet complete, are committed
to purchase or sell the platform and related equipment or enter into an
operating lease 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 is expected in early 2004, at
which time the Gunnison synthetic lease will be converted to an operating lease.
Under this type of financing structure, the company leases the platforms under
operating lease agreements, and neither the platform assets nor the related debt
are recognized in the company's Consolidated Balance Sheet. In conjunction with
the operating lease agreements, the company has guaranteed that the residual
values of the Nansen, Boomvang and Gunnison platforms at the end of the
operating leases shall be equal to at least 10% of their fair market value at
the inception of the lease. For Nansen and Boomvang, the guaranteed values are
$14 million and $8 million, respectively, in 2022, and for Gunnison the
estimated guaranteed value is $16 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.
A pigment accounts receivable monetization program began in December 2000. Under
the terms of the credit-insurance-backed asset securitization, up to $165
million of selected pigment customers' accounts receivables may be sold monthly
to an unconsolidated special-purpose entity (SPE). Since the collection of the
receivables is insured, only receivables that qualify for credit insurance can
be sold. The SPE borrows the purchase price of the receivables at a lower
interest rate than Kerr-McGee's commercial paper rate and shares a portion of
the savings with the company through a reduced discount rate on the receivables
purchased. 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 and preference stock of the SPE, which is essentially
a deposit to provide credit enhancement, if needed, but otherwise recoverable by
the company) is based on the discounted present value of future cash flows. At
year-end 2002, the outstanding balance on receivables sold under the program
totaled $111 million. In the event the program is terminated, Kerr-McGee will
continue to act as collection agent until all its obligations under the
agreement are retired. Any costs resulting from a termination would be covered
by the value of the preference stock.
During 2002, the company entered into a sale-leaseback arrangement with General
Electric Capital Corporation (GECC) covering assets associated with a
gas-gathering system in the Rocky Mountain region. The lease agreement was
entered into for the purpose of monetizing the related assets. The sales price
of the 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. The operating lease agreement has an initial
term of five years, with two 12-month renewal options. The company may elect to
purchase the equipment at specified amounts after the end of the fourth year. In
the event the company does not purchase the equipment and it is returned to
GECC, the company guarantees a residual value ranging from $32 million at the
end of the initial five-year term to $25 million at the end of the last renewal
option. The company recorded no gain or loss associated with the GECC
sale-leaseback agreement. 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 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.
Obligations and Commitments
In the normal course of business, the company enters into purchase obligations,
contracts, leases and borrowing arrangements. The company has no material 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 the 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, 2002, are summarized in the following table:
(Millions of dollars) Payments due by period
- --------------------- --------------------------------------------------------------
Less than More than
Type of Obligation Total 1 year 1-3 years 3-5 years 5 years
- ------------------ ------ --------- --------- --------- ---------
Long-term debt $3,904 $106 $1,240 $475 $2,083
Operating leases for Nansen,
Boomvang and Gunnison 648 11 44 58 535
All other operating leases 201 28 52 44 77
Leveraged leases 1 1 - - -
Drilling rig commitments 24 15 9 - -
Purchase obligations 957 297 417 166 77
Guarantee of residual values
of leased equipment 70 - - 32 38
------ ---- ------ ---- ------
Total $5,805 $458 $1,762 $775 $2,810
====== ==== ====== ==== ======
In connection with certain contracts and agreements, the company enters into
indemnifications related to title claims, environmental matters, litigation and
other claims. Because of the inherent uncertainty surrounding these matters, the
amount of any future liability related to these indemnifications cannot be
reasonably estimated. If a claim is asserted or if information becomes known to
management indicating it is probable that a liability has been incurred and the
amount can be reasonably estimated, an accrual is established at that time.
- --------------------------------------------------------------------------------
Capital Spending
Capital expenditures are summarized as follows:
(Millions of dollars) Est. 2003 2002 2001 2000
- --------------------- --------- ------ ------ ------
Exploration and production $ 860 $ 988 $1,557 $682
Chemicals 130 86 153 118
Other, including discontinued
operations 20 85 82 42
------ ------ ------ ----
Total $1,010 $1,159 $1,792 $842
====== ====== ====== ====
Capital spending, excluding acquisitions, totaled $3.8 billion in the three-year
period ended December 31, 2002, and dividends paid totaled $520 million in the
same three-year period, which compares with $4.4 billion of net cash provided by
operating activities during the same period. This reflects the company's
philosophy of providing for its capital programs and dividends, along with debt
reduction, through internally generated funds. During the three-year period, the
company made three major acquisitions that further expanded its global presence
- - the 2001 acquisition of HS Resources for $955 million cash plus common stock
and assumed debt and the 2000 acquisitions of Repsol S.A.'s North Sea oil and
gas operations and the Kemira U.S. and Dutch pigment plants for a total of $975
million.
Kerr-McGee has budgeted approximately $1 billion for its capital program in
2003. Management anticipates that the 2003 capital program, dividends and debt
reduction can continue to be provided 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. Of the $860 million total
budget for 2003, $385 million is allocated to the Gulf of Mexico, $170 million
to the North Sea, $200 million to U.S. onshore and $105 million to other
international projects. Successful exploration and appraisal drilling in the
deepwater Gulf of Mexico has resulted in the development of two major projects
during the last two years - Nansen (50% working interest) and Boomvang (30%),
along with North Sea developments of Leadon (100%), Tullich (100%) and Maclure
(33%). The Gunnison (50%) and Red Hawk (50%) projects currently under
development are also in the deepwater Gulf of Mexico. Gunnison capitalizes on
the success of truss spar technology introduced at the Nansen and Boomvang
fields, while Red Hawk is being developed using innovative cell spar technology.
Gunnison is expected to reach initial production during the first quarter of
2004, with Red Hawk following in mid-2004. The company is also developing
discoveries in Bohai Bay, China, using a centrally located floating production,
storage and offloading facility. These projects plus additional development at
Nansen and Boomvang comprise 29% of the capital budget for 2003. The company
also expects to fund its share of drilling 30 to 45 exploratory wells in 2003.
Chemicals
Capital expenditures for chemical operations are budgeted at $130 million for
2003. These expenditures will be primarily for chloride oxidation process and
technology upgrades aimed at improving the capacity, efficiency and
cost-effectiveness of the company's pigment operations. The Hamilton,
Mississippi, plant capacity is expected to reach 225,000 tonnes by the end of
2003, up from approximately 200,000 tonnes at year-end 2002, and the Savannah,
Georgia, chloride plant is expected to reach annual capacity of 110,000 tonnes
by year-end 2003, up from 91,000 tonnes. Chemical has also budgeted $50 million
of additional investment in AVESTOR for 2003.
- --------------------------------------------------------------------------------
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) have been designated and have
qualified as cash flow hedges of the company's operating and capital expenditure
requirements. 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.
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 euros. These contracts have not been designated as
hedges even though they do protect the company from changes in foreign currency
rates. Certain pigment receivables have been sold in an asset securitization
program at their equivalent U.S. dollar value at the date the receivables were
sold. However, the company retains the risk of foreign currency rate changes
between the date of the sale and collection of the receivables.
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 2002 and 2001 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, 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
Open contracts at December 31, 2001 -
Maturing in 2002 -
British pound sterling 79 1.4159 80
Australian dollar 64 .5943 54
Euro (7) .8894 (7)
New Zealand dollar (1) .4073 (1)
Maturing in 2003 -
Australian dollar 44 .5702 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 2002. All borrowings are in
U.S. dollars.
There- Fair Value
(Millions of dollars) 2003 2004 2005 2006 2007 after Total 12/31/02
- --------------------- ---- ---- ---- ---- ---- ------ ----- ----------
Fixed-rate debt -
Principal amount $106 $471 $501 $325 $150 $2,083 $3,636 $4,075
Weighted-average
interest rate 8.09% 6.45% 6.21% 5.88% 6.63% 6.67% 6.55%
Variable-rate debt -
Principal amount - $268 - - - - $ 268 $ 268
Weighted-average
interest rate - 2.43% - - - - 2.43%
At December 31, 2001, long-term debt included fixed-rate debt of $3.300 billion
(fair value - $3.384 billion) with a weighted-average interest rate of 6.69% and
$1.266 billion of variable-rate debt, which approximated fair value, with a
weighted-average interest rate of 2.93%.
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 $21 million at December 31, 2002.
Commodity Price Risk
The company has periodically used derivative instruments to reduce the effect of
the price volatility of crude oil and natural gas. Effective August 1, 2001, the
company purchased 100% of the outstanding shares of common stock of HS
Resources. At the time of the purchase, HS Resources (now Kerr-McGee Rocky
Mountain Corp.) and its marketing subsidiary (now Kerr-McGee Energy Services
Corp.) had a number of derivative contracts for purchases and sales of gas,
basis differences and energy-related contracts. Prior to 2002, the company had
treated all of these derivatives as speculative and marked to market through
income each month the change in derivative fair values. In 2002, the company
designated the remaining portion of the HS Resources gas basis swaps that
settled in 2002 and all that settle in 2003 as hedges. Additionally, in March
2002, the company began hedging a portion of its 2002 oil and natural gas
production to increase the predictability of its cash flows and support
additional capital expenditures. The hedges were in the form of fixed-price
swaps and covered 30,000 barrels of U.S. oil production per day at an average
price of $24.09 per barrel, 60,000 barrels of North Sea oil production per day
at an average price of $23.17 per barrel and 250,000 MMBtu of U.S. natural gas
production per day at an average price of $3.10 per MMBtu. In October 2002, the
company expanded the hedging program to cover a portion of the estimated 2003
crude oil and natural gas production by adding fixed-price swaps, new basis
swaps and costless collars. 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 is recorded as a current asset and
$110 million is recorded as a current liability. The fair value of these
derivative instruments at December 31, 2002, was determined based on prices
actively quoted, generally NYMEX and Dated Brent prices. The company had
after-tax deferred losses of $50 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 2002, the
company realized a $28 million loss on domestic oil hedging, a $50 million loss
on North Sea oil hedging and a $2 million loss on domestic natural gas hedging.
The losses offset the 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 to Sales in the Consolidated Statement of Operations and totaled $2
million in 2002.
At December 31, 2002, the following commodity-related derivative contracts were
outstanding:
Daily Average
Contract Type (1) Period Volume Price
- ----------------- ------ ------ -------
Natural Gas MMBtu $/MMBtu
- ----------- ------ -------
Fixed-price swaps (NYMEX) 2003 310,000 $4.00
Costless collars (NYMEX) 2003 65,000 $3.50-$5.26
Basis swaps (CIG) Q1 - 2003 134,580 $0.53
Q2,3,4 - 2003 64,580 $0.36
Crude Oil Bbl $/Bbl
- --------- --- -----
Fixed-price swaps (WTI) Q1 - 2003 57,000 $27.40
Q2 - 2003 35,000 $26.02
Q3 - 2003 34,500 $25.99
Q4 - 2003 3,500 $26.03
Fixed-price swaps (Brent) Q1 - 2003 55,000 $25.71
Q2 - 2003 44,500 $25.01
Q3 - 2003 44,500 $24.99
Q4 - 2003 6,500 $25.04
(1) These contracts may be subject to margin calls above certain limits
established with individual counterparty institutions.
In January 2003, the following derivative contacts were added to the company's
2003 hedging program and, combined with the hedges outstanding at December 31,
2002, cover approximately 54% of the expected 2003 U.S. crude oil production,
65% of the North Sea crude oil production and 54% of the U.S. natural gas
production.
Daily Average
Contract Type (1) Period Volume Price
- ----------------- ------ ------ -----
Crude Oil Bbl $/Bbl
- --------- --- -----
Fixed-price swaps (WTI) Q4 - 2003 31,500 $26.01
Fixed-price swaps (Brent) Q4 - 2003 38,500 $25.04
(1) These contracts may be subject to margin calls above certain limits
established with individual counterparty institutions.
The HS Resources gas basis swaps that settle between 2004 and 2008 continue to
be treated by the company as speculative and are marked to market through
income. These derivatives are recorded at their fair value of $21 million in
Investments - Other assets. The net gain associated with these derivatives was
$8 million in 2002 and is included in Other Income in the Consolidated Statement
of Operations. In 2001, all of the HS Resources derivative contracts were
treated by the company as speculative and marked to market through income each
month. At December 31, 2001, the fair value of these contracts was $6 million.
The net gain associated with these derivatives was $27 million in 2001 and is
included in Other Income in the Consolidated Statement of Operations.
The marketing subsidiary, Kerr-McGee Energy Services (KMES) markets purchased
gas (primarily equity gas) in the Denver area. Existing contracts for the
physical delivery of gas at fixed or index-plus prices are marked to market in
accordance with FAS 133. KMES has entered into natural gas basis and price
derivative contracts 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 the physical and offsetting derivative contracts was $8 million at
year-end 2002. Of this amount, $31 million was recorded in current assets, $1
million in Investments - Other assets, $23 million in current liabilities and $1
million in deferred credits. The fair value of the outstanding derivative
instruments at December 31, 2002, was based on prices actively quoted, generally
NYMEX futures prices. During 2002, the net loss associated with these derivative
contracts was $20 million and is included in Sales in the Consolidated Statement
of Operations. At year-end 2001, the net asset fair value of the
commodity-related derivatives and physical contracts was $21 million. The 2001
net loss associated with these derivative contracts was $24 million and is
included in Sales in the Consolidated Statement of Operations. The losses on the
derivative contracts are generally offset by the 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
which 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 crude oil and natural gas reserve estimation, site dismantlement
and asset retirement obligations, impairment 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.
Oil and Gas Reserves
The estimates of oil and gas reserves 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 may
be necessary due to a number of factors, including reservoir performance, new
drilling, sales price and cost changes, technological advances, new geological
or geophysical data, or other economic factors. The company cannot predict the
amounts or timing of future reserve revisions.
Depreciation rates are calculated using both reserve quantity estimates and the
capitalized costs of producing properties. As the estimated reserves are
adjusted, the depreciation expense for a property will change, assuming no
change in production volumes or the costs capitalized. Estimated reserves may
also be 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. Such costs have historically been
accumulated over the estimated life of the facilities by use of the
unit-of-production method. Accordingly, the rate of accumulation of such costs
has been affected by changes in the underlying reserve estimates. In addition,
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."
FAS 143 requires asset retirement costs to be capitalized as part of the cost of
the related tangible long-lived asset and subsequently allocated to expense
using a systematic and rational method over the useful life of the asset. The
timing of implementation and the expected impact of this new standard are
discussed below in the New Accounting Standards section.
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.
Impairment of Assets
All long-lived assets are monitored for potential impairment when 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 inflation rates; future
sales prices for oil, gas or chemicals; future costs to produce these products;
estimates of future oil and gas reserves to be recovered 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 impairment when the company approves the plan to sell and
thereafter while the asset is held for sale. Estimates of anticipated sales
prices are highly judgmental and subject to material revision in future periods.
Because of the uncertainty inherent in these factors, the company cannot predict
when or if future impairment charges 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 are limited to creditworthy 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 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. In developing the
assumed long-term rate of return on plan assets for determining net periodic
pension cost, the company considers long-term historical returns (arithmetic
average) of the plan's investments, the asset allocation among types of
investments, estimated long-term returns by investment type from external
sources, and the current economic environment. Based on this information the
company selected 9% for 2002 and 8.5% for 2003 for U.S. pension plans. This
decrease in the company's expected long-term rate of return as of the beginning
of 2003 is expected to increase 2003 net periodic pension cost by $7 million but
not affect expected contributions to fund the 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 2001, the average Moody's Long-term AA
Corporate Bond Yield was 7.19%, and the company chose 7.25% as its discount rate
at the end of 2001. 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. This decrease in the discount rate effective December 31,
2002, is expected to increase 2003 net periodic pension cost by $3 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 5%
at December 31, 2001, and 4.5% at December 31, 2002, for U.S. pensions plans.
This decrease in assumed rate of compensation is expected to decrease 2003 net
periodic pension cost by $4 million but not affect expected contributions to
fund pension plans.
The net effect the U.S. pension plans had on results of operations for 2002 was
$41 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 2002 was $125 million, compared with an actual loss of $83 million. During
2002, the company's contributions to the retirement plans totaled $6 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, 2003, the amount of unrecognized losses on U.S. pension assets
was $317 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 $27 million in 2004 through 2008.
A 25 basis point increase/decrease in the company's expected long-term rate of
return assumption as of the beginning of 2003 would decrease/increase net
periodic pension cost for U.S. pension plans for 2003 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 trends 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.
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 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, 2002, 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
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, the Water
Pollution 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 announced in 2002 that its chemical affiliate would be exiting 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 will 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, 2002, are as follows:
(Millions of dollars) 2002 2001 2000 Total
- --------------------- ---- ---- ---- -----
Charges to environmental reserves $128 $142 $116 $386
Recurring expenses 37 57 23 117
Capital expenditures 22 21 28 71
---- ---- ---- ----
Total $187 $220 $167 $574
==== ==== ==== ====
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, the status of site
characterization, the stage of the remedial design, evaluation of existing
remediation technologies, 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, 2002, the company's financial reserves for all active and
inactive sites totaled $258 million. This includes $202 million added in 2002
for active and inactive sites. In the Consolidated Balance Sheet, $158 million
of the total reserve is classified as a deferred credit, and the remaining $100
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 2002. In the table, aggregated information is presented for certain
sites that are individually not significant or for which there is insufficient
information to estimate liability. 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
below.
Remaining
Reserve
Total Balance at
Expenditures December
Through 2002 31, 2002 Total
------------ ---------- -----
Location of Site Stage of Investigation/Remediation (Millions of dollars)
- ---------------- ---------------------------------- ---------------------------------------
EPA Superfund sites on National
Priority List (NPL)
West Chicago, Ill.
Kress Creek and Conceptual agreement for cleanup of thorium
Sewage Treatment Plant tailings at these two contiguous sites is being
reviewed by relevant agencies. Approval is
expected in 2003. $ 10 $87 $ 97
Residential areas and Thorium tailings remediation is substantially
Reed-Keppler Park complete at both sites. 100 - 100
Milwaukee, Wis. Completed soil cleanup at former wood-treatment
facility and began cleanup of offsite tributary
creek. Groundwater remediation is continuing. 29 13 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. 32 12 44
------ ---- ------
171 112 283
------ ---- ------
Sites under consent order, license or
agreement, not on EPA Superfund NPL
West Chicago, Ill.
