2002
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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 000-49987
CONOCOPHILLIPS
(Exact name of registrant as specified in its charter)
DELAWARE 01-0562944
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
600 NORTH DAIRY ASHFORD
HOUSTON, TX 77079
(Address of principal executive offices)
Registrant's telephone number, including area code: 281-293-1000
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Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, $.01 Par Value New York Stock Exchange
Preferred Share Purchase Rights Expiring June 30, 2012 New York Stock Exchange
6 3/8% Notes due 2009 New York Stock Exchange
6.65% Notes due March 1, 2003 New York Stock Exchange
6.65% Debentures due July 15, 2018 New York Stock Exchange
7% Debentures due 2029 New York Stock Exchange
7.125% Debentures due March 15, 2028 New York Stock Exchange
7.20% Notes due November 1, 2023 New York Stock Exchange
7.92% Notes due April 15, 2023 New York Stock Exchange
8.5% Notes due 2005 New York Stock Exchange
8.75% Notes due 2010 New York Stock Exchange
9 3/8% Notes due 2011 New York Stock Exchange
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 (or for such shorter period that the registrant was
required to file such reports), 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 the 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 | |
Excluding shares held by affiliates, the registrant had 672,131,287 shares of
Common Stock, $.01 Par Value, outstanding at February 28, 2003. The aggregate
market value of common stock held by non-affiliates of the registrant was
$34,077,056,251 as of February 28, 2003. The registrant, solely for the purpose
of this required presentation, has deemed its Board of Directors and the
Compensation and Benefits Trust to be affiliates, and deducted their
stockholdings of 6,156,952 and 26,785,094 shares, respectively, in determining
the aggregate market value.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to
be held on May 6, 2003 (Part III)
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TABLE OF CONTENTS
PART I
Item Page
---- ----
1 and 2. Business and Properties ............................................. 1
Corporate Structure and Current Developments .................... 1
Segment and Geographic Information .............................. 2
Exploration and Production (E&P) ............................ 2
Midstream ................................................... 17
Refining and Marketing (R&M) ................................ 18
Chemicals ................................................... 25
Emerging Businesses ......................................... 27
Competition ..................................................... 28
General ......................................................... 29
3. Legal Proceedings ................................................... 29
4. Submission of Matters to a Vote of Security Holders ................. 32
Executive Officers of the Registrant ................................ 32
PART II
5. Market for Registrant's Common Equity and Related Stockholder Matters 34
6. Selected Financial Data ............................................. 35
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations ........................................... 36
7a. Quantitative and Qualitative Disclosures About Market Risk .......... 78
8. Financial Statements and Supplementary Data ......................... 82
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure ............................................ 174
PART III
10. Directors and Executive Officers of the Registrant .................. 175
11. Executive Compensation .............................................. 175
12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters ................................. 175
13. Certain Relationships and Related Transactions ...................... 175
14. Controls and Procedures ............................................. 176
PART IV
15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K .... 176
PART I
Unless otherwise indicated, "the company" and "ConocoPhillips" are used in this
report to refer to the businesses of ConocoPhillips and its consolidated
subsidiaries. "Conoco" and "Phillips" are used in this report to refer to the
individual companies prior to the merger date of August 30, 2002. Items 1 and 2,
Business and Properties, contain forward-looking statements including, without
limitation, statements relating to the company's plans, strategies, objectives,
expectations, intentions, and resources, that are made pursuant to the "safe
harbor" provisions of the Private Securities Litigation Reform Act of 1995. The
words "forecasts," "intends," "believes," "expects," "plans," "scheduled,"
"anticipates," "estimates," and similar expressions identify forward-looking
statements. The company does not undertake to update, revise or correct any of
the forward-looking information. Readers are cautioned that such forward-looking
statements should be read in conjunction with the company's disclosures under
the heading: "CAUTIONARY STATEMENT FOR THE PURPOSES OF THE `SAFE HARBOR'
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995," beginning
on page 76.
ConocoPhillips files annual, quarterly and current reports, proxy statements and
other information with the U.S. Securities and Exchange Commission (SEC). These
filings are available free of charge through the company's internet website at
www.conocophillips.com as soon as reasonably practicable after the company
electronically files such material with, or furnishes it to, the SEC.
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE AND CURRENT DEVELOPMENTS
ConocoPhillips is a major, integrated, global energy company. ConocoPhillips was
incorporated in the state of Delaware on November 16, 2001, in connection with,
and in anticipation of, the merger between Conoco Inc. (Conoco) and Phillips
Petroleum Company (Phillips). The merger between Conoco and Phillips (the
merger) was consummated on August 30, 2002, at which time Conoco and Phillips
combined their businesses by merging with separate acquisition subsidiaries of
ConocoPhillips. As a result of the merger, Conoco and Phillips each became
wholly owned subsidiaries of ConocoPhillips. For accounting purposes, Phillips
was designated as the acquirer of Conoco and ConocoPhillips was treated as the
successor of Phillips. Accordingly, Phillips' operations and results are
presented in this Form 10-K for all periods prior to the close of the merger.
From the merger date forward, the operations and results of ConocoPhillips
reflect the combined operations of the two companies. Subsequent to the merger,
Conoco was renamed ConocoPhillips Holding Company, and Phillips was renamed
ConocoPhillips Company, but for ease of reference, those companies will be
referred to respectively in this document as Conoco and Phillips.
ConocoPhillips' business is organized into five operating segments:
1) Exploration and Production (E&P)--This segment explores for and
produces crude oil, natural gas, and natural gas liquids worldwide,
and mines oil sands to extract bitumen and upgrade it into synthetic
crude oil.
2) Midstream--This segment gathers and processes natural gas produced
by ConocoPhillips and others, and fractionates and markets natural
gas liquids, primarily in the United States, Canada and Trinidad.
The Midstream segment includes ConocoPhillips' 30.3 percent equity
investment in Duke Energy Field Services, LLC, a joint venture with
Duke Energy.
1
3) Refining and Marketing (R&M)--This segment refines, markets and
transports crude oil and petroleum products, primarily in the United
States, Europe and Asia.
4) Chemicals--This segment manufactures and markets petrochemicals and
plastics on a worldwide basis. The Chemicals segment consists
primarily of ConocoPhillips' 50 percent equity investment in Chevron
Phillips Chemical Company LLC, a joint venture with ChevronTexaco
Corporation.
5) Emerging Businesses--This segment encompasses the development of new
businesses beyond the company's traditional operations. Emerging
Businesses includes new technologies related to carbon fibers,
natural gas conversion into clean fuels and related products
(gas-to-liquids), fuels technology, and power generation.
At December 31, 2002, ConocoPhillips employed approximately 57,000 people in
over 40 countries.
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment information and geographic information, see Note
26--Segment Disclosures and Related Information in the Notes to Consolidated
Financial Statements, which is incorporated herein by reference.
EXPLORATION AND PRODUCTION (E&P)
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This segment explores for and produces crude oil, natural gas, and natural gas
liquids on a worldwide basis. It also mines deposits of oil sands in Canada to
extract the bitumen and upgrade it into a synthetic crude oil. At December 31,
2002, ConocoPhillips' E&P operations were producing in the United States; the
Norwegian and U.K. sectors of the North Sea; Canada; Nigeria; Venezuela; the
Timor Sea; offshore Australia and China; Indonesia; the United Arab Emirates;
Vietnam; Russia; and Ecuador.
The information listed below appears in the supplemental oil and gas operations
disclosures on pages 146 through 163 and is incorporated herein by reference.
o Proved worldwide crude oil, natural gas and natural gas liquids
reserves;
o Net production of crude oil, natural gas and natural gas liquids;
o Average sales prices of crude oil, natural gas and natural gas
liquids;
o Average production costs per barrel of oil equivalent;
o Net wells completed, wells in progress and productive wells; and
o Developed and undeveloped acreage.
In 2002, ConocoPhillips' worldwide crude oil production, including its share of
equity affiliates' production, averaged 682,000 barrels per day, a 21 percent
increase from 563,000 barrels per day in 2001.
2
During the year, 371,000 barrels per day of crude oil was produced in the United
States, down slightly from 373,000 barrels per day in 2001. The decrease in U.S.
production was due to lower production in Alaska, reflecting normal field
declines, as well as operating interruptions during the year, partially offset
by increased production volumes following the merger. Foreign crude oil
production volumes increased 64 percent in 2002, primarily as a result of the
merger.
E&P's worldwide production of natural gas liquids averaged 46,000 barrels per
day in 2002, compared with 35,000 barrels per day in 2001. U.S. production
accounted for 32,000 barrels per day in 2002, compared with 26,000 barrels per
day in 2001. The increases were primarily the result of the merger.
The company's worldwide production of natural gas averaged 2,047 million cubic
feet per day in 2002, compared with 1,335 million cubic feet per day in 2001.
U.S. natural gas production increased 20 percent in 2002, while foreign natural
gas production increased 126 percent. The increases were primarily due to the
merger.
ConocoPhillips' worldwide annual average crude oil sales price increased 1
percent in 2002, to $24.07 per barrel. E&P's annual average worldwide natural
gas sales price decreased 14 percent from 2001, to $2.77 per thousand cubic
feet.
The company's finding and development costs in 2002 were $5.57 per barrel of oil
equivalent, compared with $5.97 in 2001. Over the last five years,
ConocoPhillips' finding and development costs averaged $4.31 per barrel of oil
equivalent. Finding and development costs per barrel of oil equivalent is
calculated by dividing the net reserve change for the period (excluding
production and sales) into the costs incurred for the period, as reported in the
"Costs Incurred" disclosure required by Statement of Financial Accounting
Standards No. 69, "Disclosures about Oil and Gas Producing Activities."
At December 31, 2002, ConocoPhillips, including its share of equity affiliates,
held a combined 101.9 million net developed and undeveloped acres, compared with
25.8 million net acres at year-end 2001. The increase in acreage was primarily
the result of the merger. At year-end 2002, the company held acreage in 29
countries (counting the Timor Gap Zone of Cooperation between Australia and East
Timor as a single country for this purpose).
E&P--U.S. OPERATIONS
In 2002, U.S. E&P operations contributed 55 percent of ConocoPhillips' worldwide
liquids production and 54 percent of its worldwide natural gas production. The
company's U.S. operations are managed in two divisions: Alaska and the Lower 48
States.
ALASKA
ConocoPhillips is a major producer of crude oil on Alaska's North Slope, and
produces natural gas in the Cook Inlet. A brief summary of the major Alaskan
producing fields, transportation infrastructure, and exploration activities
follows.
Greater Prudhoe Area
The Greater Prudhoe Area is comprised of the Prudhoe Bay field and satellites,
as well as the Greater Point McIntyre Area fields. In 2002, an agreement was
reached among all owners to align ownership across all fields within the Greater
Prudhoe Area. ConocoPhillips now holds a 36.1 percent interest in all fields
within the Greater Prudhoe Area, all of which are operated by BP p.l.c. (BP).
3
The Prudhoe Bay field is the largest oil field on Alaska's North Slope. It is
the site of a large waterflood and enhanced oil recovery project, as well as a
gas processing plant that processes and re-injects more than 8 billion cubic
feet of natural gas daily. ConocoPhillips' net crude oil production from the
Prudhoe Bay field averaged 130,800 barrels per day in 2002, compared with
144,900 barrels per day in 2001, while natural gas liquids production averaged
24,100 barrels per day in 2002, compared with 25,000 barrels per day in 2001.
Prudhoe Bay satellite fields Aurora, Borealis, Polaris, and Midnight Sun
produced 12,700 net barrels per day of crude oil in 2002 compared with 3,400 net
barrels per day in 2001. The newly developed Borealis satellite field
contributed the biggest share in 2002, producing 7,200 net barrels per day
compared with 1,100 net barrels per day in 2001. All Prudhoe Bay satellite
fields are produced through Prudhoe Bay production facilities.
The Greater Point McIntyre Area (GPMA) is made up of the Point McIntyre, Niakuk,
Lisburne, West Beach, and North Prudhoe Bay State fields. All fields within the
GPMA are produced through the Lisburne Production Center. Net crude oil
production for GPMA averaged 19,800 barrels per day in 2002, compared with
26,000 barrels per day in 2001. The bulk of this production came from the Point
McIntyre field where an enhanced oil recovery project began in 2000.
Greater Kuparuk Area
ConocoPhillips operates the Greater Kuparuk Area, which is comprised of the
Kuparuk field and four satellite fields: Tarn, Tabasco, Meltwater and West Sak.
ConocoPhillips holds a 55.2 percent interest in the Kuparuk field, located about
40 miles west of Prudhoe Bay. Field installations include three central
production facilities that separate oil, gas and water. The gas is either used
for fuel or compressed for reinjection. ConocoPhillips' net crude oil production
from Kuparuk averaged 79,000 barrels per day in 2002, compared with 91,400
barrels per day in 2001. The decrease was due to normal field declines.
The Greater Kuparuk Area's satellite fields of Tarn, Tabasco and Meltwater
produced 21,300 net barrels per day of crude oil in 2002, compared with 12,600
net barrels per day in 2001. The increase was due to a full year's production
from Meltwater, which came online in late 2001. ConocoPhillips holds a 55.4
percent interest in these satellite fields.
In late 2002, ConocoPhillips announced the startup of Kuparuk field Drill Site
3S (Palm). This drill site will develop the oil accumulation discovered by the
Palm exploration wells drilled during the winter 2001 season. The Palm oil
accumulation effectively extends the Kuparuk field on Alaska's North Slope
approximately three miles to the northwest. The drill site produced crude oil at
a 6,000 net-barrel-per-day rate following startup and is expected to reach peak
production in 2004 following additional development drilling. Production from
Palm is processed through existing Kuparuk field facilities.
The Greater Kuparuk Area also includes the West Sak heavy-oil field.
ConocoPhillips is studying and applying new ways to develop this heavy-oil
field. In 2002, West Sak produced 3,300 net barrels of heavy oil per day,
compared with 2,700 net barrels per day in 2001. ConocoPhillips holds a 55.4
percent interest in this field.
Alpine Field
The Alpine field, located west of the Kuparuk field, began production in
November 2000. In 2002, the field produced at a net rate of 63,400 barrels of
oil per day, compared with 57,800 barrels per day in 2001. ConocoPhillips is the
operator and holds a 78 percent interest in Alpine.
4
In January 2003, ConocoPhillips and the U.S. Department of Interior Bureau of
Land Management signed a Memorandum of Understanding that provides for
completion of an Environmental Impact Statement (EIS) for five prospective
satellites, Fiord, Nanuq, Lookout, Spark, and Alpine West, as well as future
potential developments in the northeast corner of the National Petroleum
Reserve-Alaska (NPR-A) and near the Alpine oil field. A final decision to move
forward on these projects will be made after the EIS is completed and the
appropriate permits have been granted.
Cook Inlet
ConocoPhillips' assets in Alaska include the North Cook Inlet field, the Beluga
natural gas field, and the Kenai liquefied natural gas facility.
ConocoPhillips has a 100 percent interest in the North Cook Inlet field. Net
production in 2002 averaged 125 million cubic feet per day. All of the
production from the North Cook Inlet field is used to supply ConocoPhillips'
share of gas to the Kenai liquefied natural gas plant.
ConocoPhillips' interest in the Beluga River field is 33 percent. Net production
averaged 41 million cubic feet per day in 2002. Gas from the Beluga River field
is sold to local utilities and industrial consumers.
ConocoPhillips owns a 70 percent interest in the Kenai liquefied natural gas
plant, which supplies liquefied natural gas to two utility companies in Japan.
Utilizing two leased tankers, the company transports the liquefied natural gas
to Japan, where it is reconverted to dry gas at the receiving terminal.
ConocoPhillips sold 44.4 billion cubic feet of liquefied natural gas to Japan in
2002, compared with 46.1 billion cubic feet in 2001.
Exploration
ConocoPhillips holds more than one million net exploration acres in Alaska.
ConocoPhillips drilled or participated in eight exploratory wells during 2002,
on locations near Kuparuk, Prudhoe Bay and Alpine, as well as in the NPR-A and
the Cook Inlet. Of the eight wells, two are moving forward with development
plans and one is pending further appraisal. In May 2001, ConocoPhillips
announced the first discoveries in the NPR-A since the area was reopened to
exploration in 1999. ConocoPhillips plans to drill or participate in four
exploration wells in Alaska during 2003.
Transportation
ConocoPhillips transports the petroleum liquids it produces on the North Slope
to market through the Trans-Alaska Pipeline System (TAPS), an 800-mile pipeline,
marine terminal and spill response and escort vessel system that ties the North
Slope of Alaska to the port of Valdez in south-central Alaska. While ownership
interest in TAPS was 26.7 percent in 2002, regulatory approval was received in
early 2003 to purchase an additional 1.5 percent interest from Amerada Hess,
thereby increasing ConocoPhillips ownership in TAPS to 28.2 percent. The
purchase was effective January 24, 2003.
In the second quarter of 2001, ConocoPhillips and the five other owners of TAPS
completed and filed state and federal applications for renewal of the pipeline's
right-of-way permit through 2034. The State of Alaska approved the 30-year
right-of-way renewal in November 2002 and U.S. federal approval was received in
January 2003.
TAPS was shut down in early November 2002 following a major earthquake in
Alaska. There were no associated oil leaks, spills or pipeline ruptures. TAPS
remained shut down for approximately three days and was restarted after all
necessary inspections, leak testing and temporary repairs were made.
5
ConocoPhillips' ownership of stock in the Alyeska Pipeline Service Company
increased from 26.7 percent in 2002 to 28.2 percent as a result of the January
2003 purchase of an additional interest from Amerada Hess. Alyeska constructed
and operates the pipeline system on behalf of the TAPS owners. ConocoPhillips
also has ownership interests in the Alpine, Kuparuk and Oliktok pipelines on the
North Slope. In 2002, ConocoPhillips sold its 20 percent ownership interest in
the Cook Inlet Pipeline Company.
ConocoPhillips, BP and ExxonMobil agreed in late 2000 to jointly evaluate a gas
pipeline project to deliver natural gas from Alaska's North Slope to the Lower
48. The three co-owners shared equally in the costs and governance of the
program. ConocoPhillips does not believe the project provides the desired return
on investment in the current economic environment, given the significant size
and risk associated with the project. However, ConocoPhillips continues to
search for a solution that will allow this energy resource to be produced.
ConocoPhillips' wholly owned subsidiary, Polar Tankers Inc., manages the marine
transportation of the company's Alaska North Slope production. Polar Tankers is
based in Long Beach, California, and operates five ships in the Alaskan trade,
chartering additional third party operated vessels as necessary. In 2001, Polar
Tankers brought the Polar Endeavour into service, and the Polar Resolution was
brought into service in 2002. After the Polar Endeavour was placed in service,
ConocoPhillips entered into a transaction to sell and subsequently lease back
the vessel for 10 years. These 125,000-deadweight-ton, double-hulled crude oil
tankers are the first two of five Endeavour Class tankers that ConocoPhillips
plans to add to its Alaskan-trade fleet over a five-year period. The third
tanker, the Polar Discovery, is scheduled to enter the fleet in 2003.
LOWER 48 STATES
ConocoPhillips' operations in the Lower 48 States are principally located in the
following areas:
o Offshore: Gulf of Mexico;
o Onshore: Various trends in Texas, New Mexico, Oklahoma, Louisiana,
Utah, Colorado, and Wyoming
Gulf of Mexico
ConocoPhillips' current portfolio of producing properties in the Gulf of Mexico
includes three fields operated by ConocoPhillips and 24 operated by other
companies. At December 31, 2002, ConocoPhillips had 14 leases in production or
under development in the deepwater Gulf of Mexico.
ConocoPhillips held interests in 391 lease blocks in the deepwater Gulf of
Mexico as of December 31, 2002. In 2003, ConocoPhillips expects to participate
in four exploration wells in the deepwater Gulf of Mexico.
ConocoPhillips' deepwater Gulf of Mexico drilling program utilizes the Deepwater
Pathfinder, a drillship that is owned by a joint venture between Transocean
Sedco Forex Inc. and ConocoPhillips. The vessel, which went into service in
January 1999, is capable of drilling in water depths of up to 10,000 feet.
ConocoPhillips holds a 16 percent interest in the Ursa field, which is operated
by Shell. The Ursa tension-leg platform was installed in late 1998 in
approximately 3,900 feet of water, with first production occurring in March
1999. As Ursa was owned by Conoco before the merger, only the production from
August 30 through December 31, 2002, is included in ConocoPhillips' 2002
statistics and financial results. Production during this period averaged a net
12,500 barrels per day of liquids and 16 million cubic feet per day of gas.
6
The Princess field, which is adjacent to the Ursa field, was discovered in 2000.
Because of Princess' proximity to Ursa, petroleum liquids and natural gas
produced from Princess can be processed and transported via the Ursa
infrastructure already in place. ConocoPhillips owns a 16 percent interest in
Princess. First production from Princess began in late 2002 with the completion
of a well on the Ursa platform.
ConocoPhillips operates and holds a 75 percent interest in the Garden Banks 783
and 784 leases which contain the Magnolia field. First production from Magnolia
is scheduled for late 2004.
ConocoPhillips owns a non-operated interest of 18.2 percent in the K2 discovery.
K2 was discovered in 1999 and appraisal continued in 2002. Further appraisal and
preliminary development operations are scheduled for 2003.
Onshore
ConocoPhillips is a large natural gas producer in three major gas producing
trends: the Lobo trend in south Texas, the San Juan Basin of New Mexico, and the
Guymon-Hugoton trend in the panhandles of Texas and Oklahoma. At December 31,
2002, the company held over 2.2 million net acres of oil and gas leases in these
trends. Combined production from the date of the merger through year-end from
these three areas averaged a net 948 million cubic feet per day of natural gas.
E&P--THE NORTH SEA
In 2002, E&P operations in the North Sea contributed 28 percent of
ConocoPhillips' worldwide liquids production and 29 percent of its worldwide
natural gas production. The company's North Sea assets are principally located
in the Norwegian and U.K. sectors.
NORWAY
The Ekofisk Area is located approximately 200 miles offshore Norway in the
center of the North Sea. The Ekofisk Area is comprised of four producing fields:
Ekofisk, Eldfisk, Embla and Tor. Ekofisk serves as a hub for petroleum
operations in the area, with surrounding developments utilizing the
infrastructure. Net production in 2002 from the Ekofisk Area was 127,000 barrels
of liquids per day and 133 million cubic feet of natural gas per day.
ConocoPhillips is the operator and has a 35.1 percent interest in Ekofisk. The
production license for the Ekofisk Area runs until 2028.
ConocoPhillips also has ownership interests in several other producing fields in
the Norwegian North Sea, the more significant of which include a 24.3 percent
interest in the Heidrun field, a 10.3 percent interest in the Statfjord field,
and a 1.6 percent interest in the Troll field.
Production from these, and other fields in the Norwegian sector of the North Sea
acquired in the merger, averaged a net 105,000 barrels of liquids per day and
112 million cubic feet of natural gas per day for the last four months of 2002.
UNITED KINGDOM
ConocoPhillips is the largest equity owner in and the joint operator of the
Britannia natural gas/condensate field. ConocoPhillips holds a 58.7 percent
interest in Britannia. First production from Britannia occurred in August 1998.
ConocoPhillips' proved reserves in Britannia included approximately 1.1 trillion
cubic feet of natural gas and 34 million barrels of petroleum liquids at
December 31, 2002. For the last four months of 2002, production from Britannia
averaged a net 13,000 barrels per day of liquids and 336 million cubic feet per
day of natural gas.
7
ConocoPhillips operates and holds a 36.5 percent interest in the Judy/Joanne
fields which together comprise J-Block. Additionally, the Jade field began
production in the first quarter of 2002 from a wellhead platform and pipeline
tied to the J-Block facilities. ConocoPhillips is the operator and holds a 32.5
percent interest in Jade. Together, these fields produced a net 14,000 barrels
of liquids per day and 96 million cubic feet of natural gas per day in 2002.
ConocoPhillips continues to supply gas from J-Block to Enron Capital and Trade
Resources Limited (Enron Capital), which was placed in Administration in the
United Kingdom on November 29, 2001. ConocoPhillips has been paid all amounts
currently due and payable by Enron Capital, including outstanding amounts due
for the period prior to the appointment of the Administrator. The company
believes that Enron Capital will continue to pay the amounts due for gas
supplied by ConocoPhillips in accordance with the terms of the gas sales
agreement. ConocoPhillips does not currently expect that it will have to curtail
sales of gas under the gas sales agreement or shut in production as a result of
the Administration of Enron Capital. However, in the event Enron Capital is no
longer under Administration, there may be additional risk of production
constraints.
ConocoPhillips has various ownership interests in 15 producing gas fields in the
southern North Sea that were acquired in the merger. These fields mostly feed
into the ConocoPhillips-operated Theddlethorpe gas processing facility through
three ConocoPhillips-operated pipeline systems. Production for the last four
months of 2002 averaged a net 357 million cubic feet per day of natural gas. The
investment in the Viscount development was charged to impairment expense in the
fourth quarter of 2002 due to disappointing development drilling results.
In September 2002, ConocoPhillips began production from the Hawksley field in
the southern sector of the U.K. North Sea. The Hawksley discovery well, 44/17
a-6y, was completed in July 2002 in one of five natural gas reservoirs currently
being developed by ConocoPhillips as a single, unitized project. The other
reservoirs are McAdam, Murdoch K., Boulton, and Watt. Collectively, they are
known as CMS3 due to their utilization of the production and transportation
facilities of the ConocoPhillips-operated Caister Murdoch System (CMS).
ConocoPhillips is the operator of CMS3 and holds a 59.5 percent interest.
ConocoPhillips has a 24 percent interest in the Clair field development. Net
proved reserves are 24 million barrels of petroleum liquids. The Clair
development is comprised of a conventional steel jacket structure with minimum
manned facilities topside. First production from Clair is targeted for 2004.
ConocoPhillips is also assessing the development of the Callanish and Brodgar
fields. These new satellite development projects would be tied back to the
Britannia facility. Appraisal wells for both discoveries were drilled in 2000.
ConocoPhillips has a 75 percent interest in the Brodgar field and an 83.5
percent interest in the Callanish field.
ConocoPhillips also has ownership interests in several other producing fields in
the U.K. North Sea, including a 23.4 percent interest in the Alba field, a 40
percent interest in the MacCulloch field, and an 11.5 percent interest in the
Armada field. Production from these and other fields in the U.K. sector of the
North Sea averaged a net 50,000 barrels of liquids per day and 85 million cubic
feet of natural gas per day for the last four months of 2002.
The Interconnector pipeline, which connects the United Kingdom and Belgium,
facilitates the marketing throughout Europe of the natural gas ConocoPhillips
produces in the United Kingdom. ConocoPhillips' 10 percent equity share of the
Interconnector pipeline allows the company to ship approximately 200 million
cubic feet of natural gas per day to markets in continental Europe.
ConocoPhillips has multi-year contracts to supply natural gas to Gasunie in the
Netherlands and Wingas in Germany. Because the Interconnector pipeline provides
the flexibility to flow in either direction, ConocoPhillips is able to take
8
advantage of the long-term and short-term market conditions in both the United
Kingdom and continental Europe.
OTHER AREAS
ConocoPhillips sold its interests in the Netherlands in the fourth quarter of
2002. Financial results for the Netherlands from the date of the merger through
the date of sale are included in Corporate and Other as discontinued operations.
Accordingly, the Netherlands production statistics are not included in E&P.
EXPLORATION
ConocoPhillips plans six exploration wells and two appraisal wells in the North
Sea in 2003. In the Norwegian sector, three exploration wells and an appraisal
well are planned for 2003. In the U.K. sector, two exploratory wells that were
spudded in late 2002 will continue drilling operations into 2003. ConocoPhillips
plans to participate in an additional exploration well and an appraisal well in
the U.K. sector in 2003.
E&P--CANADA
In 2002, E&P operations in Canada contributed 2 percent of ConocoPhillips'
worldwide liquids production and 8 percent of its worldwide natural gas
production, excluding Syncrude production.
CONVENTIONAL OIL AND GAS OPERATIONS
Operations in western Canada encompass properties in Alberta, northeastern
British Columbia and southwestern Saskatchewan. The reserve base in central and
northwestern Alberta and northeastern British Columbia is dominated by
liquids-rich natural gas and light-oil fields, as well as large enhanced oil
recovery projects. The reserve base in southern Alberta and southwestern
Saskatchewan is a mix of medium-gravity crude oil and natural gas.
ConocoPhillips is working with three other energy companies, as members of the
Mackenzie Delta Producers' Group (Group), on the possibility of transporting
onshore gas production from the Mackenzie Delta in northern Canada to existing
markets. In October 2001, the Group signed a Memorandum of Understanding (MOU)
with the Aboriginal peoples of the Northwest Territories, as represented by the
Mackenzie Valley Aboriginal Pipeline Corporation (MVAPC). The MOU provides a
framework for the parties to move forward on the development of a Mackenzie
Valley pipeline, running some 800 miles to serve the North American gas market.
In January 2002, the Group and the MVAPC announced that they would begin
preparing the regulatory applications needed to develop onshore natural gas
resources in the Mackenzie Delta, including the Mackenzie Valley pipeline.
Conceptual engineering commenced in April 2002, and in September 2002, after
receiving expressions of interest from other potential shippers, the consortium
decided to increase the initial design capacity for the Mackenzie Valley
pipeline from 830 to 1,200 million cubic feet per day. The pipeline capacity
would be expandable with additional compression. ConocoPhillips would hold a 16
percent interest in the pipeline and a 75 percent interest in the development of
the Parsons Lake gas field. The Parsons Lake gas field would be one of the three
primary fields in the Mackenzie Delta that would anchor the pipeline
development. Submission of regulatory applications for the project is
anticipated in late 2003 and first gas production is currently targeted by 2008.
ConocoPhillips owns approximately 47 percent of Petrovera, a joint venture that
combines a substantial portion of ConocoPhillips' Canadian heavy-oil assets and
certain associated natural gas assets. Net production was approximately 15,100
barrels of petroleum liquids per day from the date of the merger through
year-end 2002, and is reported separately in equity affiliate production.
9
OTHER CANADIAN OPERATIONS
ConocoPhillips has two oil sands projects in Canada: Syncrude Canada Ltd. and
Surmont.
Syncrude Canada Ltd.
ConocoPhillips owns a 9.03 percent undivided interest in Syncrude Canada Ltd., a
joint venture created by a number of energy companies for the purpose of mining
shallow deposits of oil sands, extracting the bitumen and upgrading it into a
light sweet crude oil called Syncrude Sweet Blend (Syncrude). The primary plant
and facilities are located at Mildred Lake, about 25 miles north of Fort
McMurray, Alberta, together with an auxiliary mining and extraction facility
approximately 20 miles from the Mildred Lake plant. Syncrude Canada Ltd. holds
eight oil sands leases, of which ConocoPhillips' share is approximately 23,000
net acres. The necessary surface rights are also held and the sites are readily
accessible. In December 1999, the Alberta Energy and Utilities Board extended
the project license term to the year 2035.
The U.S. Securities and Exchange Commission's regulations define this project as
mining-related and not part of conventional oil and gas operations. As such,
Syncrude reserves are not included in the company's proved oil and gas reserves
as reported in its supplemental oil and gas reserves information.
Surmont
The Surmont lease is located about 35 miles south of Fort McMurray, Alberta.
ConocoPhillips owns a 43.5 percent interest and is the operator. Currently, a
pilot project is being conducted to evaluate the potential of the Steam Assisted
Gravity Drainage technology at Surmont to economically develop oil sands that
are too deep to mine. In 2001, the company submitted a regulatory application to
develop 100,000 barrels per day of heavy-oil production. This application is in
the final stages of review and a regulatory decision is expected in 2003.
E&P--SOUTH AMERICA
In 2002, E&P operations in South America were comprised of interests in
Venezuela, Ecuador and Brazil. South American operations contributed 4 percent
of ConocoPhillips' worldwide liquids production.
VENEZUELA
ConocoPhillips has two major heavy-oil projects in Venezuela: Petrozuata and
Hamaca. In addition, ConocoPhillips owns blocks in the Gulf of Paria, which
contains the Corocoro conventional oil and gas discovery and other exploration
opportunities.
Petrozuata
Petrozuata is a joint venture between ConocoPhillips, which holds a 50.1 percent
non-controlling equity interest that was acquired in the merger, and a
subsidiary of Petroleos de Venezuela S.A. (PDVSA), the national oil company of
Venezuela, which holds the remaining interest.
The project is an integrated operation that produces extra-heavy crude oil from
reserves in the Zuata region of the Orinoco Oil Belt, transports it to the Jose
industrial complex on the north coast of Venezuela, and upgrades it into
medium-grade crude oil, with associated by-products of liquefied petroleum gas,
sulfur, petroleum coke and heavy gas oil. The joint-venture agreement has a
35-year term.
Petrozuata began early production of extra-heavy crude oil in August 1998, and,
after completion of the upgrader at Jose, made the first commercial sales of
upgraded, medium-grade crude oil in April 2001. ConocoPhillips' net production
was approximately 52,200 barrels of medium-grade crude oil per day for the last
four months of 2002, and is reported separately as equity affiliate production.
The medium-grade
10
crude oil produced by Petrozuata is used as a feedstock for ConocoPhillips' Lake
Charles, Louisiana, refinery and the Cardon refinery operated by PDVSA.
ConocoPhillips has entered into an agreement to purchase up to 104,000 barrels
per day of the Petrozuata upgraded crude oil for a market-based formula price
over the term of the joint venture in the event that Petrozuata is unable to
sell the production for higher prices. All upgraded crude oil sales are
denominated in U.S. dollars. By-products produced by the upgrading facility,
principally coke and sulfur, are sold to a variety of domestic and foreign
purchasers. The loading facilities at Jose transfer crude oil and some of the
by-products to ocean vessels for export.
Hamaca
The Hamaca project also involves the development of heavy-oil reserves from the
Orinoco Oil Belt. ConocoPhillips' share in the Hamaca project is 40 percent.
ConocoPhillips holds its interest in Hamaca through a jointly held limited
liability company, which ConocoPhillips accounts for using the equity method.
The other participants in Hamaca are PDVSA and ChevronTexaco Corporation.
Drilling of development wells started in January 2001, with early production of
extra-heavy oil starting in the fourth quarter of 2001. Production averaged
8,500 net barrels per day of heavy oil in 2002, and is reported separately as
equity affiliate production.