Former manufacturing Decommissioning and cleanup of former thorium
facility mill is nearing completion under supervision of
State of Illinois. Groundwater monitoring
and/or remediation will continue. 402 16 418
Cushing, Okla. Soil remediation at site of former oil refinery
is continuing. Bulk of thorium and uranium
residuals was removed in 2002. 105 23 128
Henderson, Nev. Groundwater treatment to address perchlorate
contamination is being conducted under consent
decree with Nevada Department of Environmental
Protection. 80 17 97
Other sites Includes sites related to wood-treating,
chemical production, landfills, mining, oil and
gas production, and petroleum refining,
distribution and marketing. These sites are in
various stages of investigation/ remediation.
No individual site has a remaining reserve
balance exceeding $10 million. 265 90 355
------ ---- ------
852 146 998
------ ---- ------
Total $1,023 $258 $1,281
====== ==== ======
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. If recoveries from third
parties other than the U.S. government under Title X become probable, they will
be disclosed but will not generally be recognized until received.
Sites specifically identified in the table above are discussed below.
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 NPL.
Closed Facility - In 1994, Chemical, the City of West Chicago (the City) and the
State reached agreement on the initial phase of the decommissioning plan for the
closed West Chicago facility, and Chemical began shipping material from the site
to a licensed permanent disposal facility. In February 1997, Chemical executed
an agreement with the City covering the terms and conditions for completing the
final phase of decommissioning work. The agreement requires Chemical to excavate
contaminated soil and ship it to a licensed disposal facility, monitor and, if
necessary, remediate groundwater, and restore the property. The State indicated
approval of the agreement and issued license amendments authorizing the work.
Chemical expects most of the work to be completed by the end of 2003, leaving
principally surface restoration and groundwater monitoring and/or remediation
for subsequent years. Surface restoration is expected to be completed in 2004.
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 will be affected by the ongoing work.
Vicinity Areas - EPA has listed four areas in the vicinity of the closed West
Chicago facility on the NPL and has designated Chemical as a PRP in these four
areas. EPA issued unilateral administrative orders for two of the areas (known
as the Residential Areas and Reed-Keppler Park), which required Chemical to
conduct removal actions to excavate contaminated soil and ship the soil to a
licensed disposal facility. Chemical has substantially completed the work
required by the two orders.
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 conducted a thorough characterization of the two sites and has
reached conceptual agreement with local governmental authorities on a cleanup
plan, which is currently being reviewed by EPA. The cleanup plan will require
excavation of contaminated soils and stream sediments, shipment of excavated
materials to a licensed disposal facility, and restoration of affected areas.
The agreement is conditioned upon the resolution of certain matters, including
agreements regarding potential natural resource damages and government response
costs, and is expected to be incorporated in a consent decree that will address
the outstanding issues. The consent decree must be approved by EPA, the State,
local communities and Chemical and then entered by a federal court. It is
expected that the necessary parties will approve the terms of a consent decree
in 2003 and the work, once it begins, will take about four years to complete.
Financial Reserves - As of December 31, 2002, the company had remaining reserves
of $103 million for costs related to West Chicago. This includes $99 million
added to the reserves in 2002, of which $84 million reflects the estimated costs
to implement the conceptual agreement with respect to the Kress Creek and Sewage
Treatment Plant sites, and the remainder principally reflects changes in the
scope of excavation and construction and increased estimates of the volumes of
soil contamination at the other West Chicago sites. Although actual costs may
exceed current estimates, the amount of any increases cannot be reasonably
estimated at this time. The amount of the reserve has not been reduced by
reimbursements expected from the federal government under 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,
2002, Chemical had been reimbursed approximately $156 million under Title X.
Reimbursements under Title X are provided by congressional appropriations.
Historically, congressional appropriations have lagged Chemical's cleanup
expenditures. As of December 31, 2002, the government's share of costs incurred
by Chemical but not yet reimbursed by the DOE totaled approximately $113
million. The company believes receipt of this arrearage in due course following
additional congressional appropriations is probable and has reflected the
arrearage as a receivable in the financial statements. The company will
recognize recovery of the government's share of future remediation costs at 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
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.
Production expanded significantly in 1953 with completion of a plant for
manufacture of ammonium perchlorate. The U.S. Navy paid for construction of this
plant and took title to it in 1953. 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.
In 1998, Chemical decided to exit the business and began decommissioning the
facility and remediating associated perchlorate, including surface impoundments
and groundwater. In 1999 and 2001, Chemical entered into consent orders with the
Nevada Department 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.
Chemical subsequently developed and installed a long-term remediation system
based on new technology, but startup difficulties have prevented successful
commissioning of the long-term system. Chemical currently is evaluating possible
solutions to resolve the startup difficulties and is also evaluating an
alternative technology in the event the startup difficulties cannot be resolved.
The evaluation process should be completed in the first half of 2003. The
interim system has been enhanced pending the successful commissioning of a
long-term system. 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 - As of December 31, 2002, the company's remaining reserves
for Henderson totaled $17 million. This includes $22 million added in 2002
principally as a result of technological difficulties encountered with the
long-term remediation system and the resulting need to enhance and prolong the
interim treatment measures. The reserves do not include any cost that might be
incurred to install an alternate technology as possible solutions to address the
startup difficulties still are being evaluated, and evaluation of the alternate
technology is not complete. 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 additions cannot be
reasonably estimated at this time.
Government Litigation - In 2000, Chemical initiated litigation against the
United States seeking contribution for response costs. The government owned the
plant in the early years of its operation and was the largest consumer of
products produced at the plant. The litigation is in the early stages of
discovery. 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 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, 2002, Chemical incurred
expenditures of about $38 million that it believes can be applied to the
self-insured retention. Additionally, the company believes that the $17 million
reserve remaining at December 31, 2002, will be creditable against the
self-insured retention. The company has not recorded a receivable or otherwise
reflected in the financial statements any potential recovery from the insurance
policy since costs incurred to date and estimated costs for future work do not
exhaust the self-insured retention. The applicability of expenditures to the
self-insured retention is a matter currently under discussion with the insurance
carrier. Therefore, the amount of the remaining self-insured retention may be
greater than currently estimated.
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, using a pump and treat system, 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.
It is expected that the soil and sediment remediation will take about four more
years.
As of December 31, 2002, the company had remaining reserves of $13 million for
the costs of the remediation work described above. This includes $12 million
added to the reserve in 2002 to implement the remedy related to the tributary
creek. Although actual costs may exceed current estimates, the amount of any
increases cannot be reasonably estimated at this time.
Cushing, Oklahoma
In 1972, a company affiliate closed a petroleum refinery it had operated near
Cushing, Oklahoma. Prior to being closed, 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. When the refinery was closed in 1972, it
also was cleaned up to applicable standards.
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. Remediation of
hydrocarbon contamination is being performed under a plan approved by the
Oklahoma Department of Environmental Quality. Soil remediation to address
hydrocarbon contamination is expected to continue for about four more years. The
scope of any groundwater remediation that may be required is not known.
Additionally, in 1993, the affiliate received a decommissioning license from the
Nuclear Regulatory Commission (NRC), the successor to AEC's licensing authority,
to clean up certain uranium and thorium residuals. To avoid anticipated future
increases in disposal costs, much of the uranium and thorium residuals were
cleaned up and disposed of in 2002 after obtaining NRC approvals to conduct soil
removal without first completing the site characterization, work that is
necessary for identifying the scope of required cleanup activities. Because
excavation preceded characterization, contamination that had not been previously
identified was encountered and removed during the expedited excavation and
disposal work. Characterization and verification work is ongoing to confirm
whether the work undertaken in 2002 adequately addressed the contaminated areas.
Additional excavation may be required in the future depending on the results of
the characterization and verification work.
As of December 31, 2002, the company had remaining reserves of $23 million for
the costs of the ongoing remediation and decommissioning work described above.
This included $32 million added to the reserves in 2002 principally as a result
of costs incurred to perform the expedited uranium and thorium cleanup work and
costs for excavating and disposing of additional refinery-related wastes
identified in 2002. Although actual costs may exceed current estimates, the
amount of any increases cannot be reasonably estimated at this time.
- --------------------------------------------------------------------------------
New Accounting Standards
In June 2001, the FASB issued FAS 142, "Goodwill and Other Intangible Assets."
The company adopted the provisions of FAS 142 as of January 1, 2002, for all
goodwill and other intangible assets recognized in the company's Consolidated
Balance Sheet as of that date. Under FAS 142, goodwill and indefinite-lived
intangible assets are no longer amortized but are instead reviewed annually for
impairment, or more frequently if impairment indicators arise. The
nonamortization provisions of this standard were immediately applicable for any
goodwill acquired after June 30, 2001, which included goodwill associated with
the August 1, 2001, acquisition of HS Resources, Inc. Separately identifiable
intangible assets that have finite lives will continue to be amortized over
their useful lives. The company completed its required annual test for
impairment as of June 30, 2002, with no impairment loss being indicated.
In August 2001, the FASB issued FAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." FAS 144 supersedes FAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of,"
and the portion of Accounting Principles Board Opinion No. 30 that deals with
disposal of a business segment. The new standard resolves significant
implementation issues related to FAS 121 and establishes a single accounting
model for long-lived assets to be disposed of by sale. The company adopted FAS
144 as of January 1, 2002, and, in accordance with the standard, has classified
certain asset disposal groups whose operations and cash flows can be clearly
distinguished from the rest of the company as discontinued operations.
Prior-year amounts in the company's Consolidated Statement of Operations and
Consolidated Balance Sheet and related disclosures have been reclassified for
consistency with the current-year presentation. See Note 20 for further
discussion.
In June 2001, the FASB issued FAS 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 (as defined), with an offsetting
increase in the carrying amount of the associated asset. The cost of the
tangible asset, including the initially recognized ARO, is depreciated such that
the cost of the ARO is recognized 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 was required to adopt FAS 143 on January 1, 2003. As a result,
Kerr-McGee will accrue 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.
Additionally, the company will accrue an abandonment liability associated with
its plans to decommission the Mobile, Alabama, synthetic rutile plant. The
company recorded an after-tax charge to earnings of approximately $35 million on
January 1, 2003, to recognize the cumulative effect of retroactively applying
the new accounting principle. In addition, beginning in 2003, the company will
record accretion expense for its ARO liabilities and additional depreciation
expense on the associated assets. The new accounting principle is not expected
to have a significant effect on 2003 income from continuing operations.
In June 2002, the FASB issued FAS 146, "Accounting for Costs Associated with
Exit or Disposal Activities." FAS 146 nullifies Emerging Issues Task Force
(EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred
in a Restructuring)." The new standard requires that the liability for costs
associated with an exit or disposal activity be recognized when the liability is
incurred, in contrast to the previous guidance set forth in EITF Issue No. 94-3,
which required accrual of such costs at the date of an entity's commitment to an
exit plan. FAS 146 is effective for exit or disposal activities initiated after
December 31, 2002. Adoption of the new standard will impact the timing of
liability recognition but will not have a material effect on the company's
ultimate costs associated with future exit or disposal activities.
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 disclosure provisions of FIN 45 are effective for
guarantees outstanding as of December 31, 2002; however, the recognition
provisions are to be applied on a prospective basis to guarantees issued or
modified after December 31, 2002. The company does not expect the implementation
of this new standard to have a material impact on 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 requires
consolidation by the primary beneficiary in the interim period beginning after
June 15, 2003.
In accordance with the provisions of FIN 46, the company believes it is
reasonably likely that it will be required to consolidate the business trust
created to construct and finance the Gunnison production platform. The
construction is being financed via a 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 on the financing. If
required, consolidation of the financing trust will occur in the period
beginning July 1, 2003, and the trust is expected to remain subject to
consolidation through December 31, 2003. Completion of the Gunnison platform is
expected to occur in the first quarter of 2004, at which time the Gunnison
synthetic lease will be converted to an operating lease and a different trust
will become the lessor/owner of the platform and related equipment and will no
longer be subject to consolidation. The company continues to review the effects
of FIN 46 relative to the company's other variable interest entities, such as
the Nansen and Boomvang operating leases.
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 52
Report of Independent Auditors 53
Consolidated Statement of Operations for the years ended
December 31, 2002, 2001 and 2000 54
Consolidated Statement of Comprehensive Income
and Stockholders' Equity for the years ended
December 31, 2002, 2001 and 2000 55
Consolidated Balance Sheet at December 31, 2002 and 2001 56
Consolidated Statement of Cash Flows for the years ended
December 31, 2002, 2001 and 2000 57
Notes to Financial Statements 58
Index to Supplementary Data
- ---------------------------
Nine-year Financial Summary 109
Nine-year Operating Summary 110
Index to the Financial Statement Schedules
- ------------------------------------------
Schedule II - Valuation Accounts and Reserves 116
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. 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, 2002 and 2001, 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, 2002.
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, 2002 and 2001, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2002, 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 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
February 27, 2003
- --------------------------------------------------------------------------------
Consolidated Statement of Operations
- --------------------------------------------------------------------------------
(Millions of dollars,
except per-share amounts) 2002 2001 2000
- ------------------------- ------ ------ ------
Sales $3,700 $3,566 $4,063
------ ------ ------
Costs and Expenses
Costs and operating expenses 1,550 1,309 1,265
Selling, general and administrative expenses 313 228 197
Shipping and handling expenses 125 111 98
Depreciation and depletion 774 713 678
Asset impairment 828 76 -
Exploration, including dry holes and
amortization of undeveloped leases 273 210 169
Taxes, other than income taxes 104 114 122
Provision for environmental remediation and restoration,
net of reimbursements 80 82 90
Purchased in-process research and development - - 32
Interest and debt expense 275 195 208
------ ------ ------
Total Costs and Expenses 4,322 3,038 2,859
------ ------ ------
(622) 528 1,204
Other Income (Loss) (35) 224 50
------ ------ ------
Income (Loss) from Continuing Operations
before Income Taxes (657) 752 1,254
Taxes on Income 46 (276) (437)
------ ------ ------
Income (Loss) from Continuing Operations (611) 476 817
Discontinued Operations, including tax expense (benefit)
of $(22) in 2002, $22 in 2001 and $20 in 2000 126 30 25
Cumulative Effect of Change in Accounting
Principle, net of taxes of $11 - (20) -
------ ------ ------
Net Income (Loss) $ (485) $ 486 $ 842
====== ====== ======
Income (Loss) per Common Share
Basic -
Continuing operations $(6.09) $ 4.91 $ 8.75
Discontinued operations 1.25 .31 .26
Cumulative effect of accounting change - (.21) -
------ ------ ------
Net income (loss) $(4.84) $ 5.01 $ 9.01
====== ====== ======
Diluted -
Continuing operations $(6.09) $ 4.65 $ 8.13
Discontinued operations 1.25 .28 .24
Cumulative effect of accounting change - (.19) -
------ ------ ------
Net income (loss) $(4.84) $ 4.74 $ 8.37
====== ====== ======
The accompanying notes are an integral part of this statement.
Consolidated Statement of Comprehensive Income and Stockholders' Equity
- --------------------------------------------------------------------------------
Compre- Accumulated Total
hensive Capital in Other Deferred Stock-
Income Common Excess of Retained Comprehensive Treasury Compensation holders'
(Millions of dollars) (Loss) Stock Par Value Earnings Income (Loss) Stock and Other Equity
- ---------------------------------- ------- ------ ---------- -------- ------------- -------- ------------ --------
Balance December 31, 1999 $ 93 $1,284 $ 576 $ 45 $(388) $(118) $1,492
Net income $ 842 - - 842 - - - 842
Unrealized gains on securities,
net of $32 tax provision 60 - - - 60 - - 60
Foreign currency translation
adjustment 3 - - - 3 - - 3
Minimum pension liability adjust-
ment, net of $2 tax provision 5 - - - 5 - - 5
Shares issued - 8 375 - - - - 383
Dividends declared ($1.80 per share) - - - (170) - - - (170)
Other - - 1 (15) - 5 27 18
----- ---- ------ ------ ---- ----- ----- ------
Total $ 910
=====
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 adjust-
ment, 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 adjust-
ment, 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) $ - $ (75) $2,536
==== ====== ====== ==== ===== ===== ======
(1)
(1) The balance of the items in Accumulated Other Comprehensive Income (Loss)
at December 31, 2002, includes unrealized gains on securities of $6
million, fair value of cash flow hedges of $(57) million, foreign currency
translation adjustments of $6 million and minimum pension liability of
$(17) million.
The accompanying notes are an integral part of this statement.