Construction of the heavy-oil upgrader, pipelines and associated production
facilities at the Jose industrial complex began in 2000. The upgrader is
expected to begin producing commercial quantities of medium-grade crude oil in
2004, at which time ConocoPhillips' net production from the Hamaca field is
expected to increase to over 60,000 barrels per day from proved reserves.
Gulf of Paria
In 1999, Conoco drilled the Corocoro discovery that, during drill stem tests,
flowed hydrocarbons from multiple zones. In 2001, Conoco and its partners
commenced a four-well appraisal program to evaluate the Corocoro discovery.
Three of the four wells were drilled in 2001 and the fourth well was completed
in the first quarter of 2002. All four wells were successful. ConocoPhillips
currently holds a 50 percent working interest in the Gulf of Paria West Block
and is the operator. In November 2002, ConocoPhillips began progressing
development discussions with the Venezuelan government and the company expects
development approval in the first half of 2003. Upon approval of the development
plan, an affiliate of PDVSA has the option to increase its participation in the
development, which could reduce ConocoPhillips' current 50 percent interest down
to as low as 32.5 percent. In addition, Venezuelan legislation enacted in 2001
introduced a new 30 percent flat royalty regime and reduced the income tax rate
on light oil projects from 67.7 percent to 50 percent. The Corocoro Project's
Royalty Agreement, which provides for a sliding scale royalty with a 16.55
percent maximum rate, was in effect prior to the 2001 legislation and is
expected to continue to apply to the project.
In addition to the Corocoro discovery, ConocoPhillips is pursuing additional
prospects in the Gulf of Paria, with two exploration wells planned for 2003.
In December of 2002, political unrest in Venezuela caused economic and other
disruptions that shut down most oil and gas operations in Venezuela, including
the company's Petrozuata, Hamaca and Gulf of Paria operations. Limited
production began from these operations in February 2003. For more information
about the impact of the disruptions on the company's operations in Venezuela,
see "Management's Discussion and Analysis of Financial Condition and Results of
Operations--Outlook" on page 74.
11
BRAZIL
ConocoPhillips announced in August 2001 that the Brazilian government had signed
concession agreements finalizing the award of two exploration blocks.
ConocoPhillips, bidding alone, previously placed winning bids on BM-ES-11 and
BM-PAMA-3 in Brazil's third bid round held in June 2001. Both blocks are located
in deepwater offshore Brazil. ConocoPhillips entered into partnerships on both
blocks in late 2002, reducing its interest to 70 percent in BM-ES-11 and 65
percent in BM-PAMA-3. In 2002 a significant seismic program was initiated over
the acreage position. The evaluation of that seismic is ongoing and will
continue in 2003. ConocoPhillips will operate both blocks.
ECUADOR
ConocoPhillips has a 14 percent non-operating interest in producing fields in
the Oriente basin in Ecuador in the area collectively referred to as "Block 16,"
that was acquired in the merger. Repsol YPF, s.a. is the operator of the Block
16 area. ConocoPhillips' net production was 3,200 barrels of crude oil per day
for the last four months of 2002. Net production for 2003 is expected to
increase to over 8,000 barrels of crude oil per day with the completion of a
trans-Andean heavy-oil pipeline. The pipeline completion is anticipated in the
second half of 2003.
E&P--ASIA PACIFIC
In 2002, E&P operations in the Asia Pacific area contributed 3 percent of
ConocoPhillips' worldwide liquids production and 7 percent of its worldwide
natural gas production.
CHINA
In the South China Sea, ConocoPhillips' combined net production of crude oil
from its Xijiang facilities averaged 11,600 barrels per day in 2002.
Production from Phase I development of the Peng Lai 19-3 field in Bohai Bay
Block 11-05 began in late December 2002. By the end of January 2003, the field
was producing at a net rate of 8,200 barrels per day. ConocoPhillips holds a 49
percent interest, with the remainder held by the China National Offshore Oil
Corporation. The Phase I development utilizes one wellhead platform and a
floating production, storage and offloading facility.
ConocoPhillips continues to move forward with feasibility planning and design
for Phase II of the Peng Lai 19-3 development. Phase II would include multiple
wellhead platforms, central processing facilities, and a floating storage and
offloading facility. The Peng Lai 25-6 field, discovered in 2000 and located
three miles east of Peng Lai 19-3, will be developed in conjunction with Phase
II of the Peng Lai 19-3 development project.
Several other exploration prospects have been identified in Block 11-05, with
two exploration wells planned for 2003.
INDONESIA
ConocoPhillips operates 14 Production Sharing Contracts (PSCs) in Indonesia and
has a non-operating interest in three others, all of which were acquired in the
merger. ConocoPhillips' assets are concentrated in two core areas: the West
Natuna Sea and South Sumatra; with a potentially emerging area offshore East
Java. ConocoPhillips is party to five long-term U.S. dollar pipeline gas
contracts that have been signed in Indonesia.
12
Offshore Assets
ConocoPhillips operates six offshore PSCs: 1) South Natuna Sea Block B, 2) Nila,
3) Tobong, 4) Kakap, 5) Sakala Timur, and 6) Ketapang. The company holds a
non-operator interest in the Pangkah PSC offshore East Java, and is a
co-venturer in the West Natuna Gas Supply Group (WNG). ConocoPhillips
participates in various gas marketing arrangements in connection with these
assets. The Block B PSC is comprised of two mature oil fields and 15 gas fields
in various phases of development. The largest current development in the Block B
PSC is the Belanak field, which is scheduled for first production in late 2004.
Two additional developments are scheduled for startup dates in 2006 and 2008,
and would produce into the Belanak infrastructure. The company also has an
active exploration program in both the Natuna Sea and East Java.
Onshore Assets
ConocoPhillips operates eight onshore PSCs: 1) Corridor TAC, 2) Corridor PSC, 3)
South Jambi 'B', 4) Sakakemang JOB (jointly operated with a co-venturer), 5)
Banyumas, 6) Tungkal, 7) Block A PSC in Aceh, and 8) Warim, and holds
non-operator interests in the Bentu and Korinci-Baru PSCs. As with its offshore
properties, the company participates in various gas marketing arrangements in
connection with these fields. Exploration efforts focus on locating additional
natural gas reserves.
Gas sales are transported to Duri through a pipeline system formerly owned and
operated by the state-owned pipeline company, PGN. This system has recently
been transferred to a new company, Transgasindo (TGI), in which ConocoPhillips
received a 14 percent equity share.
Production of natural gas from Indonesia averaged a net 217 million cubic feet
per day for the last four months of 2002, while production of crude oil over the
same period averaged a net 14,700 barrels per day. The company plans to drill
five exploratory and four appraisal wells in Indonesia in 2003.
VIETNAM
ConocoPhillips has a 23.25 percent interest in Block 15-1 in the Cuu Long Basin.
In 2001, the partners in Block 15-1 declared the southwest portion of the Su Tu
Den (Black Lion) field commercial after a successful appraisal program. In
addition, an appraisal well in the northeast portion of Su Tu Den was
successfully drilled in 2002. The Su Tu Den Phase I development project was
approved in December 2001. A floating production, storage and offloading vessel
and a wellhead platform will be utilized. The field is scheduled to begin
production in the second quarter of 2004. An exploration discovery was also made
on the nearby Su Tu Vang (Golden Lion) prospect in the third quarter of 2001.
The potential commerciality of Su Tu Vang and the Northeast portion of Su Tu Den
are currently being evaluated.
ConocoPhillips has a 36 percent interest in the Rang Dong field in Block 15-2 in
the Cuu Long Basin. In the third quarter of 2002, production began from two new
wellhead platforms in the Rang Dong field. These additional platforms increased
net production from the field from under 6,800 to over 12,400 barrels per day at
year-end 2002. A successful appraisal step-out well, Rang Dong-12X, was drilled
in the central part of the field in late 2001 and tested at a rate of 9,300
barrels of petroleum liquids per day. A development plan for this area of the
field is being evaluated.
ConocoPhillips also owns interests in offshore Blocks 16-2, 5-3, 133 and 134, as
well as a 16.33 percent interest in the Nam Con Son gas pipeline.
13
TIMOR SEA AND AUSTRALIA
Bayu-Undan
ConocoPhillips' direct interest in the unitized Bayu-Undan field, located in the
Timor Sea, was 55.9 percent at year-end 2002. A further 8.25 percent interest
was held through Petroz N.L., in which the company had an 89.7 percent stock
ownership at year-end. The field is being developed in two phases. Phase I is a
gas-recycle project, where condensate and natural gas liquids will be separated
and removed and the dry gas reinjected into the reservoir. This phase is
expected to begin production in 2004, with the goal of attaining a net rate of
50,000 barrels of liquids per day from proved reserves. Phase II would involve
the export and sale of the natural gas from the field.
In March 2002, ConocoPhillips announced that it had signed a Heads of Agreement
(LNG HOA) with The Tokyo Electric Power Company, Incorporated (TEPCO) and Tokyo
Gas Co., Ltd. (Tokyo Gas) that would enable Phase II to proceed upon resolution
of certain legal, regulatory, and fiscal issues. The Timor Sea Treaty (Treaty)
was ratified by Timor-Leste (formerly East Timor) in December 2002 and by
Australia in March 2003 and is subject to certain procedural events before it is
fully effective. The Treaty will allow the issuance of new production sharing
contracts to the existing contractors in the Bayu-Undan unit, which when
combined with the expected approval of the Development Plan and the expected
enactment of certain Timor-Leste legislation will provide the legal, regulatory
and fiscal basis necessary to proceed with the project.
Under the LNG HOA, TEPCO and Tokyo Gas will purchase 3 million tons per year in
total of liquefied natural gas (LNG) for a period of 17 years, utilizing natural
gas from the Bayu-Undan field. Shipments would begin in 2006 from an LNG
facility near Darwin, Australia, utilizing ConocoPhillips' Optimized Cascade
liquefied natural gas process. Under a separate agreement, the company plans to
sell a 22.5 percent interest in one of the production sharing contracts via an
indirect sale of an affiliate to TEPCO and Tokyo Gas. Following the sale to
TEPCO and Tokyo Gas and a rebalancing of interests, ConocoPhillips' interest in
the unitized Bayu-Undan field, including Petroz N.L., would be 56.72 percent.
Greater Sunrise
During 2002, the Sunrise joint venture conducted a thorough review of a proposal
based on piping gas 330 miles to shore for sale in Darwin and elsewhere in
Australia and an alternative proposal to supply LNG to North America from a
floating LNG facility. The review found neither proposal to be commercially
viable at that time. However, the review did acknowledge the level of demand and
interest within the Australian domestic gas market, and highlighted the
potential for a floating LNG facility at Greater Sunrise to become a cost
competitive supplier of LNG into regional markets.
Consequently, in 2003, the Greater Sunrise joint venture participants plan to
continue evaluating commercial development options and markets. The Sunrise
joint venture participants are: Woodside 33.44 percent (Operator),
ConocoPhillips 30 percent, Shell 26.56 percent and Osaka Gas 10 percent.
E&P--AFRICA AND THE MIDDLE EAST
NIGERIA
ConocoPhillips' crude oil production from five leases in Nigeria averaged a net
29,100 barrels per day in 2002. These five leases include four onshore Oil
Mining Leases (OML) and a shallow-water offshore OML. Continued development and
exploratory drilling is planned for 2003 on the leases.
14
ConocoPhillips entered into a production sharing contract on Oil Prospecting
Lease (OPL) 318, deepwater Nigeria, on June 14, 2002, where ConocoPhillips is
operator with 50 percent interest. The acquisition of 3D seismic data on OPL 318
is planned to begin in 2003, with the first exploratory well expected to be
drilled in the fourth quarter of 2004.
The company is participating in a 450-megawatt gas-fired power plant to supply
electricity to Nigeria's national electricity supplier. The plant will consume
75 million cubic feet per day of natural gas sourced from within ConocoPhillips'
Nigerian proved natural gas reserves. The plant is expected to be operational in
2005.
ANGOLA
ConocoPhillips has a 20 percent interest in exploratory activity in deepwater
Block 34, offshore Angola. The first exploration well, completed in 2002, did
not encounter commercial quantities of hydrocarbons, which led to a substantial
financial impairment of the investment in the block. Further drilling is planned
on the block in 2003.
CAMEROON
On December 18, 2002, ConocoPhillips announced a successful drill stem test on
an exploratory well offshore Cameroon. The well, located in exploration permit
PH 77, offshore in the Douala Basin, obtained a maximum flow rate of 3,000
barrels of oil per day and 1.8 million cubic feet of natural gas per day during
the test.
Contractor interests in the 2,830 square mile permit are held 50 percent by
ConocoPhillips and 50 percent by a subsidiary of Petronas Carigali (Petronas).
ConocoPhillips serves as the operator of the consortium. ConocoPhillips and
Petronas are currently analyzing well results, and will be working with the
National Hydrocarbon Corporation of Cameroon on developing forward plans to
evaluate the discovery and other identified exploration prospects in the permit.
DUBAI
In Dubai, United Arab Emirates, ConocoPhillips is using horizontal drilling
techniques and advanced reservoir drainage technology to enhance the efficiency
of the offshore production operations and improve recovery rates from four
fields.
SAUDI ARABIA
ConocoPhillips has a 15 percent interest in Core Venture 1 and a 30 percent
interest in Core Venture 3 of the Kingdom of Saudi Arabia's natural gas
initiative. ConocoPhillips and its co-venturers continue to define the project
components in more detail, and to negotiate the implementation agreement, which
would set out all major financial, operational and legal terms for the
initiative, as well as a timeline for the project execution.
E&P--RUSSIA AND CASPIAN SEA REGION
RUSSIA
ConocoPhillips holds a 50 percent ownership interest in Polar Lights Company, a
Russian limited liability company established in January 1992 to develop the
Ardalin field in the Timan-Pechora basin in Northern Russia. Polar Lights, which
was acquired in the merger, started producing oil in August 1994 from the
Ardalin field. In June 2002, production commenced from the Oshkotyn field, the
first of three satellite fields under development. Net production averaged
13,500 barrels of petroleum liquids per day for the last four months of 2002.
ConocoPhillips accounts for its interest in Polar Lights using the equity method
of accounting.
15
CASPIAN SEA
ConocoPhillips has an 8.33 percent interest in an exploration project in the
Kazakhstan sector of the Caspian Sea. The exploration area consists of 10.5
blocks, totaling nearly 2,000 square miles about 50 miles west-northwest of the
Tengiz oil field, onshore Kazakhstan. The blocks are covered by a production
sharing agreement with the Kazakhstan government. The initial production phase
of the contract is for 20 years, with options to extend the agreement an
additional 20 years. In June 2002, ConocoPhillips and the other contracting
companies in conjunction with KazMunayGas, which represents the Government of
the Republic of Kazakhstan, declared the Kashagan discovery commercial. The
declaration of commerciality enables the preparation of a development plan for
the Kashagan field. The contracting companies plan to continue to explore other
structures within the North Caspian Sea license. In October 2002, ConocoPhillips
and its co-venturers announced a new hydrocarbon discovery in the Kazakhstan
sector of the Caspian Sea. An initial test well, the Kalamkas-1, located
adjacent to the Kashagan field, flowed oil.
E&P--OTHER
ConocoPhillips is continuing with plans to develop a project to build a
liquefied natural gas import terminal in northern Baja California to provide
access to gas markets in that region. The company is working with federal,
state, and local officials in Mexico to secure permits for the project, and a
decision whether or not to proceed with the terminal project is expected during
2003, pending resolution of local permitting issues.
E&P--RESERVES
The company has not filed any information with any other federal authority or
agency with respect to its estimated total proved reserves at December 31, 2002.
No difference exists between the company's estimated total proved reserves for
year-end 2001 and year-end 2000, which are shown in this filing, and estimates
of these reserves shown in a filing with another federal agency in 2002.
DELIVERY COMMITMENTS
ConocoPhillips has future commitments to deliver fixed and determinable
quantities of crude oil to U.S. customers under various supply agreements over
the next three years. During the period, the company is obligated to supply a
total of 127 million barrels of crude oil under long-term contracts. To fulfill
these obligations, ConocoPhillips plans to use production from domestic proved
reserves, which are greater than these obligations and which have estimated
production levels sufficient to meet the required delivery amounts.
ConocoPhillips has a commitment to deliver a fixed and determinable quantity of
liquefied natural gas in the future to two utility customers in Japan. The
company is obligated over the next three years to supply a total of 108 billion
cubic feet of liquefied natural gas. Production from one field in Alaska, with
estimated proved reserves greater than the company's obligation and estimated
production levels sufficient to meet the required delivery amount, will be used
to fulfill the obligation.
16
MIDSTREAM
---------
ConocoPhillips' Midstream business is conducted through owned and operated
assets as well as through its 30.3 percent equity investment in Duke Energy
Field Services, LLC (DEFS). The Midstream businesses purchase raw natural gas
from producers and gather natural gas through extensive pipeline gathering
systems. The gathered natural gas is then processed to extract natural gas
liquids from the raw gas stream. The remaining "residue" gas is marketed by both
ConocoPhillips and DEFS to electrical utilities, industrial users, and gas
marketing companies. Most of the natural gas liquids are fractionated--separated
into individual components like ethane, butane and propane--and marketed as
chemical feedstock, fuel, or blendstock. Total natural gas liquids extracted in
2002, including ConocoPhillips' share of DEFS, was 156,000 barrels per day, with
133,000 barrels per day of natural gas liquids fractionated.
DEFS supplies a substantial portion of its natural gas liquids to ConocoPhillips
and Chevron Phillips Chemical Company LLC (a joint venture between
ConocoPhillips and ChevronTexaco) under a supply agreement that continues until
December 31, 2014. This purchase commitment is on an "if-produced,
will-purchase" basis and so it has no fixed production schedule, but has been,
and is expected to be, a relatively stable purchase pattern over the term of the
contract. Under this agreement, natural gas liquids are purchased at various
published market index prices, less transportation and fractionation fees. DEFS
also purchases raw natural gas from ConocoPhillips' E&P operations.
DEFS is headquartered in Denver, Colorado. At December 31, 2002, DEFS owned and
operated 60 natural gas liquids extraction plants, and owned an equity interest
in another 11. Also at year end, DEFS' gathering and transmission systems
included 60,000 miles of pipeline. In 2002, DEFS' raw natural gas throughput
averaged 7.4 billion cubic feet per day, and natural gas liquids extraction
averaged 392,000 barrels per day. DEFS' assets are primarily located in the Gulf
Coast area, west Texas, Oklahoma, the Texas Panhandle, the Rocky Mountain area,
and western Canada.
Outside of DEFS, ConocoPhillips' U.S. Midstream assets at December 31, 2002,
included nine owned and operated natural gas liquids extraction plants in New
Mexico, Texas and Louisiana with a combined net plant inlet capacity of 757
million cubic feet per day and an equity interest in another two plants. One of
the company owned plants in Louisiana also includes a 10,500 barrel-per-day
liquids fractionator. In addition, ConocoPhillips owns an underground natural
gas liquids storage facility in each of Texas and Louisiana.
ConocoPhillips owns a 25,000 barrel-per-day capacity liquids fractionation plant
in Gallup, New Mexico; owns a 22.5 percent equity interest in Gulf Coast
Fractionators, which owns a natural gas liquids fractionating plant in Mt.
Belvieu, Texas (with ConocoPhillips' net share of capacity at 25,000 barrels per
day); and owns a 40 percent interest in a fractionation plant in Conway, Kansas
(with ConocoPhillips' share of capacity at 42,000 barrels per day).
ConocoPhillips owns a 700-mile intrastate natural gas and liquids pipeline
system in Louisiana and gas gathering and natural gas liquids pipelines in
several states.
ConocoPhillips' Canadian natural gas liquids business includes the following
assets:
o A 92 percent operating interest in the 2.4
billion-cubic-feet-per-day Empress natural gas processing straddle
plant near Medicine Hat, Alberta, with natural gas liquids
production capacity of 46,000 barrels per day;
o A 580-mile Petroleum Transmission Company pipeline from Empress to
Winnipeg and six related pipeline terminals;
17
o An underground natural gas liquids storage facility with 1 million
barrels of capacity;
o A 10 percent interest in the 1,902-mile Cochin liquefied petroleum
gas pipeline, originating in Edmonton, Alberta, and ending in
Sarnia, Ontario, and a terminal storage system that transports
propane, ethane and ethylene; and
o An 18 percent interest in a 30,000 barrel-per-day propane-plus
fractionator and a 5 percent interest in a 65-mile natural gas
liquids pipeline with storage near Edmonton, Alberta.
Canadian natural gas liquids extracted averaged 15,000 barrels per day in 2002.
ConocoPhillips also owns a 39 percent equity interest in Phoenix Park Gas
Processors Limited, a joint venture with the National Gas Company of Trinidad
and Tobago Limited, which processes gas in Trinidad and markets natural gas
liquids throughout the Caribbean and into the U.S. Gulf Coast. Phoenix Park's
facilities include a gas processing plant and a natural gas liquids
fractionator. ConocoPhillips' share of natural gas liquids extracted averaged
3,000 barrels per day in 2002.
REFINING AND MARKETING (R&M)
----------------------------
R&M operations encompass refining crude oil and other feedstocks into petroleum
products (such as gasoline, distillates and aviation fuels), buying and selling
crude oil and refined products, and transporting, distributing and marketing
petroleum products. R&M operations are organized regionally with operations in
the United States, Europe and the Asia Pacific region.
As a condition to the merger, the U.S. Federal Trade Commission (FTC) required
that the company divest specified Conoco and Phillips assets, the most
significant of which were Phillips' Woods Cross, Utah, refinery and associated
motor fuel marketing operations; Conoco's Commerce City, Colorado, refinery and
related crude oil pipelines; and Phillips' Colorado motor fuel marketing
operations. In addition, in December 2002, the company committed to and
initiated a plan to sell a substantial portion of its company-owned retail
sites. Both the FTC-required dispositions and the retail site dispositions have
been classified as discontinued operations for financial reporting purposes, and
are included in Corporate and Other. Accordingly, they are excluded from the
descriptions of R&M's continuing operations contained in this section. See Note
4--Discontinued Operations, in the Notes to Consolidated Financial Statements,
for additional information.
UNITED STATES
REFINING
At December 31, 2002, ConocoPhillips owned and operated 12 crude oil refineries
in the United States (excluding two refineries that are held for sale and
reported in discontinued operations in Corporate and Other) having an aggregate
rated crude oil refining capacity at year-end 2002 of 2,166,000 barrels per day.
The average purchase cost of a barrel of crude delivered to the company's U.S.
refineries in 2002 was $24.92, compared to $20.77 in 2001.
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East Coast Region
BAYWAY REFINERY
Located on the New York Harbor in Linden, New Jersey, Bayway has a crude oil
processing capacity of 250,000 barrels per day and processes mainly light
low-sulfur crudes. Crude oil is supplied to the refinery by tanker, primarily
from the North Sea and West Africa. The refinery produces a high percentage of
transportation fuels such as gasoline, diesel, and jet fuel along with home
heating oil. Other products include petrochemical feedstocks (propylene) and
residual fuel oil. The facility distributes its refined products to East Coast
customers through pipelines, barges, railcars and trucks. Product production
changes to meet seasonal demand. Gasoline is in higher demand during the summer,
while in winter, the refinery optimizes operations to increase heating oil
production. A 775 million-pound-per-year polypropylene plant became operational
in March 2003.
TRAINER REFINERY
The Trainer refinery is located in Trainer, Pennsylvania, about 10 miles
southwest of the Philadelphia airport on the Delaware River. The refinery has a
crude oil processing capacity of 180,000 barrels per day and processes mainly
light low-sulfur crudes. The Bayway and Trainer refineries are operated in
coordination with each other by sharing crude oil cargoes, moving feedstocks
between the facilities, and sharing certain personnel. Trainer also receives
crude oil from the North Sea and West Africa. The refinery produces a high
percentage of transportation fuels such as gasoline, diesel, and jet fuel along
with home heating oil. Other products include petrochemical feedstocks
(propylene) and residual fuel oil. Refined products are distributed to customers
in Pennsylvania, New York and New Jersey via pipeline, barge, railcar and truck.
Gulf Coast Region
ALLIANCE REFINERY
The Alliance refinery, located in Belle Chasse, Louisiana, on the Mississippi
River, is about 25 miles south of New Orleans and 63 miles north of the Gulf of
Mexico. The refinery has a crude oil processing capacity of 250,000 barrels per
day and processes mainly light low-sulfur crudes. Alliance receives domestic
crude oil via pipeline, and crude oil from the North Sea and West Africa via
pipeline connected to the Louisiana Offshore Oil Port. The refinery produces a
high percentage of transportation fuels such as gasoline, diesel, and jet fuel
along with home heating oil. Other products include petrochemical feedstocks
(benzene) and petroleum (fuel) coke. The majority of the refined products are
distributed to customers through the Colonial and Plantation pipeline systems.
LAKE CHARLES REFINERY
The Lake Charles refinery is located in Westlake, Louisiana. The refinery has a
crude oil processing capacity of 252,000 barrels per day. The refinery receives
domestic and international crude oil and processes heavy, high-sulfur,
low-sulfur and acidic crude oil. While the sources of international crude oil
can vary, the majority is Venezuelan and Mexican heavy crudes delivered via
tanker. The refinery produces a high percentage of transportation fuels such as
gasoline, off-road diesel, and jet fuel along with heating oil. The majority of
the refined products are distributed to customers by truck, rail or major
common-carrier pipelines. In addition, refinery products can be sold into export
markets through the refinery's marine terminal.
The Lake Charles facilities also include a specialty coker and calciner that
manufactures graphite and anode petroleum cokes supplied to the steel and
aluminum industries, and provides a substantial increase in light oils
production by breaking down the heaviest part of the crude barrel to allow
additional production of diesel fuel and gasoline.
The Lake Charles refinery supplies feedstocks to Excel Paralubes, Penreco and
Venture Coke Company (Venco), all joint ventures that are part of the company's
Specialty Businesses function within R&M.
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SWEENY REFINERY
The Sweeny refinery is located in Old Ocean, Texas, about 65 miles southwest of
Houston. Effective March 1, 2003, the refinery's crude oil processing capacity
increased to 215,000 barrels per day as a result of incremental debottlenecking.
The refinery primarily receives crude oil through ConocoPhillips' and jointly
owned terminals on the Gulf Coast, including a deepwater terminal at Freeport,
Texas. The refinery produces a high percentage of transportation fuels such as
gasoline, diesel, and jet fuel along with home heating oil. Other products
include petrochemical feedstocks (benzene) and petroleum (fuel) coke. Refined
products are distributed throughout the Midwest and southeastern United States
through pipeline, barge and railcar.
ConocoPhillips and PDVSA have a limited partnership that operates a 58,000
barrel-per-day delayed coker and related facilities at the Sweeny refinery.
Under the terms of the agreements, PDVSA supplies the refinery up to 165,000
barrels per day of Venezuelan Merey, or equivalent, crude oil. ConocoPhillips is
the operator of, and holds a 50 percent interest in, the coker through its
interest in Merey Sweeny, L.P.
Central Region
WOOD RIVER REFINERY
The Wood River refinery is located in Roxana, Illinois, about 15 miles north of
St. Louis, Missouri, on the east side of the Mississippi River. It is the
company's largest refinery, with a crude oil processing capacity of 286,000
barrels per day and can process a mix of both light low-sulfur and heavy
high-sulfur crudes. The facility receives domestic and foreign crude oil by
pipeline. The refinery produces a high percentage of transportation fuels such
as gasoline, diesel, and jet fuel along with home heating oil. Other products
include petrochemical feedstocks (benzene) and asphalt. Through an off-take
agreement, a significant portion of its gasoline, diesel and jet fuel is sold to
a third party at the refinery for delivery via pipelines into the upper Midwest,
including the Chicago, Illinois, and Milwaukee, Wisconsin, metropolitan areas.
Remaining refined products are distributed to customers in the Midwest by
pipeline, truck, barge and railcar.
PONCA CITY REFINERY
ConocoPhillips' refinery located in Ponca City, Oklahoma, has a crude oil
processing capacity of 194,000 barrels per day. Both foreign and domestic crudes
are delivered by pipeline from the Gulf of Mexico, Oklahoma, Kansas, Texas and
Canada. The refinery's facilities include fluid catalytic cracking, delayed
coking and hydrodesulfurization units, which enable it to produce high ratios of
gasoline and diesel fuel from crude oil. Finished petroleum products are shipped
by truck, rail and company-owned and common-carrier pipelines to markets
throughout the mid-continent region.
BORGER REFINERY
The Borger refinery is located in Borger, Texas, in the Texas Panhandle about 50
miles north of Amarillo. It includes a natural gas liquids fractionation
facility. The crude oil processing capacity is 148,000 barrels per day, and the
natural gas liquids fractionation capacity is 95,000 barrels per day. The
refinery processes mainly heavy high-sulfur crudes. The refinery receives crude
oil and natural gas liquids feedstocks through ConocoPhillips' pipelines from
west Texas, the Texas Panhandle and Wyoming. The Borger refinery can also
receive water-borne crude oil via ConocoPhillips' pipeline systems. The refinery
produces a high percentage of transportation fuels such as gasoline, diesel, and
jet fuel along with a variety of natural gas liquids and solvents. Pipelines
move refined products from the refinery to west Texas, New Mexico, Arizona,
Colorado, Kansas, Nebraska and the Chicago area.
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BILLINGS REFINERY
ConocoPhillips' Billings, Montana, refinery has a crude oil processing capacity
of 60,000 barrels per day, processing a mixture of about 95 percent Canadian
heavy high-sulfur crude plus domestic high-sulfur and low-sulfur crudes, all
delivered by pipeline. A delayed coker converts heavy high-sulfur residue into
higher value light oils. The refinery produces a high percentage of
transportation fuels such as gasoline, jet fuel, diesel and fuel grade petroleum
coke. Finished petroleum products from the refinery are delivered via
company-owned pipelines, rail, and trucks.
West Coast Region
LOS ANGELES REFINERY
The Los Angeles refinery is composed of two linked facilities located about five
miles apart in Carson and Wilmington, California, about 15 miles southeast of
Los Angeles International airport. Carson serves as the front-end of the
refinery by processing crude oil, and Wilmington serves as the back-end by
upgrading products. The refinery has a crude oil processing capacity of 132,000
barrels per day and processes mainly heavy high-sulfur crudes. The refinery
receives domestic crude oil via pipeline from California and foreign and
domestic crude oil by tanker through company-owned and third-party terminals in
the Port of Los Angeles. The refinery produces a high percentage of
transportation fuels such as gasoline, diesel, and jet fuel. Other products
include fuel grade petroleum coke. The refinery produces California Air
Resources Board gasoline, and also produces gasoline without methyl
tertiary-butyl ether (MTBE) by using ethanol to meet federally mandated
oxygenate requirements. Refined products are distributed to customers in
southern California, Nevada and Arizona by pipeline and truck.
SAN FRANCISCO AREA REFINERY
The San Francisco Area refinery is composed of two linked facilities located
about 200 miles apart. The Santa Maria facility is located in Arroyo Grande,
California, about 200 miles south of San Francisco, while the Rodeo facility is
in the San Francisco Bay area. The refinery's crude oil processing capacity is
109,000 barrels per day of mainly heavy high-sulfur crudes. Both the Santa Maria
and Rodeo facilities have calciners to upgrade the value of the coke that is
produced. The refinery receives crude oil from central California, including the
Elk Hills oil field, and foreign crude oil by tanker. Semi-refined liquid
products from the Santa Maria facility are sent by pipeline to the Rodeo
facility for upgrading to finished petroleum products. The refinery produces
transportation fuels such as gasoline, diesel, and jet fuel. Other products
include fuel grade petroleum coke. The refinery produces California Air
Resources Board gasoline, and also produces gasoline without MTBE by using
ethanol to meet federally mandated oxygenate requirements. Refined products are
distributed by pipeline, railcar, truck and barge.
FERNDALE REFINERY
The Ferndale refinery in Ferndale, Washington, is about 20 miles south of the
United States-Canada border on Puget Sound. The refinery has a crude oil
processing capacity of 92,000 barrels per day. The refinery receives crude oil
primarily from the Alaskan North Slope, with secondary sources supplied by
Canada or the Far East. Ferndale operates a deepwater dock that is capable of
taking in full tankers bringing North Slope crude oil from Valdez, Alaska. The
refinery is also connected to the Transmountain crude oil pipeline that
originates in Canada. The refinery produces transportation fuels such as
gasoline, diesel, and jet fuel. Other products include residual fuel oil
supplying the northwest marine transportation market. Construction of a new
fluidized catalytic cracking unit that will increase the yield of transportation
fuel is expected to become fully operational in the second quarter of 2003. Most
refined products are distributed by pipeline and barge to major markets in the
northwest United States.
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MARKETING
At December 31, 2002, ConocoPhillips marketed gasoline through approximately
13,700 outlets in 48 states (excluding operations reported in discontinued
operations in Corporate and Other). About 31 percent of these utilize the Conoco
brand, about 47 percent are branded Phillips 66 outlets, while the remaining
outlets feature the Circle K, 76, Exxon and Mobil brands. ConocoPhillips has the
right to use the Exxon and Mobil brands in certain areas until 2010.
ConocoPhillips also has the use of the Coastal brand in 10 states until 2011.
Wholesale
In its wholesale operations, the company utilizes a network of marketers and
dealers operating approximately 12,600 outlets. ConocoPhillips also buys and
sells petroleum products in spot markets. ConocoPhillips' refined products are
marketed on both a branded and unbranded basis.
In addition to automotive gasoline and diesel fuel, ConocoPhillips produces and
markets aviation gasoline, which is used by smaller, piston-engine aircraft.
Aviation gasoline and jet fuel are sold through independent marketers at
approximately 600 branded locations in the United States.
At December 31, 2002, CFJ Properties, a 50/50 joint venture between
ConocoPhillips and Flying J, owned and operated 96 truck travel plazas that
carry the Conoco and/or Flying J brands.
Retail
At December 31, 2002, ConocoPhillips owned and operated approximately 400
convenience stores under the Circle K, Phillips 66, Conoco and 76 brands in 12
states. The company-operated retail operations are focused in the mid-continent
and West Coast regions. All the Phillips 66 branded outlets market merchandise
through the Kicks 66 brand convenience stores.