Consolidated Balance Sheet
- --------------------------------------------------------------------------------
(Millions of dollars) 2002 2001
- --------------------- ------ -------
ASSETS
Current Assets
Cash $ 90 $ 91
Accounts receivable, net of allowance for doubtful
accounts of $10 in 2002 and $11 in 2001 608 421
Inventories 402 429
Deposits, prepaid expenses and other assets 133 351
Current assets associated with properties held for disposal 57 75
------ -------
Total Current Assets 1,290 1,367
Investments
Equity affiliates 123 101
Other assets 584 422
Property, Plant and Equipment - Net 7,036 7,378
Deferred Charges 328 261
Goodwill 356 356
Long-Term Assets Associated with Properties
Held for Disposal 192 1,191
------ -------
Total Assets $9,909 $11,076
====== =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 772 $ 620
Short-term borrowings - 8
Long-term debt due within one year 106 26
Taxes on income 170 86
Taxes, other than income taxes 40 31
Accrued liabilities 520 358
Current liabilities associated with properties held for disposal 2 45
------ -------
Total Current Liabilities 1,610 1,174
------ -------
Long-Term Debt 3,798 4,540
------ -------
Deferred Credits and Reserves
Income taxes 1,145 1,362
Other 804 646
------ -------
Total Deferred Credits and Reserves 1,949 2,008
------ -------
Long-Term Liabilities Associated with Properties
Held for Disposal 16 180
------ -------
Stockholders' Equity
Common stock, par value $1.00 - 300,000,000 shares
authorized, 100,391,054 shares issued in 2002
and 100,186,350 shares issued in 2001 100 100
Capital in excess of par value 1,687 1,676
Preferred stock purchase rights 1 1
Retained earnings 886 1,543
Accumulated other comprehensive loss (62) (64)
Common stock in treasury, at cost - 7,299 shares
in 2002 and 1,020 shares in 2001 - -
Deferred compensation (76) (82)
------ -------
Total Stockholders' Equity 2,536 3,174
------ -------
Total Liabilities and Stockholders' Equity $9,909 $11,076
====== =======
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) 2002 2001 2000
- --------------------- ------- ------- --------
Cash Flow from Operating Activities
Net income (loss) $ (485) $ 486 $ 842
Adjustments to reconcile to net cash
provided by operating activities -
Depreciation, depletion and amortization 844 779 732
Deferred income taxes (112) 205 18
Dry hole costs 113 72 54
Asset impairment 862 76 -
Provision for environmental remediation
and restoration, net of reimbursements 89 82 90
Gains on asset retirements and sales (110) (12) (6)
Purchased in-process research
and development - - 32
Noncash items affecting net income 126 (147) 45
Changes in current assets and liabilities
and other, net of effects of operations acquired-
(Increase) decrease in accounts receivable (104) 278 (55)
(Increase) decrease in inventories 37 (51) (46)
(Increase) decrease in deposits,
prepaids and other assets 185 (201) 3
Increase (decrease) in accounts
payable and accrued liabilities 137 (131) 129
Increase (decrease) in taxes payable 63 (120) 137
Other (197) (173) (135)
------- ------- --------
Net cash provided by operating activities 1,448 1,143 1,840
------- ------- --------
Cash Flow from Investing Activities
Capital expenditures (1,159) (1,792) (842)
Dry hole costs (113) (72) (54)
Acquisitions (24) (978) (1,018)
Purchase of long-term investments (65) (92) (56)
Proceeds from sale of long-term investments 12 18 35
Proceeds from sale of assets 756 19 42
------- ------- --------
Net cash used in investing activities (593) (2,897) (1,893)
------- ------- --------
Cash Flow from Financing Activities
Issuance of long-term debt 418 2,513 677
Issuance of common stock 5 32 383
Decrease in short-term borrowings (8) (9) (3)
Repayment of long-term debt (1,093) (661) (966)
Dividends paid (181) (173) (166)
------- ------- --------
Net cash provided by (used in) financing activities (859) 1,702 (75)
------- ------- --------
Effects of Exchange Rate Changes on Cash and Cash Equivalents 3 (1) 5
------- ------- --------
Net Decrease in Cash and Cash Equivalents (1) (53) (123)
Cash and Cash Equivalents at Beginning of Year 91 144 267
------- ------- --------
Cash and Cash Equivalents at End of Year $ 90 $ 91 $ 144
======= ======= ========
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, Brazil, Gabon, Morocco, Canada, Yemen
and the Danish sector 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 and the proportionate share of joint
ventures in which the company has an undivided interest. 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.
Certain prior-year amounts in the consolidated financial statements have been
reclassified to present the oil and gas operations in Kazakhstan, Indonesia and
Australia as discontinued (see Note 20) and to conform with the current-year
presentation.
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 in the Consolidated Statement of Operations. The
company recorded net foreign currency transaction gains (losses) of ($38)
million, $3 million and $30 million in 2002, 2001 and 2000, 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 $23 million in 2002 and $26
million in 2001 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 a credit-insurance-backed asset securitization program, Kerr-McGee sells
selected pigment customers' accounts receivable to a special-purpose entity
(SPE). The company does not own any of the common stock of the SPE. When the
receivables are sold, Kerr-McGee retains interests in the securitized
receivables for servicing and in preference stock of the SPE. The interest in
the preference stock is essentially a deposit to provide further credit
enhancement to the securitization program, if needed, but is otherwise
recoverable by the company at the end of the program. The recorded value of the
preference stock is adjusted with each sale to maintain its fair value. 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 the
associated indirect manufacturing expenses. Costs for materials and supplies are
determined by average cost to acquire.
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 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 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 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
2002, 2001 and 2000 was $8 million, $31 million and $5 million, respectively.
Impairment of Long-Lived Assets
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 estimated future oil and gas prices to estimated future production,
less estimated future expenditures 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 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.
Assets classified as held for sale are reviewed for impairment at the time the
assets are reclassified from the held-for-use category, which occurs upon
managements' approval of a plan of sale that is expected to be completed within
one year. Impairment losses are measured as the difference between fair value
less costs to sell, and the assets' carrying value. Upon transfer to the
held-for-sale category, long-lived assets are no longer depreciated.
Revenue Recognition
Revenue is recognized when title passes to the customer. Natural gas revenues
involving gas-balancing arrangements with partners in natural gas wells 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, 2002 and 2001,
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.
Site Dismantlement, Remediation and Restoration Costs
The company provides for the estimated costs at current prices of the
dismantlement and removal of oil and gas production and related facilities. Such
costs are accumulated over the estimated lives of the facilities by the use of
the unit-of-production method. 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 Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (FAS) 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 (as defined), with an offsetting
increase in the carrying amount of the associated asset. The cost of the
tangible asset, including the initially recognized ARO, is depreciated on a
unit-of-production basis, such that the cost of the ARO is recognized 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 was required to adopt FAS 143 on January 1, 2003. As a result, the
company will accrue 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.
Additionally, the company will accrue an abandonment liability associated with
its plans to decommission the Mobile, Alabama, synthetic rutile plant. The
company recorded an after-tax charge to earnings of approximately $35 million on
January 1, 2003, to recognize the cumulative effect of retroactively applying
the new accounting principle. In addition, beginning in 2003, the company will
record accretion expense for its ARO liabilities and additional depreciation
expense on the associated assets. The new accounting principle is not expected
to have a significant effect on 2003 income from continuing operations.
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. Compensation cost for stock
appreciation rights, which is recognized under both accounting methods, was
immaterial for 2002, 2001 and 2000.
Had compensation expense for stock option grants been determined in accordance
with FAS 123, the resulting compensation 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) 2002 2001 2000
- ------------------------- ------ ----- -----
Net income (loss) as reported $ (485) $ 486 $ 842
Less stock-based compensation expense
determined using a fair-value method
for all awards, net of taxes (15) (8) (7)
------ ----- -----
Pro forma net income (loss) $ (500) $ 478 $ 835
====== ===== =====
Net income (loss) per share -
Basic -
As reported $(4.84) $5.01 $9.01
Pro forma (4.99) 4.92 8.94
Diluted -
As reported (4.84) 4.74 8.37
Pro forma (4.99) 4.66 8.30
The fair value of each option granted in 2002, 2001 and 2000 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
------------- -------------- ------------ ---------- ---------------
2002 4.8% 3.4% 5.8 36.0% $16.97
2001 5.0 3.3 5.8 42.9 22.54
2000 6.6 3.1 5.8 31.3 19.15
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. 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 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.
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, and the costs
incurred by the company for shipping and handling 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 2002, with no impairment indicated for the
$356 million of goodwill and $53 million of indefinite lived intangible assets.
The company's net income for 2001 and 2000 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 ($14 million and $15 million at December
31, 2002 and 2001, respectively).
2. Cash Flow Information
Net cash provided by operating activities reflects cash payments for income
taxes and interest as follows:
(Millions of dollars) 2002 2001 2000
- --------------------- ---- ---- ----
Income tax payments $ 89 $434 $338
Less refunds received (268) (19) (34)
----- ---- ----
Net income tax payments (refunds) $(179) $415 $304
===== ==== ====
Interest payments $ 258 $189 $193
===== ==== ====
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) 2002 2001 2000
- --------------------- ---- ----- ----
Litigation reserve provisions $ 72 $ - $ 7
Net periodic pension credit for qualified plan (48) (53) (43)
Abandonment provisions - exploration and production 38 34 37
Increase (decrease) in fair value of embedded options
in the DECS (1) 34 (205) -
Increase (decrease) in fair value of trading
securities (1) (61) 7 -
All other (2) 91 70 44
---- ----- ----
Total $126 $(147) $ 45
==== ===== ====
Details of other changes in current assets and liabilities and other within the
operating section of the Consolidated Statement of Cash Flows consist of the
following:
(Millions of dollars) 2002 2001 2000
- --------------------- ---- ---- ----
Environmental expenditures $(107) $ (94) $(117)
Cash abandonment expenditures -
exploration and production (48) (29) (9)
All other (2) (42) (50) (9)
----- ----- ----
Total $(197) $(173) $(135)
===== ===== =====
Information about noncash investing and financing activities not reflected in
the Consolidated Statement of Cash Flows follows:
(Millions of dollars) 2002 2001 2000
- --------------------- ---- ---- ----
Noncash investing activities
Increase (decrease) in fair value of securities available for sale (1) $11 $ (34) $280
Increase (decrease) in fair value of trading securities (1) 61 (188) -
Investment in equity affiliate 2 - -
Noncash financing activities
Common stock issued in HS Resources acquisition - 355 -
Debt assumed in HS Resources acquisition - 506 -
Increase in the valuation of the DECS (1) 8 8 187
Increase (decrease) in fair value of embedded options in
the DECS (1) 34 (205) -
Dividends declared but not paid - 3 4
(1) See Notes 1 and 18 for discussion of FAS 133 adoption.
(2) No other individual item is material to total cash flows from operations.
3. Inventories
Major categories of inventories at year-end 2002 and 2001 are:
(Millions of dollars) 2002 2001
- --------------------- ---- ----
Chemicals and other products $306 $338
Materials and supplies 89 88
Crude oil and natural gas liquids 7 3
---- ----
Total $402 $429
==== ====
4. Investments - Other Assets
Investments in other assets consist of the following at December 31, 2002 and
2001:
(Millions of dollars) 2002 2001
- --------------------- ---- ----
Devon Energy Corporation common stock (1) $457 $385
Long-term receivables, net of allowance for
doubtful notes of $9 in both 2002 and 2001 94 12
Derivatives (fixed-priced and basis swap
commodity contracts)(1) 22 16
U.S. government obligations 2 2
Other 9 7
---- ----
Total $584 $422
==== ====
(1) See Note 18.
5. Property, Plant and Equipment
Property, plant and equipment and related reserves at December 31, 2002 and
2001, are as follows:
Reserves for
Depreciation and
Gross Property Depletion Net Property
------------------- ------------------ -----------------
(Millions of dollars) 2002 2001 2002 2001 2002 2001
- --------------------- ------- ------- ------ ------ ------ ------
Exploration and production $11,585 $11,392 $5,632 $5,080 $5,953 $6,312
Chemicals 1,963 1,860 965 857 998 1,003
Other 176 151 91 88 85 63
------- ------- ------ ------ ------ ------
Total $13,724 $13,403 $6,688 $6,025 $7,036 $7,378
======= ======= ====== ====== ====== ======
6. Deferred Charges
Deferred charges are as follows at year-end 2002 and 2001:
(Millions of dollars) 2002 2001
- --------------------- ---- ----
Pension plan prepayments $240 $188
Nonqualified benefit plans deposits 35 26
Unamortized debt issue costs 27 34
Amounts pending recovery from third parties 13 10
Other 13 3
---- ----
Total $328 $261
==== ====
7. 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. The company
retained servicing responsibilities and subordinated interests 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 $1 million
in both 2002 and 2001, and were insignificant in 2000. No recourse obligations
were recorded since the company has very limited obligations for any recourse
actions on the sold receivables. The collection of the receivables is insured,
and only receivables that qualify for credit insurance can be sold. A portion of
the insurance is reinsured by the company's captive insurance company; however,
the company believes that the risk of insurance loss is very low since its
bad-debt experience has historically been insignificant. The company also
received preference stock in the special-purpose entity equal to 3.5% of the
receivables sold. This preference stock is essentially a retained deposit to
provide further credit enhancements, if needed.
During 2002, 2001 and 2000, the company sold $609 million, $597 million and $160
million, respectively, of its pigment receivables, resulting in pretax losses of
$5 million, $8 million and $3 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 2002 and 2001, the outstanding balance on receivables sold totaled $111
million and $96 million, respectively. There were no delinquencies as of
year-end 2002.
8. Accrued Liabilities
Accrued liabilities at year-end 2002 and 2001 are as follows:
(Millions of dollars) 2002 2001
- --------------------- ---- ----
Interest payable $105 $100
Employee-related costs and benefits 103 102
Derivatives 135 32
Current environmental reserves 100 68
Litigation reserves 43 21
Royalties payable 13 2
Drilling and operating costs 6 4
Acquisition and merger reserves - 9
Other 15 20
---- ----
Total $520 $358
==== ====
9. 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.
During 1999, the company recorded an accrual of $163 million for items
associated with the Oryx merger. Included in this charge were transaction costs,
severance and other employee-related costs, contract termination costs, lease
cancellations, write-off of redundant systems and equipment, and other
merger-related costs. Of this total accrual, zero and $1 million remained in the
reserve at the end of 2002 and 2001, respectively.
The accruals, payments and reserve balances for 2002 and 2001 are as follows:
(Millions of dollars) 2002 2001
- --------------------- ---- ----
Beginning balance $ 9 $ 10
Accruals 3 42
Payments (12) (43)
---- ----
Ending balance $ - $ 9
==== ====
10. Restructuring Provisions and Exit Activities
During 2002, the company provided $17 million for costs associated with exiting
its forest products business, which is part of the chemical - other operating
unit. Included in the 2002 provision were $16 million for dismantlement and
closure costs, and $1 million for severance costs. These costs are reflected in
Costs and operating expenses in the Consolidated Statement of Operations. Of the
total provision, $16 million remained in the accrual as of year-end 2002.
The Indianapolis, Indiana, plant was identified for closure in 2001.
Dismantlement of the facility began in 2002 and is expected to be completed in
2003. The company will also close four of its five remaining forest
products-treating plants. The disposition of the fifth plant, a leased facility
located in The Dalles, Oregon, is the subject of ongoing discussions. The
company's options at the site include continuation of operations for the term of
the lease, which runs through November 30, 2004, or sale. Commercial operations
will continue at the company's four owned plants until all current contracts are
fulfilled. The company expects to close the Columbus, Mississippi; Madison,
Illinois; Springfield, Missouri; and Texarkana, Texas, plants by year-end 2003.
In connection with the plant closures, 252 employees will be terminated, of
which 25 were terminated as of year-end 2002.
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, $9 million and $21 million remained in the
restructuring accrual at the end of 2002 and 2001, respectively. As a result of
this plant closure, 121 employees will ultimately be terminated, of which 118
were terminated as of December 31, 2002. The remainder will be terminated when
dismantlement of the plant is completed, which is expected to occur in 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, $2 million and $7 million remained in the
restructuring accrual at the end of 2002 and 2001, 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 2002 and 2001 are
included in the table below.
2002 2001
------------------------------------ ------------------------------------------------
Dismantlement Dismantlement
and and
(Millions of dollars) Total Severance Closure Total Severance Closure Other
- --------------------- ----- --------- ------- ----- --------- ------- -----
Beginning balance $ 28 $ 12 $ 16 $ - $ - $ - $ -
Provisions 17 1 16 44 14 23 7
Payments (1) (20) (10) (10) (16) (2) (7) (7)
Adjustments (2) 2 1 1 - - - -
---- ---- ---- ---- --- --- ---
Ending balance $ 27 $ 4 $ 23 $ 28 $12 $16 $ -
==== ==== ==== ==== === === ===
(1) Includes amounts in total provision that were charged directly to expense.
(2) Foreign-currency translation adjustments related to Antwerp, Belgium,
accrual.
Following are the revenues and pretax income included in the Consolidated
Statement of Operations for operations subject to exit plans. Since each of
these operations represents a small portion of a business segment or legal
entity, the pretax income amounts may not include all indirect costs that might
otherwise have been incurred by an unrelated operation. The restructuring
provisions and any related impairment losses (see Note 20) are included in the
pretax income from continuing operations for 2002 and 2001.
(Millions of dollars) 2002 2001 2000
- --------------------- ---- ---- ----
Sales -
Chemicals - pigment $ 11 $ 37 $ 52
Chemicals - other 132 114 134
---- ---- ----
Total $143 $151 $186
==== ==== ====
Pretax income (loss) -
Chemicals - pigment $ 2 $(53) $ -
Chemicals - other (8) (30) 9
---- ---- ----
Total $ (6) $(83) $ 9
==== ==== ====
11. Debt
Lines of Credit and Short-Term Borrowings
At year-end 2002, the company had available unused bank lines of credit and
revolving credit facilities of $1.499 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 2002, 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.
The company had no short-term borrowings at year-end 2002. Short-term borrowings
at year-end 2001 consisted of a note payable totaling $8 million (4.42% average
interest rate). The note was denominated in euros and represented approximately
9 million euros.
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 2002 and 2001, debt
totaling $68 million and $1.066 billion, respectively, was classified as
long-term consistent with this policy.
Long-term debt consisted of the following at year-end 2002 and 2001:
(Millions of dollars) 2002 2001
- --------------------- ------ ------
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 $90 in 2002
and $94 in 2001 (14.25% effective rate) 160 156
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) 325 325
6-7/8% Notes due September 15, 2011,
net of unamortized debt discount of $1
in both 2002 and 2001 (6.90% effective rate) 674 674
7-7/8% Notes due September 15, 2031,
net of unamortized debt discount of $2
in both 2002 and 2001 (7.91% effective rate) 498 498
5-1/2% Exchangeable Notes (DECS) due August 2, 2004,
net of unamortized debt discount of $12 in 2002
and $20 in 2001 (5.60% effective rate) (See Note 18) 318 310
6.625% Notes due October 15, 2007 150 150
8.375% Notes due July 15, 2004 150 150
8.125% Notes due October 15, 2005 150 150
8% Notes due October 15, 2003 100 100
5.375% Notes due April 15, 2005 350 -
Variable interest rate revolving credit agreements with banks - 254
Floating rate notes due June 28, 2004 (2.54% average
interest rate at December 31, 2002) 200 200
Medium-Term Notes (9.29% average effective
interest rate at December 31, 2001) - 13
Commercial paper (3.01% average effective
interest rate at December 31, 2001) - 732
Euro Commercial paper (2.10% average effective
interest rate at December 31, 2002) 68 80
Guaranteed Debt of Employee Stock Ownership Plan 9.61%
Notes due in installments through January 2, 2005 11 21
Other - 3
------ ------
3,904 4,566
Long-term debt due within one year (106) (26)
------ ------
Total $3,798 $4,540
====== ======
Maturities of long-term debt due after December 31, 2002, are $106 million in
2003; $739 million in 2004, of which $318 million may be a noncash settlement of
the DECS and $68 million is borrowings that the company expects to be able to
maintain as long-term, see above; $501 million in 2005; $325 million in 2006;
$150 million in 2007; and $2.083 billion thereafter.
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 agreement. At
December 31, 2002, the company was in compliance with its debt covenants.
12. Income Taxes
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 composed of the following:
(Millions of dollars) 2002 2001 2000
- --------------------- ----- ---- ------
United States $(116) $524 $ 562
International (541) 228 692
----- ---- ------
Total $(657) $752 $1,254
===== ==== ======
On July 24, 2002, the United Kingdom government made certain changes to its
existing tax laws. Under one of these changes, companies will pay a
supplementary corporate tax charge of 10% on profits from their U.K. oil and gas
production. This is in addition to the existing 30% corporate tax on these
profits. The U.K. government has also accelerated tax depreciation for capital
investments in U.K. upstream activities. The deferred income tax liability was
adjusted to reflect this revised rate, causing a net increase in the 2002
international deferred provision for income taxes of $132 million. Finally, the
U.K. government announced on November 27, 2002, that royalty will be abolished
on North Sea production effective January 1, 2003.
For the year 2002, the effective income tax rates in Canada and the Netherlands
decreased to 35% and 34.5%, respectively, from 37% and 35%, respectively. The
effect on the international deferred provision for income taxes was less than $1
million.
The effective income tax rate in Canada decreased to 37% from 38% for the year
2001. The deferred income tax liability balance was adjusted to reflect this
revised rate, causing a decrease in the 2001 international deferred provision
for income taxes of $1 million.
The income tax rate in Australia decreased to 30% from 34% for the year 2001,
and decreased to 34% from 36% for the year 2000. Effective January 1, 2001, the
German corporate income tax rate decreased to 25% from 30%. The deferred income
tax asset and liability balances were adjusted to reflect these revised rates,
causing a net increase in the 2000 international deferred provision for income
taxes of $2 million.
The Internal Revenue Service has examined the Kerr-McGee Corporation and
subsidiaries' Federal income tax returns for all years through 1996, and the
years have been closed through 1994. 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 become payable with respect to open tax
years.
The 2002, 2001 and 2000 income tax provisions (benefits) from continuing
operations are summarized below:
(Millions of dollars) 2002 2001 2000
- --------------------- ---- ---- ----
U.S. Federal -
Current $ 12 $(70) $101
Deferred (104) 219 82
----- ---- ----
(92) 149 183
----- ---- ----
International -
Current 36 130 286
Deferred 10 (8) (34)
----- ---- ----
46 122 252
----- ---- ----
State - 5 2
----- ---- ----
Total $ (46) $276 $437
===== ==== ====
At December 31, 2002, the company had foreign operating loss carryforwards
totaling $305 million. Of this amount, $8 million expires in 2003, $11 million
in 2004, $13 million in 2006, $2 million in 2007 and $271 million has no
expiration date. Realization of these operating loss carryforwards depends on
generating sufficient taxable income in future periods.
Net deferred tax liabilities at December 31, 2002 and 2001, are composed of the
following:
(Millions of dollars) 2002 2001
- --------------------- ------ ------
Net deferred tax liabilities -
Accelerated depreciation $1,088 $1,281
Exploration and development 192 160
Undistributed earnings of foreign subsidiaries 28 28
Postretirement benefits (89) (89)
Dismantlement, remediation, restoration and other reserves (34) (58)
U.S. and foreign operating loss carryforward (92) (46)
AMT credit carryforward (47) (18)
Other 99 104
------ ------
Total $1,145 $1,362
====== ======
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.
2002 2001 2000
---- ---- ----
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) .1
Taxation of foreign operations 12.1 1.7 .5
Refunds of prior years' income taxes - - (.8)
Federal income tax credits (1.8) - -
Other - net (2.2) .1 -
---- ---- ----
Total (7.0)% 36.7% 34.8%
==== ==== ====
13. Taxes, Other than Income Taxes
Taxes, other than income taxes, as shown in the Consolidated Statement of
Operations for the years ended December 31, 2002, 2001 and 2000, are comprised
of the following:
(Millions of dollars) 2002 2001 2000
- --------------------- ---- ---- ----
Production/severance $ 58 $ 67 $ 85
Payroll 21 27 21
Property 20 15 13
Other 5 5 3
---- ---- ----
Total $104 $114 $122
==== ==== ====
14. Deferred Credits and Reserves - Other
Other deferred credits and reserves consist of the following at year-end 2002
and 2001:
(Millions of dollars) 2002 2001
- --------------------- ---- ----
Reserves for site dismantlement, remediation
and restoration $387 $300
Postretirement benefit obligations 210 205
Pension plan liabilities 54 23
Derivatives (1) 67 42
Litigation reserves 30 25
Ad valorem taxes 21 27
Other 35 24
---- ----
Total $804 $646
==== ====
(1) Options associated with exchangeable debt, forward foreign currency
contracts and commodity derivative contracts (see Note 18).
The company provided for environmental remediation and restoration, net of
authorized reimbursements, during each of the years 2002, 2001 and 2000, as
follows:
(Millions of dollars) 2002 2001 2000
- --------------------- ---- ---- ----
Provision, net of authorized reimbursements $ 80 $90 $112
Reimbursements received 9 11 66
Authorized reimbursements accrued 113 - -
The reimbursements, which pertain to the former facility in West Chicago,
Illinois, are authorized pursuant to Title X of the Energy Policy Act of 1992
(see Note 16).
15. Other Income (Loss)
Other income (loss) was as follows during each of the years in the three-year
period ended December 31, 2002:
(Millions of dollars) 2002 2001 2000
- --------------------- ---- ---- ----
Derivatives and Devon stock revaluation (1) $ 35 $225 $ -
Interest income 5 10 21
Income (loss) from unconsolidated affiliates (25) (5) 23
Gain (loss) on foreign currency exchange (38) 3 30
Gain (loss) on sale of assets (3) 4 6
Plant closing/product line discontinuation - - (21)
Other (9) (13) (9)
---- ---- ----
Total $(35) $224 $ 50
==== ==== ====
(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 Priority List
(NPL).
Closed Facility - In 1994, Chemical, the City of West Chicago (the City) and the
State reached agreement on the initial phase of the decommissioning plan for the
closed West Chicago facility, and Chemical began shipping material from the site
to a licensed permanent disposal facility. In February 1997, Chemical executed
an agreement with the City covering the terms and conditions for completing the
final phase of decommissioning work. The agreement requires Chemical to excavate
contaminated soil and ship it to a licensed disposal facility, monitor and, if
necessary, remediate groundwater and restore the property. The State indicated
approval of the agreement and issued license amendments authorizing the work.
Chemical expects most of the work to be completed by the end of 2003, leaving
principally surface restoration and groundwater monitoring and/or remediation
for subsequent years. Surface restoration is expected to be completed in 2004.
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 will be affected by the ongoing 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. The EPA issued unilateral administrative orders for two of the areas
(known as the Residential Areas and Reed-Keppler Park), which required Chemical
to conduct removal actions to excavate contaminated soil and ship the soil to a
licensed disposal facility. Chemical has substantially completed the work
required by the two orders.
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 conducted a thorough characterization of the two sites and has
reached conceptual agreement with local governmental authorities on a cleanup
plan, which is currently being reviewed by EPA. The cleanup plan will require
excavation of contaminated soils and stream sediments, shipment of excavated
materials to a licensed disposal facility and restoration of affected areas. The
agreement is conditioned upon the resolution of certain matters, including
agreements regarding potential natural resource damages and government response
costs, and is expected to be incorporated in a consent decree that will address
the outstanding issues. The consent decree must be approved by EPA, the State,
local communities and Chemical and then entered by a federal court. It is
expected that the necessary parties will approve the terms of a consent decree
in 2003 and the work, once commenced, will take about four years to complete.
Financial Reserves - As of December 31, 2002, the company had remaining reserves
of $103 million for costs related to West Chicago. This includes $99 million
added to the reserves in 2002, of which $84 million reflects the estimated costs
to implement the conceptual agreement with respect to the Kress Creek and Sewage
Treatment Plant sites, and the remainder principally reflects changes in the
scope of excavation and construction and increased estimates of the volumes of
soil contamination at the other West Chicago sites. 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,
2002, Chemical had been reimbursed approximately $156 million under Title X.
Reimbursements under Title X are provided by congressional appropriations.
Historically, congressional appropriations have lagged Chemical's cleanup
expenditures. As of December 31, 2002, the government's share of costs incurred
by Chemical but not yet reimbursed by the DOE totaled approximately $113
million. The company believes receipt of this arrearage in due course following
additional congressional appropriations is probable and has reflected the
arrearage as a receivable in the financial statements. The company will
recognize recovery of the government's share of future remediation costs for the
West Chicago sites as 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.
Production expanded significantly in 1953 with completion of a plant for
manufacture of ammonium perchlorate. The U.S. Navy paid for construction of this
plant and took title to it in 1953. 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 decided to exit the business in 1998 and began decommissioning the
facility and remediating associated perchlorate contamination, including surface
impoundments and groundwater. In 1999 and 2001, Chemical entered into consent
orders with the Nevada Department 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.
Chemical subsequently developed and installed a long-term remediation system
based on new technology, but startup difficulties have prevented successful
commissioning of the long-term system. Chemical currently is evaluating possible
solutions to resolve the startup difficulties and is also evaluating an
alternative technology in the event the startup difficulties cannot be resolved.
The evaluation process should be completed in the first half of 2003. The
interim system has been enhanced pending the successful commissioning of a
long-term system. 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 - As of December 31, 2002, the company's remaining reserves
for Henderson totaled $17 million. This includes $22 million added in 2002,
principally as a result of technological difficulties encountered with the
long-term remediation system and the resulting need to enhance and prolong the
interim treatment measures. The reserves do not include any cost that might be
incurred to install an alternate technology as possible solutions to address the
startup difficulties still are being evaluated, and evaluation of the alternate
technology is not complete. 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 additions 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, Kerr-McGee
Chemical LLC v. United States of America, is pending in U.S. District Court for
the District of Columbia. The government owned the plant in the early years of
its operation and was the largest consumer of products produced at the plant.
The litigation is in the early stages of discovery. 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 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, 2002, Chemical has incurred
expenditures of about $38 million that it believes can be applied to the
self-insured retention. Additionally, the company believes that the $17 million
reserve remaining at December 31, 2002, will be creditable against the
self-insured retention. The company has not recorded a receivable or otherwise
reflected in the financial statements any potential recovery from the insurance
policy since costs incurred to date and estimated costs for future work do not
exhaust the self-insured retention. The applicability of expenditures to the
self-insured retention is a matter currently under discussion with the insurance
carrier. Therefore, the amount of the remaining self-insured retention may be
greater than currently estimated.
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 the Comprehensive
Environmental Response, Compensation, and Liability Act of 1980 (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, using a pump-and-treat system, 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.
It is expected that the soil and sediment remediation will take about four more
years.
As of December 31, 2002, the company had remaining reserves of $13 million for
the costs of the remediation work described above. This includes $12 million
added to the reserve in 2002 to implement the remedy related to the tributary
creek. 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. Remediation of
hydrocarbon contamination is being performed under a plan approved by the
Oklahoma Department of Environmental Quality. Soil remediation to address
hydrocarbon contamination is expected to continue for about four more years. The
scope of any groundwater remediation that may be required is not known.
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. To avoid
anticipated future increases in disposal costs, much of the uranium and thorium
residuals were cleaned up and disposed in 2002 after obtaining NRC approvals to
conduct soil removal without first completing the site characterization, work
that is necessary for identifying the scope of required cleanup activities.
Because excavation preceded characterization, contamination that had not been
previously identified was encountered and removed during the expedited
excavation and disposal work. Characterization and verification work is ongoing
to confirm whether the work undertaken in 2002 adequately addressed the
contaminated areas. Additional excavation may be required in the future,
depending on the results of the characterization and verification work.
As of December 31, 2002, the company had remaining reserves of $23 million for
the costs of the ongoing remediation and decommissioning work described above.
This included $32 million added to the reserves in 2002, principally as a result
of costs incurred to perform the expedited uranium and thorium cleanup work and
costs for excavating and disposing of additional refinery-related wastes
identified in 2002. 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
Primary Lawsuits - 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. The lawsuits seek 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. Some of the lawsuits are
filed on behalf of specifically named individual plaintiffs, while others
purport to be filed on behalf of classes of allegedly similarly situated
plaintiffs.
Seven of the 22 cases were filed in Mississippi and relate to Chemical's
Columbus, Mississippi, wood-treatment plant. Two of the Mississippi cases are
pending in the U.S. District Court for the Northern District: Andrews v.
Kerr-McGee (filed September 8, 1999) and Bachelder v. Kerr-McGee (filed March 7,
2001). Three of the Mississippi cases are pending in the Circuit Court of
Lowndes County: Spirit of Prayer v. Kerr-McGee (filed March 16, 2000), Burgin v.
Kerr-McGee (filed March 6, 2001) and Maranatha Faith Center v. Kerr-McGee (filed
February 18, 2000). Two of the Mississippi cases are pending in Circuit Court of
Hinds County: Jamison v. Kerr-McGee (filed February 18, 2000) and Cockrell v.
Kerr-McGee (filed March 6, 2001).
Seven of the 22 cases were filed in Louisiana and relate to a former
wood-treatment plant that was located in Bossier City, Louisiana. One of the
Louisiana cases is pending in the U.S. District Court for the Western District:
Shirlean Taylor, et al. v. Kerr-McGee (filed June 15, 2000). Five of the
Louisiana cases are pending in the U.S. District Court for the Western District,
subject to remand to 26th District Court of Bossier Parish, and all were filed
on October 25, 2001: Brenda Sue Adams, et al. v. Kerr-McGee; J.C. Adams, et al.
v. Kerr-McGee; Linda Paul Anderson, et al. v. Kerr-McGee; Shirley Marie Austin,
et al. v. Kerr-McGee; and Ronald Donald Bailey, et al. v. Kerr-McGee. One of the
Louisiana cases is pending in the 26th District Court of Bossier Parish: T. J.
Allen, et al. v. Kerr-McGee (filed October 25, 2001).
Eight of the 22 cases were filed in the Court of Common Pleas, Luzerne County,
Pennsylvania, and relate to a closed wood-treatment plant in Avoca,
Pennsylvania. Five of the Pennsylvania cases were filed on October 23, 2001:
Mary Beth Marriggi, et al. v. Kerr-McGee; Delores Kubasko, et al. v. Kerr-McGee;
Barbara Fromet, et al. v. Kerr-McGee; Ann Culp, et al. v. Kerr McGee; and Robert
Battista, et al. v. Kerr-McGee. Three of the Pennsylvania cases were filed on
November 15, 2001: Stacey Berkoski, et al. v. Kerr-McGee; Kenneth Battista, et
al. v. Kerr-McGee; and James Butcher, et al. v. Kerr-McGee.
The parties have executed agreements to settle five of the seven Mississippi
cases and all seven of the Louisiana cases. The settlement agreements require
Chemical to pay up to $56 million for the benefit of about 9,400 identified
claimants who are eligible under the agreements and who sign releases. Of that
potential maximum of $56 million, approximately $44 million had been paid as of
December 31, 2002. In addition, the agreements require Chemical to pay up to an
additional $11 million from any recovery in certain insurance litigation that
Chemical and its parent filed against their insurance carriers (see below). The
agreements also contemplated two class-action settlement funds - one in
Mississippi and one in Louisiana - for the benefit of a class of residents who
did not sign individual releases and who did not choose to opt out of the class
settlements. The parties moved forward with the class settlement in Mississippi
but agreed not to pursue a class-action settlement in Louisiana. Chemical may be
required to pay up to a maximum of $7.5 million to the Mississippi class-action
settlement fund. The precise amount of Chemical's obligations under the
agreements depends on the number of plaintiffs who sign and deliver valid
individual releases, the number of the Mississippi class members who submit
proof of claim forms and the number of class members who opt out of the class.
Further payments pursuant to the settlements of the nonclass-action cases are
subject to a number of conditions, including the signing and delivery of
releases by named plaintiffs and court approval of various matters such as
minors' settlements. The class-action settlement agreement, including
certification of the settlement class and approval of the class settlement,
requires court approval. On February 21, 2003, the federal court in Mississippi
approved the Mississippi class settlement. Subsequently, two members of the
class filed a notice appealing the order approving the class settlement.
Although the settlement agreements are expected to resolve all of the Louisiana
lawsuits and substantially all of the Columbus, Mississippi, lawsuits described
above, the settlements will not resolve the claims of plaintiffs who do not sign
releases, the claims of any class members who opt out of the class settlement or
any claims by class members that may arise in the future for currently
unmanifested personal injuries. The settlements also do not cover the Maranatha
Faith Center v. Kerr-McGee or the Jamison v. Kerr-McGee cases which, together,
involve 27 plaintiffs who allege property damage and/or personal injury arising
out of the Columbus, Mississippi, operations or the eight cases in Pennsylvania,
which involve 55 named plaintiffs and an undetermined number of allegedly
similarly situated persons. The company is vigorously defending the two
remaining Mississippi lawsuits and the Pennsylvania cases, pending any
settlement of those cases.
The implementation of the settlements is progressing. Of approximately 6,100
identified claimants in Columbus, Mississippi, approximately 5,300 claimants
have delivered releases. Of approximately 3,300 identified claimants in
Louisiana, approximately 3,000 claimants have delivered releases. Through
December 31, 2002, Chemical had paid approximately $44 million pursuant to the
settlement agreements to Mississippi and Louisiana plaintiffs who signed
releases. No payments will be made to either of the class settlement funds
unless and until the appropriate court in each state has certified the class and
approved the respective class settlement.