TRANSPORTATION
Pipelines and Terminals
At December 31, 2002, ConocoPhillips' R&M segment had approximately 31,500 miles
of common-carrier crude oil, raw natural gas liquids and products pipeline
systems in the United States, including those partially owned and/or operated by
affiliates. The company also owned and/or operated 82 finished product
terminals, six liquefied petroleum gas terminals, seven crude oil terminals and
one coke exporting facility.
Tankers
At December 31, 2002, ConocoPhillips chartered 15 double-hulled crude oil
tankers, with capacities ranging in size from 650,000 to 1,100,000 barrels.
These tankers are utilized to transport feedstocks to certain of the company's
U.S. refineries. The company also has an ocean-going barge under charter, as
well as a domestic fleet of both owned and chartered boats and barges providing
inland waterway transportation. The information above excludes the operations of
the company's subsidiary, Polar Tankers Inc., which is discussed in the E&P
section, as well as an owned tanker on lease to a third party for use in the
North Sea.
ConocoPhillips has agreements for the long-term chartering of five double-hulled
crude oil tankers that are currently under construction. Delivery is expected in
the third and fourth quarters of 2003. Two of these vessels are 825,000-barrel
tankers, and three are 1,115,000-barrel tankers. The term of the agreement is 12
years from date of delivery. ConocoPhillips plans to utilize the new tankers to
replace older vessels in supplying its East Coast refining operations.
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SPECIALTY BUSINESSES
ConocoPhillips manufactures and sells a variety of high-value lubricants and
specialty products including petroleum cokes, lubes, such as automotive and
industrial lubricants, solvents and pipeline flow improvers, to commercial,
industrial and wholesale accounts worldwide. Lubricants are marketed under the
Conoco, Hydroclear, Phillips 66, 76 and Kendall brands. These lubricants are
sold by marketers, mass merchandise stores, fast lubes, tire stores, automotive
dealers, and convenience stores. Lubricants are also sold to industrial
customers in many markets.
Excel Paralubes is a joint-venture hydrocracked lubricating base oil
manufacturing facility located adjacent to the Lake Charles refinery, and is 50
percent owned by ConocoPhillips. Excel Paralubes' lube oil facility produces
approximately 20,000 barrels per day of high-quality, clear hydrocracked base
oils. Hydrocracked base oils are second in quality only to synthetic base oils,
but are produced at a much lower cost. The Lake Charles refinery supplies Excel
Paralubes with gas-oil feedstocks.
ConocoPhillips has a 50 percent interest in Penreco, a fully integrated
specialties company, which manufactures and markets highly refined specialty
petroleum products, including solvents, waxes, petrolatums and white oils, for
global markets.
The company manufactures high-quality graphite and anode-grade cokes in the
United States and Europe, for use in the global steel and aluminum industries.
Venco is a coke calcining joint venture in which ConocoPhillips has a 50 percent
interest. Green petroleum coke is supplied to Venco's Lake Charles calcining
facility from the Lake Charles refinery.
INTERNATIONAL
REFINING
At December 31, 2002, ConocoPhillips owned or had an interest in six refineries
outside the United States with an aggregate rated crude oil capacity of 440,000
net barrels per day. The average purchase cost of crude oil delivered to the
company's international refineries in 2002 was $24.55 per barrel, compared with
a $21.10 per barrel in 2001.
Humber Refinery
ConocoPhillips' wholly owned Humber refinery is located in North Lincolnshire,
United Kingdom. Effective January 1, 2003, Humber's capacity was increased by
2,000 barrels per day to 234,000 barrels per day as a result of incremental
debottlenecking. Crude oil processed at the refinery is supplied primarily from
the North Sea and includes lower-cost, acidic crudes. The refinery also
processes other intermediate feedstocks, mostly vacuum gas oils and residual
fuel oil. The refinery's location on the east coast of England provides for
cost-effective North Sea crude imports and product exports to European and world
markets.
The Humber refinery is a fully integrated refinery that produces a full slate of
light products and minimal fuel oil. The refinery also has two coking units with
associated calcining plants, which upgrade the heavy "bottoms" and imported
feedstocks into light-oil products and high-value graphite and anode petroleum
cokes. Approximately 58 percent of the light oils produced in the refinery are
marketed in the United Kingdom, while the other products are exported to the
rest of Europe and the United States. This gives the refinery the flexibility to
take full advantage of inland and global export market opportunities.
23
Whitegate Refinery
The Whitegate refinery is located in Cork, Ireland. Whitegate is Ireland's only
refinery, and has a processing capacity of 72,000 barrels per day. Crude oil
processed by the refinery is light sweet crude sourced mostly from the North
Sea. The refinery primarily produces transportation fuels and fuel oil, which
are distributed to the inland market via truck and sea, as well as being
exported to the European market. ConocoPhillips also operates a deepwater crude
oil and products storage complex in Bantry Bay, Ireland.
MiRO Refinery
The MiRO refinery in Karlsruhe, Germany, is a joint-venture refinery with a
crude oil processing capacity of 283,000 barrels per day. ConocoPhillips has an
18.75 percent interest in MiRO, giving the company a net capacity share of
53,000 barrels per day. The other owners of MiRO are Shell & DEA Oil GmbH
(formerly DEA Mineraloel AG), Esso AG and Ruhr Oel GmbH, a 50/50 joint venture
between Veba and PDVSA. Approximately 60 percent of the refinery's crude oil
feedstock is low-cost, high-sulfur crude. The MiRO complex is a fully integrated
refinery producing gasoline, middle distillates, and specialty products along
with a small amount of residual fuel oil. The refinery has a high capacity to
convert lower-cost feedstocks into higher value products, primarily with a fluid
catalytic cracker and delayed coker. The refinery produces both fuel grade and
specialty calcined cokes. The refinery processes crude and other feedstocks
supplied by each of the partners in proportion to their respective ownership
interests.
Czech Republic Refineries
ConocoPhillips, through its participation in Ceska rafinerska, a.s. (CRC), has
an interest in two refineries in the Czech Republic: one in Kralupy and the
other in Litvinov. The other owners of CRC are Unipetrol A.S., Agip Petroli, and
Shell Overseas Investment B.V. The refinery at Litvinov has a crude oil
processing capacity of 103,000 barrels per day, and the Kralupy refinery has a
crude oil processing capacity of 63,000 barrels per day. ConocoPhillips' 16.33
percent ownership share of the combined capacity is 27,000 barrels per day. Both
refineries process mostly high-sulfur crude oil, with a large portion being
Russian export blend delivered by pipeline. The refineries have an alternative
crude supply via a pipeline from the Mediterranean. The two refineries are
operated as a single entity, with certain intermediate streams moving between
the two facilities. CRC markets finished products both inland and abroad.
Melaka Refinery
The refinery in Melaka, Malaysia, is a joint venture with Petronas, the
Malaysian state oil company. ConocoPhillips owns a 47 percent interest in the
joint venture. The refinery has a rated crude oil processing capacity of 120,000
barrels per day, of which ConocoPhillips' share is 56,000 barrels per day. Crude
oil processed by the refinery is sourced mostly from the Middle East. The
refinery produces a full range of refined petroleum products. The refinery
capitalizes on ConocoPhillips' proprietary coking technology to upgrade low-cost
feedstocks to higher-margin products. ConocoPhillips' share of refined products
is distributed by truck to the company's ProJET retail sites in Malaysia, or
transported by sea primarily to Asian markets.
MARKETING
ConocoPhillips had marketing operations in 15 European countries at December 31,
2002. The company's European marketing strategy is to sell primarily through
owned, leased or joint-venture retail sites using a low-cost, high-volume,
low-price strategy. ConocoPhillips also markets aviation fuels, liquid petroleum
gases, heating oils, transportation fuels and marine bunkers to commercial
customers and into the bulk or spot market.
24
ConocoPhillips uses the "JET" brand name to market its retail products in its
wholly owned operations in Austria, the Czech Republic, Denmark, Finland,
Belgium, Luxembourg, Germany, Hungary, Norway, Poland, Slovakia, Sweden and the
United Kingdom. In addition, various joint ventures in which ConocoPhillips has
an equity interest market products in Switzerland and Turkey under the "Coop"
and "Tabas" or "Turkpetrol" brand names, respectively.
As of December 31, 2002, ConocoPhillips had approximately 2,100 marketing
outlets in its wholly owned European operations, of which about 1,200 were
company-owned. Through ConocoPhillips' joint venture operations in Turkey and
Switzerland, the company also has an interest in an additional 770 sites.
The company's largest branded site networks are in Germany and the United
Kingdom, which account for 60 percent of total European branded units.
As of December 31, 2002, ConocoPhillips had 137 marketing outlets in its wholly
owned Thailand operations in Asia. In addition, through a joint venture in
Malaysia with Sime Darby Bhd., a company that has a major presence in the
Malaysian business sector, ConocoPhillips also has an interest in another 25
retail sites. In Thailand and Malaysia, retail products are marketed under the
"JET" and "ProJET" brands, respectively.
CHEMICALS
---------
On July 1, 2000, ConocoPhillips and ChevronTexaco combined their worldwide
chemicals businesses, excluding ChevronTexaco's Oronite business, into a new
company, Chevron Phillips Chemical Company LLC (CPChem). In addition to
contributing the assets and operations included in the company's Chemicals
segment, ConocoPhillips also contributed the natural gas liquids business
associated with its Sweeny, Texas, complex. ConocoPhillips and ChevronTexaco
each own 50 percent of CPChem. ConocoPhillips uses the equity method of
accounting for its investment in CPChem.
CPChem, headquartered in The Woodlands, Texas, has 32 production facilities and
six research and technology centers. CPChem uses natural gas liquids and other
feedstocks to produce petrochemicals such as ethylene, propylene, styrene,
benzene and paraxylene. These products are then marketed and sold, or used as
feedstocks to produce plastics and specialty chemicals, such as polyethylene,
cumene, and cyclohexane.
CPChem's domestic facilities are located at Baytown, Borger, Conroe, La Porte,
Orange, Pasadena, Port Arthur and Old Ocean, Texas; St. James, Louisiana;
Pascagoula, Mississippi; Marietta, Ohio; and Guayama, Puerto Rico. CPChem also
has nine plastic pipe plants and one pipe fittings plant in eight states.
Major international facilities are located or under construction in Belgium,
China, Saudi Arabia, Singapore, South Korea and Qatar. There is one plastic pipe
plant in Mexico.
Construction continued in Qatar on a major olefins and polyolefins complex,
named Q-Chem I. The facility is designed to have an annual capacity of 1.1
billion pounds of ethylene, 1 billion pounds of polyethylene and 100 million
pounds of 1-hexene. Construction of the complex, located in Mesaieed, Qatar, is
nearing completion and the complex is undergoing commissioning. CPChem has a 49
percent interest, with a Qatar state-firm owning the remaining 51 percent
interest. CPChem also signed an agreement for the development of a complex to be
built in Ras Laffan, Qatar, named Q-Chem II. The facility will be an integrated
ethylene and polyethylene complex. Final approval of Q-Chem II is anticipated in
mid-2004, with startup expected in 2007.
25
CPChem announced plans in 2002 for a 50 percent-owned joint venture project in
Al Jubail, Saudi Arabia. The project, expected to cost approximately $1 billion,
is planned to produce styrene and propylene. Final approval of the project is
anticipated in the fourth quarter of 2003, with operational start-up expected in
2006.
A brief description of CPChem's major product lines follows.
OLEFINS AND POLYOLEFINS
Ethylene: Ethylene is a simple olefin used primarily to produce plastics, such
as polyethylene. Ethylene is produced at Old Ocean, Port Arthur and Baytown,
Texas. CPChem's net annual capacity at December 31, 2002, was approximately 7.6
billion pounds.
Polyethylene: Polyethylene is used to make a wide variety of plastic products,
including trash bags, milk jugs, bottles and plastic films. Polyethylene is
produced at Pasadena, Baytown, and Orange, Texas, as well as in China and
Singapore. CPChem's net annual capacity at December 31, 2002, was approximately
5.1 billion pounds.
Plastic Pipe: Polyethylene is used to manufacture plastic pipe and pipe
fittings. Plastic pipe is produced at nine plants in the United States and one
plant in Mexico. Pipe fittings are produced at one plant in the United States.
CPChem's net annual capacity at December 31, 2002, was approximately 544 million
pounds.
Normal Alpha Olefins: Normal alpha olefins can be custom blended for special
applications and are used extensively as polyethylene comonomers and in
plasticizers, synthetic motor oils and lubricants. Normal alpha olefins are
produced at Baytown, Texas. CPChem's net annual capacity at December 31, 2002,
was approximately 1.3 billion pounds.
AROMATICS AND STYRENICS
Styrene: Styrene, produced from benzene and ethylene, is used as a feedstock for
polystyrene and other applications. Styrene is produced at St. James, Louisiana.
CPChem's net annual capacity at December 31, 2002, was approximately 2.1 billion
pounds.
Polystyrene: Polystyrene is a thermoplastic polymer used in cups, disposable
cameras, disposable signs, and other applications. It is produced at Marietta,
Ohio, and in China. CPChem's net annual capacity at December 31, 2002, was
approximately 990 million pounds.
Benzene: Benzene is used to make cumene, cyclohexane, styrene and other
products. Benzene is produced at Pascagoula, Mississippi; Port Arthur, Texas;
and in Saudi Arabia. CPChem's net annual capacity at December 31, 2002, was
approximately 2.7 billion pounds.
Cyclohexane: Cyclohexane is a derivative of benzene that is used as a feedstock
for nylon. It is produced at Port Arthur, Texas, and in Saudi Arabia. CPChem
markets all of its own cyclohexane production, as well as that of its
affiliates. CPChem's net annual capacity at December 31, 2002, was approximately
575 million pounds. In addition, CPChem markets cyclohexane production from
ConocoPhillips' Sweeny and Borger complexes.
K-Resin(R): K-Resin(R) is a styrene-butadiene (SBC) copolymer used to produce a
clear, shatter-resistant resin. It is produced at the Houston Chemical Complex
(HCC) in Pasadena, Texas, and in South Korea. Production of K-Resin SBC at HCC
was idled in March 2000 as a result of an accident and fire at the plant. The
plant began a phased-in start-up in the fourth quarter of 2001 and the force
majeure status of the plant was lifted in May 2002. CPChem's annual capacity at
HCC at December 31, 2002, was
26
approximately 270 million pounds. CPChem also has a net annual capacity of 69
million pounds at an equity affiliate's plant in Yochon, South Korea.
Paraxylene: Paraxylene is an aromatic used as a feedstock for polyester. It is
produced at Pascagoula, Mississippi. CPChem's net annual capacity at December
31, 2002, was approximately 1.0 billion pounds.
SPECIALTY PRODUCTS
Specialty Chemicals: CPChem manufactures, markets and distributes organosulfur,
paraffinic, olefinic and aromatic specialty chemicals as well as a complete line
of natural gas odorants, specialty catalysts, specialty fuels, mining chemicals
and oilfield drilling additives, enhancers and cements. These products are
manufactured and processed in Borger and Conroe, Texas and Tessenderlo, Belgium.
Ryton(TM) Polyphenylene Sulfide: CPChem produces high-performance polyphenylene
sulfide polymers sold under the trademark Ryton(TM), which is produced at
Borger, Texas. CPChem's annual capacity of Ryton polymer at December 31, 2002,
was 22 million pounds. Ryton compounds are produced in Belgium and Singapore.
These facilities have a net annual capacity of approximately 29 million pounds
of Ryton compounds in the aggregate.
CPChem has research facilities in Oklahoma, Ohio, and Texas, as well as in
Singapore and Brussels, Belgium.
EMERGING BUSINESSES
-------------------
Emerging businesses encompass the development of new businesses beyond the
company's traditional operations.
CARBON FIBERS
In 2002, ConocoPhillips completed the construction of its first carbon fibers
manufacturing plant located in Ponca City, Oklahoma. ConocoPhillips confronted
technology issues during construction, which resulted in a delay in the
development of carbon fibers applications. As a result of market, operating and
technological uncertainties, the company announced in February 2003 that it
would shut down this project.
GAS-TO-LIQUIDS (GTL)
The GTL process refines natural gas into a wide range of transportable products.
ConocoPhillips' GTL research facility is located in Ponca City, Oklahoma. The
research facility includes laboratories and pilot plants to facilitate
technology advancements. A 400 barrel-per-day pilot plant, designed to produce
clean fuels from natural gas, is under construction in Ponca City and scheduled
for completion in 2003.
FUELS TECHNOLOGY
ConocoPhillips' fuels technology businesses provide technologies and services
that can be used in the company's operations or licensed to third parties.
Downstream, major product lines include sulfur removal technologies (S Zorb),
alkylation technologies (ReVAP), and delayed coking technologies. For upstream
and downstream, fuels technology offers analytical services, pilot plant, and
industrial hygiene services.
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POWER GENERATION
The focus of the power business is on developing integrated projects in support
of the company's E&P and R&M strategies and business objectives. The projects
that enable these strategies are included within the respective E&P and R&M
segments. The projects and assets that have a significant merchant component are
included in the Emerging Business segment.
The power business is developing a 730-megawatt gas-fired combined heat and
power plant in North Lincolnshire, United Kingdom. The facility will provide
steam and electricity to the Humber refinery and steam to a neighboring
refinery, as well as market power into the U.K. market. Construction began in
2002, with commercial operation anticipated in 2004.
ConocoPhillips also owns or has an interest in gas-fired cogeneration plants in
Orange and Corpus Christi, Texas.
EMERGING TECHNOLOGY
Emerging Technology focuses on developing new business opportunities designed to
provide growth options for ConocoPhillips well into the future. Example areas of
interest include renewable energy, advanced hydrocarbon processes, energy
conversion technologies and new petroleum-based products.
COMPETITION
ConocoPhillips competes with private, public and state-owned companies in all
facets of the petroleum and chemicals businesses. Some of the company's
competitors are larger and have greater resources. Each of the segments in which
ConocoPhillips operates is highly competitive. No single competitor, or small
group of competitors, dominates any of ConocoPhillips' business lines.
Upstream, the company's E&P segment competes with numerous other companies in
the industry to locate and obtain new sources of supply, and to produce oil and
natural gas in an efficient, cost-effective manner. Based on reserves statistics
published in the September 9, 2002, issue of the Oil and Gas Journal,
ConocoPhillips had the sixth-largest total of worldwide reserves of
non-state-owned companies. The company delivers its oil and natural gas
production into the worldwide oil and natural gas commodity markets. The
principal methods of competing include geological, geophysical and engineering
research and technology; experience and expertise; and economic analysis in
connection with property acquisitions.
The company's Midstream segment, through its equity investment in DEFS and its
consolidated operations, competes with numerous other integrated petroleum
companies, as well as natural gas transmission and distribution companies, to
deliver the components of natural gas to end users in the commodity natural gas
markets. DEFS is one of the largest producers of natural gas liquids in the
United States, based on the November 18, 2002, Gas Processors Report. DEFS'
principle methods of competing include economically securing the right to
purchase raw natural gas into its gathering systems, managing the pressure of
those systems, operating efficient natural gas liquids processing plants, and
securing markets for the products produced.
Downstream, the company's R&M segment competes primarily in the United States,
Europe and the Asia Pacific region. Based on the statistics published in the
December 23, 2002, issue of the Oil and Gas Journal, ConocoPhillips had the
largest U.S. refining capacity of about 20 large refiners of petroleum products.
In the Chemicals' segment, through its equity investment in CPChem, the company
generally ranks in the middle of approximately 10 major competitors, based on
ethylene, polyethylene, benzene and
28
styrene production capacity at year-end 2002, as published by Chemical Market
Associates Inc. Petroleum products are primarily delivered into U.S. commodity
markets, while petrochemicals and plastics are delivered into the worldwide
commodity markets. Elements of downstream competition include product
improvement, new product development, low-cost structures, and manufacturing and
distribution systems. In the marketing portion of the business, competitive
factors include product properties and processibility, reliability of supply,
customer service, price and credit terms, advertising and sales promotion, and
development of customer loyalty to ConocoPhillips' or CPChem's branded products.
GENERAL
At the end of 2002, ConocoPhillips held a total of 2,043 active patents in 72
countries worldwide, including 737 active U.S. patents. During 2002, the company
received 61 patents in the United States and 134 foreign patents. The company's
products and processes generated licensing revenues of $28 million in 2002. The
overall profitability of any business segment is not dependent on any single
patent, trademark, license, franchise or concession.
Company-sponsored research and development activities charged against earnings
were $355 million, $44 million and $43 million in 2002, 2001 and 2000,
respectively.
The environmental information contained in Management's Discussion and Analysis
on pages 66 through 70 under the caption, "Environmental" is incorporated herein
by reference. It includes information on expensed and capitalized environmental
costs for 2002 and those expected for 2003 and 2004.
Like all major, international oil companies, the company has for many years
operated in countries that are subject to U.S. Government restrictions or
prohibitions on business activities by U.S. companies. In some cases, business
is permitted if the company has received a license from the Office of Foreign
Assets Control (OFAC). In some cases where the company is prohibited from doing
business, non-U.S. subsidiaries of the company are not restricted. The
regulations implementing the restrictions are complicated and subject to
interpretation by OFAC. The company has programs designed to ensure compliance
with the restrictions and believes that its present operations do not violate
the restrictions.
In view of recent political, diplomatic and military developments in the Middle
East, and throughout the world, the company is reexamining its policies and
procedures in order to prevent any actions that would violate the letter, or
even the spirit of the restrictions. These developments may affect prices,
production levels, allocation and distribution of raw materials and products,
including their import, export and ownership; the amount of tax and timing of
payment; and the cost of compliance with environmental regulations. In recent
weeks, a number of institutional investors and state governmental agencies have
questioned the appropriateness of U.S. companies transacting business in or
with any country that has reportedly been linked to terrorism, even if the
country is not subject to legal restrictions. The company is also reexamining
its policies to seek to ensure that its activities in or with certain countries
is consistent with the U.S. government's policy, interests and objectives in
such countries. Political or military developments, enactment by the U.S. of
new legal restrictions, more stringent interpretation of existing legal
restrictions, or decisions by the company to voluntarily cease operations in
certain areas in order to protect its reputation could materially adversely
affect the company.
ITEM 3. LEGAL PROCEEDINGS
The following is a description of legal proceedings involving governmental
authorities under federal, state and local laws regulating the discharge of
materials into the environment for this reporting period. The
29
following proceedings include those matters previously reported in Conoco's and
Phillips' respective 2001 Forms 10-K, first- and second- quarter 2002 Forms 10-Q
and ConocoPhillips' third-quarter 2002 Form 10-Q that have not been resolved.
While it is not possible to predict the outcome of such proceedings, if any of
such proceeding were decided adversely to ConocoPhillips, there would be no
material effect on the company's consolidated financial position. Nevertheless,
such proceedings are reported pursuant to the United States Securities and
Exchange Commission's regulations.
ConocoPhillips has responded to information requests from the United States
Environmental Protection Agency (EPA) regarding New Source Review compliance
at its Alliance, Bayway, Borger, Ferndale, Los Angeles, Rodeo, Santa Maria,
Sweeny, Trainer and Wood River refineries. Although ConocoPhillips has not
been notified of any formal findings or violations arising from these
information requests, ConocoPhillips has been informed that the EPA is
contemplating the filing of a civil proceeding against ConocoPhillips for
alleged violations of the Clean Air Act. ConocoPhillips currently seeks a
negotiated resolution of these matters which will likely result in increased
environmental capital expenditures and governmental monetary sanctions.
On December 31, 2002, the company received a Revised Proposed Agreed Order,
which amended the June 24, 2002, Proposed Agreed Order, from the Texas
Commission on Environmental Quality (TCEQ), proposing a penalty of $458,163 in
connection with alleged air emission violations at the company's Borger, Texas,
refinery as a result of an inspection conducted by the TCEQ in October 2000. On
March 19, 2003, the TCEQ issued a recalculation of the proposed penalty in the
amount of $467,834.
On December 17, 2002, the United States Department of Justice (DOJ) notified
ConocoPhillips of various alleged violations of the National Pollution
Discharge Elimination System (NPDES) Permit for the Sweeny Refinery. DOJ
asserts that these alleged violations occurred at various times during the
period beginning January 1997 through July 2002. DOJ seeks a civil penalty in
the amount of $1.6 million.
On November 14, 2002, the TCEQ issued a proposed agreed Findings Order to
resolve alleged water discharge violations of the Texas Water Code and
Commission Rules at the Sweeny Refinery for the period beginning March 2000
through July 2002. The proposed order assesses a penalty in the amount of
$488,125.
On September 27, 2002, the Montana Department of Environmental Quality (MDEQ)
issued a Notice of Violation (NOV) to ConocoPhillips. The NOV alleges that on
December 13, 2000, the company discharged 52,374 gallons of gasoline from Tank
32 at its Helena, Montana product storage terminal. The NOV seeks a penalty in
the amount of $114,000. The company anticipates that this matter will be settled
early in the second quarter of 2003.
On September 26, 2002, the EPA Region 5 filed an Administrative Complaint
against the company alleging federal clean air act compliance violations
associated with a product tank roof seal during the period December 15, 1997
through October 1, 2001. On November 25, 2002, the company and the EPA entered
into a Consent Agreement and Final Order requiring the company to pay a
$46,381 cash penalty and perform a supplemental environmental project (SEP).
The SEP is estimated to cost approximately $180,000.
On July 15, 2002, the United States filed a Comprehensive Environmental
Response, Compensation and Liability Act (CERCLA) cost recovery action against
the company alleging that the United States has incurred unreimbursed oversight
costs at the Lowry Superfund Site located in Arapahoe County, Colorado. The
United States seeks recovery of approximately $12.3 million in past oversight
costs and a declaratory judgment for future CERCLA response cost liability.
Pursuant to the terms of a prior settlement agreement between the company, Waste
Management, Inc. and others, Waste Management has assumed the
30
company's defense for this matter and it is the company's position that Waste
Management should indemnify it for any liability arising from this action.
On June 28, 2002, the company received an administrative civil complaint from
the EPA, alleging violation of Emergency Planning and Community Right to Know
Act found during an audit of the Los Angeles refinery in March 2000. This matter
was settled in the first quarter of 2003.
The company conducted negotiations with the EPA and the states of Colorado,
Louisiana, Montana, and Oklahoma throughout 2001 as part of the EPA's nationwide
initiative to enforce federal air regulations at petroleum refineries. In
December 2001, the company entered into a Consent Decree with the United States,
Colorado, Louisiana, Montana, and Oklahoma to reduce emissions from the
company's Billings, Denver, Lake Charles and Ponca City refineries by a total of
7,500 tons per year over the subsequent seven years. The company expects to
spend an estimated $95 million to $110 million over that time period to install
control technology and equipment to reduce emissions from stacks, vents, valves,
heaters, boilers and flares. The Consent Decree required and the company has
paid a civil penalty of $1.5 million, in addition to requiring $5.1 million to
be spent on supplemental environmental projects in Colorado, Louisiana, Montana
and Oklahoma. This Consent Decree also resolves certain refinery air compliance
issues previously self-disclosed to the state environmental agencies for
Colorado, Montana and Oklahoma. Other self-disclosed air compliance issues that
were outside the scope of the Consent Decree have been or will be resolved by
consent orders entered directly with the appropriate state agency.
During August 2001, the EPA and the DOJ notified the company of their intent
to seek sanctions for alleged violations of the Clean Air Act arising from a
1998 Maximum Achievable Control Technology (MACT) compliance test of a flare at
the company's Denver refinery. The matter was settled in the fourth quarter of
2002.
In June of 1997, the company experienced pipeline spills on its Seminoe pipeline
at Banner, Wyoming, and Lodge Grass, Montana. In response to these spills, the
DOJ advised the company in August 2000 that the United States is contemplating a
legal proceeding under the Clean Water Act against the company. The company and
DOJ are currently in negotiations to resolve these matters.
In addition to the above environmental matters, on March 27, 2000, an explosion
and fire occurred at the K-Resin SBC plant due to the overpressurization of an
out-of-service butadiene storage tank. One employee was killed and several
individuals, including employees of both ConocoPhillips and its contractors,
were injured. Additionally, individuals who were allegedly in the area of the
Houston Chemical Complex at the time of the incident have claimed they suffered
various personal injuries due to exposure to the event. The wrongful death claim
and the claims of the most seriously injured workers have been resolved.
Currently, there are eight lawsuits pending on behalf of approximately 100
primarily plaintiffs. Under the indemnification provisions of subcontracting
agreements with Zachry Construction Corporation and Brock Maintenance, Inc.,
ConocoPhillips sought indemnification from these subcontractors with respect to
claims made by their employees. Although that plant was contributed to CPChem
under the Contribution Agreement, ConocoPhillips retains liability for damages
arising out of the incident.
Additionally, the company is subject to various lawsuits and claims including,
but not limited to: actions challenging oil and gas royalty and severance tax
payments; actions related to gas measurement and valuation methods; actions
related to joint interest billings to operating agreement partners; claims for
damages resulting from leaking underground storage tanks; and toxic tort claims.
As a result of Conoco's separation agreement with DuPont, ConocoPhillips also
has assumed responsibility for current and future claims related to certain
discontinued chemicals and agricultural chemicals businesses operated by Conoco
in the past. In general, the effect on future financial results is not subject
to reasonable estimation because
31
considerable uncertainty exists. The ultimate liabilities resulting from such
lawsuits and claims may be material to results of operations in the period in
which they are recognized.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Position Held Age*
---- ------------- ----
Rand C. Berney Vice President and Controller 47
William B. Berry Executive Vice President, Exploration and Production 50
John A. Carrig Executive Vice President, Finance, and Chief Financial Officer 51
Archie W. Dunham Chairman of the Board of Directors 64
Philip L. Frederickson Executive Vice President, Commercial 46
Rick A. Harrington Senior Vice President, Legal, and General Counsel 58
John E. Lowe Executive Vice President, Planning and Strategic Transactions 44
Robert E. McKee III Executive Vice President 56
J. J. Mulva President and Chief Executive Officer 56
J. W. Nokes Executive Vice President, Refining, Marketing, Supply and Transportation 56
----------
*On March 1, 2003.
There is no family relationship among the officers named above. Each officer of
the company is elected by the Board of Directors at its first meeting after the
Annual Meeting of Stockholders and thereafter as appropriate. Each officer of
the company holds office from date of election until the first meeting of the
directors held after the next Annual Meeting of Stockholders or until a
successor is elected. The date of the next annual meeting is May 6, 2003. Set
forth below is information concerning the executive officers.
32
RAND C. BERNEY was appointed Vice President and Controller of ConocoPhillips
upon completion of the merger. Prior to the merger, he was Phillips' Vice
President and Controller since 1997.
WILLIAM B. BERRY was appointed Executive Vice President, Exploration and
Production of ConocoPhillips on January 1, 2003, having previously served as
President of ConocoPhillips' Asia Pacific operations since completion of the
merger. Prior to the merger, he was Phillips' Senior Vice President E&P
Eurasia-Middle East operations since 2001; and Phillips' Vice President E&P
Eurasia operations since 1998.
JOHN A. CARRIG was appointed Executive Vice President, Finance, and Chief
Financial Officer of ConocoPhillips upon completion of the merger. Prior to the
merger, he was Phillips' Senior Vice President and Chief Financial Officer since
2001; Phillips' Senior Vice President, Treasurer and Chief Financial Officer
since 2000; and Phillips' Vice President and Treasurer since 1996.
ARCHIE W. DUNHAM was appointed Chairman of the Board of Directors of
ConocoPhillips upon completion of the merger. Prior to the merger, he was
Conoco's Chairman of the Board, President and Chief Executive Officer since
1999; and Conoco's President and Chief Executive Officer since 1996.
PHILIP L. FREDERICKSON was appointed Executive Vice President, Commercial of
ConocoPhillips upon completion of the merger. Prior to the merger, he was
Conoco's Senior Vice President of Corporate Strategy and Business Development
since 2001; and Conoco's Vice President of Business Development since 1998.
RICK A. HARRINGTON was appointed Senior Vice President, Legal, and General
Counsel of ConocoPhillips upon completion of the merger. Prior to the merger, he
was Conoco's Senior Vice President, Legal and General Counsel since 1998.
JOHN E. LOWE was appointed Executive Vice President, Planning and Strategic
Transactions of ConocoPhillips upon completion of the merger. Prior to the
merger, he was Phillips' Senior Vice President, Corporate Strategy and
Development since 2001; Phillips' Senior Vice President of Planning and
Strategic Transactions since 2000; Phillips' Vice President of Planning and
Strategic Transactions since 1999; Phillips' Manager of Strategic Growth
Projects since earlier in 1999; and Phillips' Supply Chain Manager in refining,
marketing and transportation since 1997.
ROBERT E. MCKEE III was appointed Executive Vice President of ConocoPhillips on
January 1, 2003, having previously served as Executive Vice President,
Exploration and Production since the completion of the merger. Prior to the
merger, he was Conoco's Executive Vice President, Exploration Production since
1996.
J. J. MULVA was appointed President and Chief Executive Officer of
ConocoPhillips upon completion of the merger. Prior to the merger, he was
Phillips' Chairman of the Board of Directors and Chief Executive Officer since
1999; Phillips' Vice Chairman of the Board of Directors, President, and Chief
Executive Officer since earlier in 1999; and Phillips' President and Chief
Operating Officer since 1994.
J. W. NOKES was appointed Executive Vice President, Refining, Marketing, Supply
and Transportation of ConocoPhillips upon completion of the merger. Prior to the
merger, he was Conoco's Executive Vice President, Worldwide Refining, Marketing,
Supply and Transportation since 1999; and Conoco's President of North American
Refining and Marketing since 1998.
33
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
QUARTERLY COMMON STOCK PRICES AND CASH DIVIDENDS PER SHARE
Phillips Petroleum Company's (predecessor to ConocoPhillips) stock was traded
primarily on the New York, Pacific and Toronto stock exchanges. On August 30,
2002, it ceased trading.
Stock Price
----------------------
Phillips Petroleum Company (predecessor to ConocoPhillips) High Low Dividends
---------------------- ---------
2002
First $ 63.80 55.30 .36
Second 64.10 54.53 .36
Third (through August 30) 59.21 44.75 N/A
------------------------------------------------------------------------------------------------------------
2001
First $ 59.00 51.70 .34
Second 68.00 52.78 .34
Third 59.86 50.00 .36
Fourth 60.95 50.66 .36
------------------------------------------------------------------------------------------------------------
ConocoPhillips' common stock began trading on September 3, 2002, the first
trading day after the effective date of the merger.
Stock Price
----------------------
High Low Dividends
---------------------- ---------
2002
Third (from September 3) $ 53.20 45.87 .36
Fourth 50.75 44.03 .40
------------------------------------------------------------------------------------------------------------
Closing Stock Price at December 31, 2002 $ 48.39
Number of Stockholders of Record at February 28, 2003 60,666
------------------------------------------------------------------------------------------------------------
ConocoPhillips' common stock is traded on the New York Stock Exchange.
34
ITEM 6. SELECTED FINANCIAL DATA
Millions of Dollars Except Per Share Amounts
-----------------------------------------------------
2002 2001 2000 1999 1998
-----------------------------------------------------
Sales and other operating revenues* $ 56,748 24,892 22,155 14,988 12,853
Income from continuing operations* 714 1,611 1,848 604 228
Per common share
Basic 1.48 5.50 7.26 2.39 .88
Diluted 1.47 5.46 7.21 2.37 .88
Net income (loss) (295) 1,661 1,862 609 237
Per common share
Basic (.61) 5.67 7.32 2.41 .92
Diluted (.61) 5.63 7.26 2.39 .91
Total assets 76,836 35,217 20,509 15,201 14,216
Long-term debt* 18,917 8,610 6,622 4,271 4,106
Mandatorily redeemable other minority interests and
preferred securities 491 650 650 650 650
Cash dividends declared per
common share 1.48 1.40 1.36 1.36 1.36
-----------------------------------------------------------------------------------------------------------
*Restated to exclude discontinued operations.
See Management's Discussion and Analysis of Financial Condition and Results of
Operations for a discussion of factors that will enhance an understanding of
this data. The following transactions affect the comparability of the amounts
included in the table above:
o the merger of Conoco and Phillips in 2002;
o the acquisition of Tosco Corporation in 2001;
o the acquisition of Atlantic Richfield Company's Alaskan operations
in 2000; and
o the contribution of a significant portion of the company's midstream
and chemicals businesses into joint ventures accounted for using
equity-method accounting in 2000.
35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
March 24, 2003
Management's Discussion and Analysis is the company's analysis of its financial
performance and of significant trends that may affect future performance. It
should be read in conjunction with the financial statements and notes, and
supplemental oil and gas disclosures. It contains forward-looking statements
including, without limitation, statements relating to the company's plans,
strategies, objectives, expectations, intentions, and resources that are made
pursuant to the "safe harbor" provisions of the Private Securities Litigation
Reform Act of 1995. The words "intends," "believes," "expects," "plans,"
"scheduled," "anticipates," "estimates," and similar expressions identify
forward-looking statements. The company does not undertake to update, revise or
correct any of the forward-looking information. Readers are cautioned that such
forward-looking statements should be read in conjunction with the company's
disclosures under the heading: "CAUTIONARY STATEMENT FOR THE PURPOSES OF THE
'SAFE HARBOR' PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF
1995," beginning on page 76.
RESULTS OF OPERATIONS
CONOCO AND PHILLIPS MERGER
On August 30, 2002, Conoco Inc. (Conoco) and Phillips Petroleum Company
(Phillips) combined their businesses by merging with wholly owned subsidiaries
of a new company named ConocoPhillips (the merger). The merger was accounted for
using the purchase method of accounting. Although the business combination of
Conoco and Phillips was a merger of equals, generally accepted accounting
principles required that one of the two companies in the transaction be
designated as the acquirer for accounting purposes. Phillips was designated as
the acquirer based on the fact that its former common stockholders initially
held more than 50 percent of the ConocoPhillips common stock after the merger.
Because Phillips was designated as the acquirer, its operations and results are
presented in this annual report for all periods prior to the close of the
merger. From the merger date forward, the operations and results of
ConocoPhillips reflect the combined operations of the two companies.
As a condition of the merger, the U.S. Federal Trade Commission (FTC) required
that the company divest specified Conoco and Phillips assets, the most
significant of which were Phillips' Woods Cross, Utah, refinery and associated
motor fuel marketing operations; Conoco's Commerce City, Colorado, refinery and
related crude oil pipelines and Phillips' Colorado motor fuel marketing
operations. All assets and operations that are required by the FTC to be
divested are included in Corporate and Other as discontinued operations.
Included in the results of discontinued operations in 2002 was a $69 million
after-tax charge for the write-down to fair value of the Phillips operations to
be disposed. Because the Conoco assets to be disposed of were recorded at fair
value in the purchase price allocation, no further write-downs were required.
Discontinued operations also include other, non-FTC mandated assets held for
sale. See Note 4--Discontinued Operations in the Notes to Consolidated Financial
Statements for additional information, including a complete list of assets
required by the FTC to be divested.
As a result of the merger, the company implemented a restructuring program in
September 2002 to capture the synergies of combining Phillips and Conoco by
eliminating redundancies, consolidating assets, and sharing common services and
functions across regions. The restructuring program that was implemented in
September 2002 is expected to be completed by the end of February 2004 and,
through December 31,
36
2002, approximately 2,900 positions worldwide, most of which are in the United
States, had been identified for elimination. Of this total, 775 employees were
terminated by December 31, 2002. Associated with implementation of the
restructuring program, ConocoPhillips accrued $770 million for merger-related
restructuring and work force reduction liabilities in 2002. These liabilities
primarily represent estimated termination payments and related employee benefits
associated with the reduction in positions. These liabilities include $337
million related to Conoco operations, which was reflected in the purchase price
allocation as an assumed liability, and $422 million ($253 million after-tax)
related to Phillips operations that was charged to selling, general and
administrative, and production and operating expenses; and $11 million
before-tax included in discontinued operations. Of the above accruals, $598
million related primarily to severance benefits. Payments will be made to former
Conoco and Phillips employees under each company's respective severance plans.
During 2002, payments of $223 million were made, resulting in a year-end 2002
severance accrual balance of $375 million.
Also related to the merger and recorded in 2002 was a $246 million write-off of
acquired in-process research and development costs related to Conoco's natural
gas-to-liquids and other technologies. In accordance with Financial Accounting
Standards Board (FASB) Interpretation No. 4, "Applicability of FASB Statement
No. 2 to Business Combinations Accounted for by the Purchase Method," value
assigned to research and development activities in the purchase price allocation
that have no alternative future use should be charged to expense at the date of
the consummation of the combination. The $246 million charge was recorded in the
Emerging Businesses segment and was the same on both a before-tax and after-tax
basis.
ConocoPhillips also accrued $22 million, after-tax, in 2002 for
change-in-control costs associated with seismic contracts as a result of the
merger. The expense was recorded in Corporate and Other and did not impact
exploration expenses. In addition, the 2002 net loss also included transition
costs of $36 million, bringing total after-tax merger-related costs to $557
million. See Note 3--Merger of Conoco and Phillips in the Notes to Consolidated
Financial Statements for additional information on the merger.
CONSOLIDATED RESULTS
Millions of Dollars
--------------------------
Years Ended December 31 2002 2001 2000
--------------------------
Income from continuing operations $ 714 1,611 1,848
Income (loss) from discontinued operations (993) 32 14
Extraordinary items (16) (10) --
Cumulative effect of accounting changes -- 28 --
-----------------------------------------------------------------------
Net income (loss) $ (295) 1,661 1,862
=======================================================================
37
A summary of the company's net income (loss) by business segment follows:
Millions of Dollars
-----------------------------
Years Ended December 31 2002 2001 2000
-----------------------------
Exploration and Production (E&P) $ 1,749 1,699 1,945
Midstream 55 120 162
Refining and Marketing (R&M) 143 397 238
Chemicals (14) (128) (46)
Emerging Businesses (310) (12) --
Corporate and Other* (1,918) (415) (437)
----------------------------------------------------------------------------------------
Net income (loss) $ (295) 1,661 1,862
========================================================================================
*Includes income (loss) from discontinued operations of: $ (993) 32 14
2002 vs. 2001
ConocoPhillips incurred a net loss of $295 million in 2002, compared with net
income of $1,661 million in 2001. The decrease was primarily attributable to
recognizing impairments and loss accruals totaling $1,077 million after-tax
associated with the company's retail and wholesale marketing operations that
were classified as discontinued operations in late 2002, as well as
merger-related costs totaling $557 million after-tax. Also negatively impacting
results for 2002 were asset impairments totaling $192 million after-tax, lower
refining margins, lower natural gas sales prices, decreased equity earnings from
Duke Energy Field Services, LLC (DEFS), and higher interest expenses. These
factors were partially offset by improved results from Chemicals and higher
production volumes in E&P after the merger.
2001 vs. 2000
ConocoPhillips' net income was $1,661 million in 2001, an 11 percent decline
from net income of $1,862 million in 2000. The decrease was primarily
attributable to lower crude oil and natural gas liquids prices and lower results
from the Chemicals business, partially offset by improved petroleum products
margins, as well as the acquisition of Tosco Corporation (Tosco) in September
2001. See Note 6--Acquisition of Tosco Corporation in the Notes to Consolidated
Financial Statements for additional information on the acquisition. Also
contributing to the lower results in 2001 was a decrease in the amount of gains
on asset sales, compared with 2000, partially offset by lower property
impairments in 2001.
INCOME STATEMENT ANALYSIS
2002 vs. 2001
In addition to the merger discussed previously, ConocoPhillips closed on the $7
billion acquisition of Tosco on September 14, 2001. Together, these transactions
significantly increased operating revenues, purchase costs, operating expenses
and other income statement line items. See Note 3--Merger of Conoco and Phillips
and Note 6--Acquisition of Tosco Corporation in the Notes to Consolidated
Financial Statements for additional information.
38
Sales and other operating revenues increased 128 percent in 2002. The increase
was primarily attributable to increased product sales volumes due to the impact
of the Tosco acquisition and the merger. These items were partially offset by
lower natural gas sales prices in 2002 compared with 2001.
Equity in earnings of affiliates increased 537 percent in 2002. In addition to
equity earnings from affiliates acquired in the merger for the last four months
of 2002, equity earnings from Chevron Phillips Chemical Company LLC (CPChem)
improved in 2002 as a result of improved margins. Partially offsetting these
items were lower earnings in 2002 from DEFS and Merey Sweeny, L.P. (MSLP). DEFS'
decline was primarily attributable to higher operating expenses, gas imbalance
adjustments, and lower natural gas liquids prices, while MSLP's decline was
mainly due to lower crude oil light-heavy differentials.
Other income increased 94 percent in 2002, mainly the result of a favorable
revaluation and settlement of long-term incentive performance units held by
former senior Tosco executives, as well as additional interest income following
the merger. During 2002, the company recorded gains totaling $59 million
before-tax, as the incentive performance units were marked-to-market each
reporting period and eventually settled. See Note 6--Acquisition of Tosco
Corporation in the Notes to Consolidated Financial Statements for more
information.
Purchased crude oil and products increased 176 percent in 2002. The increase
reflects higher purchase volumes of crude oil and petroleum products resulting
from the Tosco acquisition and the merger.
Production and operating expenses increased 89 percent in 2002, while selling,
general and administrative (SG&A) expenses increased 171 percent. Both increases
were primarily attributable to the Tosco acquisition and the merger. In
conjunction with the merger, ConocoPhillips wrote off $246 million of acquired
in-process research and development costs related to Conoco's natural
gas-to-liquids and other technologies to production and operating expenses in
2002. ConocoPhillips also expensed $135 million in merger-related costs to
production and operating expenses and $379 million to SG&A expenses in 2002.
Exploration expenses increased 93 percent in 2002. The increase reflects the
merger, a $77 million leasehold impairment of deepwater Block 34, offshore
Angola, and dry hole costs of $161 million in 2002, compared with $48 million in
2001.
Depreciation, depletion and amortization increased 65 percent in 2002, compared
with 2001. The increase was primarily the result of an increased depreciable
base of properties, plants and equipment following the merger and the Tosco
acquisition.
During 2002, ConocoPhillips recorded property impairments totaling $49 million
in connection with the sale of its Point Arguello assets, offshore California;
two fields in the U.K. North Sea; and its interest in a non-producing field in
Alaska. Impairment of tradenames ($102 million) was also recognized in the
statement of operations in 2002. Property impairments recorded in 2001 consisted
primarily of a $23 million impairment of the Siri field, offshore Denmark. See
Note 10--Impairments in the Notes to Consolidated Financial Statements for
additional information.
Taxes other than income taxes increased 153 percent in 2002, compared with 2001.
The increase reflects higher excise taxes due to higher petroleum products sales
and increased property and payroll taxes following the merger and the Tosco
acquisition.
Environmental liabilities assumed in acquisitions and mergers are recorded as
liabilities at discounted amounts--i.e. the total future estimated cost is
determined, then discounted back to current dollars using a time-value-of-money
concept. Over time the liability is increased by accretion to reflect the time
value of
39
money. Accretion on discounted liabilities increased 214 percent in 2002,
reflecting the impact of the environmental liabilities assumed in the Tosco
acquisition and the merger.
Interest expense increased 67 percent in 2002, mainly due to higher debt levels
following the Tosco acquisition and the merger. Foreign currency losses of $24
million were recorded in 2002, compared with losses of $11 million in 2001.
Preferred dividend requirements decreased in 2002, reflecting the redemption of
$300 million of preferred securities in May 2002.
The company's effective tax rate from continuing operations in 2002 was 67
percent, compared with 51 percent in 2001. The increase in the effective tax
rate in 2002 was primarily the result of the write-off of in-process research
and development costs without a corresponding tax benefit and a higher
proportion of income in higher-tax-rate jurisdictions.
Losses from discontinued operations were $993 million in 2002, compared with
income of $32 million in 2001. The 2002 amount includes after-tax impairments
and loss accruals. See Note 4--Discontinued Operations in the Notes to
Consolidated Financial Statements for additional information.
2001 vs. 2000
On March 31, 2000, ConocoPhillips and Duke Energy Corporation contributed their
midstream gas gathering, processing and marketing businesses to DEFS. Effective
July 1, 2000, ConocoPhillips and ChevronTexaco Corporation contributed their
chemicals businesses, excluding ChevronTexaco's Oronite business, to CPChem.
Both of these joint ventures are being accounted for using the equity method of
accounting, which significantly affects how these operations are reflected in
ConocoPhillips' consolidated statement of operations. Under the equity method of
accounting, ConocoPhillips' share of a joint venture's net income is recorded in
a single line item on the statement of operations: "Equity in earnings of
affiliates." Correspondingly, the other income statement line items (for
example, operating revenues, operating costs, etc.) include activity related to
these operations only up to the effective dates of the joint ventures.
Sales and other operating revenues increased 12 percent in 2001, primarily due
to the Tosco acquisition and increased crude oil production. These items were
partially offset by the use of equity-method accounting for the DEFS and CPChem
joint ventures, as well as a reduction in revenues attributable to certain
non-core assets sold at year-end 2000.
Equity in earnings of affiliated companies decreased 64 percent in 2001. In the
2001 period, ConocoPhillips incurred a before-tax equity loss from its
investment in CPChem of $240 million. ConocoPhillips' equity earnings related to
DEFS were higher in 2001, as a result of a full year's activity in 2001,
compared with only nine months in 2000. Equity earnings in 2001 benefited from a
full year's operations at MSLP, a 50-percent-owned equity company that owns and
operates the coker unit at the Sweeny, Texas, refinery. Other income decreased
59 percent in 2001, primarily attributable to lower net gains on asset sales in
2001 compared with 2000.
Total costs and expenses increased 16 percent in 2001, compared with 2000. The
increase was mainly the result of the Tosco acquisition, as well as a full
year's ownership of the company's Alaskan E&P operations that were acquired in
April 2000. These items were partially offset by the use of equity-method
accounting for the DEFS and CPChem joint ventures, and lower crude oil
acquisition costs at the company's refineries.
40
SEGMENT RESULTS
E&P
2002 2001 2000
------------------------------
Millions of Dollars
------------------------------
NET INCOME
Alaska $ 870 866 829
Lower 48 286 476 559
-------------------------------------------------------------------------------------------
United States 1,156 1,342 1,388
International 593 357 557
-------------------------------------------------------------------------------------------
$1,749 1,699 1,945
===========================================================================================
Dollars Per Unit
------------------------------
AVERAGE SALES PRICES
Crude oil (per barrel)
United States $23.83 23.57 28.83
International 25.14 24.16 28.42
Total consolidated 24.38 23.77 28.65
Equity affiliates 18.41 12.36 --
Worldwide 24.07 23.74 28.65
Natural gas--lease (per thousand cubic feet)
United States 2.75 3.56 3.47
International 2.79 2.60 2.56
Total consolidated 2.77 3.23 3.13
Equity affiliates 2.71 -- --
Worldwide 2.77 3.23 3.13
-------------------------------------------------------------------------------------------
AVERAGE PRODUCTION COSTS PER BARREL OF OIL EQUIVALENT
United States $ 5.66 5.52 5.27
International 3.99 2.70 2.85
Total consolidated 4.94 4.60 4.29
Equity affiliates 4.38 2.74 --
Worldwide 4.92 4.60 4.29
-------------------------------------------------------------------------------------------
FINDING AND DEVELOPMENT COSTS PER BARREL OF OIL
EQUIVALENT
United States $ 7.46 5.15 2.78
International* 5.09 6.80 1.17
Worldwide* 5.57 5.97 2.41
-------------------------------------------------------------------------------------------
*Includes ConocoPhillips' share of equity affiliates
Millions of Dollars
------------------------------
WORLDWIDE EXPLORATION EXPENSES
General administrative; geological and geophysical; and
lease rentals $ 285 207 168
Leasehold impairment 146 51 39
Dry holes 161 48 91
-------------------------------------------------------------------------------------------
$ 592 306 298
===========================================================================================
41
2002 2001 2000
------------------------------
Thousands of Barrels Daily
------------------------------
OPERATING STATISTICS
Crude oil produced
Alaska 331 339 207
Lower 48 40 34 34
-------------------------------------------------------------------------------------------
United States 371 373 241
Norway 157 117 114
United Kingdom 39 19 25
Canada 13 1 6
Other areas 67 51 51
-------------------------------------------------------------------------------------------
Total consolidated 647 561 437
Equity affiliates 35 2 --
-------------------------------------------------------------------------------------------
682 563 437
===========================================================================================
Natural gas liquids produced
Alaska 24 25 19
Lower 48 8 1 1
-------------------------------------------------------------------------------------------
United States 32 26 20
Norway 6 5 5
United Kingdom 2 2 2
Canada 4 -- 1
Other areas 2 2 1
-------------------------------------------------------------------------------------------
46 35 29
===========================================================================================
Millions of Cubic Feet Daily
------------------------------
Natural gas produced*
Alaska 175 177 158
Lower 48 928 740 770
-------------------------------------------------------------------------------------------
United States 1,103 917 928
Norway 171 130 136
United Kingdom 424 178 214
Canada 165 18 83
Other areas 180 92 33
-------------------------------------------------------------------------------------------
Total consolidated 2,043 1,335 1,394
Equity affiliates 4 -- --
-------------------------------------------------------------------------------------------
2,047 1,335 1,394
===========================================================================================
*Represents quantities available for sale. Excludes gas equivalent of natural
gas liquids shown above.
Thousands of Barrels Daily
------------------------------
Mining operations
Syncrude produced 8 -- --
-------------------------------------------------------------------------------------------
2002 vs. 2001
Net income from ConocoPhillips' E&P segment increased 3 percent in 2002.
Although E&P benefited from four months of increased production volumes in 2002
following the merger, this was mostly offset by lower natural gas sales prices,
higher exploration expenses, and the unfavorable $24 million impact of a tax law
change in the United Kingdom. ConocoPhillips' average worldwide crude oil sales
price was
42
$24.07 per barrel in 2002, a 1 percent increase over $23.74 in 2001. The
company's average worldwide natural gas price in 2002 was $2.77 per thousand
cubic feet, a 14 percent decrease from $3.23 in 2001. However, natural gas
prices trended upward during 2002, with the company's December 2002 worldwide
price averaging $3.51 per thousand cubic feet.
ConocoPhillips' proved reserves at year-end 2002 were 7.81 billion barrels of
oil equivalent, a 52 percent increase over 5.13 billion barrels at year-end
2001. The increase was attributable to the merger.
2001 vs. 2000
Net income from ConocoPhillips' E&P segment decreased 13 percent in 2001, as the
positive impact of increased crude oil production was more than offset by lower
crude oil prices, and, to a lesser extent, lower natural gas production due
mainly to asset dispositions in Canada. Benefiting 2000 net income was higher
net gains on asset sales than in 2001. ConocoPhillips' average worldwide crude
oil sales price was $23.74 per barrel in 2001, a 17 percent decrease from $28.65
in 2000. Natural gas prices began 2001 at historically high levels, but trended
lower during the remainder of the year, with the company's December 2001 average
price at $2.34 per thousand cubic feet.
ConocoPhillips' proved reserves at year-end 2001 were 5.13 billion barrels of
oil equivalent, a 2 percent increase over 5.02 billion barrels at year-end 2000.
U.S. E&P
2002 vs. 2001
Net income from the company's U.S. E&P operations decreased 14 percent in 2002.
Although net income for 2002 benefited from four months of increased production
volumes following the merger, this was more than offset by lower natural gas
prices, lower production volumes in Alaska, and higher dry hole costs. The
company's U.S. average natural gas price in 2002 was 23 percent lower than 2001.
However, natural gas prices trended upward during 2002, with the company's
December 2002 average U.S. price at $3.66 per thousand cubic feet.
The company's U.S. crude oil production decreased slightly in 2002, while
natural gas production increased 20 percent. The increase in natural gas
production was mainly due to four months of production from fields acquired in
the merger. The merger impact on total crude oil production was offset by lower
production in Alaska, which experienced normal field declines, along with
operating interruptions at the Prudhoe Bay field during the year. With a full
year's combined production from both Conoco and Phillips operations, the company
expects that its total U.S. oil and gas production volumes will increase in 2003
over those of 2002. ConocoPhillips' fourth quarter production volumes, which
included a full period of combined operations, averaged 426,000 barrels per day
of liquids and 1,548 million cubic feet per day of natural gas.
2001 vs. 2000
Net income from the company's U.S. E&P operations decreased 3 percent in 2001,
compared with 2000. The 2001 results reflect a 55 percent increase in crude oil
production, due to a full year's production from the Alaska operations acquired
in April 2000, as well as increased production due to the startup of the Alpine
field in Alaska in December 2000. The benefit of increased crude oil production
was offset by
43
lower U.S. crude oil prices, which declined 18 percent in 2001. U.S. natural gas
production declined slightly in 2001, reflecting field declines and asset
dispositions. Benefiting 2000 net income was a net gain on asset sales of $44
million--most of which was related to the disposition of the company's coal and
lignite operations.
International E&P
2002 vs. 2001
Net income from the company's international E&P operations increased 66 percent
in 2002. The improvement reflects four months of increased production volumes
following the merger. However, 2002 net income included a $24 million deferred
tax charge related to tax law changes in the United Kingdom. In April 2002, the
U.K. government announced proposed changes to corporate tax laws specifically
impacting the oil and gas industry and production from the U.K. sector of the
North Sea. The proposed changes became law in July 2002. A 10 percent
supplementary charge to corporation taxes is now assessed on profits, which is
expected to be partially offset by the elimination of royalties and an increase
in first-year deduction allowances for capital investments. Net income in 2002
also included a $77 million leasehold impairment of deepwater Block 34, offshore
Angola, due to an unsuccessful exploratory well in the block, along with higher
dry hole charges.
The company's international crude oil production increased 64 percent in 2002,
while natural gas production increased 126 percent. The increases were mainly
due to the addition of four months of production from fields acquired in the
merger. With a full year's combined production from both Conoco and Phillips
operations, the company expects that its total international oil and gas
production volumes will increase in 2003 over those of 2002. ConocoPhillips'
fourth quarter production volumes, which included a full period of combined
operations, averaged 585,000 barrels per day of liquids and 1,994 million cubic
feet per day of natural gas.
2001 vs. 2000
Net income from ConocoPhillips' international E&P operations decreased 36
percent in 2001. The decrease was primarily the result of lower crude oil and
natural gas production volumes, as well as lower crude oil prices. Additionally,
after-tax foreign currency gains of $2 million were included in international
E&P's net income in 2001, compared with losses of $10 million in 2000. Net
income in 2000 included a net gain on property dispositions of $118 million
related to the disposition of the Zama area fields in Canada, partially offset
by an $86 million impairment of the Ambrosio field in Venezuela.
International crude oil production declined 3 percent in 2001, mainly due to
lower production in the U.K. North Sea, Venezuela and Canada, partly offset by
increased production from Norway and Nigeria. Canadian and Venezuelan crude oil
production declined relative to 2000 due to asset dispositions. Production in
the U.K. North Sea decreased on normal field declines. Production from Norway
improved in 2001 due to improved processing reliability and well workovers,
while Nigerian production increased on development activities and higher quotas.
International natural gas production declined 10 percent in 2001, primarily the
result of the Canadian asset dispositions and lower U.K. North Sea output noted
above, partially offset by higher production in Nigeria and new natural gas
production from offshore western Australia.
44
MIDSTREAM
2002 2001 2000
----------------------------
Millions of Dollars
----------------------------
NET INCOME $ 55 120 162
-------------------------------------------------------------------
Dollars Per Barrel
----------------------------
AVERAGE SALES PRICES
U.S. natural gas liquids*
Consolidated $19.07 -- --
Equity 15.92 18.77 21.83**
-------------------------------------------------------------------
Thousands of Barrels Daily
----------------------------
OPERATING STATISTICS
Natural gas liquids extracted 156 120 131***
Natural gas liquids fractionated 133 108 158
--------------------------------------------------------------------
*Based on index prices from the Mont Belvieu and Conway market hubs that
are weighted by natural gas liquids component and location mix.
**Estimate based on ConocoPhillips' first quarter realized price and DEFS'
index price for the remainder of the year.
***Based on a weighted average of ConocoPhillips' volumes in the first
quarter of 2000, and ConocoPhillips' share of DEFS volumes for the
remainder of 2000.
2002 vs. 2001
ConocoPhillips' Midstream segment consists of the company's 30.3 percent
interest in Duke Energy Field Services, LLC (DEFS), as well as company-owned
natural gas gathering and processing operations and natural gas liquids
fractionation and marketing businesses. Net income from the Midstream segment
decreased 54 percent in 2002. The decrease was primarily due to lower results
from DEFS, which experienced a decline in natural gas liquids prices, increased
costs for gas imbalance accruals and other adjustments, and higher operating
expenses. These items were partially offset by the benefit of four month's
results from operations acquired in the merger.
Included in the Midstream segment's net income in 2002 was a benefit of $35
million, representing the amortization of the basis difference between the book
value of ConocoPhillips' contribution to DEFS and its 30.3 percent equity
interest in DEFS. The corresponding amount for 2001 was $36 million. See Note
8--Investments and Long-Term Receivables, in the Notes to Consolidated Financial
Statements for additional information on the basis difference.
2001 vs. 2000
Net income from the Midstream segment decreased 26 percent in 2001, primarily
the result of a 14 percent decline in natural gas liquids prices. In addition,
the Midstream segment's results were affected by the lack of interest charges in
the first quarter of 2000 prior to the formation of DEFS. DEFS incurs interest
expense in connection with financing incurred upon formation to fund cash
distributions to the parent entities. Prior to the formation of DEFS, the
Midstream segment did not have interest expense. Included in the Midstream
segment's net income in 2001 was a benefit of $36 million, representing the
amortization of the basis difference between the book value of ConocoPhillips'
contribution to DEFS and its 30.3 percent equity interest in DEFS. The
corresponding amount for 2000 was $27 million.
45
R&M
2002 2001 2000
-------------------------------
Millions of Dollars
-------------------------------
NET INCOME
United States $ 138 395 209
International 5 2 29
--------------------------------------------------------------------------
$ 143 397 238
==========================================================================
Dollars Per Gallon
-------------------------------
U.S. AVERAGE SALES PRICES*
Automotive gasoline
Wholesale $ .96 .83 .92
Retail 1.03 1.01 1.07
Distillates--wholesale .77 .78 .88
--------------------------------------------------------------------------
*Excludes excise taxes
Thousands of Barrels Daily
-------------------------------
OPERATING STATISTICS
Refining operations*
United States
Rated crude oil capacity** 1,829 732 335
Crude oil runs 1,661 686 303
Capacity utilization (percent) 91% 94 90
Refinery production 1,847 795 365
International
Rated crude oil capacity** 195 22 --
Crude oil runs 152 20 --
Capacity utilization (percent) 78% 91 --
Refinery production 164 19 --
Worldwide
Rated crude oil capacity** 2,024 754 335
Crude oil runs 1,813 706 303
Capacity utilization (percent) 90% 94 90
Refinery production 2,011 814 365
--------------------------------------------------------------------------
Petroleum products sales volumes***
United States
Automotive gasoline 1,147 465 267
Distillates 392 170 107
Aviation fuels 185 78 41
Other products 372 220 50
--------------------------------------------------------------------------
2,096 933 465
International 162 10 43
--------------------------------------------------------------------------
2,258 943 508
==========================================================================
*2002 includes ConocoPhillips' share of equity affiliates.
**Weighted-average crude oil capacity for the period, including the refineries
acquired in the Tosco acquisition in September 2001 and the refineries
acquired as a result of the merger. Actual capacity at year-end 2002 and 2001
was 2,166 thousand and 1,656 thousand barrels per day, respectively, in the
United States and 440 thousand and 72 thousand barrels per day, respectively,
internationally.
***Excludes spot market sales.
46
2002 vs. 2001
Net income from the R&M segment declined 64 percent in 2002, reflecting lower
refining margins, along with an $84 million after-tax impairment of a tradename
and leasehold improvements of certain retail sites. See Note 10--Impairments in
the Notes to Consolidated Financial Statements for additional information on
these impairments. The R&M earnings for 2002 included four months' results from
operations acquired in the merger, as well as the impact of a full year's
results from Tosco operations, while the 2001 results included Tosco operations
for only the last three and one-half months of 2001.
Worldwide crude oil refining capacity utilization was 90 percent in 2002,
compared with 94 percent in 2001. The company's refineries produced 2,011,000
barrels per day of petroleum products in 2002, compared with 814,000 barrels per
day in 2001. The increase reflects a full year of operations for refineries
acquired in the Tosco acquisition and four months of operations for the
refineries acquired in the merger.
2001 vs. 2000
Net income from the R&M segment increased 67 percent in 2001. On September 14,
2001, ConocoPhillips closed on the acquisition of Tosco. This transaction
significantly increased the size of ConocoPhillips' R&M segment and benefited
2001 results. In addition to the Tosco acquisition, R&M's net income benefited
from higher gasoline and distillates margins, particularly during the second
quarter of 2001. Negatively affecting R&M results for the year were higher
utility costs at the company's refineries, resulting from higher natural gas
prices experienced in the first half of 2001.
Worldwide crude oil refining capacity utilization was 94 percent in 2001,
compared with 90 percent in 2000. The company's refineries produced 814,000
barrels per day of petroleum products in 2001, compared with 365,000 barrels per
day in 2000. The increase reflects the Tosco acquisition.
U.S. R&M
2002 vs. 2001
Net income from U.S. R&M operations declined 65 percent in 2002. The decrease
was primarily due to lower refining margins, particularly in the Midcontinent
and Gulf Coast regions, along with an $84 million after-tax impairment of a
tradename and leasehold improvements of certain retail sites. See Note
10--Impairments in the Notes to Consolidated Financial Statements for additional
information on these impairments. These items were partially offset by increased
production and sales volumes as a result of the Tosco acquisition and the
merger. Net income for 2002 included four months from operations acquired in the
merger, and a full year of Tosco operations, while the 2001 results included
Tosco operations for only three and one-half months. Results for 2001 included a
cumulative effect of a change in accounting principle that increased R&M net
income by $26 million. Effective January 1, 2001, ConocoPhillips changed its
method of accounting for the costs of major maintenance turnarounds from the
accrue-in-advance method to the expense-as-incurred method. Also included in
2001 was a $27 million write-down of inventories to market value.
The crude oil capacity utilization rate for ConocoPhillips' U.S. refineries was
91 percent in 2002, compared with 94 percent in 2001. The lower utilization rate
in 2002 reflects increased maintenance turnaround activity in 2002, the impact
of tropical storms on the company's Gulf Coast refineries in the third quarter
of 2002, and the impact of the loss of Venezuelan crude oil supply in the fourth
quarter.
47
2001 vs. 2000
Net income from the R&M segment's U.S. operations increased 89 percent in 2001,
compared with 2000. On September 14, 2001, ConocoPhillips closed on the
acquisition of Tosco. This transaction significantly increased the size of
ConocoPhillips' U.S. R&M operations and benefited 2001 net income.
In addition to the Tosco acquisition, R&M's earnings benefited from higher
gasoline and distillates margins, particularly during the second quarter of
2001, and the accounting change discussed above. Negatively affecting R&M
results for the year were higher utility costs at the company's refineries,
resulting from higher natural gas prices experienced in the first half of 2001,
as well as a $27 million write-down of inventories to market value. The Sweeny
refinery's 2001 net income benefited from the coker unit that was started up in
late 2000. The coker unit allows for the processing of heavier, lower-cost crude
oil, which reduced crude oil purchase costs and contributed to the improved
gasoline and distillates margins experienced during 2001.
ConocoPhillips' U.S. refineries (including those acquired in the Tosco
acquisition since the acquisition date) processed an average of 686,000 barrels
per day of crude oil in 2001, yielding a 94 percent capacity utilization rate.
This compares with 303,000 barrels per day and a utilization rate of 90 percent
in 2000. The Tosco acquisition accounted for 378,000 barrels per day in 2001.
International R&M
2002 vs. 2001
Net income from international R&M operations increased $3 million in 2002,
reflecting the impact of the merger, which added one wholly owned and five
joint-venture international refineries. A substantial part of ConocoPhillips'
international R&M results are related to its Humber refinery in the United
Kingdom, which had a 232,000 barrel per day crude oil processing capacity at
December 31, 2002. This refinery was shut down for an extended period of time
during the fourth quarter due to a power outage and subsequent downtime, which
negatively impacted international R&M's 2002 results.
The crude oil capacity utilization rate for ConocoPhillips' international
refineries was 78 percent in 2002, compared with 91 percent in 2001. The lower
utilization rate in 2002 reflects the extended shutdown at the Humber refinery
noted above.