Insurance Litigation - In 2001, Chemical and its parent company filed suit
against insurance carriers in the Superior Court of Somerset County, New Jersey.
The suit, Kerr-McGee Corporation and Kerr-McGee Chemical LLC v. Hartford
Accident & Indemnity Company and Liberty Mutual Insurance Company, is to recover
losses associated with certain environmental litigation, agency proceedings and
the Pennsylvania forest products litigation described above. Chemical and its
parent believe that they have valid claims against their insurers; however, the
prospects for recovery are uncertain and the litigation is in its early stages.
Further, a portion of any recovery will be paid to the plaintiffs in the forest
products litigation as a part of the settlement agreements described above.
Accordingly, the company has not recorded a receivable or otherwise reflected in
its financial statements any potential recovery from the insurance litigation.
Financial Reserves - The company previously established a $70 million reserve in
connection with the forest products litigation. The reserve included the
estimated amounts owed under the settlements described above and an estimated
amount for the remaining two Mississippi cases and the eight Pennsylvania cases.
As noted above, through December 31, 2002, Chemical had paid approximately $44
million pursuant to the settlement agreements. As of December 31, 2002, the
company's remaining reserves for the forest products litigation totaled $26
million. The company believes the reserve adequately provides for the potential
liability associated with these matters; however, there is no assurance that the
company will not be required to adjust the reserve in the future in light of the
inherent uncertainties associated with litigation.
Follow-on Litigation - A class-action settlement sometimes results in the filing
of additional lawsuits alleging facts and causes of action substantially similar
to those alleged in the case(s) covered by the settlement. In addition, in the
fall of 2002, the Mississippi legislature enacted a tort reform law that became
effective for lawsuits filed on or after January 1, 2003. Among other things,
the new law limits punitive damages and makes other changes intended to help
ensure fairness in the Mississippi civil justice system. The tort reform law
resulted in numerous lawsuits being filed in Mississippi immediately before the
effective date of the new law. On December 31, 2002, approximately 245 lawsuits
were filed against Chemical and its affiliates on behalf of approximately 4,598
claimants in connection with Chemical's Columbus, Mississippi, operations. All
of the lawsuits were filed in the Circuit Court of Lowndes County, Mississippi,
Case Nos. 2002-0302 CV1 through 2002-0543 CV1; 2002-0549 CV1; 2002-0550 CV1;
2002-0294 CV1 and 2002-0278 CV1. Chemical and its affiliates believe the
lawsuits are without substantial merit and intend to vigorously defend the
lawsuits. The company has not provided a reserve for the new lawsuits because it
cannot reasonably determine the probability of a loss, and the amount of loss,
if any, cannot be reasonably estimated.
Hattiesburg Litigation - On December 31, 2002, a lawsuit was filed against
Chemical in the Circuit Court of Forest County, Mississippi. The lawsuit, Betty
Bolton et al. v. Kerr-McGee Chemical Corporation, names approximately 975
plaintiffs and relates to a former wood-treatment plant located in Hattiesburg,
Mississippi. The lawsuit seeks recovery on legal theories substantially similar
to those advanced in the forest products litigation described above.
There are substantial uncertainties about Chemical's responsibility for
operations at the former facility. A predecessor of Chemical had been the sole
stockholder of a company that owned and operated the facility. The company that
had operated the facility already had been dissolved and its leasehold interest
in the site had been sold to a third party before Chemical became affiliated
with the former stockholder in 1964. Based on available historical records, it
is uncertain whether and, if so, under what terms, the former stockholder
assumed liabilities of the dissolved company. In any case, Chemical believes the
lawsuit is without substantial merit and intends to vigorously defend the
litigation. The company has not provided a reserve for the litigation because it
cannot reasonably determine the probability of a loss, and the amount of a loss,
if any, cannot be reasonably estimated.
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, and 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 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 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 are continually changing, and court
proceedings 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, 2002, the company had reserves totaling $258 million for
cleaning up and remediating environmental sites, reflecting the reasonably
estimable costs for addressing these sites. This includes $103 million for the
West Chicago sites, $17 million for the Henderson, Nevada, site, and $45 million
for forest products sites. Cumulative expenditures at all environmental sites
through December 31, 2002, total $1.023 billion (before considering government
reimbursements). Additionally, as of December 31, 2002, the company had
litigation reserves totaling approximately $73 million for the reasonably
estimable losses associated with litigation. This includes $26 million for the
forest products litigation described above. 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 $61 million in 2002, $38 million in 2001 and $34
million in 2000.
The company has various commitments under noncancelable operating lease
agreements, principally for office space, production and gathering facilities,
and drilling and other equipment. During 2002, the company entered into
operating lease agreements for the use of the Nansen and Boomvang platforms
located in the Gulf of Mexico. Including the lease rentals for these platforms,
aggregate minimum annual rentals under all operating leases in effect at
December 31, 2002, total $571 million, of which $39 million is due in 2003, $41
million in 2004, $41 million in 2005, $40 million in 2006, $38 million in 2007
and $372 million thereafter.
During 2001, the company entered into an 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
is being financed by a $157 million synthetic lease between the trust and a
group of financial institutions. After construction, the company and the trust
are committed to purchase or sell the platform and related equipment or enter
into an operating lease for the use of the platform. Currently, the company is
obligated to make lease payments in amounts sufficient to pay interest at
varying rates on the financing. The payments under the operating lease
obligation are expected to be nil in 2003, $6 million in 2004, $9 million in
2005, $10 million in 2006, $13 million in 2007 and $240 million thereafter. The
future minimum annual rentals due under the noncancelable operating leases shown
above exclude any payments related to this agreement. In accordance with the
provisions of FASB Interpretation (FIN) No. 46, "Consolidation of Variable
Interest Entities - an Interpretation of ARB No. 51," the company believes it is
reasonably likely that it will be required to consolidate the business trust
created to construct and finance the Gunnison production platform in the period
beginning July 1, 2003. The company continues to review the effects of FIN 46
relative to the company's other variable interest entities, such as the Nansen
and Boomvang operating leases.
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 estimate of the guarantee is $16
million in 2024.
During 2002, the company entered into a sale-leaseback arrangement with General
Electric Capital Corporation (GECC) covering assets associated with a
gas-gathering system in the Rocky Mountain region. The lease agreement was
entered into for the purpose of monetizing the related assets. The sales price
of the 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. The operating lease agreement has an initial
term of five years, with two 12-month renewal options. The company may elect to
purchase the equipment at specified amounts after the end of the fourth year. In
the event the company does not purchase the equipment and it is returned to
GECC, the company guarantees a residual value ranging from $32 million at the
end of the initial five-year term to $25 million at the end of the last renewal
option. The company recorded no gain or loss associated with the GECC
sale-leaseback agreement. The future minimum annual rentals due under
noncancelable operating leases shown above include payments related to this
agreement.
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. Because of the inherent uncertainty surrounding these matters, the
amount of any future liability related to these indemnifications cannot be
reasonably estimated. If a claim is asserted or if information becomes known to
management indicating it is probable that a liability has been incurred, an
accrual is established at that time.
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 $24 million, depending on partner participation.
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, 2002 or 2001. At
December 31, 2002 and 2001, available-for-sale securities for which fair value
can be determined are as follows:
2002 2001
----------------------------------- ----------------------------------
Gross Gross
Unrealized Unrealized
Fair Holding Fair Holding
(Millions of dollars) Value Cost Gains Value Cost Losses
- --------------------- ----- ---- ---------- ----- ---- ----------
Equity securities $70 $32 $10 (1) $59 $32 $(1) (1)
U.S. government obligations -
Maturing within one year 2 2 - 3 3 -
Maturing between one year
and four years 2 2 - 2 2 -
--- ---
Total $10 $(1)
=== ===
(1) This amount includes $28 million 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
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 as deferred credits. (See further discussion
on derivatives below.)
The Devon securities are carried in the Consolidated Balance Sheet as
Investments - Other 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, 2002,
2001 and 2000, is as follows:
(Millions of dollars) 2002 2001 2000
- --------------------- ---- ----- ----
Beginning balance $(1) $ 139 $ 79
Net unrealized holding gains (losses) 7 (22) 60
Reclassification of gains included in
net income - (118) -
--- ----- ----
Ending balance $ 6 $ (1) $139
=== ===== ====
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,
2002, the market value of 8.4 million shares of Devon was $387 million, and $61
million in unrealized pretax gains was recognized during 2002 in Other Income
(Loss) in the Consolidated Statement of Operations. However, this gain was
partially offset by a $34 million unrealized loss on the embedded options
associated with the DECS. See the discussion of these derivatives below. At
year-end 2001, the market value of 8.4 million shares of Devon was $326 million,
and $188 million in unrealized pretax losses was recognized during 2001. This
loss was more than offset by the $205 million unrealized gain 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,
2002 and 2001, the carrying amount and estimated fair value of these instruments
for which fair value can be determined are as follows:
2002 2001
---------------------- -----------------------
Carrying Fair Carrying Fair
(Millions of dollars) Amount Value Amount Value
- --------------------- ------ ----- ------ -----
Cash and cash equivalents $ 90 $ 90 $ 91 $ 91
Long-term notes receivable 2 2 2 2
Long-term receivables 86 71 4 3
Contracts to purchase foreign currencies 2 2 (15) (15)
Short-term borrowings - - 8 8
Debt exchangeable for stock, excluding options 318 330 310 330
Long-term debt, except DECS 3,586 4,013 4,256 4,319
The carrying amount of cash and cash equivalents approximates fair value of
those instruments due to their short maturity. The fair value of notes
receivable is based on the fair value of the note's collateral. 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
short-term and 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
Effective August 1, 2001, the company purchased 100% of the outstanding shares
of common stock of HS Resources. At the time of the purchase, HS Resources (now
Kerr-McGee Rocky Mountain Corp.) and its marketing subsidiary (now Kerr-McGee
Energy Services Corp.) had a number of derivative contracts for purchases and
sales of gas, basis differences and energy-related contracts. Prior to 2002, the
company had treated all of these derivatives as speculative and marked to market
through income each month the change in derivative fair values. In 2002, the
company designated the remaining portion of the HS Resources gas basis swaps
that settled in 2002 and all that settle in 2003 as hedges. Additionally, in
March 2002, the company began hedging a portion of its 2002 oil and natural gas
production to increase the predictability of its cash flow and support
additional capital expenditures. The hedges were in the form of fixed-price
swaps and covered 30,000 barrels of U.S. oil production per day at an average
price of $24.09 per barrel, 60,000 barrels of North Sea oil production per day
at an average price of $23.17 per barrel and 250,000 MMBtu of U.S. natural gas
production per day at an average price of $3.10 per MMBtu. In October 2002, the
company expanded the hedging program to cover a portion of the estimated 2003
crude oil and natural gas production by adding fixed-price swaps, new basis
swaps and costless collars. 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 is recorded as a current asset and
$110 million is recorded as a current liability. The fair value of these
derivative instruments at December 31, 2002, was determined based on prices
actively quoted, generally NYMEX and Dated Brent prices. The company had
after-tax deferred losses of $50 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 2002, the
company realized a $28 million loss on domestic oil hedging, a $50 million loss
on North Sea oil hedging and a $2 million loss on domestic natural gas hedging.
The losses offset the 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 to Sales in the Consolidated Statement of Operations and totaled $2
million in 2002.
The HS Resources gas basis swaps that settle between 2004 and 2008 continue to
be treated by the company as speculative and are marked to market through
income. These derivatives are recorded at fair value of $21 million in
Investments - Other assets. The net gain associated with these derivatives was
$8 million in 2002 and is included in Other Income in the Consolidated Statement
of Operations. In 2001, all of the HS Resources derivative contracts were
treated by the company as speculative and marked to market through income each
month. At December 31, 2001, the fair value of these contracts was $6 million.
Of this amount, $6 million was recorded in current assets, $5 million in
Investments - Other assets, $4 million in current liabilities and $1 million in
deferred credits. The net gain associated with these derivatives was $27 million
in 2001 and is included in Other Income in the Consolidated Statement of
Operations.
The marketing subsidiary, Kerr-McGee Energy Services (KMES) markets purchased
gas (primarily equity gas) in the Denver area. Existing contracts for the
physical delivery of gas at fixed or index-plus prices are marked to market each
month in accordance with FAS 133. KMES has entered into natural gas basis and
price derivative contracts 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 the physical and offsetting derivative contracts was $8 million at
year-end 2002. Of this amount, $31 million was recorded in current assets, $1
million in Investments - Other assets, $23 million in current liabilities and $1
million in deferred credits. The fair value of the outstanding derivative
instruments at December 31, 2002, was determined based on prices actively
quoted, generally NYMEX prices. During 2002, the net loss associated with these
derivative contracts was $20 million and is included in Sales in the
Consolidated Statement of Operations. At year-end 2001, the net asset fair value
of the commodity-related derivatives and physical contracts was $21 million. Of
this amount, $30 million was recorded in current assets, $11 million in
Investments - Other assets, $19 million in current liabilities and $1 million in
deferred credits. The 2001 net loss associated with these derivative contracts
was $24 million and is included in Sales in the Consolidated Statement of
Operations. The losses on the derivative contracts are generally offset by the
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) 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 and operating costs. These forward 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. The $7 million
after-tax loss in accumulated other comprehensive income at December 31, 2002,
will be recognized in earnings in the periods during which the hedged forecasted
transactions affect earnings (i.e., when the hedged transaction is paid in the
case of a hedge of operating costs, and when the hedged assets are depreciated
in the case of a hedge of capital expenditures). In 2002, the company
reclassified $5 million of losses on forward contracts from accumulated other
comprehensive income to operating expenses in the Consolidated Statement of
Operations. Of the existing unrealized net losses at December 31, 2002,
approximately $2 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 2002, and no ineffectiveness was recognized. The
company recognized net foreign currency hedging losses of $9 million and $6
million in 2001 and 2000, respectively.
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 foreign
currency rate changes. The estimated value of these contracts was immaterial.
Certain pigment receivables have been sold in an asset securitization program at
their equivalent U.S. dollar value at the date the receivables were sold.
However, the company retains the risk of foreign currency rate changes between
the date of sale and collection of the receivables.
The company issued 5 1/2% notes exchangeable for common stock (DECS) in August
1999, allowing each holder to receive between .85 and 1.0 share of Devon stock
or the equivalent amount of cash at maturity in August 2004. Embedded options in
the DECS provide Kerr-McGee a floor price on Devon's common stock of $33.19 per
share (the put option). The company also retains the right to 15% of the shares
if Devon's stock price is greater than $39.16 per share (the DECS holders have a
call option on 85% of the shares). Using the Black-Scholes valuation model, the
company recognizes in Other Income on a monthly basis any gains or losses of the
put and call options. On December 31, 2002, the fair values of the embedded put
and call options were less than $1 million and $67 million, respectively. At
year-end 2001, the fair values of the embedded put and call options were $2
million and $35 million, respectively, for a net fair value of $33 million.
During 2002 and 2001, the company recorded losses of $34 million and gains of
$205 million, respectively, in Other Income for the changes in the fair values
of the put and call options. As discussed above, the fluctuation in the value of
the put and call derivative financial instruments will generally offset the
increase or decrease in the market value of 85% of the Devon stock owned by the
company. The remaining 15% of the Devon shares is accounted for as
available-for-sale securities in accordance with FAS 115, "Accounting for
Certain Investments in Debt and Equity Securities," with changes in market value
recorded in accumulated other comprehensive income.
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 $21 million at December 31, 2002. The company
recognized a $6 million reduction in interest expense in 2002 from the swap
arrangement.
19. Acquisition
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 provides the company a more balanced
portfolio, geographic diversity and production mix. In addition, the acquisition
provides 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 include $348 million recorded as goodwill. 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 are the amounts allocated to the acquired assets and liabilities
based on their fair value:
(Million of dollars)
- --------------------
Accounts receivable $ 70
Deposits and prepaids 13
Other current assets 42
Property, plant and equipment 1,987
Investments and other assets 29
Goodwill 348
Accounts payable (94)
Accrued payables (33)
Other current liabilities (56)
Deferred income taxes (442)
Other deferred credits and reserves (48)
------
Total $1,816
======
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 the periods presented, including purchase accounting adjustments.
(Millions of dollars, except per-share amounts) 2001 2000
- ----------------------------------------------- ------ ------
Sales $3,798 $4,386
Income from continuing operations 490 801
Net income 499 826
Earnings per share-
Basic 4.99 8.39
Diluted 4.73 7.83
20. Discontinued Operations, Asset Impairments and Asset Disposals
During the first quarter of 2002, the company approved a plan to dispose of its
exploration and production operations in Kazakhstan and its interest in the
Bayu-Undan project in the East Timor Sea offshore Australia. During the second
quarter of 2002, the company approved a plan to dispose of its exploration and
production 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 planned
disposals, the related assets were evaluated and an impairment loss was 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 impairment loss totaled $35 million and is reported as part
of discontinued operations. On May 3, 2002, the company completed the sale of
its interest in the Bayu-Undan project for $132 million in cash. The sale
resulted in a pretax gain of $35 million. On June 13, 2002, the company
completed the sale of its interest in the Jabung block in Sumatra for $171
million in cash with an $11 million contingent purchase price pending government
approval of the 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. In February 2003,
the company announced an agreement with Shell Kazakhstan Development for the
sale of its exploration and production operations in Kazakhstan. The transaction
is expected to close March 31, 2003.
Revenues applicable to the discontinued operations totaled $36 million, $72
million and $58 million for 2002, 2001 and 2000, respectively. Pretax income for
the discontinued operations totaled $104 million (including the gains on sale of
$107 million and the impairment loss of $35 million), $52 million and $45
million for the years 2002, 2001 and 2000, respectively.