2001 vs. 2000
Net income from the R&M segment's international operations decreased 93 percent
in 2001, compared with 2000, reflecting the late-2000 disposition of the
company's 50 percent interest in a refinery in Teesside, England. This was
partially offset by the addition of the Whitegate refinery in Ireland as part of
the Tosco acquisition in September 2001.
48
CHEMICALS
2002 2001 2000
------------------------------------
Millions of Dollars
------------------------------------
NET LOSS $ (14) (128) (46)
-----------------------------------------------------------------
Millions of Pounds
-----------------------------------
OPERATING STATISTICS
Production*
Ethylene 3,217 3,291 3,574
Polyethylene 2,004 1,956 2,230
Styrene 887 456 404
Normal alpha olefins 592 563 293
----------------------------------------------------------------
*Production volumes for periods after July 1, 2000, include ConocoPhillips'
50 percent share of Chevron Phillips Chemical Company LLC.
2002 vs. 2001
ConocoPhillips' Chemicals segment consists of its 50 percent equity investment
in CPChem, which was formed when the company and ChevronTexaco combined their
worldwide chemicals businesses in July 2000.
The Chemicals segment incurred a net loss of $14 million in 2002, compared with
a net loss of $128 million in 2001. The worldwide chemicals industry experienced
an economic downturn beginning in the second half of 2000, and these difficult
conditions remained present through 2001 and 2002. The downturn has been marked
by decreased product demand and low product margins across key product lines.
The smaller net loss in 2002 was primarily the result of higher margins due to
lower operating expenses, feedstock costs and energy prices, partially offset by
decreased sales prices.
A fire caused the shutdown of styrene production at CPChem's St. James,
Louisiana, facility in February 2001. Production was restored in October 2001.
Production volumes for other major product lines were comparable between 2002
and 2001.
The net loss in 2001 included several asset retirements and impairments totaling
$84 million after-tax because of depressed economic conditions. A developmental
reactor at the Houston Chemical Complex in Pasadena, Texas, was retired;
property impairments were recorded on two polyethylene reactors at the Orange
chemical plant in Orange, Texas; an ethylene unit was retired at the Sweeny
complex in Old Ocean, Texas; an equity affiliate of CPChem recorded a property
impairment related to a polypropylene facility; property impairments were taken
on the manufacturing facility in Puerto Rico; and the benzene and cyclohexane
units at the Puerto Rico facility were retired. In addition, the valuation
allowance on the Puerto Rico facility's deferred tax asset related to its net
operating losses was increased in 2001 so that the deferred tax assets were
fully offset by valuation allowances. Partially offsetting these impairments was
a business interruption insurance settlement recorded by CPChem and a favorable
deferred tax adjustment, related to the tax basis of its investment, recorded by
ConocoPhillips that resulted from an impairment related to the Puerto Rico
facility, together totaling $57 million after-tax.
49
2001 vs. 2000
The Chemicals segment incurred a net loss of $128 million in 2001, compared with
a net loss of $46 million in 2000. Global conditions for the chemicals and
plastics industry were extremely difficult in 2001. Worldwide economic
slowdowns, including a recessionary economy in the United States, led to
decreased product demand and low product margins across many key product lines.
CPChem's results were negatively affected by low ethylene, polyethylene and
aromatics margins, as well as lower ethylene and polyethylene production. In
addition to low margins and production volumes, 2001 contained interest charges
incurred by CPChem that were not present in the first six months of 2000 prior
to the formation of CPChem.
The difficult marketing environment led to several asset retirements and
impairments being recorded by CPChem in 2001. Partially offsetting these
impairments was a business interruption insurance settlement recorded by CPChem
and a favorable deferred tax adjustment recorded by ConocoPhillips that resulted
from the Puerto Rico facility impairment, together totaling $57 million
after-tax.
The net loss in 2000 included ConocoPhillips' share of a property impairment
that CPChem recorded in the fourth quarter related to its Puerto Rico facility.
The impairment was required due to the deteriorating outlook for future
paraxylene market conditions and a shift in strategic direction at the facility.
In addition, a valuation allowance was recorded against a related deferred tax
asset. Combined, these two items resulted in a non-cash $180 million after-tax
charge to CPChem's earnings. ConocoPhillips' share was $90 million.
EMERGING BUSINESSES
Millions of Dollars
--------------------------------
2002 2001 2000
--------------------------------
NET LOSS
Carbon fibers $ (15) -- --
Fuels technology (16) (12) --
Gas-to-liquids (273) -- --
Power generation and other (6) -- --
------------------------------------------------------------------
$ (310) (12) --
==================================================================
2002 vs. 2001
The Emerging Businesses segment includes the development of new businesses
beyond the company's traditional operations. Emerging Businesses include carbon
fibers, natural gas-to-liquids technology, fuels technology and power
generation. Prior to the merger, this segment only included Phillips' fuels
technology business.
The Emerging Businesses segment posted a net loss of $310 million in 2002,
compared with a net loss of $12 million in 2001. Results for 2002 included a
$246 million write-off of acquired in-process research and development costs
related to Conoco's natural gas-to-liquids and other technologies. In accordance
with FASB Interpretation No. 4, "Applicability of FASB Statement No. 2 to
Business Combinations Accounted for by the Purchase Method," value assigned to
research and development activities in the purchase price allocation that have
no alternative future use should be charged to expense at the date of the
consummation of the combination. The $246 million charge was the same on both a
before-tax and after-
50
tax basis, as there was no tax basis to the assigned value prior to its
write-off. The increased number of developing businesses after the merger also
contributed to the larger losses in 2002.
ConocoPhillips announced in February 2003 that it will shut down its carbon
fibers project, as a result of market, operating and technology uncertainties.
At the time of the merger, the company identified these uncertainties facing the
carbon fibers project and initiated a strategic update for the new management of
the company. In early 2003, the strategic update was completed and management
made the decision to shut down the project. In the preliminary purchase price
allocation, the company valued the carbon fibers technology at an amount equal
to the plant construction costs. In the first quarter of 2003, the company will
reduce the preliminary purchase price allocation associated with this project
and accrue for shutdown, severance and other related costs that will result in a
corresponding net increase in goodwill of $125 million.
2001 vs. 2000
In 2001, the Emerging Businesses segment included the company's development of
new fuels technologies. Prior to 2001, these activities were not separately
identifiable, and were included in the R&M segment.
CORPORATE AND OTHER
Millions of Dollars
----------------------------------------
2002 2001 2000
----------------------------------------
NET LOSS
Net interest $ (396) (262) (278)
Corporate general and administrative expenses (173) (114) (87)
Discontinued operations (993) 32 14
Merger-related costs (307) -- --
Other (49) (71) (86)
---------------------------------------------------------------------------------------------
$(1,918) (415) (437)
=============================================================================================
2002 vs. 2001
Net interest represents interest expense, net of interest income and capitalized
interest. Net interest increased 51 percent in 2002, mainly due to higher debt
levels following the Tosco acquisition and the merger of Conoco and Phillips.
Corporate general and administrative expenses increased 52 percent in 2002,
primarily due to the impact of the merger. In addition, 2002 also included
higher benefit-related costs, primarily from the accelerated vesting of awards
under certain long-term compensation plans that occurred at the time of
stockholder approval of the merger.
Losses from discontinued operations were $993 million in 2002, compared with
income of $32 million in 2001. The 2002 amount included after-tax impairments
and loss accruals of $1,077 million associated with the assets held for sale.
See Note 4--Discontinued Operations in the Notes to Consolidated Financial
Statements for additional information on the impairments and loss accruals, as
well as a description of the assets included in discontinued operations.
51
Merger-related costs in 2002 included restructuring accruals of $252 million,
primarily related to work force reduction charges; change-in-control costs
associated with seismic contracts totaling $22 million; and other transition
costs of $33 million. Other merger-related costs of $250 million were recorded
by the operating segments, bringing total merger-related costs to $557 million
after-tax.
The category "Other" consists primarily of items not directly associated with
the operating segments on a stand-alone basis, including captive insurance
operations, certain foreign currency gains and losses, the tax impact of
consolidations, and dividends on the preferred securities of the Phillips 66
Capital Trusts I and II. Results from Other were improved in 2002 primarily due
to more favorable foreign currency transactions, and a favorable revaluation and
settlement of certain long-term incentive units that were converted into
Phillips performance units held by former senior Tosco executives, none of whom
are employees of ConocoPhillips. Included in 2002 and 2001 were extraordinary
losses on the early retirement of debt totaling $16 million and $10 million,
respectively.
2001 vs. 2000
Corporate and Other net loss decreased 5 percent in 2001, compared with 2000,
primarily due to lower net interest expense and improved results from
discontinued operations partially offset by higher staff costs, contributions,
corporate advertising and corporate transportation costs.
52
CAPITAL RESOURCES AND LIQUIDITY
FINANCIAL INDICATORS
Millions of Dollars
Except as Indicated
--------------------------------------
2002 2001 2000
--------------------------------------
Current ratio .9 1.3 .8
Total debt repayment obligations due within one year $ 849 44 262
Total debt $19,766 8,654 6,884
Mandatorily redeemable preferred securities of trust subsidiaries $ 350 650 650
Other minority interests $ 651 5 1
Common stockholders' equity $29,517 14,340 6,093
Percent of total debt to capital* 39% 37 51
Percent of floating-rate debt to total debt 12% 20 17
-------------------------------------------------------------------------------------------------------------
*Capital includes total debt, mandatorily redeemable preferred securities, other
minority interests and common stockholders' equity. Expected new accounting
rules in 2003 likely will cause mandatorily redeemable preferred securities to
be presented as a liability. The increase in ConocoPhillips' debt-to-capital
ratio from December 31, 2001, to December 31, 2002, resulted primarily from the
merger. In addition to $12 billion of Conoco debt assumed, purchase accounting
required the debt to be recorded at fair value at the time of the merger,
increasing total debt by an additional $565 million.
SIGNIFICANT SOURCES OF CAPITAL
During 2002, cash of $4,969 million was provided by operating activities, an
increase of $1,407 million from 2001. Cash provided by operating activities
before changes in working capital increased $54 million compared with 2001,
primarily due to higher dividends from equity affiliates, higher crude oil
prices and higher crude oil and natural gas volumes, offset by lower natural gas
prices, lower refining margins, higher interest expenses and merger-related
costs. Positive working capital changes of $1,184 million were primarily due to
an increase in accounts payable, an increase in taxes and other accruals and a
decrease in inventories, partially offset by increased receivables. Discontinued
operations provided $202 million of operating cash flows in 2002, an increase of
$169 million compared to 2001. The increase in 2002 was primarily due to 2002
including a full year of cash flow from a portion of assets acquired in the
Tosco acquisition that are now included in discontinued operations.
During 2002, cash and cash equivalents increased $165 million. In addition to
the cash provided by operating activities, $815 million was received from the
sale of various ConocoPhillips assets; including the sale of exploration and
production assets in the Netherlands, assets in Canada and propane terminal
assets at Jefferson City, Missouri, and East St. Louis, Illinois. Funds were
used to support the company's ongoing capital expenditures program, repay debt
and pay dividends. In October 2002, ConocoPhillips' Board of Directors declared
a dividend of $.40 per share, payable December 2, 2002, which represented an 11
percent increase in the quarterly dividend.
To meet its liquidity requirements, including funding its capital program,
paying dividends and repaying debt, the company looks to a variety of funding
sources, primarily cash generated from operating activities. By the end of 2004,
however, the company anticipates raising funds of $3 billion to $4 billion, of
which approximately $600 million had been raised as of December 31, 2002, from
the sale of assets, including those assets required by the FTC to be sold. In
December 2002, ConocoPhillips entered into an agreement to sell its Woods Cross
refinery and associated marketing assets, subject to state and federal
regulatory approvals. Also in December 2002, the company committed to and
initiated a plan to sell a substantial portion of its U.S. company-owned retail
sites.
53
While the stability of the company's cash flows from operating activities
benefits from geographic diversity and the effects of upstream and downstream
integration, the company's operating cash flows remain exposed to the volatility
of commodity crude oil and natural gas prices and downstream margins, as well as
periodic cash needs to finance tax payments and crude oil, natural gas and
petroleum product purchases. The company's primary funding source for short-term
working capital needs is a $4 billion commercial paper program, a portion of
which may be denominated in euros (limited to euro 3 billion), supported by $4
billion in revolving credit facilities. Commercial paper maturities are
generally kept within 90 days. At December 31, 2002, ConocoPhillips had $1,517
million of commercial paper outstanding, of which $206 million was denominated
in foreign currencies.
Effective October 15, 2002, ConocoPhillips entered into two new revolving credit
facilities to replace the previously existing $2.5 billion Conoco credit
facilities, and also amended and restated a prior Phillips revolving credit
facility to include ConocoPhillips as a borrower. The company now has a $2
billion 364-day revolving credit facility expiring on October 14, 2003, and two
revolving credit facilities totaling $2 billion expiring in October 2006. There
were no outstanding borrowings under any of these facilities at December 31,
2002. These credit facilities support the company's $4 billion commercial paper
program. ConocoPhillips' Norwegian subsidiary has two $300 million revolving
credit facilities that expire in June 2004, under which no borrowings were
outstanding as of December 31, 2002.
In addition to the bank credit facilities, ConocoPhillips sells certain credit
card and trade receivables to two Qualifying Special Purpose Entities (QSPEs) in
revolving-period securitization arrangements. These arrangements provide for
ConocoPhillips to sell, and the QSPEs to purchase, certain receivables and for
the QSPEs to then issue beneficial interests of up to $1.5 billion to five
bank-sponsored entities. At December 31, 2002 and 2001, the company had sold
accounts receivable of $1.3 billion and $940 million, respectively. The
receivables sold have been sufficiently isolated from ConocoPhillips to qualify
for sales treatment. All five bank-sponsored entities are multi-seller conduits
with access to the commercial paper market and purchase interests in similar
receivables from numerous other companies unrelated to ConocoPhillips.
ConocoPhillips has no ownership in any of the bank-sponsored entities and has no
voting influence over any bank-sponsored entity's operating and financial
decisions. As a result, ConocoPhillips does not consolidate any of these
entities. Beneficial interests retained by ConocoPhillips in the pool of
receivables held by the QSPEs are subordinate to the beneficial interests issued
to the bank-sponsored entities and were measured and recorded at fair value
based on the present value of future expected cash flows estimated using
management's best estimates concerning the receivables performance, including
credit losses and dilution discounted at a rate commensurate with the risks
involved to arrive at present value. These assumptions are updated periodically
based on actual credit loss experience and market interest rates. ConocoPhillips
also retains servicing responsibility related to the sold receivables. The fair
value of the servicing responsibility approximates adequate compensation for the
servicing costs incurred. ConocoPhillips' retained interest in the sold
receivables at December 31, 2002 and 2001, was $1.3 billion and $450 million,
respectively. Under accounting principles generally accepted in the United
States, the QSPEs are not consolidated by ConocoPhillips. ConocoPhillips
retained interest in sold receivables is reported on the balance sheet in
accounts and notes receivable. See Note 13--Sales of Receivables in the Notes to
Consolidated Financial Statements for additional information.
On October 9, 2002, ConocoPhillips issued $2 billion of senior unsecured debt
securities, consisting of $400 million 3.625% notes due 2007, $1 billion 4.75%
notes due 2012, and $600 million 5.90% notes due 2032. The $1,980 million net
proceeds of the offering were used to reduce commercial paper, to retire
Conoco's $500 million floating rate notes due October 15, 2002, and for general
corporate purposes.
54
Moody's Investor Service has assigned a rating of A3 on ConocoPhillips' senior
long-term debt; and Standard and Poors and Fitch have assigned a rating of A-.
ConocoPhillips does not have any ratings triggers on any of its corporate debt
that would cause an automatic event of default in the event of a downgrade of
ConocoPhillips' debt rating and thereby impacting ConocoPhillips' access to
liquidity. In the event that ConocoPhillips' credit were to deteriorate to a
level that would prohibit ConocoPhillips from accessing the commercial paper
market, ConocoPhillips would still be able to access funds under its $4.6
billion revolving credit facilities. Based on ConocoPhillips' year-end
commercial paper balance of $1.5 billion, ConocoPhillips had access to $3.1
billion in borrowing capacity as of December 31, 2002, after repaying all
outstanding commercial paper, which provides ample liquidity to cover any needs
that its businesses may require to cover daily operations.
OTHER FINANCING AND OFF-BALANCE SHEET ARRANGEMENTS
During 1996 and 1997, ConocoPhillips formed two statutory business trusts,
Phillips 66 Capital I and Phillips 66 Capital II. The company owns all of the
common securities of the trusts and the trusts are consolidated by the company.
The trusts exist for the sole purpose of issuing preferred securities to outside
investors, and investing the proceeds thereof in an equivalent amount of
subordinated debt securities of ConocoPhillips. The two trusts were established
to raise funds for general corporate purposes. The subordinated debt securities
of ConocoPhillips held by the trusts are eliminated in consolidation. The $300
million of 8.24% Trust Originated Preferred Securities issued by Phillips 66
Capital Trust I became callable, at par, $25 per share, during May 2001. On May
31, 2002, ConocoPhillips redeemed all of its outstanding subordinated debt
securities held by the Trust, which triggered the redemption of the $300 million
of trust preferred securities at par value, $25 per share. The redemption was
funded by the issuance of commercial paper. The remaining $350 million of
mandatorily redeemable preferred trust securities issued by Phillips 66 Capital
Trust II are mandatorily redeemable in 2037, when the subordinated debt
securities of ConocoPhillips held by the trust are required to be repaid. The
mandatorily redeemable preferred securities are presented in the mezzanine
section of the balance sheet. See Note 17--Preferred Stock and Other Minority
Interests in the Notes to Consolidated Financial Statements.
ConocoPhillips also had outstanding, at December 31, 2002, $645 million of
equity held by minority interest owners, which provide a preferred return to
those minority interest holders. In 1999, Conoco formed Conoco Corporate
Holdings L.P. by contributing an office building and four aircraft. The limited
partner interest was sold to Highlander Investors L.L.C. for $141 million, which
represented an initial net 47 percent interest. Highlander is entitled to a
cumulative annual priority return on its investment of 7.86 percent. The net
minority interest in Conoco Corporate Holdings was $141 million at December 31,
2002, and is mandatorily redeemable in 2019 or callable without penalty
beginning in the fourth quarter of 2004. In 2001, Conoco and Cold Spring Finance
S.a.r.l. formed Ashford Energy Capital S.A. through the contribution of cash and
a Conoco subsidiary promissory note. Cold Spring Finance S.a.r.l. held a $504
million net minority interest in Ashford Energy at December 31, 2002, and is
entitled to a cumulative annual preferred return on its investment, based on
three-month LIBOR rates plus 1.27 percent. The preferred return at December 31,
2002, was 2.70 percent. These minority interests are presented in the mezzanine
section of the balance sheet. See Note 17--Preferred Stock and Other Minority
Interests in the Notes to Consolidated Financial Statements.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities," and later in 2003, the FASB is expected to issue
Statement of Financial Accounting Standards (SFAS) No. 149, "Accounting for
Certain Financial Instruments with Characteristics of Liabilities and Equity."
The company is evaluating these new pronouncements to determine whether the
amounts currently presented in the mezzanine section of the balance sheet will
be required to be presented as debt or as equity
55
on the balance sheet. See Note 27--New Accounting Standards and Note
28--Variable Interest Entities in the Notes to Consolidated Financial Statements
for more information.
The company leases ocean transport vessels, drillships, tank railcars, corporate
aircraft, service stations, computers, office buildings, certain refining
equipment, and other facilities and equipment. Prior to the acquisition of Tosco
and the merger, the company had in place leasing arrangements for tankers,
corporate aircraft and the construction of various retail marketing outlets. At
December 31, 2002, approximately $730 million had been utilized under those
arrangements, which is the total capacity available. At the time the company
acquired Tosco, Tosco had in place previously arranged leasing arrangements for
various retail stations and two office buildings in Tempe, Arizona. At December
31, 2002, approximately $1.3 billion had been utilized under those arrangements,
which is the total capacity available. In addition, at the time of the merger,
Conoco had in place leasing arrangements for certain refining equipment, two
drillships, and various retail marketing outlets. At December 31, 2002,
approximately $370 million had been utilized under those arrangements.
Several of the above leasing arrangements are with special purpose entities
(SPEs) that are third-party trusts established by a trustee and funded by
financial institutions. Other than those leasing arrangements, ConocoPhillips
has no other direct or indirect relationship with the trusts or their investors.
Each SPE from which ConocoPhillips leases assets is funded by at least 3 percent
substantive, unaffiliated third-party, residual equity capital investment, which
is at risk during the entire term of the lease. Changes in market interest rates
do have an impact on the periodic amount of lease payments. ConocoPhillips has
various purchase options to acquire the leased assets from the SPEs at the end
of the lease term, but those purchase options are not required to be exercised
by ConocoPhillips under any circumstances. If ConocoPhillips does not exercise
its purchase option on a leased asset, the company does have guaranteed residual
values, which are due at the end of the lease terms, but those guaranteed
amounts would be reduced by the fair market value of the leased assets returned.
These various leasing arrangements meet all requirements under generally
accepted accounting principles to be treated as operating leases. However, in
January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable
Interest Entities," which will require consolidation in July 2003 of certain
SPEs that were created prior to January 31, 2003, and which are still in
existence at June 15, 2003. The company is evaluating the new Interpretation to
determine whether the assets and debt of the leasing arrangements would be
consolidated. See Note 28--Variable Interest Entities in the Notes to
Consolidated Financial Statements for more information. If the company is
required to consolidate all of these entities, the assets of the entities and
debt of approximately $2.4 billion would be required to be included in the
consolidated financial statements. The company's maximum exposure to loss as a
result of its involvement with the entities would be the debt of the entity less
the fair value of the assets at the end of the lease terms. Of the $2.4 billion
debt that would be consolidated, approximately $1.5 billion is associated with a
major portion of the company's owned retail stores that the company has
announced it plans to sell. As a result of the planned divestiture, the company
plans to exercise purchase option provisions during 2003 and terminate various
operating leases involving approximately 900 store sites and two office
buildings. In addition, see Note 4--Discontinued Operations in the Notes to
Consolidated Financial Statements for details regarding the provisions for
losses and penalties recorded in the fourth quarter, 2002 for the planned
divestiture. Depending upon the timing of the company's exercise of these
purchase options, and the determination of whether or not the lessor entities in
these operating leases are variable interest entities requiring consolidation in
2003, some or all of these lessor entities could become consolidated
subsidiaries of the company prior to the exercise of the purchase options and
termination of the leases. See Note 14--Guarantees and Note 19--Non-Mineral
Leases in the Notes to Consolidated Financial Statements.
56
During 2000, ConocoPhillips contributed its midstream gas gathering, processing
and marketing business and its worldwide chemicals business to joint ventures
with Duke Energy Corporation and ChevronTexaco Corporation, as successor to
Chevron Corporation (ChevronTexaco), respectively, forming DEFS and CPChem,
respectively. ConocoPhillips owns 30.3 percent of DEFS and 50 percent of CPChem,
accounting for its interests in both companies using the equity method of
accounting. The capital and financing programs of both of these joint-venture
companies are intended to be self-funding.
DEFS supplies a substantial portion of its natural gas liquids to ConocoPhillips
and CPChem under a supply agreement that continues until December 31, 2014. This
purchase commitment is on an "if-produced, will-purchase" basis so it has no
fixed production schedule, but has been, and is expected to be, a relatively
stable purchase pattern over the term of the contract. Natural gas liquids are
purchased under this agreement at various published market index prices, less
transportation and fractionation fees. DEFS also purchases raw natural gas from
ConocoPhillips' E&P operations.
ConocoPhillips and CPChem have multiple supply and purchase agreements in place,
ranging in initial terms from four to 15 years, with extension options. These
agreements cover sales and purchases of refined products, solvents, and
petrochemical and natural gas liquids feedstocks, as well as fuel oils and
gases. Delivery quantities vary by product, ranging from zero to 100 percent of
production capacity at a particular refinery, most at the buyer's option. All
products are purchased and sold under specified pricing formulas based on
various published pricing indexes, consistent with terms extended to third-party
customers.
In the second quarter of 2001, ConocoPhillips and its co-venturers in the Hamaca
project secured approximately $1.1 billion in a joint debt financing for their
heavy-crude oil project in Venezuela. The Export-Import Bank of the United
States provided a guarantee supporting a 17-year-term $628 million bank
facility. The joint venture also arranged a $470 million 14-year-term commercial
bank facility for the project. Total debt of $947 million was outstanding under
these credit facilities at December 31, 2002. ConocoPhillips, through the joint
venture, holds a 40 percent interest in the Hamaca project, which is operated on
behalf of the co-venturers by Petrolera Ameriven. The proceeds of these joint
financings are being used to partially fund the development of the heavy-oil
field and the construction of pipelines and a heavy-oil upgrader. The remaining
necessary funding will be provided by capital contributions from the
co-venturers on a pro rata basis to the extent necessary to successfully
complete construction. Once completion certification is achieved, the joint
project financings will become non-recourse with respect to the co-venturers and
the lenders under those facilities can then look only to the Hamaca project's
cash flows for payment.
MSLP is a limited partnership in which ConocoPhillips and PDVSA each own an
indirect 50 percent interest. During 1999, MSLP issued $350 million of 8.85
percent bonds due 2019 that ConocoPhillips and PDVSA are joint-and-severally
liable for under a construction completion guarantee. The bond proceeds were
used to fund construction of a coker, vacuum unit and related facilities at the
ConocoPhillips Sweeny refinery plus certain improvements to existing facilities
at the same location. MSLP owns and operates the coker and vacuum unit and, in
the third quarter of 2000, began processing long residue produced from the
Venezuelan Merey crude oil delivered under a supply agreement that
ConocoPhillips has with PDVSA. MSLP charges ConocoPhillips a fee to process the
long residue through the vacuum unit and coker. This is the partnership's
primary source of revenue. If completion certification is not attained by 2004,
the full debt is due. Upon completion certification, the 8.85 percent bonds
become non-recourse to the two MSLP partners and the bondholders can then look
only to MSLP cash flows for payment.
57
ConocoPhillips purchased the improvements to existing facilities from MSLP for a
price equal to the cost of construction and MSLP provided seller financing.
Terms of financing provide for 240 monthly payments of principal and interest
commencing September 2000 with interest accruing at a 7 percent annual rate. The
principal balance due on the seller financing was $131 million at December 31,
2002, and is included as long-term debt in ConocoPhillips' balance sheet. MSLP
pays a monthly access fee to ConocoPhillips for the use of the improvements to
the refinery. The access fee equals the monthly principal and interest paid by
ConocoPhillips to purchase the improvements from MSLP. To the extent the access
fee is not paid by MSLP, ConocoPhillips is not obligated to make payments for
the improvements.
During the first quarter of 2002, MSLP issued $25 million of tax-exempt bonds
due 2021. This issuance, combined with similar bonds MSLP issued in 1998, 2000,
and 2001, bring the total outstanding to $100 million. As a result of the
company's support as a primary obligor of a 50 percent share of these MSLP
financings, $50 million and $38 million of long-term debt is included in
ConocoPhillips' balance sheet at December 31, 2002, and December 31, 2001,
respectively.
ConocoPhillips has transactions with many unconsolidated affiliates. Equity
affiliate sales and services to ConocoPhillips amounted to $1,545 million in
2002, $1,110 million in 2001 and $1,347 million in 2000. Equity affiliate
purchases from ConocoPhillips totaled $1,554 million in 2002, $935 million in
2001 and $1,573 million in 2000. These agreements were not the result of
arms-length negotiations. However, ConocoPhillips believes that these contracts
are generally at values that are similar to those that could be negotiated with
independent third parties.
CAPITAL REQUIREMENTS
For information about ConocoPhillips' capital expenditures and investments, see
"Capital Spending" below.
During 2002 and January 2003, ConocoPhillips redeemed the following notes and
funded the redemptions with commercial paper:
o its $250 million 8.86% notes due May 15, 2022, at 104.43 percent;
o its $171 million 7.443% senior unsecured notes due 2004;
o its $250 million 8.49% notes due January 1, 2023, at 104.245
percent; and
o its $181 million SRW Cogeneration Limited Partnership note.
In addition, in April 2003, ConocoPhillips plans to redeem its $250 million
7.92% notes due in 2023 at 103.96 percent.
58
The following table summarizes the maturities of the drawn balances of the
company's various debt instruments, as well as other non-cancelable, fixed or
minimum, contractual commitments, as of December 31, 2002:
Millions of Dollars
-------------------------------------------------------------
Payments Due by Period
-------------------------------------------------------------
Up to 1 2-3 4-5 After
Debt and other non-cancelable cash commitments Total Year Years Years 5 Years
------------------------------------------------------------------------------------------------------------------------------
Total debt* $ 19,766 849 2,667 3,827 12,423
Mandatorily redeemable other minority interests and preferred
securities 491 -- -- -- 491
Operating leases
Minimum rental payments** 4,101 649 1,025 792 1,635
Sublease offsets (641) (129) (165) (83) (264)
Unconditional throughput and processing fee and purchase
commitments*** 3,785 438 760 598 1,989
------------------------------------------------------------------------------------------------------------------------------
*Includes net unamortized premiums and discounts.
**Excludes $383 million in lease commitments that begin upon delivery of five
crude oil tankers currently under construction. Delivery is expected in the
third and fourth quarters of 2003.
***Represents non-market purchase commitments and obligations to transfer funds
in the future for fixed or minimum amounts at fixed or minimum prices under
various throughput or tolling agreements.
In addition to the above contractual commitments, the company has various
guarantees that have the potential for requiring cash outflows resulting from a
contingent event that could require company performance pursuant to a funding
commitment to a third or related party. See Note 14--Guarantees in the Notes to
Consolidated Financial Statements for additional details. The following table
summarizes the potential amounts and remaining time frames of these direct and
indirect guarantees, as of December 31, 2002.
Millions of Dollars
------------------------------------------------------------
Amount of Expected Guarantee Expiration Per Period
------------------------------------------------------------
Up to 1 2-3 4-5 After
Direct and indirect guarantees Total Year Years Years 5 Years
------------------------------------------------------------------------------------------------------------------------------
Construction completion guarantees* $ 859 418 441 -- --
Guaranteed residual values on leases** 1,821 196 1,046 145 434
Guarantees of joint-venture debt*** 355 54 74 8 219
Other guarantees and indemnifications**** 662 121 141 37 363
------------------------------------------------------------------------------------------------------------------------------
*Amounts represent ConocoPhillips' maximum future potential payments under
construction completion guarantees for debt and bond financing arrangements
secured by the Hamaca and Merey Sweeny joint-venture projects in Venezuela
and Texas, respectively. The debt is non-recourse to ConocoPhillips upon
completion certification of the projects. Figures in the table represent
maximum amount due under the guarantee in the event completion certification
is not achieved. The Merey Sweeny debt is joint-and-several and included at
its gross amount.
**Represents maximum additional amounts that would be due at the end of the
term of certain operating leases if the fair value of the leased property
was less than the guaranteed amount. See Note 19--Non-Mineral Leases in the
Notes to Consolidated Financial Statements.
***Represents amount of obligations directly guaranteed by the company in the
event a guaranteed joint venture does not perform.
****Represents Merey Sweeny, L.P. agreement requirement to pay cash calls as
required to meet minimum operating requirements of the venture, in the event
revenues do not cover expenses over the next 18 years. Also includes certain
potential payments related to two drillships, two LNG vessels, dealer and
jobber loan guarantees to support the company's marketing business, a
guarantee supporting a lease assignment on a corporate aircraft and
guarantees of lease payment obligations for a joint venture. The maximum
amount of future payments under tax and general indemnifications from normal
ongoing operations is indeterminable.
59
CAPITAL SPENDING
CAPITAL EXPENDITURES AND INVESTMENTS
Millions of Dollars
--------------------------------------
2003
Budget 2002 2001 2000**
--------------------------------------
E&P
United States-Alaska $ 704 706 965 538
United States-Lower 48 780 499 389 413
International 3,433 2,071 1,162 726
--------------------------------------------------------------------
4,917 3,276 2,516 1,677
--------------------------------------------------------------------
Midstream 23 5 -- 17
--------------------------------------------------------------------
R&M
United States 881 676 423 217
International 250 164 5 --
--------------------------------------------------------------------
1,131 840 428 217
--------------------------------------------------------------------
Chemicals -- 60 6 67
Emerging Businesses 248 122 -- --
Corporate and Other* 173 85 66 39
--------------------------------------------------------------------
$6,492 4,388 3,016 2,017
====================================================================
United States $2,630 2,043 1,849 1,264
International 3,862 2,345 1,167 753
--------------------------------------------------------------------
$6,492 4,388 3,016 2,017
====================================================================
Discontinued operations $ 60 97 69 5
--------------------------------------------------------------------
*Excludes discontinued operations.
**Excludes the Alaskan acquisition.
ConocoPhillips' capital spending for continuing operations for the three-year
period ending December 31, 2002, totaled $9.4 billion, excluding the purchase of
ARCO's Alaskan businesses in 2000. The company's spending was primarily focused
on the growth of its E&P business, with more than 79 percent of total spending
for continuing operations in this segment. On March 31, 2000, ConocoPhillips
contributed the gas gathering, processing and marketing portion of its then
Midstream business to DEFS. On July 1, 2000, ConocoPhillips contributed its
Chemicals business to CPChem. The capital programs of these joint-venture
companies are intended to be self-funding.
Including approximately $400 million in capitalized interest and $200 million
that will be funded by minority interests in the Bayu-Undan gas export project,
ConocoPhillips' Board of Directors (Board) has approved $6.5 billion for capital
projects and investments for continuing operations in 2003, a 48 percent
increase over 2002 capital spending of $4.4 billion. The company plans to direct
approximately 75 percent of its 2003 capital budget to E&P and about 17 percent
to R&M. The remaining budget will be allocated toward emerging businesses,
mainly power generation, and general corporate purposes, with a significant
majority related to global integration of systems. Forty-one percent of the
budget is targeted for projects in the United States. In addition to the above
budget, ConocoPhillips expects to spend about $300 million to exercise purchase
options for retail stores and office buildings, which are currently within
various lease arrangements.
60
E&P
Capital spending for continuing operations for E&P during the three-year period
ending December 31, 2002, totaled $7.5 billion. The expenditures over the
three-year period supported several key exploration and development projects
including:
o National Petroleum Reserve--Alaska (NPR-A) and satellite field
prospects on Alaska's North Slope;
o the Hamaca heavy-oil project in Venezuela's Orinoco Oil Belt;
o the Peng Lai 19-3 discovery in China's Bohai Bay and additional
Bohai Bay appraisal and satellite field prospects;
o the Kashagan field in the north Caspian Sea, offshore Kazakhstan;
o the Jade, Clair and CMS3 developments in the United Kingdom;
o the Bayu-Undan gas recycle project in the Timor Sea;
o acquisition of deepwater exploratory interests in Angola, Nigeria,
Brazil, and the U.S. Gulf of Mexico;
o fields in Vietnam;
o Canadian conventional oil and gas projects, as well as expansion of
the Syncrude project; and
o fields in Indonesia.
Capital expenditures for construction of the Endeavour Class tankers and an
additional interest in the Trans-Alaska Pipeline System were also included in
the E&P segment.
ConocoPhillips has contracted to build, for approximately $200 million each,
five double-hulled Endeavour Class tankers for use in transporting Alaskan crude
oil to the U.S. West Coast. During 2001, the Polar Endeavour, the first
Endeavour Class tanker, entered service. The second tanker, the Polar
Resolution, entered service in May 2002. The third tanker, the Polar Discovery,
was christened on April 13, 2002, and is expected to enter service in 2003.
ConocoPhillips expects to add a new Endeavour Class tanker to its fleet each
year through 2005, allowing the company to retire older ships and cancel
non-operated charters.
In 2002, the company and its co-venturers drilled or participated in 69
development wells at the Alaska Prudhoe Bay field. Also, new equipment was added
to increase the efficiency of the field's existing water flood. At the Kuparuk
field, 14 new development wells were added, and the Drill Site 3S (Palm) was
installed earlier in the year. Production at Palm began in the fourth quarter.
At Alpine, nine new development wells were added. Other capital spending at
Alpine included facility improvements.
During the fourth quarter of 2001, heavy-crude-oil production began from the
Hamaca project in Venezuela's Orinoco Oil Belt. Construction of an upgrader to
convert heavy crude into a 26-degree API synthetic crude continues. Completion
of the upgrader is expected in 2004. ConocoPhillips owns a
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40 percent equity interest in the Hamaca project. ConocoPhillips' other
heavy-oil project, Petrozuata, incurred no significant capital expenditures in
2002. In addition to the Hamaca development and Petrozuata, ConocoPhillips
submitted a Declaration of Commerciality to the Venezuelan government on the
Corocoro oil discovery in the fourth quarter of 2002. Development approval is
expected in the first half of 2003, with expenditures to follow later in the
year.
In 2002, development activities continued on the company's Peng Lai 19-3
discovery in Block 11/05 in China's Bohai Bay with production beginning late in
the fourth quarter of 2002. Technical design activities for the second phase of
development continued during 2002.
In 2002, ConocoPhillips and its co-venturers, in conjunction with the government
of the Republic of Kazakhstan, declared the Kashagan field on the Kazakhstan
shelf in the north Caspian Sea to be commercial. This declaration of
commerciality enabled preparation of a development plan for the field. Drilling
of the first of five planned appraisal wells was successfully completed in early
2002. Evaluation of test results continues on the second and third wells,
drilling operations continue on the fourth, and testing continues on the fifth
of these appraisal wells. In May 2002, ConocoPhillips, along with the other
remaining co-venturers, completed the acquisition of proportionate interests of
other co-venturers rights, which increased ConocoPhillips' ownership interest
from 7.14 percent to 8.33 percent. In October 2002, ConocoPhillips and its
co-venturers announced a new hydrocarbon discovery in the Kazakhstan sector of
the Caspian Sea. An initial test well, the Kalamkas-1, flowed oil. This well is
located adjacent to the Kashagan field.
In 2002, development of ConocoPhillips' Jade field, in the U.K. sector of the
North Sea, continued with first production occurring in February 2002. A second
production well was successfully drilled and began producing during the second
quarter of 2002. In the second half of the year, two more production wells were
completed and began producing. ConocoPhillips is the operator and holds a 32.5
percent interest in Jade. An exploration well was spudded late in 2002 and
drilling operations are continuing into 2003.
In September 2002, ConocoPhillips began production from the Hawksley field in
the southern sector of the U.K. North Sea. The Hawksley discovery well,
44/17a-6y, was completed in July 2002 in one of five natural gas reservoirs
currently being developed by ConocoPhillips as a single, unitized project. The
other reservoirs are McAdam, Murdoch K, Boulton, and Watt. Collectively, they
are known as CMS3 due to their utilization of the production and transportation
facilities of the ConocoPhillips-operated Caister Murdoch system (CMS).
ConocoPhillips is the operator of CMS3 and holds a 59.5 percent interest.
ConocoPhillips' $1.9 billion gross Bayu-Undan gas-recycle project activities
continued in the Timor Sea during 2002. This involved the drilling of future
production wells from the wellhead platform and the installation of the platform
jackets and all in-field flowlines. Fabrication and assembly of two large
platform decks continues in Korea, as does work on the multi-product floating,
storage and offtake vessel (FSO). At year-end, the project was approximately 69
percent complete. During mid-2003, the decks and FSO will be installed with
first gas and commissioning commencing in the third quarter of 2003. Liquid
sales will commence in early 2004 with production ramp-up occurring during the
first six months of 2004. Activity associated with the Bayu-Undan gas export
project, including a pipeline to Darwin and a liquefied natural gas plant,
currently is focused on preparation of approval documentation and project
design. Construction is expected to start in early 2003, following the Timor Sea
Treaty ratification by Australia. ConocoPhillips' direct interest in the
unitized Bayu-Undan field was 55.9 percent at year-end 2002. A further 8.25
percent interest was held through Petroz N.L., in which the company had an 89.7
percent stock ownership at year-end. ConocoPhillips has effective voting control
over the pipeline and liquefied natural gas plant component of the gas export
project and thus plans to consolidate that part of the Bayu-Undan project and
present the other venturers as minority interests.
62
In 2002, ConocoPhillips continued pursuing the goal of increasing its presence
in high-potential deepwater areas. ConocoPhillips was the high bidder in the
central Gulf of Mexico sale for the Lorien prospect located in Green Canyon
Block 199 and was officially awarded the block in 2002. In Brazil,
ConocoPhillips acquired joint-venture partners for its two deepwater blocks and
purchased additional seismic data. Plans for 2003 include the purchase of
additional seismic data and the further evaluation of the two blocks' prospects.
In May 2002, initial results showed that the first exploratory well drilled in
Block 34, offshore Angola, was a dry hole. In view of this information,
ConocoPhillips reassessed the fair value of the remainder of the block and
determined that its investment in the block was impaired by $77 million, both
before- and after-tax. Further technical analysis of the results of this first
well continues. The second of three commitment wells in this block is scheduled
for drilling in 2003.
ConocoPhillips entered into a production sharing contract on Oil Prospecting
Lease (OPL) 318, deepwater Nigeria, on June 14, 2002, where ConocoPhillips is
operator with 50 percent interest. The acquisition of 3-D seismic data on OPL
318 is planned to begin in 2003, with the first exploratory well expected to be
drilled in the fourth quarter of 2004.
In the third quarter of 2002, production began from two new wellhead platforms
in the Block 15-2 Rang Dong field in Vietnam. These additional platforms
increased production from the field from under 6,800 to over 12,400 net barrels
per day at year-end 2002.
In Canada, total capital expended in 2002 was $136 million. Capital spending for
conventional oil and gas properties was $75 million and Syncrude expansion
continued with $54 million expended. In addition, the Mackenzie Delta/Parson's
Lake project efforts focused on gaining pipeline regulatory approval and
acquiring seismic data.
ConocoPhillips continued with the development of key gas fields in the Natuna
Sea in Indonesia. Total spending on Block B gas development in the last four
months of 2002 was $101 million, including investment in the Belanak floating,
production, storage and offtake vessel and wellhead platform, plus wells and
pipeline infrastructure required for the newly commenced gas sales to Petronas
Malaysia.
ConocoPhillips acquired a 14 percent interest in PT Transportasi Gas Indonesia
(TGI) in 2002. The primary assets of TGI are the Grissik-Duri pipeline, which
has been in operation since 1998, and the Grissik-Singapore pipeline that is
currently under construction with a completion date expected in late 2003. Total
funding in 2002 was $54 million, which includes acquisition cost and capital
expenditures.
Other capital spending for E&P during the three year-period ended December 31,
2002, supported:
o the Eldfisk waterflood development in Norway;
o the acquisition and development of coalbed-methane and conventional
gas prospects and producing properties in the U.S. Lower 48; and
o North Sea prospects in the U.K. and Norwegian sectors, plus other
Atlantic Margin wells in the United Kingdom, Greenland and the Faroe
Islands.
63
2003 Capital Budget
E&P's 2003 capital budget for continuing operations is $4.9 billion, 50 percent
higher than actual expenditures in 2002. Thirty percent of E&P's 2003 capital
budget is planned for the United States. Of that, 47 percent is slated for
Alaska.
ConocoPhillips has budgeted $461 million for worldwide exploration capital
activities in 2003, with 28 percent of that amount, $131 million allocated for
the United States. More than $41 million of the U.S. total will be directed
toward the exploration program in Alaska, where wells are planned in the NPR-A
and other locations on the North Slope. Outside the United States, significant
exploration expenditures are planned in Kazakhstan, Venezuela, the United
Kingdom and Norway.
The company plans to spend about $700 million in 2003 for its Alaskan
operations. Large capital projects include the ongoing construction of three
Endeavour Class tankers; development of the Meltwater, Palm and West Sak fields
in the Greater Kuparuk area; development of the Borealis field in the Greater
Prudhoe Bay area; as well as the exploratory activity discussed above.
In the Lower 48, capital expenditures will be focused on exploration and
continued development of the company's acreage positions in the deepwater Gulf
of Mexico, South Texas, the San Juan Basin, the Permian Basin, and the Texas
Panhandle. Major deepwater developments include Magnolia, K2, and the Princess
fields, while exploration continues using the drillship Pathfinder.
E&P is directing $3.4 billion of its 2003 capital budget to international
projects. The majority of these funds will be directed to developing major
long-term projects, including the Bayu-Undan liquids development and
gas-recycling project in the Timor Sea, the Hamaca heavy-oil project and
Corocoro development in Venezuela, additional development of oil and gas
reserves in offshore Block B and onshore South Sumatra blocks in Indonesia,
Blocks 15-1 and 15-2 in Vietnam, and Bohai Bay in China. In addition, funds will
be used to expand the company's positions in the U.K. and Norwegian sectors of
the North Sea, Syncrude operations in western Canada and to develop the Surmont
heavy-oil project in Canada, and the Kashagan field in the Caspian Sea.
Costs incurred for the years ended December 31, 2002, 2001, and 2000, relating
to the development of proved undeveloped oil and gas reserves were $1,631
million, $1,423 million, and $857 million, respectively. As of December 31,
2002, estimated future development costs relating to the development of proved
undeveloped oil and gas reserves for the years 2003 through 2005 were projected
to be $1,815 million, $939 million, and $539 million, respectively.
R&M
Capital spending for continuing operations for R&M during the three-year period
ending December 31, 2002, was primarily for refinery-upgrade projects to improve
product yields, to meet new environmental standards, to improve the operating
integrity of key processing units, and to install advanced process control
technology, as well as for safety projects.
Key significant projects during the three-year period included:
o construction of a polypropylene plant at the Bayway refinery in New
Jersey;
o construction on a fluid catalytic cracking (FCC) unit at the
Ferndale, Washington, refinery;
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o expansion of the alkylation unit at the Los Angeles refinery;
o completion of a coker and continuous catalytic reformer at the
company's Sweeny, Texas, refinery;
o capacity expansion and debottlenecking projects at the Borger,
Texas, refinery;
o completion of a commercial S Zorb Sulfur Removal Technology (S Zorb)
unit at the Borger refinery;
o an expansion of capacity in the Seaway crude-oil pipeline; and
o installation of advanced central control buildings and technologies
at the Sweeny and Borger facilities.
Total capital spending for continuing operations for R&M for the three-year
period was $1.5 billion, representing approximately 16 percent of
ConocoPhillips' total capital spending for continuing operations.
During 2002, construction continued on two major projects: a polypropylene plant
at the Bayway refinery in Linden, New Jersey, and an FCC unit at the Ferndale,
Washington, refinery. The Bayway polypropylene plant will utilize propylene
feedstock from the Bayway refinery to make up to 775 million pounds per year of
polypropylene. The plant became operational in March 2003. The FCC unit at
Ferndale is expected to be fully operational in the second quarter of 2003 and
will enable the refinery to significantly improve gasoline production per barrel
of crude input.
In 2002, ConocoPhillips made investments to improve its ability to meet
regulatory "clean fuels" requirements throughout its refining system. The
company plans to spend approximately $400 million per year for the next two
years on clean fuels projects in the United States and already is well ahead of
regulatory mandates for producing clean fuel in Europe. In 2002, ConocoPhillips
completed a large continuous pilot plant demonstrating S Zorb for diesel, began
construction of an S Zorb gasoline unit at its Ferndale, Washington, refinery,
and announced its sixth licensing agreement for the use of S Zorb for gasoline
and second licensing agreement for the use of S Zorb for diesel. The S Zorb
process significantly reduces sulfur content in gasoline or diesel fuel for
meeting new government regulations.
In 2002, a major expansion of the alkylation unit at the Los Angeles refinery
was completed and as a result, production of non-MTBE (methyl tertiary-butyl
ether) gasoline has increased.
2003 Capital Budget
R&M's 2003 capital budget for continuing operations is $1.1 billion, a 35
percent increase over spending of $840 million in 2002. Domestic spending is
expected to consume about 80 percent of the R&M budget.
The company plans to direct about $750 million of the R&M capital budget to
domestic refining, of which about 45 percent of the expenditures are related to
clean fuels, safety and environmental projects. Domestic marketing,
transportation and specialty businesses expect to spend about $130 million, with
the remaining budget to fund projects in the company's international refining
and marketing businesses in Europe and the Asia-Pacific region.
65
EMERGING BUSINESSES
Capital spending for Emerging Businesses during 2002 was primarily for
construction of the Immingham combined heat and power cogeneration plant near
the company's Humber refinery in the United Kingdom. Additional investments were
made at a domestic power plant in Orange, Texas, and at the company's carbon
fibers plant in Ponca City, Oklahoma.
Emerging Businesses' 2003 capital budget of $248 million is primarily dedicated
to the continued construction of the Immingham combined heat and power
cogeneration plant.
CONTINGENCIES
LEGAL AND TAX MATTERS
ConocoPhillips accrues for contingencies when a loss is probable and the amounts
can be reasonably estimated. Based on currently available information, the
company believes that it is remote that future costs related to known contingent
liability exposures will exceed current accruals by an amount that would have a
material adverse impact on the company's financial statements.
All significant litigation arising from the June 23, 1999, flash fire that
occurred in a reactor vessel at the K-Resin styrene-butadiene copolymer (SBC)
plant at the Houston Chemical Complex has now been resolved.
On March 27, 2000, an explosion and fire occurred at the K-Resin SBC plant due
to the overpressurization of an out-of-service butadiene storage tank. One
employee was killed and several individuals, including employees of both
ConocoPhillips and its contractors, were injured. Additionally, individuals who
were allegedly in the area of the Houston Chemical Complex at the time of the
incident have claimed they suffered various personal injuries due to exposure to
the event. The wrongful death claim and the claims of the most seriously injured
workers have been resolved. Currently, there are eight lawsuits pending on
behalf of approximately 100 primary plaintiffs. Under the indemnification
provisions of subcontracting agreements with Zachry and Brock Maintenance, Inc.,
ConocoPhillips sought indemnification from these subcontractors with respect to
claims made by their employees. Although that plant was contributed to CPChem
under the Contribution Agreement, ConocoPhillips retains liability for damages
arising out of the incident.
ENVIRONMENTAL
ConocoPhillips and each of its various businesses are subject to the same
numerous international, federal, state, and local environmental laws and
regulations as are other companies in the petroleum exploration and production;
and refining, marketing and transportation of crude oil and refined products
businesses. The most significant of these environmental laws and regulations
include, among others, the:
o Federal Clean Air Act, which governs air emissions;
o Federal Clean Water Act, which governs discharges to water bodies;
o Federal Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA), which imposes liability on generators,
transporters, and arrangers of hazardous substances at sites where
hazardous substance releases have occurred or are threatened to
occur;
66
o Federal Resource Conservation and Recovery Act (RCRA), which governs
the treatment, storage, and disposal of solid waste;
o Federal Oil Pollution Act of 1990 (OPA90) under which owners and
operators of onshore facilities and pipelines, lessees or permittees
of an area in which an offshore facility is located, and owners and
operators of vessels are liable for removal costs and damages that
result from a discharge of oil into navigable waters of the United
States;
o Federal Emergency Planning and Community Right-to-Know Act (EPCRA)
which requires facilities to report toxic chemical inventories with
local emergency planning committees and responses departments;
o Federal Safe Drinking Water Act which governs the disposal of
wastewater in underground injections wells; and
o U.S. Department of the Interior regulations, which relate to
offshore oil and gas operations in U.S. waters and impose liability
for the cost of pollution cleanup resulting from the lessee's
operations and potential liability for pollution damages.
These laws and their implementing regulations set limits on emissions and, in
the case of discharges to water, establish water quality limits. They also, in
most cases, require permits in association with new or modified operations.
These permits can require an applicant to collect substantial information in
connection with the application process, which can be expensive and
time-consuming. In addition, there can be delays associated with notice and
comment periods and the agency's processing of the application. Many of the
delays associated with the permitting process are beyond the control of the
applicant.
Many states and foreign countries where ConocoPhillips operates also have, or
are developing, similar environmental laws and regulations governing the same
types of activities. While similar, in some cases these regulations may impose
additional, or more stringent, requirements that can add to the cost and
difficulty of marketing or transporting products across state and international
borders.
The ultimate financial impact arising from environmental laws and regulations is
neither clearly known nor easily determinable as new standards, such as air
emission standards, water quality standards and stricter fuel regulations,
continue to evolve. However, environmental laws and regulations are expected to
continue to have an increasing impact on ConocoPhillips' operations in the
United States and in most of the countries in which the company operates.
Notable areas of potential impacts include air emission compliance and
remediation obligations in the United States. Under the Clean Air Act, the EPA
has promulgated a number of stringent limits on air emissions and established a
federally mandated operating permit program. Violations of the Clean Air Act are
enforceable with civil and criminal sanctions.
The EPA has also promulgated specific rules governing the sulfur content of
gasoline, known generically as the "Tier II Sulfur Rules," which become
applicable to ConocoPhillips' gasoline as early as 2004. The company is
implementing a compliance strategy for meeting the requirements, including the
use of ConocoPhillips' proprietary technology known as S Zorb. The company
expects to use a combination of technologies to achieve compliance with these
rules and has made preliminary estimates of its cost of compliance. These costs
will be included in future budgeting for refinery compliance. The EPA has also
promulgated sulfur content rules for highway diesel fuel that become applicable
in 2006. ConocoPhillips is currently developing and testing an S Zorb system for
removing sulfur from diesel fuel. It is anticipated that S Zorb will be used as
part of ConocoPhillips' strategy for complying with these rules. Because the
company is still evaluating and developing capital strategies for compliance
with the rule, ConocoPhillips cannot provide precise cost estimates at this
time, but will do so and report these compliance costs as required by law.
67
Additional areas of potential air-related impacts to ConocoPhillips are the
proposed revisions to the National Ambient Air Quality Standards (NAAQS) and the
Kyoto Protocol. In July 1997, the EPA promulgated more stringent revisions to
the NAAQS for ozone and particulate matter. Since that time, final adoption of
these revisions has been the subject of litigation (American Trucking
Association, Inc. et al. v. United States Environmental Protection Agency) that
eventually reached the U.S. Supreme Court during fall 2000. In February 2001,
the U.S. Supreme Court remanded this matter, in part, to the EPA to address the
implementation provisions relating to the revised ozone NAAQS. If adopted, the
revised NAAQS could result in substantial future environmental expenditures for
ConocoPhillips.
In 1997, an international conference on global warming concluded an agreement,
known as the Kyoto Protocol, which called for reductions of certain emissions
that contribute to increases in atmospheric greenhouse gas concentrations. The
United States has not ratified the treaty codifying the Kyoto Protocol but may
in the future. In addition, other countries where ConocoPhillips has interests,
or may have interests in the future, have made commitments to the Kyoto Protocol
and are in various stages of formulating applicable regulations. It is not,
however, possible to accurately estimate the costs that could be incurred by
ConocoPhillips to comply with such regulations, but such expenditures could be
substantial.
ConocoPhillips also is subject to certain laws and regulations relating to
environmental remediation obligations associated with current and past
operations. Such laws and regulations include CERCLA and RCRA and their state
equivalents. Remediation obligations include cleanup responsibility arising from
petroleum releases from underground storage tanks located at numerous past and
present ConocoPhillips owned and/or operated petroleum-marketing outlets
throughout the United States. Federal and state laws require that contamination
caused by such underground storage tank releases be assessed and remediated to
meet applicable standards. In addition to other cleanup standards, many states
have adopted cleanup criteria for MTBE for both soil and groundwater. MTBE
standards continue to evolve, and future environmental expenditures associated
with the remediation of MTBE-contaminated underground storage tank sites could
be substantial.
RCRA requires permitted facilities to undertake an assessment of environmental
conditions at the facility. If conditions warrant, ConocoPhillips may be
required to remediate contamination caused by prior operations. In contrast to
CERCLA, which is often referred to as "Superfund," the cost of corrective action
activities under the RCRA corrective action program typically is borne solely by
ConocoPhillips. Over the next decade, ConocoPhillips anticipates that
significant ongoing expenditures for RCRA remediation activities may be
required, but such annual expenditures for the near term are not expected to
vary significantly from the range of such expenditures the company has
experienced over the past few years. Longer term, expenditures are subject to
considerable uncertainty and may fluctuate significantly.
ConocoPhillips from time to time receives requests for information or notices of
potential liability from the EPA and state environmental agencies alleging that
we are a potentially responsible party under CERCLA or an equivalent state
statute. On occasion, ConocoPhillips also has been made a party to cost recovery
litigation by those agencies or by private parties. These requests, notices and
lawsuits assert potential liability for remediation costs at various sites that
typically are not owned by ConocoPhillips but allegedly contain wastes
attributable to the company's past operations. As of December 31, 2001, the
company reported it had been notified of potential liability under CERCLA at 29
sites around the United States. The company also had been notified of potential
liability under comparable state laws at 11 sites around the United States. At
August 30, 2002, the date of the merger, Conoco had been notified of potential
liability under CERCLA and comparable state laws at 24 sites around the United
States. At seven of these sites, both Conoco and the company had been notified
of potential liability. The resulting total for ConocoPhillips was 57 sites. At
December 31, 2002, ConocoPhillips had resolved three of these
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sites and received four new notices of potential liability, leaving
approximately 58 sites where ConocoPhillips has been notified of potential
liability.
For most Superfund sites, ConocoPhillips' potential liability will be
significantly less than the total site remediation costs because the percentage
of waste attributable to ConocoPhillips versus that attributable to all other
potentially responsible parties is relatively low. Although liability of those
potentially responsible is generally joint and several for federal sites and
frequently so for state sites, other potentially responsible parties at sites
where ConocoPhillips is a party typically have had the financial strength to
meet their obligations, and where they have not, or where potentially
responsible parties could not be located, ConocoPhillips' share of liability has
not increased materially. Many of the sites at which the company is potentially
responsible are still under investigation by the EPA or the state agencies
concerned. Prior to actual cleanup, those potentially responsible normally
assess site conditions, apportion responsibility and determine the appropriate
remediation. In some instances, ConocoPhillips may have no liability or attain a
settlement of liability. Actual cleanup costs generally occur after the parties
obtain EPA or equivalent state agency approval. There are relatively few sites
where ConocoPhillips is a major participant, and neither the cost to
ConocoPhillips of remediation at those sites nor such cost at all CERCLA sites
in the aggregate is expected to have a material adverse effect on the
competitive or financial condition of ConocoPhillips.
Expensed environmental costs were $546 million in 2002 and are expected to be
approximately $687 million in 2003 and $717 million in 2004. Capitalized
environmental costs were $325 million in 2002 and are expected to be
approximately $638 million and $718 million in 2003 and 2004, respectively.
Remediation Accruals
ConocoPhillips accrues for remediation activities when it is probable that a
liability has been incurred and reasonable estimates of the liability can be
made. These accrued liabilities are not reduced for potential recoveries from
insurers or other third parties and are not discounted (except, if assumed in a
purchase business combination, such costs are recorded on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state laws that
require the company to undertake certain investigative and remedial activities
at sites where it conducts, or once conducted, operations or at sites where
ConocoPhillips-generated waste was disposed. The accrual also includes a number
of sites identified by ConocoPhillips that may require environmental
remediation, but which are not currently the subject of CERCLA, RCRA or state
enforcement activities. If applicable, undiscounted receivables are accrued for
probable insurance or other third-party recoveries. In the future,
ConocoPhillips may incur significant costs under both CERCLA and RCRA.
Considerable uncertainty exists with respect to these costs, and under adverse
changes in circumstances, potential liability may exceed amounts accrued as of
December 31, 2002.
Remediation activities vary substantially in duration and cost from site to
site, depending on the mix of unique site characteristics, evolving remediation
technologies, diverse regulatory agencies and enforcement policies, and the
presence or absence of potentially liable third parties. Therefore, it is
difficult to develop reasonable estimates of future site remediation costs.
At December 31, 2002, ConocoPhillips' balance sheet included a total
environmental accrual of $743 million, compared with $439 million at December
31, 2001, an increase of $304 million, primarily resulting from the merger. The
majority of these expenditures are expected to be incurred within the next 30
years.
Notwithstanding any of the foregoing and as with other companies engaged in
similar businesses, environmental costs and liabilities are inherent in
ConocoPhillips' operations and products, and there can be no assurance that
material costs and liabilities will not be incurred. However, ConocoPhillips
currently
69
does not expect any material adverse effect upon its results of operations or
financial position as a result of compliance with environmental laws and
regulations.
OTHER
ConocoPhillips has deferred tax assets related to certain accrued liabilities,
alternative minimum tax credits, and loss carryforwards. Valuation allowances
have been established for certain foreign and state net operating loss
carryforwards that reduce deferred tax assets to an amount that will, more
likely than not, be realized. Uncertainties that may affect the realization of
these assets include tax law changes and the future level of product prices and
costs. Based on the company's historical taxable income, its expectations for
the future, and available tax-planning strategies, management expects that the
net deferred tax assets will be realized as offsets to reversing deferred tax
liabilities and as reductions in future taxable income. The alternative minimum
tax credit can be carried forward indefinitely to reduce the company's regular
tax liability.
NEW ACCOUNTING STANDARDS
There are a number of new FASB Statements of Financial Accounting Standards
(SFAS) and Interpretations that ConocoPhillips implemented either in December
2002 or January 2003, as required: SFAS No. 143, "Accounting for Asset
Retirement Obligations;" SFAS No. 145, "Rescission of FASB Statements No. 4, 44,
and 64, Amendment of FASB Statement No. 13, and Technical Corrections;" SFAS No.
146, "Accounting for Costs Associated with Exit or Disposal Activities;" SFAS
No. 148, "Accounting for Stock-Based Compensation--Transition and Disclosure;"
Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others;" and
Interpretation No. 46, "Consolidation of Variable Interest Entities." In
addition, in 2003, the FASB is expected to issue SFAS No. 149, "Accounting for
Certain Financial Instruments with Characteristics of Liabilities and Equity."
For additional information about these, see Note 27--New Accounting Standards in
the Notes to Consolidated Financial Statements, which is incorporated herein by
reference.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to select appropriate accounting
policies and to make estimates and assumptions that affect the reported amounts
of assets, liabilities, revenues and expenses. See Note 1--Accounting Policies
in the Notes to Consolidated Financial Statements for descriptions of the
company's major accounting policies. Certain of these accounting policies
involve judgments and uncertainties to such an extent that there is a reasonable
likelihood that materially different amounts would have been reported under
different conditions, or if different assumptions had been used.
OIL AND GAS ACCOUNTING
Accounting for oil and gas exploratory activity is subject to special accounting
rules that are unique to the oil and gas industry. The acquisition of geological
and geophysical seismic information, prior to the discovery of proved reserves,
is expensed as incurred, similar to accounting for research and development
costs. However, leasehold acquisition costs and exploratory well costs are
capitalized on the balance sheet, pending determination of whether proved oil
and gas reserves have been discovered on the prospect.
70
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for
impairment based on exploration and drilling efforts to date. For leasehold
acquisition costs that individually are relatively small, management exercises
judgment and determines a percentage probability that the prospect ultimately
will fail to find proved oil and gas reserves and pools that leasehold
information with others in the geographic area. For prospects in areas that have
had limited, or no, previous exploratory drilling, the percentage probability of
ultimate failure is normally judged to be quite high. This judgmental percentage
is multiplied by the leasehold acquisition cost, and that product is divided by
the contractual period of the leasehold to determine a periodic leasehold
impairment charge that is reported in exploration expense. This judgmental
probability percentage is reassessed and adjusted throughout the contractual
period of the leasehold based on favorable or unfavorable exploratory activity
on the leasehold or on adjacent leaseholds, and leasehold impairment
amortization expense is adjusted prospectively. By the end of the contractual
period of the leasehold, the impairment probability percentage will have been
adjusted to 100 percent if the leasehold is expected to be abandoned, or will
have been adjusted to zero percent if there is an oil or gas discovery that is
under development. See the supplemental Oil and Gas Operations disclosures about
Costs Incurred and Capitalized Costs for more information about the amounts and
geographic locations of costs incurred in acquisition activity, and the amounts
on the balance sheet related to unproved properties.
Exploratory Costs
For exploratory wells, drilling costs are temporarily capitalized, or
"suspended," on the balance sheet, pending a judgmental determination of whether
potentially economic oil and gas reserves have been discovered by the drilling
effort. This judgment usually is made within two months of the completion of the
drilling effort, but can take longer, depending on the complexity of the
geologic structure. Accounting rules require that this judgment be made at least
within one year of well completion. If a judgment is made that the well did not
encounter potentially economic oil and gas quantities, the well costs are
expensed as a dry hole and are reported in exploration expense. Exploratory
wells that are judged to have discovered potentially economic quantities of oil
and gas and that are in areas where a major capital expenditure (e.g., a
pipeline or offshore platform) would be required before production could begin,
and where the economic viability of that major capital expenditure depends upon
the successful completion of further exploratory work in the area, remain
capitalized on the balance sheet as long as additional exploratory appraisal
work is under way or firmly planned. For complicated offshore exploratory
discoveries, it is not unusual to have exploratory wells remain suspended on the
balance sheet for several years while the company performs additional appraisal
drilling and seismic work on the potential oil and gas field. Unlike leasehold
acquisition costs, there is no periodic impairment assessment of suspended
exploratory well costs. Management continuously monitors the results of the
additional appraisal drilling and seismic work and expenses the suspended well
costs as dry holes when it judges that the potential field does not warrant
further exploratory efforts in the near term. See the supplemental Oil and Gas
Operations disclosures about Costs Incurred and Capitalized Costs for more
information about the amounts and geographic locations of costs incurred in
exploration activity and the amounts on the balance sheet related to unproved
properties, as well as the Wells In Progress disclosure for the number and
geographic location of wells not yet declared productive or dry.
Proved Oil and Gas Reserves
Engineering estimates of the quantities of recoverable oil and gas reserves in
oil and gas fields are inherently imprecise and represent only approximate
amounts because of the subjective judgments involved in developing such
information. Despite the inherent imprecision in these engineering estimates,
accounting rules require supplemental disclosure of "proved" oil and gas reserve
estimates due to the importance of these estimates to better understanding the
perceived value and future cash flows of a company's oil and gas operations. The
judgmental estimation of proved oil and gas reserves is also important to the
income statement because the proved oil and gas reserve estimate for a field
serves as the
71
denominator in the unit-of-production calculation of depreciation, depletion and
amortization of the capitalized costs for that field. There are several
authoritative guidelines regarding the engineering criteria that have to be met
before estimated oil and gas reserves can be designated as "proved." The
company's reservoir engineering department has policies and procedures in place
that are consistent with these authoritative guidelines. The company has
qualified and experienced internal engineering personnel who make these
estimates. Proved reserve estimates are updated annually and take into account
recent production and seismic information about each field. Also, as required by
authoritative guidelines, the estimated future date when a field will be
permanently shut-in for economic reasons is based on an extrapolation of oil and
gas prices and operating costs prevalent at the balance sheet date. This
estimated date when production will end affects the amount of estimated
recoverable reserves. Therefore, as prices and cost levels change from year to
year, the estimate of proved reserves also changes.
Canadian Syncrude Reserves
Canadian Syncrude proven reserves cannot be measured precisely. Reserve
estimates of Canadian Syncrude are based on subjective judgments involving
geological and engineering assessments of in-place crude bitumen volume, the
mining plan, historical extraction recovery and upgrading yield factors,
installed plant operating capacity and operating approval limits. The
reliability of these estimates at any point in time depends on both the quality
and quantity of the technical and economic data and the efficiency of extracting
the bitumen and upgrading it into a light sweet crude oil. Despite the inherent
imprecision in these engineering estimates, these estimates are used in
determining depreciation expense.
IMPAIRMENT OF ASSETS
Long-lived assets used in operations are assessed for impairment whenever
changes in facts and circumstances indicate a possible significant deterioration
in the future cash flows expected to be generated by an asset group. If, upon
review, the sum of the undiscounted pretax cash flows is less than the carrying
value of the asset group, the carrying value is written down to estimated fair
value. Individual assets are grouped for impairment purposes based on a
judgmental assessment of the lowest level for which there are identifiable cash
flows that are largely independent of the cash flows of other groups of
assets--generally on a field-by-field basis for exploration and production
assets, at an entire complex level for downstream assets, or at a site level for
retail stores. Because there usually is a lack of quoted market prices for
long-lived assets, the fair value usually is based on the present values of
expected future cash flows using discount rates commensurate with the risks
involved in the asset group. The expected future cash flows used for impairment
reviews and related fair value calculations are based on judgmental assessments
of future production volumes, prices and costs, considering all available
information at the date of review. See Note 10--Impairments in the Notes to
Consolidated Financial Statements.