During late 2001 and 2002, certain U.S., North Sea and Ecuador exploration and
production segment assets were identified for disposal as part of the company's
plan to divest noncore properties as discussed above. In connection with this
recharacterization, the assets were evaluated and determined to be impaired. The
impairment losses reflect the difference between the estimated sales prices for
the individual properties or group of properties, less the costs to sell, and
the carrying amount of the net assets. The amount of the impairment loss
associated with the U.S., North Sea and Ecuador assets held for sale totaled
$176 million and is reported as Asset Impairment in the Consolidated Statement
of Operations.
Pretax impairment losses totaling $652 million were also provided in 2002 for
certain assets used in operations that are not considered held for sale, 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 $646 million 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. These impairment losses were determined based on the difference
between the carrying value of the assets and their estimated fair values,
determined using either discounted future cash flows or quoted market prices, as
applicable. 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.
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 is expected to be
completed during 2003. An impairment loss of $47 million was recorded in 2001
based on the difference between the carrying value of the assets and the present
value of the field's discounted future cash flows, net of expected proceeds from
the sale of the Hutton tension-leg platform (TLP), a production, drilling and
accommodation facility located at the Hutton field. An additional $4 million
impairment charge recorded in 2002 for the Hutton field (included in the $82
million North Sea impairments discussed above) resulted from lower than
originally projected realization from the sale of the Hutton TLP, which occurred
in August 2002. The Hutton field had no remaining carrying value at year-end
2002.
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 2001.
The asset had no remaining carrying value at year-end 2002.
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 2001, reducing the
carrying value of the asset to nil. 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, which had a carrying value of
less than $1 million at year-end 2002.
The company recognized a net gain (loss) on disposal of property, excluding
discontinued operations, of $1 million in 2002, $12 million in 2001 and ($4)
million in 2000, which is reflected in Other Income in the Consolidated
Statement of Operations. The company expects to complete the divestiture of its
other remaining assets held for sale in the first six months of 2003. 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.
21. Common Stock
Changes in common stock issued and treasury stock held for 2002, 2001 and 2000
are as follows:
(Thousands of shares) Common Stock Treasury Stock
- --------------------- ------------ --------------
Balance December 31, 1999 93,494 7,011
Exercise of stock options and stock appreciation rights 423 -
Public offering 7,500 -
Issuance of restricted stock - (78)
------- ------
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
======= ======
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
awards to key employees. 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. Grants generally vest between three and five years.
Compensation expense is recognized over the vesting period and was $6 million,
$4 million and $1 million in 2002, 2001 and 2000, respectively. The company
granted 99,000, 118,000 and 74,000 shares of restricted common stock in 2002,
2001 and 2000, respectively, for which the weighted average fair value at the
date of grant was $4 million, $7 million and $5 million, respectively.
The company has had a stockholders-rights plan since 1986. The current rights
plan is dated July 26, 2001, and replaced the previous plan prior to its
expiration. Rights were distributed as a dividend at the rate of one right for
each share of the company's common stock and continue to trade together with
each share of common stock. Generally, the rights become exercisable the earlier
of 10 days after a public announcement that a person or group has acquired, or a
tender offer has been made for, 15% or more of the company's then-outstanding
stock. If either of these events occurs, each right would entitle the holder
(other than a holder owning more than 15% of the outstanding stock) to buy the
number of shares of the company's common stock having a market value two times
the exercise price. The exercise price is $215. Generally, the rights may be
redeemed at $.01 per right until a person or group has acquired 15% or more of
the company's stock. The rights expire in July 2006.
22. Employee Stock 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 that time, although options and
any accompanying stock appreciation rights outstanding may be exercised prior to
their respective 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 for the 2002 Plan,
the 2000 Plan, the BSOP, the 1998 Plan and the 1987 Program.
2002 2001 2000
------------------------ ---------------------- ------------------------
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 3,433,745 $61.18 3,036,605 $59.66 2,823,334 $56.78
Options granted 2,544,562 57.08 1,024,530 65.19 719,550 63.53
Options exercised (111,411) 46.78 (532,260) 59.55 (426,561) 46.59
Options surrendered upon exercise
of stock appreciation rights - - (1,900) 42.63 (7,300) 45.57
Options forfeited (141,116) 58.42 (62,539) 62.78 (46,779) 61.79
Options expired (319,356) 67.09 (30,691) 63.74 (25,639) 72.95
--------- --------- ---------
Outstanding, end of year 5,406,424 59.27 3,433,745 61.18 3,036,605 59.66
========= ========= =========
Exercisable, end of year 2,179,960 59.60 1,935,880 59.32 2,007,036 59.70
========= ========= =========
The following table summarizes information about stock options issued under the
plans described above that are outstanding and exercisable at December 31, 2002:
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 2.5 $34.19 9,457 $34.19
297,128 40.00 - 49.99 3.1 42.91 297,128 42.91
2,106,585 50.00 - 59.99 7.5 55.03 672,533 56.91
2,865,610 60.00 - 69.99 7.7 63.54 1,073,198 64.48
127,644 70.00 - 79.99 3.1 73.41 127,644 73.41
--------- ---------
5,406,424 30.00 - 79.99 7.2 59.27 2,179,960 59.60
========= =========
23. 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. Following are the changes in the benefit obligations during the past
two years:
Postretirement
Retirement Plans Health and Life Plans
----------------------- ---------------------
(Millions of dollars) 2002 2001 2002 2001
- --------------------- ------ ------ ---- ----
Benefit obligation, beginning of year $1,075 $1,014 $271 $230
Service cost 24 22 3 2
Interest cost 76 73 19 17
Plan amendments - 21 - -
Net actuarial loss 30 17 53 43
Foreign exchange rate changes 12 (3) - -
Assumption changes 30 37 - -
Contributions by plan participants - - 6 8
Benefits paid (100) (106) (25) (29)
------ ------ ---- ----
Benefit obligation, end of year $1,147 $1,075 $327 $271
====== ====== ==== ====
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 benefit obligation
for the U.S and certain foreign unfunded retirement plans was $58 million and
$44 million at December 31, 2002 and 2001, respectively. 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 2002 and $28 million at year-end 2001. The postretirement plans are
also unfunded.
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, 2002 and 2001:
Postretirement
Retirement Plans Health and Life Plans
----------------------- ---------------------
(Millions of dollars) 2002 2001 2002 2001
- --------------------- ------- ------- ----- -----
Fair value of plan assets, beginning of year $ 1,364 $ 1,558 $ - $ -
Actual return on plan assets (90) (93) - -
Employer contribution 6 9 - -
Foreign exchange rate changes 10 (4) - -
Benefits paid (100) (106) - -
------- ------- ----- -----
Fair value of plan assets, end of year 1,190 1,364 - -
Benefit obligation (1,147) (1,075) (327) (271)
------- ------- ----- -----
Funded status of plans - over (under) 43 289 (327) (271)
Amounts not recognized in the
Consolidated Balance Sheet -
Prior service costs 79 89 3 4
Net actuarial loss (gain) 83 (215) 96 45
------- ------- ----- -----
Prepaid expense (accrued liability) $ 205 $ 163 $(228) $(222)
======= ======= ===== =====
Following is the classification of the amounts recognized in the Consolidated
Balance Sheet at December 31, 2002 and 2001:
Postretirement
Retirement Plans Health and Life Plans
--------------------- ---------------------
(Millions of dollars) 2002 2001 2002 2001
- --------------------- ---- ---- ---- ----
Prepaid benefits expense $240 $191 $ - $ -
Accrued benefit liability (62) (31) (228) (222)
Additional minimum liability -
intangible asset 1 - - -
Accumulated other comprehensive income 26 3 - -
---- ---- ----- -----
Total $205 $163 $(228) $(222)
==== ==== ===== =====
Total costs recognized for employee retirement and postretirement benefit plans
for each of the years ended December 31, 2002, 2001 and 2000, were as follows:
Postretirement
Retirement Plans Health and Life Plans
------------------------------- -------------------------------
(Millions of dollars) 2002 2001 2000 2002 2001 2000
- --------------------- ----- ---- ---- ---- ---- ----
Net periodic cost -
Service cost $ 24 $ 22 $ 17 $ 3 $ 2 $ 2
Interest cost 76 73 72 19 17 15
Expected return on plan assets (130) (124) (111) - - -
Net amortization -
Transition asset - (1) (5) - - -
Prior service cost 10 9 8 1 1 1
Net actuarial gain (16) (23) (17) 1 - -
----- ----- ----- ---- --- ---
Total $ (36) $ (44) $ (36) $ 24 $20 $18
===== ===== ===== ==== === ===
The following assumptions were used in estimating the actuarial present value of
the plans' benefit obligations and net periodic expense:
2002 2001 2000
-------------------------- --------------------------- ------------------------
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 9.0 5.75 - 7.0 9.0 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 health care cost trend rates used to determine the year-end 2002
postretirement benefit obligation were 10% in 2003, 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, 2002, by $29 million and increase the aggregate of
the service and interest cost components of net periodic postretirement expense
for 2002 by $2 million. A 1% decrease in the trend rate for each future year
would reduce the benefit obligation at year-end 2002 by $25 million and decrease
the aggregate of the service and interest cost components of the net periodic
postretirement expense for 2002 by $2 million.
24. 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). The third-party borrowings are guaranteed by the company and are
reflected in the Consolidated Balance Sheet as Long-Term Debt (see Note 11),
while the sponsor financing does not appear in the company's balance sheet. The
remaining balance of the sponsor financing is $3 million at year-end 2002.
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
$64 million at year-end 2002. 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) 2002 2001
- --------------------- ----- -----
Participants' accounts 1,448 1,339
Loan suspense account 630 941
The shares in the loan suspense account included approximately 6,000 shares and
68,000 shares that were released but not allocated to participants accounts at
December 31, 2002 and 2001, respectively.
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 $19 million, $12 million and $11
million in 2002, 2001 and 2000, respectively. These amounts include interest
expense incurred on the third-party ESOP debt of $1 million in 2002, $2 million
in 2001 and $3 million in 2000. The company contributed $27 million, $22 million
and $21 million to the ESOP in 2002, 2001, and 2000, respectively. Included in
the contributions were $19 million in 2002 and $12 million for both 2001 and
2000 for principal and interest payments on the sponsor financings. The cash
contributions are net of $5 million for the dividends paid on the company stock
held by the ESOP trust in 2002 and $4 million in each of 2001 and 2000.
25. 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, 2002, 2001 and 2000.
2002 2001 2000
------------------------------ ----------------------------- -------------------------------
(Millions of dollars, Loss from Per- Income from Per- Income from Per-
except per-share amounts Continuing share Continuing share Continuing share
and thousands of shares) Operations Shares Loss Operations Shares Income Operations Share Income
-------------------- ---------- ------ ------ ---------- ------ ------ ---------- ----- ------
Basic earnings per share $(611) 100,330 $(6.09) $476 97,106 $4.91 $817 93,406 $8.75
Effect of dilutive securities:
5-1/4% convertible
debentures - - 22 9,824 19 8,720
7-1/2% convertible
debentures - - - - 9 1,697
Employee stock options - - - 181 - 164
----- ------- ------ ---- ------- ----- ---- ------- -----
Diluted earnings per share $(611) 100,330 $(6.09) $498 107,111 $4.65 $845 103,987 $8.13
===== ======= ====== ==== ======= ===== ==== ======= =====
Not included in the calculation of the denominator for diluted earnings per
share were 4,688,853, 2,219,858 and 2,113,284 employee stock options outstanding
at year-end 2002, 2001 and 2000, 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. The company retired the 7-1/2%
Convertible Subordinated Debentures in 2001.
26. 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, Kerr-McGee Corporation, is shown as the parent in 2002 and 2001, but
since it did not exist in 2000, no parent amounts are presented. The guarantor
subsidiaries include Kerr-McGee Chemical Worldwide LLC in 2002, its
predecessors, Kerr-McGee Operating Corporation in 2001 and the original
Kerr-McGee Corporation in 2000, along with Kerr-McGee Rocky Mountain Corporation
in 2002 and 2001.
The following tables present condensed consolidating financial information for
(a) Kerr-McGee Corporation, the current 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,
2002
- --------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- --------------------- ----------- ------------ ------------ ------------ ------------
Sales $ - $351 $3,608 $(259) $3,700
----- ---- ------ ----- ------
Costs and Expenses
Costs and operating expenses - 105 1,705 (260) 1,550
Selling, general and administrative expenses - 4 309 - 313
Shipping and handling expenses - 9 116 - 125
Depreciation and depletion - 121 653 - 774
Asset impairment - 3 825 - 828
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 4,360 (459) 4,322
----- ---- ------ ----- ------
(115) 45 (752) 200 (622)
Other Income (Loss) (438) 484 (127) 46 (35)
----- ---- ------ ----- ------
Income (Loss) from Continuing Operations
before Income Taxes (553) 529 (879) 246 (657)
Taxes on Income 68 (26) 44 (40) 46
----- ---- ------ ----- ------
Income (Loss) from Continuing Operations (485) 503 (835) 206 (611)
Discontinued Operations, net of income 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
- --------------------- ----------- ------------ ------------ ------------ ------------
Sales $ - $ 122 $3,801 $ (357) $3,566
----- ------ ------ ------- ------
Costs and Expenses
Costs and operating expenses - 47 1,619 (357) 1,309
Selling, general and administrative expenses - 69 159 - 228
Shipping and handling expenses - 2 109 - 111
Depreciation and depletion - 57 656 - 713
Asset impairment - - 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 3,036 (521) 3,038
----- ------ ------ ------- ------
(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
Taxes on Income (287) (209) (362) 582 (276)
----- ------ ------ ------- ------
Income from Continuing Operations 486 631 553 (1,194) 476
Discontinued Operations, net of income taxes - - 30 - 30
Cumulative Effect of Change in Accounting
Principle, net of income taxes - (21) 1 - (20)
----- ------ ------ ------- ------
Net Income $ 486 $ 610 $ 584 $(1,194) $ 486
===== ====== ====== ======= ======
Condensed Consolidating Statement of Operations for the Year Ended December 31,
2000
- --------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- --------------------- ----------- ------------ ------------ ------------ ------------
Sales $ - $ (9) $4,085 $ (13) $4,063
----- ------ ------ ------- ------
Costs and Expenses
Costs and operating expenses - 4 1,274 (13) 1,265
Selling, general and administrative expenses - 47 150 - 197
Shipping and handling expenses - - 98 - 98
Depreciation and depletion - 8 670 - 678
Exploration, including dry holes and amortization
of undeveloped leases - - 169 - 169
Taxes, other than income taxes - 4 118 - 122
Provision for environmental remediation and
restoration, net of reimbursements - 90 - - 90
Purchased in-process research and development - - 32 - 32
Interest and debt expense - 256 203 (251) 208
----- ------ ------ ------- ------
Total Costs and Expenses - 409 2,714 (264) 2,859
----- ------ ------ ------- ------
- (418) 1,371 251 1,204
Other Income - 1,717 291 (1,958) 50
----- ------ ------ ------- ------
Income from Continuing Operations
before Income Taxes - 1,299 1,662 (1,707) 1,254
Taxes on Income - (457) (553) 573 (437)
----- ------ ------ ------- ------
Income from Continuing Operations - 842 1,109 (1,134) 817
Discontinued Operations, net of income taxes - - 25 - 25
----- ------ ------ ------- ------
Net Income $ - $ 842 $1,134 $(1,134) $ 842
===== ====== ====== ======= ======
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
Intercompany receivables 956 46 1,641 (2,643) -
Accounts receivable - 73 535 - 608
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
Property, Plant and Equipment - Net - 1,956 5,080 - 7,036
Investments and Other Assets 12 118 986 (81) 1,035
Long-Term Assets Associated with Properties
Held for Disposal - - 187 5 192
Investments in and Advances to Subsidiaries 3,673 695 80 (4,448) -
Goodwill - 347 9 - 356
------ ------ ------ ------- ------
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
Deferred Credits and Reserves - 675 1,298 (24) 1,949
Long-Term Liabilities Associated with Properties - - 16 - 16
Held for Disposal
Investments by and Advances from Parent - - 729 (729) -
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 Balance Sheet as of December 31, 2001
- --------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- --------------------- ----------- ------------ ------------ ------------ ------------
ASSETS
Current Assets
Cash $ - $ 4 $ 87 $ - $ 91
Intercompany receivables 1 (524) 1,866 (1,343) -
Accounts receivable - 41 380 - 421
Inventories - 4 425 - 429
Deposits, prepaid expenses and other assets - 49 79 223 351
Current assets associated with properties
held for disposal - - 75 - 75
------ ------ ------- -------- -------
Total Current Assets 1 (426) 2,912 (1,120) 1,367
Property, Plant and Equipment - Net - 2,067 5,311 - 7,378
Investments and Other Assets 12 641 191 (60) 784
Long-Term Assets Associated with Properties
Held for Disposal - 6 1,185 - 1,191
Investments in and Advances to Subsidiaries 4,992 5,007 1,709 (11,708) -
Goodwill - 347 9 - 356
------ ------ ------- -------- -------
Total Assets $5,005 $7,642 $11,317 $(12,888) $11,076
====== ====== ======= ======== =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 45 $ 95 $ 480 $ - $ 620
Short-term borrowings - - 8 - 8
Intercompany borrowings - 1,316 1,027 (2,343) -
Long-term debt due within one year - 23 3 - 26
Other current liabilities 34 (334) 392 383 475
Current liabilities associated with properties
held for disposal - - 45 - 45
------ ------ ------- -------- -------
Total Current Liabilities 79 1,100 1,955 (1,960) 1,174
Long-Term Debt 1,497 2,016 1,027 - 4,540
Deferred Credits and Reserves - 1,013 1,045 (50) 2,008
Long-Term Liabilities Associated with Properties
Held for Disposal - - 180 - 180
Investments by and Advances from Parent - - 955 (955) -
Stockholders' Equity 3,429 3,513 6,155 (9,923) 3,174
------ ------ ------- -------- -------
Total Liabilities and Stockholders' Equity $5,005 $7,642 $11,317 $(12,888) $11,076
====== ====== ======= ======== =======
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 (used in)
operating activities -
Depreciation, depletion and amortization - 124 720 - 844
Deferred income taxes - 9 (121) - (112)
Dry hole costs - - 113 - 113
Asset impairment - 3 859 - 862
Equity in loss (earnings) of subsidiaries 465 (25) - (440) -
Provision for environmental remediation and
restoration, net of reimbursements - - 89 - 89
Gain on asset retirements and sales - - (110) - (110)
Noncash items affecting net income - (13) 139 - 126
Changes in current assets and liabilities and other (16) 328 (191) - 121
----- ----- ------- ----- -------
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
Repayment of long-term debt - - (1,093) - (1,093)
Decrease in short-term borrowings - - (8) - (8)
Increase (decrease) in intercompany notes payable (135) (112) 248 (1) -
Issuance of common stock 5 - - - 5
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 (used in)
operating activities -
Depreciation, depletion and amortization - 60 719 - 779
Deferred income taxes - 166 39 - 205
Dry hole costs - - 72 - 72
Asset impairment - - 76 - 76
Equity in loss (earnings) of subsidiaries (520) (586) - 1,106 -
Provision for environmental remediation and
restoration, net of reimbursements - 82 - - 82
Gain on asset retirements and sales - (3) (9) - (12)
Noncash items affecting net income - (201) 54 - (147)
Changes in current assets and liabilities and other,
net of effects of operations acquired (463) 656 (688) 97 (398)
------ ------- ------- ------- -------
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
Repayment of long-term debt - (586) (75) - (661)
Increase (decrease) in short-term borrowings - (11) 2 - (9)
Increase (decrease) in intercompany notes payable - 1,009 - (1,009) -
Issuance of common stock - 32 - - 32
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
====== ======= ======= ======= =======
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31,
2000
- --------------------------------------------------------------------------------
Kerr-McGee Guarantor Non-Guarantor
(Millions of dollars) Corporation Subsidiaries Subsidiaries Eliminations Consolidated
- --------------------- ----------- ------------ ------------ ------------ ------------
Cash Flow from Operating Activities
Net income $ - $ 842 $ 1,134 $(1,134) $ 842
Adjustments to reconcile to net cash provided by
operating activities -
Depreciation, depletion and amortization - 8 724 - 732
Deferred income taxes - 59 (41) - 18
Dry hole costs - - 54 - 54
Equity in loss (earnings) of subsidiaries - (1,134) - 1,134 -
Provision for environmental remediation and
restoration, net of reimbursements - 90 - - 90
Gain on asset retirements and sales - - (6) - (6)
Purchased in-process research and development - - 32 - 32
Noncash items affecting net income - (8) 53 - 45
Changes in current assets and liabilities and other,
net of effects of operations acquired - 168 (135) - 33
---- ------- ------- ------- -------
Net cash provided by operating activities - 25 1,815 - 1,840
---- ------- ------- ------- -------
Cash Flow from Investing Activities
Capital expenditures - (6) (836) - (842)
Dry hole costs - - (54) - (54)
Acquisitions - - (1,018) - (1,018)
Other investing activities - 1 20 - 21
---- ------- ------- ------- -------
Net cash used in investing activities - (5) (1,888) - (1,893)
---- ------- ------- ------- -------
Cash Flow from Financing Activities
Issuance of long-term debt - 600 77 - 677
Repayment of long-term debt - (198) (768) - (966)
Decrease in short-term borrowings - - (3) - (3)
Increase (decrease) in intercompany notes payable - (639) 639 - -
Issuance of common stock - 383 - - 383
Dividends paid - (166) - - (166)
---- ------- ------- ------- -------
Net cash used in financing activities - (20) (55) - (75)
---- ------- ------- ------- -------
Effects of Exchange Rate Changes on Cash and Cash
Equivalents - - 5 - 5
---- ------- ------- ------- -------
Net Decrease in Cash and Cash Equivalents - - (123) - (123)
Cash and Cash Equivalents at Beginning of Year - 3 264 - 267
---- ------- ------- ------- -------
Cash and Cash Equivalents at End of Year $ - $ 3 $ 141 $ - $ 144
==== ======= ======= ======= =======
27. Reporting by Business Segments and Geographic Locations
The company has three reportable segments: oil and gas exploration and
production, production and marketing of titanium dioxide pigment, and production
and marketing of other 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,
Brazil, Gabon, Morocco, Canada, Yemen and the Danish sector 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 $408 million to
Texon L.P. and $450 million to BP Oil International in 2002; $408 million to
Texon L.P. and $401 million to BP Oil International in 2001; and $548 million to
Texon L.P. and $859 million to BP Oil International in 2000. In addition,
natural gas sales to Cinergy Marketing & Trading LP totaled $496 million, $682
million and $522 million in 2002, 2001 and 2000, respectively. Sales to
subsidiary companies are eliminated as described in Note 1.