DISMANTLEMENT, REMOVAL AND ENVIRONMENTAL COSTS
Under various contracts, permits and regulations, the company has material legal
obligations to remove tangible equipment and restore the land or seabed at the
end of operations at production sites. The largest asset removal obligations
facing ConocoPhillips involve removal and disposal of offshore oil and gas
platforms around the world, and oil and gas production facilities and pipelines
in Alaska. The estimated undiscounted costs, net of salvage values, of
dismantling and removing these facilities are accrued, using primarily the
unit-of-production method, over the productive life of the asset. Estimating the
future asset removal costs necessary for this accounting calculation is
difficult. Most of these removal obligations are many years in the future and
the contracts and regulations often have vague descriptions of what removal
practices and criteria will have to be met when the removal event actually
occurs. Asset removal technologies and costs are constantly changing, as well as
political, environmental, safety and public relations considerations. See Note
11--Accrued Dismantlement, Removal and Environmental Costs in the Notes to
Consolidated Financial Statements.
72
BUSINESS ACQUISITIONS
Purchase Price Allocation
Accounting for the acquisition of a business requires the allocation of the
purchase price to the various assets and liabilities of the acquired business.
For most assets and liabilities, purchase price allocation is accomplished by
recording the asset or liability at its estimated fair value. The most difficult
estimations of individual fair values are those involving properties, plants and
equipment and identifiable intangible assets. The company uses all available
information to make these fair value determinations and, for major business
acquisitions, typically engages an outside appraisal firm to assist in the fair
value determination of the acquired long-lived assets. The company has, if
necessary, up to one year after the acquisition closing date to finish these
fair value determinations and finalize the purchase price allocation.
Intangible Assets and Goodwill
In connection with the acquisition of Tosco Corporation on September 14, 2001,
and the merger on August 30, 2002, the company recorded material intangible
assets for tradenames, air emission permit credits, and permits to operate
refineries. These intangible assets were determined to have indefinite useful
lives and so are not amortized. This judgmental assessment of an indefinite
useful life has to be continuously evaluated in the future. If, due to changes
in facts and circumstances, management determines that these intangible assets
then have definite useful lives, amortization will have to commence at that time
on a prospective basis. As long as these intangible assets are judged to have
indefinite lives, they will be subject to periodic lower-of-cost-or-market
tests, which requires management's judgment of the estimated fair value of these
intangible assets. See Note 6--Acquisition of Tosco Corporation, Note 3--Merger
of Conoco and Phillips, and Note 10--Impairments in the Notes to Consolidated
Financial Statements.
Also in connection with the acquisition of Tosco and the merger, the company
recorded a material amount of goodwill. Under the accounting rules for goodwill,
this intangible asset is not amortized. Instead, goodwill is subject to annual
reviews for impairment based on a two-step accounting test. The first step is to
compare the estimated fair value of any reporting units within the company that
have recorded goodwill with the recorded net book value (including the goodwill)
of the reporting unit. If the estimated fair value of the reporting unit is
higher than the recorded net book value, no impairment is deemed to exist and no
further testing is required that year. If, however, the estimated fair value of
the reporting unit is below the recorded net book value, then a second step must
be performed to determine the amount of the goodwill impairment to record, if
any. In this second step, the estimated fair value from the first step is used
as the purchase price in a hypothetical new acquisition of the reporting unit.
The various purchase business combination rules are followed to determine a
hypothetical purchase price allocation for the reporting unit's assets and
liabilities. The residual amount of goodwill that results from this hypothetical
purchase price allocation is compared with the recorded amount of goodwill for
the reporting unit, and the recorded amount is written down to the hypothetical
amount if lower. Because quoted market prices for the company's reporting units
are not available, management has to apply judgment in determining the estimated
fair value of its reporting units for purposes of performing the first step of
this periodic goodwill impairment test. Management uses all available
information to make these fair value determinations and may engage an outside
appraisal firm for assistance. In addition, if the first test step is not met,
further judgment has to be applied in determining the fair values of individual
assets and liabilities for purposes of the hypothetical purchase price
allocation. Again, management has to use all available information to make these
fair value determinations and may engage an outside appraisal firm for
assistance. At year-end 2002, the estimated fair values of the company's
domestic refining and marketing reporting units, excluding those acquired in the
merger and those included in discontinued operations, were more than 10 percent
higher than the recorded net book values (including the Tosco goodwill) of the
reporting units. However, a lower fair value estimate in the future could result
in impairment of the remaining $2.4 billion
73
of Tosco goodwill. The allocation of goodwill attributable to the ConocoPhillips
merger to reporting units, and its sensitivity to future impairment, will occur
after the final allocation of the purchase price in 2003.
INVENTORY VALUATION
Prior to the acquisition of Tosco in September 2001 and the merger in August
2002, the company's inventories on the last-in, first-out (LIFO) cost basis were
predominantly reflected on the balance sheet at historical cost layers
established many years ago, when price levels were much lower. Therefore, prior
to 2001, the company's LIFO inventories were relatively insensitive to current
price level changes. However, the acquisition of Tosco and the merger added LIFO
cost layers that were recorded at replacement cost levels prevalent in late
September 2001 and August 2002, respectively. As a result, the company's LIFO
cost inventories are now much more sensitive to lower-of-cost-or-market
impairment write-downs, whenever price levels fall. ConocoPhillips recorded a
LIFO inventory lower-of-cost-or-market impairment in the fourth quarter of 2001
due to a crude oil price deterioration. While crude oil is not the only product
in the company's LIFO pools, its market value is a major factor in
lower-of-cost-or-market calculations. The company estimates that additional
impairments could occur if a 60 percent/40 percent blended average of West Texas
Intermediate/Brent crude oil prices falls below $21.75 per barrel at a reporting
date. The determination of replacement cost values for the
lower-of-cost-or-market test uses objective evidence, but does involve judgment
in determining the most appropriate objective evidence to use in the
calculations.
PROJECTED BENEFIT OBLIGATIONS
Determination of the projected benefit obligations for the company's defined
benefit pension and postretirement plans are important to the recorded amounts
for such obligations on the balance sheet and to the amount of benefit expense
in the income statement. This also impacts the required company contributions
into the plans. The actuarial determination of projected benefit obligations and
company contribution requirements involves judgment about uncertain future
events, including estimated retirement dates, salary levels at retirement,
mortality rates, lump-sum election rates, rates of return on plan assets, future
health care cost-trend rates, and rates of utilization of health care services
by retirees. Due to the specialized nature of these calculations, the company
engages outside actuarial firms to assist in the determination of these
projected benefit obligations. For Employee Retirement Income Security Act-
qualified pension plans, the actuary exercises fiduciary care on behalf of plan
participants in the determination of the judgmental assumptions used in
determining required company contributions into plan assets. Due to differing
objectives and requirements between financial accounting rules and the pension
plan funding regulations promulgated by governmental agencies, the actuarial
methods and assumptions for the two purposes differ in certain important
respects. Ultimately, the company will be required to fund all promised benefits
under pension and postretirement benefit plans not funded by plan assets or
investment returns, but the judgmental assumptions used in the actuarial
calculations significantly affect periodic financial statements and funding
patterns over time. Benefit expense is particularly sensitive to the discount
rate and return on plan assets assumptions. A 1 percent decrease in the discount
rate would increase annual benefit expense by $79 million, while a 1 percent
decrease in the return on plan assets assumption would increase annual benefit
expense by $21 million.
OUTLOOK
As a condition to the merger, the U.S. Federal Trade Commission (FTC) required
that both Conoco and Phillips divest certain assets. In the fourth quarter of
2002, the propane terminal assets at Jefferson City, Missouri, and East St.
Louis, Illinois, were sold and ConocoPhillips agreed to sell its Woods Cross
business unit in Salt Lake City, Utah, plus associated assets. See Note
4--Discontinued Operations in the Notes to Consolidated Financial Statements for
a list of the remaining assets held for sale.
74
In December 2002, ConocoPhillips committed to and initiated a plan to sell a
substantial portion of its company-owned retail sites. In connection with the
anticipated sale, the company, in the fourth quarter, recorded charges totaling
$1,412 million before-tax, $1,008 million after-tax, primarily related to the
impairment of properties, plants and equipment; goodwill; intangible assets and
provision for losses and penalties to unwind various lease arrangements. The
company expects to complete the sale of the sites in 2003.
In December of 2002, political unrest in Venezuela caused economic and other
disruptions which shut down most oil production in Venezuela, including the
company's Petrozuata, Hamaca and Gulf of Paria operations. At ConocoPhillips'
Petrozuata joint venture, operations were closed down on December 15, 2002, due
to shortages of hydrogen and natural gas (required for processing and fuel).
Prior to the disruptions, Petrozuata was producing and processing approximately
120,000 gross (60,000 net) barrels of extra-heavy crude oil per day. Similarly,
the disruptions have impacted development production and construction progress
at the Hamaca joint-venture project. Construction of the Hamaca upgrader
continues, although at a reduced rate. Difficulty in obtaining supplies has been
the primary impediment. Production was shut in on December 6, 2002. Prior to the
disruptions, Hamaca was producing approximately 55,000 gross (18,000 net)
barrels of extra-heavy crude per day. In addition, the crude oil produced by
Petrozuata is used as feedstock for ConocoPhillips' Lake Charles, Louisiana,
refinery and a Venezuelan refinery operated by PDVSA. In December 2002,
ConocoPhillips substituted about 1.2 million crude barrels for its Lake Charles
refinery. At the company's Sweeny refinery, crude throughputs were reduced
slightly due to short supply of Merey Venezuelan crude oil. Overall, there was
minimum impact to net income; however, it could reduce net income $30 million to
$50 million per month in 2003 as long as production at Petrozuata and Hamaca is
shut in. Limited production began from Hamaca and Petrozuata in February 2003.
On March 12, 2002, ConocoPhillips announced that it had signed a Heads of
Agreement (LNG HOA) with The Tokyo Electric Power Company, Incorporated (TEPCO)
and Tokyo Gas Co., Ltd. (Tokyo Gas) that would enable Phase II, which involves
the export and sale of natural gas, of the Bayu-Undan field development to
proceed upon resolution of certain legal, regulatory and fiscal issues. The
Timor Sea Treaty (Treaty) was ratified by Timor-Leste (formerly East Timor) in
December 2002 and by Australia in March 2003 and is subject to certain
procedural events before it is fully effective. The Treaty will allow the
issuance of new production sharing contracts to the existing contractors in the
Bayu-Undan unit, which when combined with the expected approval of the
Development Plan and the expected enactment of certain Timor-Leste legislation
will provide the legal, regulatory and fiscal basis necessary to proceed with
the gas project. Under the terms of the LNG HOA with TEPCO and Tokyo Gas, TEPCO
and Tokyo Gas will purchase 3 million tons per year of liquefied natural gas
(LNG) for a period of 17 years, utilizing natural gas from the Bayu-Undan field.
Shipments would begin in 2006, from an LNG facility near Darwin, Australia,
utilizing ConocoPhillips' Optimized Cascade liquefied natural gas process.
In 2003, ConocoPhillips expects worldwide production of approximately 1.55
million barrels of oil equivalent per day from currently proved reserves.
Improvements for the year are expected to come from the United Kingdom, Norway
and China. These improvements will be offset by decreases in the U.S. Lower 48
and Canada as a result of the disposition of assets, as well as the impact of
the disruptions in Venezuela. In R&M, crude oil throughputs in 2003 are expected
to average approximately 2.5 million barrels per day.
Crude oil and natural gas prices are subject to external factors over which the
company has no control, such as global economic conditions, political events,
demand growth, inventory levels, weather, competing fuels prices and
availability of supply. Crude oil prices increased significantly during 2002 due
to production restraint by major exporting countries serving to rebalance
inventories, supply concerns resulting from Middle East tensions, tropical
storms in the U.S. Gulf of Mexico temporarily shutting in oil
75
production and shipping, and the disruptions in Venezuela. Global oil demand is
starting to recover on a year-over-year basis, compared with the declines that
resulted from the U.S. recession and the events of September 11, 2001. However,
the pace of improvement will depend on a continuation of the economic recovery
in the United States and globally. Conflicts in oil-producing countries and
uncertainties surrounding the global economic recovery could keep prices
volatile in 2003. U.S. natural gas prices strengthened considerably at the end
of the third quarter and remained strong in the fourth quarter stemming from
growing natural gas supply concerns, rising oil prices and an increased demand
due to the weather. Supply concerns arose from the decline in domestic gas
production and Canadian imports versus 2001, and tropical storms temporarily
shutting in production in the Gulf of Mexico.
Refining margins are subject to movements in the price of crude oil and other
feedstocks, and the prices of petroleum products, which are subject to market
factors over which the company has no control, such as the U.S. and global
economies; government regulations; seasonal factors that affect demand, such as
the summer driving months; and the levels of refining output and product
inventories. Global refining margins remained depressed during much of 2002 due
to weak oil demand, relatively high levels of gasoline and distillate
inventories and strengthening crude prices, which increased feedstock costs. As
a result of tropical storms in the Gulf of Mexico, industry refining crude oil
runs were temporarily reduced, which caused product inventory draws in the
United States and improved refining margins modestly. Refining and marketing
margins can be expected to improve when the U.S. and global economies recover.
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This annual report includes forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. Forward-looking statements can be identified by the words
"expects," "anticipates," "intends," "plans," "projects," "believes,"
"estimates" and similar expressions.
ConocoPhillips has based the forward-looking statements relating to its
operations on its current expectations, estimates and projections about
ConocoPhillips and the industries in which it operates in general.
ConocoPhillips cautions you that these statements are not guarantees of future
performance and involve risks, uncertainties and assumptions that the company
cannot predict. In addition, ConocoPhillips has based many of these
forward-looking statements on assumptions about future events that may prove to
be inaccurate. Accordingly, ConocoPhillips' actual outcomes and results may
differ materially from what the company has expressed or forecast in the
forward-looking statements. Any differences could result from a variety of
factors, including the following:
o fluctuations in crude oil, natural gas and natural gas liquids
prices, refining and marketing margins and margins for
ConocoPhillips' chemicals business;
o changes in the business, operations, results and prospects of
ConocoPhillips;
o the operation and financing of ConocoPhillips' midstream and
chemicals joint ventures;
o potential failure to realize fully or within the expected time frame
the expected cost savings and synergies from the combination of
Conoco and Phillips;
o costs or difficulties related to the integration of the businesses
of Conoco and Phillips, as well as the continued integration of
businesses recently acquired by each of them;
76
o potential failure or delays in achieving expected reserve or
production levels from existing and future oil and gas development
projects due to operating hazards, drilling risks and the inherent
uncertainties in predicting oil and gas reserves and oil and gas
reservoir performance;
o unsuccessful exploratory drilling activities;
o failure of new products and services to achieve market acceptance;
o unexpected cost increases or technical difficulties in constructing
or modifying facilities for exploration and production projects,
manufacturing or refining;
o unexpected difficulties in manufacturing or refining ConocoPhillips'
refined products, including synthetic crude oil, and chemicals
products;
o lack of, or disruptions in, adequate and reliable transportation for
ConocoPhillips' crude oil, natural gas and refined products;
o inability to timely obtain or maintain permits, comply with
government regulations or make capital expenditures required to
maintain compliance;
o potential disruption or interruption of ConocoPhillips' facilities
due to accidents, political events or terrorism;
o international monetary conditions and exchange controls;
o liability for remedial actions, including removal and reclamation
obligations, under environmental regulations;
o liability resulting from litigation;
o general domestic and international economic and political
conditions, including armed hostilities and governmental disputes
over territorial boundaries;
o changes in tax and other laws or regulations applicable to
ConocoPhillips' business; and
o inability to obtain economical financing for exploration and
development projects, construction or modification of facilities and
general corporate purposes.
77
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
FINANCIAL INSTRUMENT MARKET RISK
ConocoPhillips and certain of its subsidiaries hold and issue derivative
contracts and financial instruments that expose cash flows or earnings to
changes in commodity prices, foreign exchange rates or interest rates. The
company may use financial and commodity-based derivative contracts to manage the
risks produced by changes in the prices of electric power, natural gas, and
crude oil and related products, fluctuations in interest rates and foreign
currency exchange rates, or to exploit market opportunities.
With the completion of the merger on August 30, 2002, the derivatives policy
adopted during the third quarter of 2001 is no longer in effect; however, the
ConocoPhillips Board of Directors has approved an "Authority Limitations"
document that prohibits the use of highly leveraged derivatives or derivative
instruments without sufficient liquidity for comparable valuations without
approval from the Chief Executive Officer. The Authority Limitations document
also authorizes the Chief Executive Officer to establish the maximum Value at
Risk (VaR) limits for the company. Compliance with these limits is monitored
daily. The function of the Risk Management Steering Committee, monitoring the
use and effectiveness of derivatives, was assumed by the Chief Financial Officer
for risks resulting from foreign currency exchange rates and interest rates, and
by the Executive Vice President of Commercial, a new position that reports to
the Chief Executive Officer, for commodity price risk. ConocoPhillips'
Commercial Group manages commercial marketing, optimizes the commodity flows and
positions of the company, monitors related risks of the company's upstream and
downstream businesses, and selectively takes price risk to add value.
Commodity Price Risk
ConocoPhillips operates in the worldwide crude oil, refined product, natural
gas, natural gas liquids, and electric power markets and is exposed to
fluctuations in the prices for these commodities. These fluctuations can affect
the company's revenues as well as the cost of operating, investing, and
financing activities. Generally, the company's policy is to remain exposed to
market prices of commodities; however, executive management may elect to use
derivative instruments to hedge the price risk of the company's equity crude oil
and natural gas production, as well as refinery margins.
The ConocoPhillips' Commercial Group uses futures, forwards, swaps, and options
in various markets to optimize the value of the company's supply chain, which
may move the company's risk profile away from market average prices to
accomplish the following objectives:
o Balance physical systems. In addition to cash settlement prior to
contract expiration, exchange traded futures contracts may also be
settled by physical delivery of the commodity, providing another
source of supply to meet the company's refinery requirements or
marketing demand;
o Meet customer needs. Consistent with the company's policy to
generally remain exposed to market prices, the company uses swap
contracts to convert fixed-price sales contracts, which are often
requested by natural gas and refined product consumers, to a
floating market price;
o Manage the risk to the company's cash flows from price exposures on
specific crude oil, natural gas, refined product and electric power
transactions; and
78
o Enable the company to use the market knowledge gained from these
activities to do a limited amount of trading not directly related to
the company's physical business. For the 12 months ended December
31, 2002 and 2001, the gains or losses from this activity were not
material to the company's cash flows or income from continuing
operations.
ConocoPhillips uses a VaR model to estimate the loss in fair value that could
potentially result on a single day from the effect of adverse changes in market
conditions on the derivative financial instruments and derivative commodity
instruments held or issued, including commodity purchase and sales contracts
recorded on the balance sheet at December 31, 2002, as derivative instruments in
accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended. Using Monte Carlo simulation, a 95 percent confidence
level and a one-day holding period, the VaR for those instruments issued or held
for trading purposes at December 31, 2002 and 2001, was $0.7 million at each
year-end. The VaR for instruments held for purposes other than trading at
December 31, 2002 and 2001, was $2 million and $1.7 million, respectively.
Interest Rate Risk
The following tables provide information about the company's financial
instruments that are sensitive to changes in interest rates. The debt tables
present principal cash flows and related weighted-average interest rates by
expected maturity dates; the derivative table shows the notional quantities on
which the cash flows will be calculated by swap termination date.
Weighted-average variable rates are based on implied forward rates in the yield
curve at the reporting date. The carrying amount of the company's floating-rate
debt approximates its fair value. The fair value of the fixed-rate financial
instruments is estimated based on quoted market prices.
79
Millions of Dollars Except as Indicated
-------------------------------------------------------------------------------------------------
Mandatorily
Redeemable Other
Minority
Interests and
Debt Preferred Securities
------------------------------------------------------------- --------------------------
Expected Fixed Average Floating Average Fixed Average
Maturity Rate Interest Rate Interest Rate Interest
Date Maturity Rate Maturity Rate Maturity Rate
--------------- -------- -------- -------- -------- -------- --------
YEAR-END 2002
2003 $ 762 7.99% $ 706 2.60% $ -- --%
2004 1,362 5.91 -- -- -- --
2005 1,169 8.49 -- -- -- --
2006 1,507 5.82 1,517 4.54 -- --
2007 613 4.88 -- -- -- --
Remaining years 10,740 6.95 691 6.02 491 7.96
------------------------------------------------------------------------------------------------------------------------
Total $16,153 $ 2,914 $ 491
========================================================================================================================
Fair value $17,930 $ 2,914 $ 516
========================================================================================================================
Year-End 2001
2002 $ 43 9.31% $ -- --% $ -- --%
2003 255 7.60 -- -- -- --
2004 6 7.02 -- -- -- --
2005 1,155 8.49 -- -- -- --
2006 246 7.61 1,081 7.06 -- --
Remaining years 5,134 7.99 625 6.86 650 8.11
------------------------------------------------------------------------------------------------------------------------
Total $ 6,839 $ 1,706 $ 650
========================================================================================================================
Fair value $ 7,469 $ 1,706 $ 662
========================================================================================================================
Interest Rate Derivatives at December 31, 2002
----------------------------------------------------
Floating-to-Fixed
----------------------------------------------------
Expected Maturity Date Notional Average Pay Rate Average Receive Rate
---------------------- -------- ---------------- --------------------
2003 $ 500 3.41% 2.56%
2004 -- -- --
2005 -- -- --
2006 166 5.85 4.76
2007 -- -- --
Remaining years -- -- --
------------------------------------------------------------------------------------------------------------------------
Total $ 666
========================================================================================================================
Fair value loss position $ 22
========================================================================================================================
80
Foreign Currency Risk
ConocoPhillips has foreign currency exchange rate risk resulting from operations
in over 40 countries around the world. ConocoPhillips does not comprehensively
hedge the exposure to currency rate changes, although the company may choose to
selectively hedge exposures to foreign currency rate risk. Examples include firm
commitments for capital projects, certain local currency tax payments and
dividends, and cash returns from net investments in foreign affiliates to be
remitted within the coming year.
At December 31, 2002, ConocoPhillips had the following significant foreign
currency derivative contracts:
o approximately $194 million in foreign currency swaps hedging the
company's European commercial paper program, with a fair value of
$7.1 million;
o approximately $536 million in foreign currency swaps hedging
short-term intercompany loans between U.K. subsidiaries and a U.S.
subsidiary, with a fair value of $9 million; and
o approximately $24 million in foreign currency swaps hedging the
company's firm purchase and sales commitments for gasoline in
Germany, with a negative fair value of $4 million.
Although these swaps hedge exposures to fluctuations in exchange rates, the
company elected not to utilize hedge accounting as allowed by SFAS No. 133. As a
result, the change in the fair value of these foreign currency swaps is recorded
directly in earnings. Assuming an adverse hypothetical 10 percent change in the
December 31, 2002, exchange rates, the potential foreign currency remeasurement
loss in non-cash pretax earning from these swaps, intercompany loans, and
commercial paper would be approximately $3 million.
In addition to the intercompany loans discussed above, at December 31, 2002 and
2001, U.S. subsidiaries held long-term sterling-denominated intercompany
receivables totaling $152 million and $191 million, respectively, due from a
U.K. subsidiary. The U.K. subsidiary also held a dollar-denominated long-term
receivable due from a U.S. subsidiary with no balance at December 31, 2002, and
a $75 million balance at December 31, 2001. A Norwegian subsidiary held $198
million and $79 million of intercompany U.S. dollar-denominated receivables due
from its U.S. parent at December 31, 2002 and 2001, respectively. Also at
year-end 2001, a foreign subsidiary with the U.S. dollar as its functional
currency owed a $9 million Norwegian kroner-denominated payable to a Norwegian
subsidiary. The potential foreign currency remeasurement gains or losses in
non-cash pretax earnings from a hypothetical 10 percent change in the year-end
2002 and 2001 exchange rates from these intercompany balances were $35 million
and $21 million, respectively.
For additional information about the company's use of derivative instruments,
see Note 16--Derivative Instruments in the Notes to Consolidated Financial
Statements.
81
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
INDEX TO FINANCIAL STATEMENTS
Page
----
Report of Management............................................................................. 83
Report of Independent Auditors................................................................... 84
Consolidated Statement of Operations for the years ended December 31, 2002, 2001 and 2000........ 85
Consolidated Balance Sheet at December 31, 2002 and 2001......................................... 86
Consolidated Statement of Cash Flows for the years ended December 31, 2002, 2001 and 2000........ 87
Consolidated Statement of Changes in Common Stockholders' Equity for the years ended
December 31, 2002, 2001 and 2000............................................................. 88
Notes to Consolidated Financial Statements....................................................... 89
Supplementary Information
Oil and Gas Operations................................................................ 146
Selected Quarterly Financial Data..................................................... 164
Condensed Consolidating Financial Information......................................... 165
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule II--Valuation and Qualifying Accounts................................................... 177
All other schedules are omitted because they are either not required, not
significant, not applicable or the information is shown in another schedule, the
financial statements or in the notes to consolidated financial statements.
82
--------------------------------------------------------------------------------
REPORT OF MANAGEMENT
Management prepared, and is responsible for, the consolidated financial
statements and the other information appearing in this annual report. The
consolidated financial statements present fairly the company's financial
position, results of operations and cash flows in conformity with accounting
principles generally accepted in the United States. In preparing its
consolidated financial statements, the company includes amounts that are based
on estimates and judgments that management believes are reasonable under the
circumstances.
The company maintains internal controls designed to provide reasonable assurance
that the company's assets are protected from unauthorized use and that all
transactions are executed in accordance with established authorizations and
recorded properly. The internal controls are supported by written policies and
guidelines and are complemented by a staff of internal auditors. Management
believes that the internal controls in place at December 31, 2002, provide
reasonable assurance that the books and records reflect the transactions of the
company and there has been compliance with its policies and procedures.
The company's financial statements have been audited by Ernst & Young LLP,
independent auditors selected by the Audit and Compliance Committee of the Board
of Directors. Management has made available to Ernst & Young LLP all of the
company's financial records and related data, as well as the minutes of
stockholders' and directors' meetings.
/s/ Archie W. Dunham /s/ J. J. Mulva /s/ John A. Carrig
ARCHIE W. DUNHAM J. J. MULVA JOHN A. CARRIG
Chairman of the Board President and Executive Vice President, Finance,
Chief Executive Officer and Chief Financial Officer
March 24, 2003
83
--------------------------------------------------------------------------------
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders
ConocoPhillips
We have audited the accompanying consolidated balance sheets of ConocoPhillips
as of December 31, 2002 and 2001, and the related consolidated statements of
operations, changes in common stockholders' equity, and cash flows for each of
the three years in the period ended December 31, 2002. Our audits also included
the condensed consolidating financial information and financial statement
schedule listed in the Index in Item 8. These financial statements, condensed
consolidating financial information and schedule are the responsibility of the
company's management. Our responsibility is to express an opinion on these
financial statements, condensed consolidating financial information 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 ConocoPhillips 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 condensed consolidating financial
information and financial statement schedule, when considered in relation to the
basic financial statements taken as a whole, present fairly in all material
respects the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, in 2001
ConocoPhillips changed its method of accounting for the costs of major
maintenance turnarounds.
/s/ Ernst & Young LLP
ERNST & YOUNG LLP
Houston, Texas
March 24, 2003
84
------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF OPERATIONS CONOCOPHILLIPS
Years Ended December 31 Millions of Dollars
-----------------------------------------
2002 2001** 2000**
-----------------------------------------
REVENUES
Sales and other operating revenues* $ 56,748 24,892 22,155
Equity in earnings of affiliates 261 41 114
Other income 215 111 270
------------------------------------------------------------------------------------------------------------------------
Total Revenues 57,224 25,044 22,539
------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Purchased crude oil and products 37,823 13,708 11,794
Production and operating expenses 4,988 2,643 2,136
Selling, general and administrative expenses 1,660 613 571
Exploration expenses 592 306 298
Depreciation, depletion and amortization 2,223 1,344 1,169
Impairments 177 26 100
Taxes other than income taxes* 6,937 2,740 2,242
Accretion on discounted liabilities 22 7 --
Interest and debt expense 566 338 369
Foreign currency transaction losses 24 11 58
Preferred dividend requirements of capital trusts and minority
interests 48 53 54
------------------------------------------------------------------------------------------------------------------------
Total Costs and Expenses 55,060 21,789 18,791
------------------------------------------------------------------------------------------------------------------------
Income from continuing operations before income taxes 2,164 3,255 3,748
Provision for income taxes 1,450 1,644 1,900
------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS 714 1,611 1,848
Income (loss) from discontinued operations (net of income taxes
(benefit) of $(394), $15 and $7 for 2002, 2001
and 2000, respectively) (993) 32 14
------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (279) 1,643 1,862
Extraordinary items (16) (10) --
Cumulative effect of change in accounting principle -- 28 --
------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ (295) 1,661 1,862
========================================================================================================================
NET INCOME (LOSS) PER SHARE OF COMMON STOCK
Basic
Continuing operations $ 1.48 5.50 7.26
Discontinued operations (2.06) .11 .06
------------------------------------------------------------------------------------------------------------------------
Before extraordinary items and cumulative effect of change
in accounting principle (.58) 5.61 7.32
Extraordinary items (.03) (.04) --
Cumulative effect of change in accounting principle -- .10 --
------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) $ (.61) 5.67 7.32
========================================================================================================================
Diluted
Continuing operations $ 1.47 5.46 7.21
Discontinued operations (2.05) .11 .05
------------------------------------------------------------------------------------------------------------------------
Before extraordinary items and cumulative effect of change in
accounting principle (.58) 5.57 7.26
Extraordinary items (.03) (.03) --
Cumulative effect of change in accounting principle -- .09 --
------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) $ (.61) 5.63 7.26
========================================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (in thousands)
Basic 482,082 292,964 254,490
Diluted 485,505 295,016 256,326
------------------------------------------------------------------------------------------------------------------------
*Includes excise taxes on petroleum products sales: $ 6,236 2,178 1,781
**Restated for discontinued operations.
See Notes to Consolidated Financial Statements.
85
-------------------------------------------------------------------------------------------------------
CONSOLIDATED BALANCE SHEET CONOCOPHILLIPS
At December 31 Millions of Dollars
-----------------------
2002 2001*
-----------------------
ASSETS
Cash and cash equivalents $ 307 142
Accounts and notes receivable (net of allowance of $48 million
in 2002 and $33 million in 2001) 2,904 1,124
Accounts and notes receivable--related parties 1,476 105
Inventories 3,845 2,452
Prepaid expenses and other current assets 766 293
Assets of discontinued operations held for sale 1,605 2,382
-------------------------------------------------------------------------------------------------------
Total Current Assets 10,903 6,498
Investments and long-term receivables 6,821 3,309
Net properties, plants and equipment 43,030 22,133
Goodwill 14,444 2,281
Intangibles 1,119 861
Other assets 519 135
-------------------------------------------------------------------------------------------------------
Total $ 76,836 35,217
=======================================================================================================
LIABILITIES
Accounts payable $ 5,949 2,531
Accounts payable--related parties 303 91
Notes payable and long-term debt due within one year 849 44
Accrued income and other taxes 1,991 897
Other accruals 3,075 720
Liabilities of discontinued operations held for sale 649 538
-------------------------------------------------------------------------------------------------------
Total Current Liabilities 12,816 4,821
Long-term debt 18,917 8,610
Accrued dismantlement, removal and environmental costs 1,666 1,059
Deferred income taxes 8,361 4,015
Employee benefit obligations 2,755 948
Other liabilities and deferred credits 1,803 769
-------------------------------------------------------------------------------------------------------
Total Liabilities 46,318 20,222
-------------------------------------------------------------------------------------------------------
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
PHILLIPS 66 CAPITAL TRUSTS I AND II 350 650
-------------------------------------------------------------------------------------------------------
OTHER MINORITY INTERESTS 651 5
-------------------------------------------------------------------------------------------------------
COMMON STOCKHOLDERS' EQUITY
Common stock (2002--2,500,000,000 shares authorized at $.01 par value;
2001--1,000,000,000 shares authorized at $1.25 par value)
Issued (2002--704,354,839 shares; 2001--430,439,743 shares)
Par value 7 538
Capital in excess of par 25,178 9,069
Treasury stock (at cost: 2001--20,725,114 shares) -- (1,038)
Compensation and Benefits Trust (CBT) (at cost: 2002--26,785,094 shares;
2001--27,556,573 shares) (907) (934)
Accumulated other comprehensive loss (164) (255)
Unearned employee compensation--Long-Term Stock Savings Plan (LTSSP) (218) (237)
Retained earnings 5,621 7,197
-------------------------------------------------------------------------------------------------------
Total Common Stockholders' Equity 29,517 14,340
-------------------------------------------------------------------------------------------------------
Total $ 76,836 35,217
=======================================================================================================
*Restated for discontinued operations.
See Notes to Consolidated Financial Statements.
86
---------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF CASH FLOWS CONOCOPHILLIPS
Years Ended December 31 Millions of Dollars
----------------------------------
2002 2001* 2000*
----------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations $ 714 1,611 1,848
Adjustments to reconcile income from continuing operations to net
cash provided by continuing operations
Non-working capital adjustments
Depreciation, depletion and amortization 2,223 1,344 1,169
Impairments 177 26 100
Dry hole costs and leasehold impairment 307 99 130
Accretion on discounted liabilities 22 7 --
Acquired in-process research and development 246 -- --
Deferred taxes 142 513 412
Other (46) 131 (210)
Working capital adjustments**
Increase (decrease) in aggregate balance of accounts receivable sold (22) (174) 317
Decrease (increase) in other accounts and notes receivable (401) 1,357 (710)
Decrease (increase) in inventories 200 (289) (12)
Decrease (increase) in prepaid expenses and other current assets (37) 50 84
Increase (decrease) in accounts payable 788 (1,004) 417
Increase (decrease) in taxes and other accruals 454 (142) 439
---------------------------------------------------------------------------------------------------------------------
Net cash provided by continuing operations 4,767 3,529 3,984
Net cash provided by discontinued operations 202 33 30
---------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 4,969 3,562 4,014
---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions, net of cash acquired 1,180 80 (6,443)
Capital expenditures and investments, including dry hole costs (4,388) (3,016) (2,017)
Proceeds from contributing assets to joint ventures -- -- 2,061
Proceeds from asset dispositions 815 262 850
Long-term advances to affiliates and other investments (92) (28) (208)
---------------------------------------------------------------------------------------------------------------------
Net cash used in continuing operations (2,485) (2,702) (5,757)
Net cash used in discontinued operations (99) (68) (5)
---------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (2,584) (2,770) (5,762)
---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of debt 3,502 566 2,552
Repayment of debt (4,592) (945) (360)
Redemption of preferred stock of subsidiary (300) -- --
Issuance of company common stock 44 51 31
Dividends paid on common stock (684) (403) (346)
Other (190) (68) (118)
---------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) continuing operations (2,220) (799) 1,759
---------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities (2,220) (799) 1,759
---------------------------------------------------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 165 (7) 11
Cash and cash equivalents at beginning of year 142 149 138
---------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 307 142 149
=====================================================================================================================
*Restated for discontinued operations.