(Millions of dollars) 2002 2001 2000
- --------------------- ------ ------ ------
Sales -
Exploration and production $2,504 $2,439 $2,802
------ ------ ------
Chemicals -
Pigment 995 931 1,034
Other 201 196 227
------ ------ ------
Total Chemicals 1,196 1,127 1,261
------ ------ ------
Total $3,700 $3,566 $4,063
====== ====== ======
Operating profit (loss) -
Exploration and production $ (140) $ 922 $1,431
------ ------ ------
Chemicals -
Pigment 24 (22) 130
Other (23) (17) 17
------ ------ ------
Total Chemicals 1 (39) 147
------ ------ ------
Total (139) 883 1,578
------ ------ ------
Net interest expense (270) (185) (187)
Net nonoperating income (expense) (248) 54 (137)
Taxes on income 46 (276) (437)
Discontinued operations, net of taxes 126 30 25
Cumulative effect of change in accounting
principle net of taxes - (20) -
------ ------ ------
Net income (loss) $ (485) $ 486 $ 842
====== ====== ======
Depreciation, depletion and amortization -
Exploration and production $ 718 $ 641 $ 626
------ ------ ------
Chemicals -
Pigment 97 103 71
Other 20 17 21
------ ------ ------
Total Chemicals 117 120 92
------ ------ ------
Other 6 8 8
Discontinued operations 3 10 6
------ ------ ------
Total $ 844 $ 779 $ 732
====== ====== ======
Capital expenditures -
Exploration and production $ 988 $1,557 $ 682
------ ------ ------
Chemicals -
Pigment 78 139 101
Other 8 14 17
------ ------ ------
Total Chemicals 86 153 118
------ ------ ------
Other 58 15 6
Discontinued operations 27 67 36
------ ------ ------
Total 1,159 1,792 842
------ ------ ------
Exploration expenses -
Exploration and production -
Dry hole costs 113 72 54
Amortization of undeveloped leases 67 56 48
Other 93 82 67
------ ------ ------
Total 273 210 169
------ ------ ------
Total capital expenditures
and exploration expenses $1,432 $2,002 $1,011
====== ====== ======
Identifiable assets -
Exploration and production $7,030 $8,076 $4,849
------ ------ ------
Chemicals -
Pigment 1,413 1,391 1,415
Other 247 245 228
------ ------ ------
Total Chemicals 1,660 1,636 1,643
------ ------ ------
Total 8,690 9,712 6,492
Corporate and other assets 1,038 1,010 915
Discontinued operations 181 354 259
------ ------ ------
Total $9,909 $11,076 $7,666
====== ======= ======
Sales -
U.S. operations $2,190 $2,125 $2,197
------ ------ ------
International operations -
North Sea - exploration and production 990 946 1,277
Other - exploration and production 58 70 86
Europe - pigment 294 258 300
Australia - pigment 168 167 203
------ ------ ------
1,510 1,441 1,866
------ ------ ------
Total $3,700 $3,566 $4,063
====== ====== ======
Operating profit (loss) -
U.S. operations $ 322 $ 647 $ 863
------ ------ ------
International operations -
North Sea - exploration and production (412) 318 651
Other - exploration and production (52) (60) (7)
Europe - pigment (21) (53) 33
Australia - pigment 24 31 38
------ ------ ------
(461) 236 715
------ ------ ------
Total $ (139) $ 883 $1,578
====== ====== ======
Net property, plant and equipment -
U.S. operations $4,631 $4,483 $2,368
------ ------ ------
International operations -
North Sea - exploration and production 1,912 2,427 2,350
Other - exploration and production 128 120 157
Europe - pigment 255 226 238
Australia - pigment 110 122 127
------ ------ ------
2,405 2,895 2,872
------ ------ ------
Total $7,036 $7,378 $5,240
====== ====== ======
28. 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, 2002, are reflected in the following table:
Property
Acquisition Exploration Development
(Millions of dollars) Costs(1) Costs(2) Costs(3)
- --------------------- ----------- ----------- -----------
2002 -
United States $ 89 $206 $ 426
North Sea 55 14 296
Other international 2 58 16
------ ---- ------
Total continuing operations 146 278 738
Discontinued operations 2 1 5
------ ---- ------
Total $ 148 $279 $ 743
====== ==== ======
2001 -
United States $1,420 $225 $ 457
North Sea - 71 695
Other international 3 99 21
------ ---- ------
Total continuing operations 1,423 395 1,173
Discontinued operations - 4 64
------ ---- ------
Total $1,423 $399 $1,237
====== ==== ======
2000 -
United States $ 41 $112 $ 230
North Sea 566 53 290
Other international 39 55 13
------ ---- ------
Total continuing operations 646 220 533
Discontinued operations - 2 35
------ ---- ------
Total $ 646 $222 $ 568
====== ==== ======
(1) Includes $69 million, $1.128 billion and $561 million applicable to
purchases of reserves in place in 2002, 2001 and 2000, 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.
29. 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, 2002, consist of the following:
Results of
Production Other Depreciation Income Tax Operations,
Gross (Lifting) Related Exploration and Depletion Asset Expenses Producing
(Millions of dollars) Revenues Costs Costs Expenses Expenses Impairment (Benefits) Activities
- --------------------- -------- ---------- ------- ----------- ------------- ---------- ---------- ----------
2002 -
United States $1,367 $268 $106 $159 $374 $111 $116 $ 233
North Sea 920 273 60 48 264 706 33 (464)
Other international 59 17 19 66 3 5 (15) (36)
------ ---- ---- ---- ---- ---- ---- -----
Total crude oil and
natural gas activities 2,346 558 185 273 641 822 134 (267)
Other (1) 158 143 12 - 10 - (4) (3)
------ ---- ---- ---- ---- ---- ---- -----
Total from continuing
operations 2,504 701 197 273 651 822 130 (270)
Discontinued operations 36 5 13 1 3 35 - (21)
------ ---- ---- ---- ---- ---- ---- -----
Total $2,540 $706 $210 $274 $654 $857 $130 $(291)
====== ==== ==== ==== ==== ==== ==== =====
2001 -
United States $1,402 $231 $69 $100 $317 $ - $248 $ 437
North Sea 922 227 61 29 253 47 120 185
Other international 69 18 19 80 11 - (19) (40)
------ ---- ---- ---- ---- ---- ---- -----
Total crude oil and
natural gas activities 2,393 476 149 209 581 47 349 582
Other (1) 46 45 5 1 4 - (7) (2)
------ ---- ---- ---- ---- ---- ---- -----
Total from continuing 2,439 521 154 210 585 47 342 580
operations
Discontinued operations 72 7 17 1 10 - 17 20
------ ---- ---- ---- ---- ---- ---- -----
Total $2,511 $528 $171 $211 $595 $ 47 $359 $ 600
====== ==== ==== ==== ==== ==== ==== =====
2000 -
United States $1,436 $198 $ 67 $ 95 $286 $ - $277 $ 513
North Sea 1,264 262 55 26 283 - 219 419
Other international 85 19 17 48 8 - 5 (12)
------ ---- ---- ---- ---- ---- ---- -----
Total crude oil and
natural gas activities 2,785 479 139 169 577 - 501 920
Other (1) 17 6 - - 1 - 4 6
------ ---- ---- ---- ---- ---- ---- -----
Total from continuing 2,802 485 139 169 578 - 505 926
operations
Discontinued operations 58 5 10 1 6 - 16 20
------ ---- ---- ---- ---- ---- ---- -----
Total $2,860 $490 $149 $170 $584 $ - $521 $ 946
====== ==== ==== ==== ==== ==== ==== =====
(1) Includes gas marketing, gas processing plants, pipelines and other items
that do not fit the definition of crude oil and natural gas 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 production costs 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).
2002 2001 2000
------ ------ ------
Average price of crude oil sold (per barrel) -
United States $21.56 $22.05 $27.50
North Sea 22.41 23.23 27.92
Other international 22.36 20.28 26.05
Average(1) 22.04 22.60 27.69
Average price of natural gas sold (per Mcf)
United States 3.04 3.99 4.11
North Sea 2.35 2.46 2.32
Average(1) 2.95 3.83 3.87
Production costs -
(per barrel of oil equivalent)
United States 3.84 3.79 3.59
North Sea 6.28 5.53 5.55
Other international 6.42 5.60 5.89
Average 4.81 4.53 4.54
(1) Includes the results of the company's 2002 hedging program that reduced the
average price of crude oil and natural gas sold by $1.13 per barrel and
$.01 per Mcf, respectively.
30. 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 2002 and
2001 are set forth in the table below.
(Millions of dollars) 2002 2001
- --------------------- ------- -------
Capitalized costs -
Proved properties $10,442 $10,288
Unproved properties 782 753
Other 361 351
------- -------
Total 11,585 11,392
Assets held for disposal 782 2,761
Discontinued operations 63 230
------- -------
Total 12,430 14,383
------- -------
Reserves for depreciation, depletion and amortization -
Proved properties 5,384 4,887
Unproved properties 155 131
Other 93 62
------- -------
Total 5,632 5,080
Assets held for disposal 746 2,015
Discontinued operations 17 32
------- -------
Total 6,395 7,127
------- -------
Net capitalized costs $ 6,035 $ 7,256
======= =======
31. 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, 2002.
Continuing Operations
-----------------------------------------------------
Total
Crude Oil, Condensate and Natural Gas Liquids United North Other Continuing Discontinued
(Millions of barrels) States Sea International Operations Operations Total
- --------------------------------------------- ------ ----- ------------- ---------- ---------- -----
Proved developed and undeveloped reserves -
Balance December 31, 1999 234 232 47 513 65 578
Revisions of previous estimates (9) 7 - (2) - (2)
Purchases of reserves in place 1 68 - 69 - 69
Sales of reserves in place (1) - - (1) - (1)
Extensions, discoveries and other
additions 30 91 9 130 2 132
Production (27) (43) (4) (74) (2) (76)
----- ---- --- ----- ---- -----
Balance December 31, 2000 228 355 52 635 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) (4) (69) (3) (72)
----- ---- --- ----- ---- -----
Balance December 31, 2001 317 388 74 779 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) (3) (70) (2) (72)
----- ---- --- ----- ---- -----
Balance December 31, 2002 241 202 35 478 9 487
===== ==== === ===== ==== =====
Natural Gas (Billions of cubic feet)
- ------------------------------------
Proved developed and undeveloped reserves -
Balance December 31, 1999 1,274 266 - 1,540 515 2,055
Revisions of previous estimates 11 40 - 51 - 51
Purchases of reserves in place 19 173 - 192 - 192
Sales of reserves in place (37) - - (37) - (37)
Extensions, discoveries and other
additions 227 13 - 240 20 260
Production (169) (25) - (194) - (194)
----- ---- --- ----- ---- -----
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
===== ==== === ===== ==== =====
Continuing Operations
-----------------------------------------------------
Total
Crude Oil, Condensate and Natural Gas Liquids United North Other Continuing Discontinued
(Millions of barrels) States Sea International Operations Operations Total
- --------------------------------------------- ------ ----- ------------- ---------- ------------ -----
Proved developed reserves -
December 31, 2000 153 185 15 353 12 365
December 31, 2001 206 248 13 467 11 478
December 31, 2002 147 130 2 279 5 284
Natural Gas (Billions of cubic feet)
- ------------------------------------
Proved developed reserves -
December 31, 2000 848 150 - 998 - 998
December 31, 2001 1,741 208 - 1,949 13 1,962
December 31, 2002 1,658 168 - 1,826 - 1,826
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 (Millions of United North Other Continuing Discontinued
barrels) States Sea International Operations Operations Total
- --------------------------------------- ------ ----- ------------- ---------- ------------ -----
Proved developed and undeveloped reserves -
Balance December 31, 1999 447 276 47 770 151 921
Revisions of previous estimates (7) 14 - 7 - 7
Purchases of reserves in place 4 97 - 101 - 101
Sales of reserves in place (8) - - (8) - (8)
Extensions, discoveries and other
additions 68 93 9 170 5 175
Production (55) (47) (4) (106) (2) (108)
--- --- --- ----- ---- -----
Balance December 31, 2000 449 433 52 934 154 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) (4) (105) (3) (108)
--- --- --- ----- ---- -----
Balance December 31, 2001 808 476 74 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) (3) (116) (2) (118)
--- --- --- ----- ---- -----
Balance December 31, 2002 704 285 35 1,024 9 1,033
=== === === ===== ==== =====
Continuing Operations
-----------------------------------------------------
Total
United North Other Continuing Discontinued
(Millions of equivalent barrels) States Sea International Operations Operations Total
- -------------------------------- ------ ----- ------------- ---------- ------------ -----
Proved developed reserves -
December 31, 2000 294 210 15 519 12 531
December 31, 2001 496 283 13 792 13 805
December 31, 2002 423 158 2 583 5 588
Proved undeveloped reserves -
December 31, 2000 155 223 37 415 142 557
December 31, 2001 312 193 61 566 138 704
December 31, 2002 281 127 33 441 4 445
32. 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
Measure of
Future Discounted
Future Future Future Future Net 10% Future
Cash Production Development Income Cash Annual Net Cash
(Millions of dollars) Inflows Costs Costs Taxes Flows Discount Flows
- --------------------- ------- ---------- ----------- ------ ------- -------- -----------
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
Other international 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
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
Other international 1,076 491 247 98 240 129 111
------- ------ ------ ------ ------- ------ ------
Total continuing
operations 21,550 7,393 2,953 3,260 7,944 3,282 4,662
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
======= ====== ====== ====== ======= ====== ======
2000
United States $14,825 $2,937 $1,008 $3,698 $ 7,182 $2,940 $4,242
North Sea 9,051 2,670 955 1,807 3,619 1,312 2,307
Other international 1,125 341 167 155 462 206 256
------- ------ ------ ------ ------- ------ ------
Total continuing
operations 25,001 5,948 2,130 5,660 11,263 4,458 6,805
Discontinued
operations 3,159 983 322 789 1,065 644 421
------- ------ ------ ------ ------- ------ ------
Total $28,160 $6,931 $2,452 $6,449 $12,328 $5,102 $7,226
======= ====== ====== ====== ======= ====== ======
The changes in the standardized measure of future net cash flows are presented
below for each of the past three years:
(Millions of dollars) 2002 2001 2000
- --------------------- ------- ------- -------
Net change in sales, transfer prices and production costs $ 6,870 $(5,879) $ 3,849
Changes in estimated future development costs (209) (639) (33)
Sales and transfers less production costs (1,795) (1,904) (2,358)
Purchases of reserves in place 243 1,117 1,065
Changes due to extensions, discoveries, etc. 347 1,232 1,477
Changes due to revisions in quantity estimates (1,433) 168 56
Changes due to sales of reserves in place (1,920) (87) (166)
Current-period development costs 743 1,237 568
Accretion of discount 701 1,093 601
Changes in income taxes (1,336) 1,689 (1,706)
Timing and other (137) (265) (138)
------- ------- -------
Net change 2,074 (2,238) 3,215
Total at beginning of year 4,988 7,226 4,011
------- ------- -------
Total at end of year $ 7,062 $ 4,988 $ 7,226
======= ======= =======
33. Quarterly Financial Information (Unaudited)
A summary of quarterly consolidated results for 2002 and 2001 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, convertible debt repaid,
and net loss sustained in a quarter.
Diluted Income (Loss)
per Common Share
--------------------------
Income Income
Operating (Loss) from Net (Loss) from Net
(Millions of dollars, Profit Continuing Income Continuing Income
except per-share amounts) Sales (Loss) Operations (Loss) Operations (Loss)
- ------------------------- ------ --------- ---------- ------ ---------- ------
2002 Quarter Ended -
March 31 $ 799 $ 111 $ (2) $ 6 $ (.02) $ .05
June 30 932 56 (178) (58) (1.77) (.58)
September 30 984 182 (87) (87) (.86) (.86)
December 31 985 (488) (344) (346) (3.43) (3.45)
------ ----- ----- ----- ------ ------
Total $3,700 $(139) $(611) $(485) $(6.09) $(4.84)
====== ===== ===== ===== ====== ======
2001 Quarter Ended -
March 31 $1,042 $ 417 $ 349 $ 335(1) $ 3.34 $ 3.21(1)
June 30 919 329 166 175 1.63 1.71
September 30 864 165 17 26 .18 .27
December 31 741 (28) (56) (50) (.57) (.50)
------ ----- ----- ----- ------ ------
Total $3,566 $ 883 $ 476 $ 486 $ 4.65 $ 4.74
====== ===== ===== ===== ====== ======
(1) Net income includes a provision of $20 million, net of taxes, for the
cumulative effect of change in accounting principle resulting from the
adoption of FAS 133, which equates to $0.19 per diluted common share.
Diluted income per common share before the accounting change was $3.40.
The company's common stock is listed for trading on the New York Stock Exchange
and at year-end 2002 was held by approximately 26,500 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
2002 2001 per Share
------------------------ ------------------------ ----------------
High Low High Low 2002 2001
------ ------ ------ ------ ---- ----
Quarter Ended -
March 31 $63.29 $50.72 $70.70 $62.80 $.45 $.45
June 30 63.58 52.80 74.10 62.52 .45 .45
September 30 53.90 39.10 66.96 46.94 .45 .45
December 31 47.51 38.02 59.60 49.00 .45 .45
Nine-Year Financial Summary
- --------------------------------------------------------------------------------
(Millions of dollars, except
per-share amounts) 2002 2001 2000 1999 1998 1997 1996 1995 1994
- ---------------------------- ------ ------ ------ ------ ------ ------ ------ ------ ------
Summary of Net Income (Loss)
- ----------------------------
Sales $3,700 $3,566 $4,063 $2,712 $2,233 $2,651 $2,779 $2,462 $ 2,389
------ ------ ------ ------ ------ ------ ------ ------ -------
Costs and operating expenses 4,047 2,843 2,651 2,314 2,626 2,059 2,162 2,343 2,203
Interest and debt expense 275 195 208 191 159 141 145 194 210
------ ------ ------ ------ ------ ------ ------ ------ -------
Total costs and expenses 4,322 3,038 2,859 2,505 2,785 2,200 2,307 2,537 2,413
------ ------ ------ ------ ------ ------ ------ ------ -------
(622) 528 1,204 207 (552) 451 472 (75) (24)
Other income (loss) (35) 224 50 36 40 81 109 146 15
Taxes on income 46 (276) (437) (105) 173 (183) (224) 41 (14)
------ ------ ------ ------ ------ ------ ------ ------ -------
Income (loss) from continuing
operations (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 - (20) - (4) - - - - (948)
------ ------ ------ ------ ------ ------ ------ ------ -------
Net income (loss) $ (485) $ 486 $ 842 $ 142 $ (68) $ 382 $ 414 $ 114 $ (936)
====== ====== ====== ====== ====== ====== ====== ====== =======
Effective Income Tax Rate (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 $(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 - (.19) - (.05) - - - - (10.82)
------ ------ ------ ------ ------ ------ ------ ------ -------
Net income (loss) $(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 $ 1.64 $ 1.55 $ 1.52
Stockholders' equity 23.01 28.83 25.01 17.19 15.58 17.88 14.59 12.47 12.33
Market high for the year 63.58 74.10 71.19 62.00 73.19 75.00 74.13 64.00 51.00
Market low for the year 38.02 46.94 39.88 28.50 36.19 55.50 55.75 44.00 40.00
Market price at year-end $44.30 $54.80 $66.94 $62.00 $38.25 $63.31 $72.00 $63.50 $ 46.25
Shares outstanding at year-end
(thousands) 100,384 100,185 94,485 86,483 86,367 86,794 87,032 89,613 90,143
Balance Sheet Information
- -------------------------
Working capital $ (320) $193 $ (34) $ 321 $ (173) $ - $ 161 $ (106) $ (254)
Property, plant and equipment - net 7,036 7,378 5,240 3,972 4,044 3,844 3,658 3,789 4,493
Total assets 9,909 11,076 7,666 5,899 5,451 5,339 5,194 5,006 5,918
Long-term debt 3,798 4,540 2,244 2,496 1,978 1,736 1,809 1,683 2,219
Total debt 3,904 4,574 2,425 2,525 2,250 1,766 1,849 1,938 2,704
Total debt less cash 3,814 4,483 2,281 2,258 2,129 1,574 1,719 1,831 2,612
Stockholders' equity 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 1,448 1,143 1,840 708 418 1,114 1,144 732 693
Capital expenditures 1,159 1,792 842 528 1,006 851 829 749 622
Dividends paid 181 173 166 138 86 85 83 79 79
Treasury stock purchased $ - $ - $ - $ - $ 25 $ 60 $ 195 $ 45 $ -
Ratios and Percentage
- ---------------------
Current ratio .8 1.2 1.0 1.4 .8 1.0 1.2 .9 .8
Average price/earnings ratio NM 12.8 6.6 27.6 NM 14.9 13.9 42.5 NM
Total debt less cash to total
capitalization 60% 59% 46% 60% 61% 50% 57% 62% 70%
Employees
- ---------
Total wages and benefits $ 412 $ 369 $ 333 $ 327 $ 359 $ 367 $ 367 $ 402 $ 422
Number of employees at year-end 4,470 4,638 4,426 3,653 4,400 4,792 4,827 5,176 6,724
Nine-Year Operating Summary
- --------------------------------------------------------------------------------
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 81.3 77.7 73.7 79.3 66.2 70.6 73.8 74.8 73.4
North Sea 102.8 101.9 117.7 102.9 87.4 83.3 86.5 91.9 88.7
Other international 7.2 9.3 9.0 9.5 13.3 15.7 14.9 16.4 26.4
------ ------ ------ ------ ------ ------ ------ ------ ------
Total 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 $21.56 $22.05 $27.50 $16.90 $12.78 $18.45 $19.56 $15.78 $14.25
North Sea 22.41 23.23 27.92 17.88 12.93 18.93 19.60 16.56 15.33
Other international 22.36 20.28 26.05 14.22 9.86 15.44 15.71 14.91 14.58
Average $22.04 $22.60 $27.69 $17.30 $12.63 $18.40 $19.26 $16.10 $14.80
Natural gas sales (MMcf per day) 760 596 531 580 584 685 781 809 872
Average price of natural gas sold
(per Mcf) $ 2.95 $ 3.83 $ 3.87 $ 2.38 $ 2.13 $ 2.44 $ 2.11 $ 1.63 $ 1.82
Net exploratory wells drilled (1)-
Productive 4.78 2.39 1.25 1.70 4.40 7.65 6.91 4.71 11.61
Dry 17.17 11.43 10.54 3.75 14.42 7.42 5.52 11.16 13.47
------ ------ ------ ------ ------ ------ ------ ------ ------
Total 21.95 13.82 11.79 5.45 18.82 15.07 12.43 15.87 25.08
====== ====== ====== ====== ====== ====== ====== ====== ======
Net development wells drilled (1)-
Productive 196.32 128.62 47.79 46.23 62.30 95.78 143.33 135.86 69.27
Dry 1.37 6.60 5.44 5.89 9.00 7.00 13.04 11.95 9.63
------ ------ ------ ------ ------ ------ ------ ------ ------
Total 197.69 135.22 53.23 52.12 71.30 102.78 156.37 147.81 78.90
====== ====== ====== ====== ====== ====== ====== ====== ======
Undeveloped net acreage (thousands)(1)-
United States 2,399 2,382 2,020 1,560 1,487 1,353 1,099 1,280 1,415
North Sea 871 932 923 861 908 523 560 570 629
Other international 42,560 51,367 26,078 19,039 14,716 14,630 4,556 4,031 7,494
------ ------ ------ ------ ------ ------ ----- ----- -----
Total 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 1,266 1,192 729 796 810 830 871 1,190 1,270
North Sea 109 149 115 105 115 70 79 58 68
Other international 18 656 656 785 612 201 198 207 1,015
------ ------ ------ ------ ------ ------ ------ ------ ------
Total 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) 1,033 1,509 1,088 920 901 892 849 864 1,059
Chemicals
- ----------
Titanium dioxide pigment
production (thousands of tonnes) 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.
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 for
2003 made in connection with its Annual Stockholders' Meeting to be
held on May 13, 2003.
(b) Identification of executive officers -
The information required under this section is set forth in the
caption "Executive Officers of the Registrant" on pages 21 and 22 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 for 2003 made in connection with its
Annual Stockholders' Meeting to be held on May 13, 2003.
Item 11. Executive Compensation
For information required under this section, reference is made to the "Executive
Compensation and Other Information" section of the company's proxy statement for
2003 made in connection with its Annual Stockholders' Meeting to be held on May
13, 2003.
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, 2002, is included in the
following table:
Number of shares of Number of shares
common stock to be Weighted-average remaining available for
issued upon exercise exercise price of future issuance under
of outstanding options, outstanding options, equity compensation
warrants and rights warrants and rights plans (1)
----------------------- -------------------- -----------------------
Equity compensation plans approved
by security holders 4,493,008 $59.48 5,932,663
Equity compensation plans not
approved by security holders 913,416 58.26 175,950
--------- ---------
Total 5,406,424 59.27 6,108,613
========= =========
(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 is attached
as exhibit 10.19 to this Form 10-K.
For information required under Item 403 of Regulation S-K, reference is made to
the "Security Ownership" portion of the "Director Information" section of the
company's proxy statement for 2003 made in connection with its Annual
Stockholders' Meeting to be held on May 13, 2003.
Item 13. Certain Relationships and Related Transactions
For information required under this section, reference is made to the "Director
Information" section of the company's proxy statement for 2003 made in
connection with its Annual Stockholders' Meeting to be held on May 13, 2003.
Item 14. Controls and Procedures
Within the 90 days prior to the date of 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-14. Based upon that
evaluation, the Chief Executive Officer and Chief Financial Officer concluded
that the company's disclosure controls and procedures are effective in timely
alerting them to material information relating to the company (including its
consolidated subsidiaries) required to be included in the company's periodic
Securities and Exchange Commission filings. There were no significant changes in
our internal controls or in other factors that could significantly affect these
controls subsequent to the date of their evaluation.
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 Bylaws 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 Revolving Credit Agreement
amended and restated as of April 25, 2002, between
Kerr-McGee China Petroleum Ltd., as borrower, and Kerr-McGee
Corporation, as guarantor, and several banks providing for
revolving credit of up to $100 million through March 3,
2003; the $100 million, 8% Note Agreement entered into by
Oryx Energy Company (Oryx) dated as of October 20, 1995, and
due October 15, 2003; 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 December 10, 2002, 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.
10.2* 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.
10.3* Benefits Restoration Plan as amended and restated effective
September 13, 1989, filed as Exhibit 10(6) to the report on
Form 10-K for the year ended December 31, 1992, and
incorporated herein by reference.
10.4* Kerr-McGee Corporation Executive Deferred Compensation Plan
as amended and restated effective January 1, 2003.
10.5* 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.
10.6* 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.
10.7* 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.
10.8* The Kerr-McGee Corporation Annual Incentive Compensation
Plan effective January 1, 1998, filed as Exhibit 10.3 on
Form 10-Q for the quarter ended March 31, 1998, and
incorporated herein by reference.
10.9* 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.
10.10* 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.
10.11* 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.
10.12* 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.
10.13* 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.
10.14* 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.
10.15* 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.
10.16* 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.
10.17* 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.
10.18* 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.
10.19* Kerr-McGee Corporation Performance Share Plan effective
January 1, 1998.
12 Computation of ratio of earnings to fixed charges.
21 Subsidiaries of the Registrant.
23 Consent of Ernst & Young LLP.
24 Powers of Attorney.
99.1 Certification of Chief Executive Officer Regarding Periodic
Report Containing Financial Statements.
99.2 Certification of Chief Financial Officer Regarding Periodic
Report Containing Financial Statements.
*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, 2002:
o Current Report dated October 25, 2002, announcing a conference
call to discuss third-quarter 2002 financial and operating results
and expectations for the future.
o Current Report dated October 30, 2002, announcing a conference
call to discuss third-quarter 2002 financial and operating results
and expectations for the future.
o Current Report dated October 30, 2002, reporting that the company
began adding to its existing oil and gas hedging positions and
expected to continue its oil and gas hedging program in 2003.
o Current Report dated November 20, 2002, announcing a conference
call to discuss interim fourth-quarter 2002 operating and
financial activities and expectations for the future.
o Current Report dated December 13, 2002, announcing a conference
call to discuss interim fourth-quarter 2002 operating and
financial activities and expectations for the future.
o Current Report dated December 19, 2002, announcing a conference
call to discuss fourth-quarter 2002 financial and operating
results and expectations for the future.
o Current Report dated December 30, 2002, announcing that the
company would take a special after-tax noncash charge of
approximately $385 million during the fourth quarter for the
estimated costs related to impairments for the Leadon field and
various other fields in the United Kingdom and the Gulf of Mexico.
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, 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
==== === === === ====
Year Ended December 31, 2000
- ----------------------------
Deducted from asset accounts
Allowance for doubtful notes
and accounts receivable $ 17 $ 2 $ 2 $ 1 $ 20
Warehouse inventory obsolescence 4 2 - 1 5
---- --- --- --- ----
Total $ 21 $ 4 $ 2 $ 2 $ 25
==== === === === ====
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 26, 2003 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 26, 2003 By: Martin C. Jischke*
- -------------- ----------------------------------
Date Martin C. Jischke, Director
By: William C. Morris*
----------------------------------
William C. Morris, Director
By: Leroy C. Richie*
----------------------------------
Leroy C. Richie, Director
By: Matthew R. Simmons*
----------------------------------
Matthew R. Simmons, Director
By: Nicholas J. Sutton*
----------------------------------
Nicholas J. Sutton, 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
CERTIFICATION
I, Luke R. Corbett, certify that:
1. I have reviewed this annual report on Form 10-K of Kerr-McGee
Corporation;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the company as of, and for, the periods presented in
this annual report;
4. The company's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the company and
we have:
i. designed such disclosure controls and procedures to ensure
that material information relating to the company, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which
this annual report is being prepared;
ii. evaluated the effectiveness of the company's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
iii. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The company's other certifying officer and I have disclosed, based
on our most recent evaluation, to the company's auditors and the
audit committee of the company's board of directors (or persons
fulfilling the equivalent function):
i. all significant deficiencies in the design or operation of
internal controls which could adversely affect the company's
ability to record, process, summarize and report financial
data and have identified for the company's auditors any
material weaknesses in internal controls; and
ii. any fraud, whether or not material, that involves management
or other employees who have a significant role in the
company's internal controls; and
6. The company's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal
controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
/s/ Luke R. Corbett
________________________________
Luke R. Corbett
Chief Executive Officer
March 26, 2003
CERTIFICATION
I, Robert M. Wohleber, certify that:
1. I have reviewed this annual report on Form 10-K of Kerr-McGee
Corporation;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the company as of, and for, the periods presented in
this annual report;
4. The company's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the company and
we have:
i. designed such disclosure controls and procedures to ensure
that material information relating to the company, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which
this annual report is being prepared;
ii. evaluated the effectiveness of the company's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
iii. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The company's other certifying officer and I have disclosed, based
on our most recent evaluation, to the company's auditors and the
audit committee of the company's board of directors (or persons
fulfilling the equivalent function):
i. all significant deficiencies in the design or operation of
internal controls which could adversely affect the company's
ability to record, process, summarize and report financial
data and have identified for the company's auditors any
material weaknesses in internal controls; and
ii. any fraud, whether or not material, that involves management
or other employees who have a significant role in the
company's internal controls; and
6. The company's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal
controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
/s/ Robert M. Wohleber
________________________________
Robert M. Wohleber
Chief Financial Officer
March 26, 2003