**Net of acquisition and disposition of businesses.
See Notes to Consolidated Financial Statements.
87
--------------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF CHANGES CONOCOPHILLIPS
IN COMMON STOCKHOLDERS' EQUITY
Shares of Common Stock
--------------------------------------------
Held in
Issued Treasury Held in CBT
--------------------------------------------
December 31, 1999 306,380,511 24,409,545 28,358,258
Net income
Other comprehensive income
Foreign currency translation
Unrealized loss on securities
Equity affiliates:
Foreign currency translation
Comprehensive income
Cash dividends paid on common stock
Distributed under incentive
compensation and other
benefit plans (1,267,540) (508,828)
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
----------------------------------------------------------------------------------------
December 31, 2000 306,380,511 23,142,005 27,849,430
Net income
Other comprehensive income
Minimum pension liability
adjustment
Foreign currency translation
Unrealized loss on securities
Hedging activities
Equity affiliates:
Foreign currency translation
Derivatives related
Comprehensive income
Cash dividends paid on common stock
Tosco acquisition 124,059,232
Distributed under incentive
compensation and other benefit
plans (2,416,891) (292,857)
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
----------------------------------------------------------------------------------------
December 31, 2001 430,439,743 20,725,114 27,556,573
Net loss
Other comprehensive income
Minimum pension liability
adjustment
Foreign currency translation
Unrealized loss on securities
Hedging activities
Equity affiliates:
Foreign currency translation
Derivatives related
Comprehensive loss
Cash dividends paid on common stock
ConocoPhillips merger 273,471,505 (19,852,674)
Distributed under incentive
compensation and other benefit
plans 443,591 (872,440) (771,479)
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
----------------------------------------------------------------------------------------
DECEMBER 31, 2002 704,354,839 -- 26,785,094
========================================================================================
Millions of Dollars
-------------------------------------------------------------------------------------------
Common Stock Accumulated Unearned
--------------------------------------- Other Employee
Par Capital in Treasury Comprehensive Compensation Retained
Value Excess of Par Stock CBT Loss --LTSSP Earnings Total
-------------------------------------------------------------------------------------------
December 31, 1999 $ 383 2,098 (1,217) (961) (31) (286) 4,563 4,549
-------
Net income 1,862 1,862
Other comprehensive income
Foreign currency translation (53) (53)
Unrealized loss on securities (1) (1)
Equity affiliates:
Foreign currency translation (15) (15)
-------
Comprehensive income 1,793
-------
Cash dividends paid on common stock (346) (346)
Distributed under incentive
compensation and other
benefit plans 55 61 18 (65) 69
Recognition of LTSSP unearned
compensation 23 23
Tax benefit of dividends on
unallocated LTSSP shares 5 5
---------------------------------------------------------------------------------------------------------------------------------
December 31, 2000 383 2,153 (1,156) (943) (100) (263) 6,019 6,093
-------
Net income 1,661 1,661
Other comprehensive income
Minimum pension liability
adjustment (143) (143)
Foreign currency translation (14) (14)
Unrealized loss on securities (2) (2)
Hedging activities (4) (4)
Equity affiliates:
Foreign currency translation (3) (3)
Derivatives related 11 11
-------
Comprehensive income 1,506
-------
Cash dividends paid on common stock (403) (403)
Tosco acquisition 155 6,883 7,038
Distributed under incentive
compensation and other benefit
plans 33 118 9 (84) 76
Recognition of LTSSP unearned
compensation 26 26
Tax benefit of dividends on
unallocated LTSSP shares 4 4
---------------------------------------------------------------------------------------------------------------------------------
December 31, 2001 538 9,069 (1,038) (934) (255) (237) 7,197 14,340
-------
Net loss (295) (295)
Other comprehensive income
Minimum pension liability
adjustment (93) (93)
Foreign currency translation 182 182
Unrealized loss on securities (3) (3)
Hedging activities (1) (1)
Equity affiliates:
Foreign currency translation 40 40
Derivatives related (34) (34)
-------
Comprehensive loss (204)
-------
Cash dividends paid on common stock (684) (684)
ConocoPhillips merger (531) 16,056 999 (562) 15,962
Distributed under incentive
compensation and other benefit
plans 53 39 27 (39) 80
Recognition of LTSSP unearned
compensation 19 19
Tax benefit of dividends on
unallocated LTSSP shares 4 4
---------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2002 $ 7 25,178 -- (907) (164) (218) 5,621 29,517
=================================================================================================================================
See Notes to Consolidated Financial Statements.
88
--------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS CONOCOPHILLIPS
NOTE 1--ACCOUNTING POLICIES
o CONSOLIDATION PRINCIPLES AND INVESTMENTS--Majority-owned, controlled
subsidiaries are consolidated. The equity method is used to account for
investments in affiliates in which the company exerts significant
influence, generally having a 20 to 50 percent ownership interest. The
company also uses the equity method for its 50.1 percent and 57.1 percent
non-controlling interests in Petrozuata C.A. and Hamaca Holding LLC,
respectively, located in Venezuela because the minority shareholders have
substantive participating rights, under which all substantive operating
decisions (e.g., annual budgets, major financings, selection of senior
operating management, etc.) require joint approvals. Undivided interests
in oil and gas joint ventures, pipelines, natural gas plants, certain
transportation assets and Canadian Syncrude mining operations are
consolidated on a proportionate basis. Other securities and investments,
excluding marketable securities, are generally carried at cost.
o REVENUE RECOGNITION--Revenues associated with sales of crude oil, natural
gas, natural gas liquids, petroleum and chemical products, and all other
items are recorded when title passes to the customer. Revenues include the
sales portion of contracts involving purchases and sales necessary to
reposition supply to address location or quality or grade requirements
(e.g., when the company repositions crude by entering into a contract with
a counterparty to sell crude in one location and purchase it in a
different location) and sales related to purchase for resale activity.
Revenues from the production of natural gas properties in which the
company has an interest with other producers are recognized based on the
actual volumes sold by the company during the period. Any differences
between volumes sold and entitlement volumes, based on the company's net
working interest, which are deemed non-recoverable through remaining
production, are recognized as accounts receivable or accounts payable, as
appropriate. Cumulative differences between volumes sold and entitlement
volumes are not significant. Revenues associated with royalty fees from
licensed technology are recorded based either upon volumes produced by the
licensee or upon the successful completion of all substantive performance
requirements related to the installation of licensed technology.
o RECLASSIFICATION--Certain amounts in the 2001 and 2000 financial
statements have been reclassified to conform with the 2002 presentation.
o USE OF ESTIMATES--The preparation of financial statements in conformity
with accounting principles generally accepted in the United States
requires management to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses, and the
disclosures of contingent assets and liabilities. Actual results could
differ from the estimates and assumptions used.
o CASH EQUIVALENTS--Cash equivalents are highly liquid short-term
investments that are readily convertible to known amounts of cash and have
original maturities within three months from their date of purchase. They
are carried at cost plus accrued interest, which approximates fair value.
o INVENTORIES--The company has several valuation methods for its various
types of inventories and consistently uses the following methods for each
type of inventory. Crude oil, petroleum products, and Canadian Syncrude
inventories are valued at the lower of cost or market in the aggregate,
primarily on the last-in, first-out (LIFO) basis. Any necessary
lower-of-cost-or-market write-downs are recorded as permanent adjustments
to the LIFO cost basis. LIFO is used to better match current inventory
costs with current revenues and to meet tax-conformity requirements.
Materials, supplies and other miscellaneous inventories are valued using
the weighted-average-cost method, consistent
89
with general industry practice. Merchandise inventories at the company's
retail marketing outlets are valued using the first-in, first-out (FIFO)
retail method, consistent with general industry practice.
o DERIVATIVE INSTRUMENTS--All derivative instruments are recorded on the
balance sheet at fair value in either accounts and notes receivable, other
assets, accounts payable, or other liabilities and deferred credits.
Recognition of the gain or loss that results from recording and adjusting
a derivative to fair value depends on the purpose for issuing or holding
the derivative. Gains and losses from derivatives that are not used as
hedges are recognized immediately in earnings. For derivative instruments
that are designated and qualify as a fair value hedge, the gains or losses
from adjusting the derivative to its fair value will be immediately
recognized in earnings and, to the extent the hedge is effective, offset
the concurrent recognition of changes in the fair value of the hedged
item. Gains or losses from derivative instruments that are designated and
qualify as a cash flow hedge will be recorded on the balance sheet in
accumulated other comprehensive income/(loss) until the hedged transaction
is recognized in earnings; however, to the extent the change in the value
of the derivative exceeds the change in the anticipated cash flows of the
hedged transaction, the excess gains or losses will be recognized
immediately in earnings.
In the consolidated statement of operations, gains and losses from
derivatives that are not directly related to the company's movement of its
products are recorded in other income. Gains and losses from derivatives
used for other purposes are recorded in either sales and other operating
revenues, other income, or purchased crude oil and products, depending on
the purpose for issuing or holding the derivative.
o OIL AND GAS EXPLORATION AND DEVELOPMENT--Oil and gas exploration and
development costs are accounted for using the successful efforts method of
accounting.
PROPERTY ACQUISITION COSTS--Oil and gas leasehold acquisition costs
are capitalized. Leasehold impairment is recognized based on
exploratory experience and management's judgment. Upon discovery of
commercial reserves, leasehold costs are transferred to proved
properties.
EXPLORATORY COSTS--Geological and geophysical costs and the costs of
carrying and retaining undeveloped properties are expensed as
incurred. Exploratory well costs are capitalized pending further
evaluation of whether economically recoverable reserves have been
found. If economically recoverable reserves are not found,
exploratory well costs are expensed as dry holes. All exploratory
wells are evaluated for economic viability within one year of well
completion. Exploratory wells that discover potentially economic
reserves that are in areas where a major capital expenditure would
be required before production could begin, and where the economic
viability of that major capital expenditure depends upon the
successful completion of further exploratory work in the area,
remain capitalized as long as the additional exploratory work is
under way or firmly planned.
DEVELOPMENT COSTS--Costs incurred to drill and equip development
wells, including unsuccessful development wells, are capitalized.
DEPLETION AND AMORTIZATION--Leasehold costs of producing properties
are depleted using the unit-of-production method based on estimated
proved oil and gas reserves. Amortization of intangible development
costs is based on the unit-of-production method using estimated
proved developed oil and gas reserves.
90
o SYNCRUDE MINING OPERATIONS--Capitalized costs, including support
facilities, include the cost of the acquisition and other capital costs
incurred. Capital costs are depreciated using the unit-of-production
method based on the applicable portion of proven reserves associated with
each mine location and its facilities.
o INTANGIBLE ASSETS OTHER THAN GOODWILL--Intangible assets that have finite
useful lives are amortized by the straight-line method over their useful
lives. Intangible assets that have indefinite useful lives are not
amortized but are tested at least annually for impairment. The company
evaluates the remaining useful lives of intangible assets not being
amortized each reporting period to determine whether events and
circumstances continue to support indefinite useful lives. Intangible
assets are considered impaired if the fair value of the intangible asset
is lower than cost. The fair value of intangible assets is determined
based on quoted market prices in active markets, if available. If quoted
market prices are not available, fair value of intangible assets is
determined based upon the present values of expected future cash flows
using discount rates commensurate with the risks involved in the asset, or
upon estimated replacement cost, if expected future cash flows from the
intangible asset are not determinable.
o GOODWILL--Goodwill is not amortized but is tested at least annually for
impairment. If the fair value of a reporting unit is less than the
recorded book value of the reporting unit's assets (including goodwill),
less liabilities, then a hypothetical purchase price allocation is
performed on the reporting unit's assets and liabilities using the fair
value of the reporting unit as the purchase price in the calculation. If
the amount of goodwill resulting from this hypothetical purchase price
allocation is less than the recorded amount of goodwill, the recorded
goodwill is written down to the new amount. Reporting units for purposes
of goodwill impairment calculations are one level below or at the
company's operating segment level. Because quoted market prices are not
available for the company's reporting units, the fair value of the
reporting units is determined based upon consideration of several factors,
including observed market multiples of operating cash flows and net
income, the depreciated replacement cost of tangible equipment, and/or the
present values of expected future cash flows using discount rates
commensurate with the risks involved in the assets.
o DEPRECIATION AND AMORTIZATION--Depreciation and amortization of
properties, plants and equipment on producing oil and gas properties,
certain pipeline assets (those which are expected to have a declining
utilization pattern), and on Syncrude mining operations are determined by
the unit-of-production method. Depreciation and amortization of all other
properties, plants and equipment are determined by either the
individual-unit-straight-line method or the group-straight-line method
(for those individual units that are highly integrated with other units).
o IMPAIRMENT OF PROPERTIES, PLANTS AND EQUIPMENT--Properties, plants and
equipment used in operations are assessed for impairment whenever changes
in facts and circumstances indicate a possible significant deterioration
in the future cash flows expected to be generated by an asset group. If,
upon review, the sum of the undiscounted pretax cash flows is less than
the carrying value of the asset group, the carrying value is written down
to estimated fair value through additional amortization or depreciation
provisions in the periods in which the determination of impairment is
made. Individual assets are grouped for impairment purposes at the lowest
level for which there are identifiable cash flows that are largely
independent of the cash flows of other groups of assets--generally on a
field-by-field basis for exploration and production assets, at an entire
complex level for downstream assets or at a site level for retail stores.
The fair value of impaired assets is determined based on quoted market
prices in active markets, if available, or upon the present values of
expected future cash flows using discount rates commensurate with the
risks involved in the asset group. Long-lived assets committed by
management for disposal within one year are accounted for at the lower of
amortized cost or fair value, less cost to sell.
91
The expected future cash flows used for impairment reviews and related
fair value calculations are based on estimated future production volumes,
prices and costs, considering all available evidence at the date of
review. If the future production price risk has been hedged, the hedged
price is used in the calculations for the period and quantities hedged.
The impairment review includes cash flows from proved developed and
undeveloped reserves, including any development expenditures necessary to
achieve that production. The price and cost outlook assumptions used in
impairment reviews differ from the assumptions used in the Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas
Reserve Quantities. In that disclosure, Statement of Financial Accounting
Standards (SFAS) No. 69, "Disclosures about Oil and Gas Producing
Activities," requires the use of prices and costs at the balance sheet
date, with no projection of future changes in those assumptions.
o MAINTENANCE AND REPAIRS--The costs of maintenance and repairs, which are
not significant improvements, are expensed when incurred. Effective
January 1, 2001, turnaround costs of major producing units are expensed as
incurred. Prior to 2001, the estimated turnaround costs of major producing
units were accrued in other liabilities over the estimated interval
between turnarounds. See Note 2--Extraordinary Items and Accounting Change
for further discussion of this change in accounting method.
o SHIPPING AND HANDLING COSTS--The company's Exploration and Production
segment includes shipping and handling costs in production and operating
expenses, while the Refining and Marketing segment records shipping and
handling costs in purchased crude oil and products.
o ADVERTISING COSTS--Production costs of media advertising are deferred
until the first public showing of the advertisement. Advances to secure
advertising slots at specific sports, racing or other events are deferred
until the event occurs. All other advertising costs are expensed as
incurred, unless the cost has benefits which clearly extend beyond the
interim period in which the expenditure is made, in which case the
advertising cost is deferred and amortized ratably over the interim
periods which clearly benefit from the expenditure. By the end of the
fiscal year, all such interim deferred advertising costs are fully
amortized to expense.
o PROPERTY DISPOSITIONS--When complete units of depreciable property are
retired or sold, the asset cost and related accumulated depreciation are
eliminated, with any gain or loss reflected in income. When less than
complete units of depreciable property are disposed of or retired, the
difference between asset cost and salvage value is charged or credited to
accumulated depreciation.
o DISMANTLEMENT, REMOVAL AND ENVIRONMENTAL COSTS--Through December 31, 2002,
the estimated undiscounted costs, net of salvage values, of dismantling
and removing major oil and gas production and transportation facilities,
including necessary site restoration, were accrued using either the
unit-of-production or the straight-line method, which was used for certain
regional production transportation assets that are expected to have a
straight-line utilization pattern. Effective January 1, 2003, the company
adopted SFAS No. 143, "Accounting for Asset Retirement Obligations." See
Note 27--New Accounting Standards.
Environmental expenditures are expensed or capitalized, depending upon
their future economic benefit. Expenditures that relate to an existing
condition caused by past operations, and that do not have future economic
benefit, are expensed. Liabilities for these expenditures are recorded on
an undiscounted basis (unless acquired in a purchase business acquisition)
when environmental assessments or cleanups are probable and the costs can
be reasonably estimated. Recoveries of environmental remediation costs
from other parties are recorded as assets when their receipt is probable.
92
o STOCK COMPENSATION--Through December 31, 2002, the company accounted for
stock options using the intrinsic value method as prescribed by the
Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations. Pro forma information
regarding changes in net income and earnings per share data (as if the
accounting prescribed by SFAS No. 123, "Accounting for Stock-Based
Compensation," had been applied) is presented in Note 20--Employee Benefit
Plans. Effective January 1, 2003, the company voluntarily adopted SFAS No.
123 prospectively. See Note 20--Employee Benefit Plans.
o FOREIGN CURRENCY TRANSLATION--Adjustments resulting from the process of
translating foreign functional currency financial statements into U.S.
dollars are included in accumulated other comprehensive loss in common
stockholders' equity. Foreign currency transaction gains and losses are
included in current earnings. Most of the company's foreign operations use
their local currency as the functional currency.
o INCOME TAXES--Deferred income taxes are computed using the liability
method and are provided on all temporary differences between the
financial-reporting basis and the tax basis of the company's assets and
liabilities, except for deferred taxes on income considered to be
permanently reinvested in certain foreign subsidiaries and foreign
corporate joint ventures. Allowable tax credits are applied currently as
reductions of the provision for income taxes.
o NET INCOME PER SHARE OF COMMON STOCK--Basic income per share of common
stock is calculated based upon the daily weighted-average number of common
shares outstanding during the year, including shares held by the Long-Term
Stock Savings Plan (LTSSP). Diluted income per share of common stock
includes the above, plus "in-the-money" stock options issued under company
compensation plans. Treasury stock and shares held by the Compensation and
Benefits Trust (CBT) are excluded from the daily weighted-average number
of common shares outstanding in both calculations.
o CAPITALIZED INTEREST--Interest from external borrowings is capitalized on
major projects with an expected construction period of one year or longer.
Capitalized interest is added to the cost of the underlying asset and is
amortized over the useful lives of the assets in the same manner as the
underlying assets.
NOTE 2--EXTRAORDINARY ITEMS AND ACCOUNTING CHANGE
During 2002, the company incurred extraordinary losses totaling $16 million
after-tax ($24 million before-tax) on the following items:
o the call premium on the early retirement of the company's $250
million 8.86% notes due May 15, 2022;
o the redemption of the company's outstanding 8.24% Junior
Subordinated Deferrable Interest Debentures due 2036, which
triggered the redemption of the $300 million of 8.24% Trust
Originated Preferred Securities of Phillips 66 Capital Trust I; and
o the call premium on the early retirement of the company's $171
million 7.443% notes due 2004.
93
In 2001, ConocoPhillips incurred an extraordinary loss of $10 million after-tax
($14 million before-tax) attributable to the call premium on the early
retirement of its $300 million 9.18% notes due September 15, 2021.
Effective January 1, 2001, the company changed its method of accounting for the
costs of major maintenance turnarounds from the accrue-in-advance method to the
expense-as-incurred method to reflect the impact of a turnaround in the period
that it occurs. The new method is preferable because it results in the
recognition of costs at the time obligations are incurred. The cumulative effect
of this accounting change increased net income in 2001 by $28 million (after
reduction for income taxes of $15 million).
The pro forma effects of retroactive application of the change in accounting
method are presented below:
Millions of Dollars
Except Per Share Amounts
------------------------
2001 2000
------------------------
Income before extraordinary items $1,643 1,851
Earnings per share
Basic 5.61 7.27
Diluted 5.57 7.22
-----------------------------------------------------------------
Net income $1,633 1,851
Earnings per share
Basic 5.57 7.27
Diluted 5.54 7.22
-----------------------------------------------------------------
NOTE 3--MERGER OF CONOCO AND PHILLIPS
On August 30, 2002, Conoco and Phillips combined their businesses by merging
with separate acquisition subsidiaries of ConocoPhillips (the merger). As a
result, each company became a wholly owned subsidiary of ConocoPhillips. For
accounting purposes, Phillips was treated as the acquirer of Conoco, and
ConocoPhillips was treated as the successor of Phillips.
Immediately after the closing of the merger, former Phillips stockholders held
approximately 56 percent of the outstanding shares of ConocoPhillips common
stock, while former Conoco stockholders held approximately 44 percent.
ConocoPhillips common stock, listed on the New York Stock Exchange under the
symbol "COP," began trading on September 3, 2002.
The primary reasons for the merger and the principal factors that contributed to
an accounting treatment that resulted in the recognition of goodwill were:
o the combination of Conoco and Phillips would create a stronger,
major, integrated oil company with the benefits of increased size
and scale, improving the stability of the combined business'
earnings in varying economic and market climates;
o ConocoPhillips would emerge with a global presence in both upstream
and downstream petroleum businesses, increasing its overall
international presence to over 40 countries while maintaining a
strong domestic base; and
94
o combining the two companies' operations would provide significant
synergies and related cost savings, and improve future access to
capital.
The $16 billion purchase price attributed to Conoco for accounting purposes was
based on an exchange of Conoco shares for ConocoPhillips common shares.
ConocoPhillips issued approximately 293 million shares of common stock and
approximately 23.3 million of employee stock options in exchange for 627 million
shares of Conoco common stock and 49.8 million Conoco stock options. The common
stock was valued at $53.15 per share, which was Phillips' average common stock
price over the two-day trading period immediately before and after the November
18, 2001, public announcement of the transaction. The Conoco stock options, the
fair value of which was determined using the Black-Scholes option-pricing model,
were exchanged for ConocoPhillips stock options valued at $384 million.
Transaction-related costs, included in the purchase price, were $82 million.
The preliminary allocation of the purchase price to specific assets and
liabilities was based, in part, upon an outside appraisal of the fair value of
Conoco's assets. Over the next few months ConocoPhillips expects to receive the
final outside appraisal of the long-lived assets and conclude the fair value
determination of all other Conoco assets and liabilities. Subsequent to
completion of the final allocation of the purchase price and the determination
of the ultimate asset and liability tax bases, the deferred tax liabilities will
also be finalized. The following table summarizes, based on the year-end
preliminary purchase price allocation, the fair values of the assets acquired
and liabilities assumed as of August 30, 2002:
Millions
of Dollars
----------
Cash and cash equivalents $ 1,250
Accounts and notes receivable 2,821
Inventories 1,603
Prepaid expenses and other current assets 324
Investments and long-term receivables 3,074
Properties, plants and equipment (including $300 million of land) 19,269
Goodwill 12,079
Intangibles 661
In-process research and development 246
Other assets 312
------------------------------------------------------------------------------
Total assets $41,639
==============================================================================
Accounts payable $ 2,879
Notes payable and long-term debt due within one year 3,101
Accrued income and other taxes 1,320
Other accruals 1,543
Long-term debt 8,930
Accrued dismantlement, removal and environmental costs 332
Deferred income taxes 4,073
Employee benefit obligations 1,648
Other liabilities and deferred credits 1,109
Minority interests 648
Common stockholders' equity 16,056
------------------------------------------------------------------------------
Total liabilities and equity $41,639
==============================================================================
95
The allocation of the purchase price, as reflected above, has not been adjusted
for the U.S. Federal Trade Commission (FTC)-mandated dispositions described in
Note 4--Discontinued Operations. Goodwill, land and certain identifiable
intangible assets recorded in the acquisition are not subject to amortization,
but the goodwill and intangible assets will be tested periodically for
impairment as required by SFAS No. 142, "Goodwill and Other Intangible Assets."
Of the $661 million allocated to intangible assets, $545 million is assigned to
marketing tradenames which are not subject to amortization. Of the remaining
value assigned to intangible assets, $66 million assigned to refining technology
will be amortized over 11 years and $50 million was allocated to other
intangible assets with a weighted-average amortization period of 11 years.
ConocoPhillips has not yet determined the assignment of Conoco goodwill to
specific reporting units. Currently, Conoco goodwill is being reported as part
of the Corporate and Other reporting segment. Of the $12,079 million of
goodwill, $4,302 million is attributable to the gross-up required under purchase
accounting for deferred taxes. This and the remaining "true" goodwill, or $7,777
million, will ultimately be assigned to reporting units based on the benefits
received by the units from the synergies and strategic advantages of the merger.
None of the goodwill is deductible for tax purposes.
The purchase price allocation included $246 million of in-process research and
development costs related to Conoco's natural gas-to-liquids and other
technologies. In accordance with Financial Accounting Standards Board (FASB)
Interpretation No. 4, "Applicability of FASB Statement No. 2 to Business
Combinations Accounted for by the Purchase Method," the value assigned to the
research and development activities was charged to production and operating
expenses in the Emerging Businesses segment at the date of the consummation of
the merger, as these research and development costs had no alternative future
use.
Merger-related items that reduced ConocoPhillips' 2002 income from continuing
operations were:
Millions of Dollars
--------------------------
Before-Tax After-Tax
--------------------------
Write-off of acquired in-process research and development costs $246 246
Restructuring charges (see Note 5) 422 253
Incremental seismic contract costs 35 22
Transition costs 55 36
-----------------------------------------------------------------------------------------------
Total $758 557
===============================================================================================
In total, these items reduced 2002 income from continuing operations by $557
million ($1.15 per share on a diluted basis).
96
The following pro forma summary presents information as if the merger had
occurred at the beginning of each period presented, and includes the $557
million effect of the merger-related items mentioned above.
Millions of Dollars
Except Per Share Amounts
---------------------------------
2002 2001
---------------------------------
Revenues $ 81,433 79,554
Income from continuing operations 918 3,635
Net income (loss) (70) 4,072
Income from continuing operations per share of common stock
Basic 1.36 5.39
Diluted 1.34 5.32
Net income (loss) per share of common stock
Basic (.10) 6.04
Diluted (.10) 5.97
--------------------------------------------------------------------------------------------------------
During 2001, both Phillips and Conoco entered into other significant
transactions that are not reflected in the companies' historical income
statements for the full year 2001. The pro forma results have been prepared as
if the Phillips' September 14, 2001, acquisition of Tosco Corporation (Tosco)
(see Note 6--Acquisition of Tosco Corporation) and Conoco's July 16, 2001, $4.6
billion acquisition of Gulf Canada Resources Limited occurred on January 1,
2001. Gulf Canada Resources Limited was a Canadian-based independent exploration
and production company with primary operations in Western Canada, Indonesia, the
Netherlands and Ecuador.
The pro forma results reflect the following:
o recognition of depreciation and amortization based on the
preliminary allocated purchase price of the properties, plants and
equipment acquired;
o adjustment of interest for the amortization of the fair-value
adjustment to debt;
o cessation of the amortization of deferred gains not recognizable in
the purchase price allocation;
o accretion of discount on environmental accruals recorded at net
present value; and
o various other adjustments to conform Conoco's accounting policies to
ConocoPhillips'.
The pro forma adjustments use estimates and assumptions based on currently
available information. Management believes that the estimates and assumptions
are reasonable, and that the significant effects of the transactions are
properly reflected.
The pro forma information does not reflect any anticipated synergies that might
be achieved from combining the operations. The pro forma information is not
intended to reflect the actual results that would have occurred had the
companies been combined during the periods presented. This pro forma information
is not intended to be indicative of the results of operations that may be
achieved by ConocoPhillips in the future.
97
NOTE 4--DISCONTINUED OPERATIONS
During 2002, the company disposed of, or had committed to a plan to dispose of,
U.S. retail and wholesale marketing assets, U.S. refining and related assets,
and exploration and production assets in the Netherlands. Certain of these
planned dispositions were mandated by the FTC as a condition of the merger. For
reporting purposes, these operations are classified as discontinued operations,
and in Note 26--Segment Disclosures and Related Information, these operations
are included in Corporate and Other.
Revenues and income (loss) from discontinued operations were as follows:
Millions of Dollars
----------------------------------
2002 2001 2000
----------------------------------
Sales and other operating revenues from discontinued operations $ 7,406 2,670 786
=======================================================================================================
Income (loss) from discontinued operations before-tax $(1,387) 47 21
Income tax expense (benefit) (394) 15 7
-------------------------------------------------------------------------------------------------------
Income (loss) from discontinued operations $ (993) 32 14
=======================================================================================================
Major classes of assets and liabilities of discontinued operations held for sale
were as follows:
Millions of Dollars
-------------------
ASSETS 2002 2001
-------------------
Inventories $ 211 166
Other current assets 136 81
Net properties, plants and equipment 1,178 1,663
Intangibles 23 452
Other assets 57 20
-------------------------------------------------------------------------------------------------------
Assets of discontinued operations $1,605 2,382
======================================================================================================
LIABILITIES
Accounts payable and other current liabilities $ 331 259
Long-term debt 34 35
Accrued dismantlement, removal and environmental costs 86 83
Other liabilities and deferred credits 198 161
------------------------------------------------------------------------------------------------------
Liabilities of discontinued operations $ 649 538
======================================================================================================
In the fourth quarter of 2002, ConocoPhillips concluded a strategic business
review of its company-owned retail sites. The review included quantitative and
qualitative measures and identified 3,200 retail sites throughout the United
States that did not fit the company's long-range plans. The assets are being
actively marketed by an investment banking firm. The retail sites are being
grouped and marketed in packages, including the planned sale of the company's
Circle K Corporation subsidiary. Discussions are under way with potential
buyers, and the company expects to complete the sales in 2003.
98
In connection with the anticipated sale of these retail sites, ConocoPhillips
recorded charges totaling $1,412 million before-tax, $1,008 million after-tax,
primarily related to the impairment of properties, plants and equipment ($249
million); goodwill ($257 million); intangible asset ($429 million); and
provisions for losses and penalties associated with various operating lease
commitments ($477 million).
The intangible asset represents the Circle K tradename. Properties, plants and
equipment include land, buildings and equipment of owned retail sites and
leasehold improvements of leased sites. Fair value determinations were based on
estimated sales prices for comparable sites.
The provisions for losses and penalties associated with various operating lease
commitments include obligations for residual value guarantee deficiencies, and
future minimum rental payments that existed prior to the commitment date that
will continue after the exit plan is completed with no economic benefit. It also
includes penalties incurred to cancel the contractual arrangements. An
additional $130 million of lease loss provisions ($85 million after-tax) will be
recognized in 2003 as the company continues to operate the sites until sold.
As a condition to the merger of Conoco and Phillips, the FTC required that the
company divest the following assets:
o Phillips' Woods Cross business unit, which includes the Woods Cross,
Utah, refinery and associated motor fuel marketing operations (both
retail and wholesale) in Utah, Idaho, Wyoming, and Montana, as well
as Phillips' 50 percent interests in two refined products terminals
in Boise and Burley, Idaho;
o Conoco's Commerce City, Colorado, refinery and related crude oil
pipelines;
o Phillips' Colorado motor fuel marketing operations (both retail and
wholesale);
o Phillips' refined products terminal in Spokane, Washington;
o Phillips' propane terminal assets at Jefferson City, Missouri, and
East St. Louis, Illinois, which include the propane portions of
these terminals and the customer relationships and contracts for the
supply of propane therefrom;
o certain of Conoco's midstream natural gas gathering and processing
assets in southeast New Mexico; and
o certain of Conoco's midstream natural gas gathering assets in West
Texas.
Further, the FTC required that certain of these assets be held separately within
ConocoPhillips, under the management of a trustee until sold. In connection with
these anticipated sales, ConocoPhillips recorded an impairment of $113 million
before-tax, $69 million after-tax, related to the Phillips assets in the third
quarter of 2002.
In the fourth quarter of 2002, ConocoPhillips agreed to sell its Woods Cross
business unit for $25 million, subject to an adjustment for certain pension
obligations and the value of crude oil, refined products and other inventories.
Also in the fourth quarter, the company sold its propane terminal assets at
Jefferson City, Missouri, and East St. Louis, Illinois. The sales amounts did
not differ significantly from the fair-value estimates used in the third quarter
impairment calculations. Sale of the Colorado assets and the midstream assets is
expected to occur in 2003.
The company's Netherlands exploration and production assets were sold in the
fourth quarter of 2002. No gain or loss was recognized on the sale, as these
assets were recorded at fair value in the Conoco purchase price allocation.
99
NOTE 5--RESTRUCTURING
As a result of the merger, the company implemented a restructuring program in
September 2002 to capture the synergies of combining the two companies. In
connection with this program, the company recorded accruals totaling $770
million for anticipated employee severance payments, incremental pension and
medical plan benefit costs associated with the work force reductions, site
closings, and Conoco employee relocations. Of the total accrual, $337 million is
reflected in the Conoco purchase price allocation as an assumed liability, and
$422 million ($253 million after-tax) related to Phillips is reflected in
selling, general and administrative expense and production and operating
expense, and $11 million before-tax is included in discontinued operations.
Included in the total accruals of $770 million was $172 million related to
pension and other post-retirement benefits that will be paid in conjunction with
other retirement benefits over a number of future years. The table below
summarizes the balance of the accrual of $598 million, which consists of
severance related benefits to be provided to approximately 2,900 employees
worldwide and other merger related expenses. By the end of 2002, approximately
775 employees had been terminated. Changes in the severance related accrual
balance are summarized below.
Millions of Dollars
----------------------------------------------------------
2002 Reserve at
Accruals Benefit Payments December 31, 2002
-------- ---------------- -----------------
Conoco $297* (191) 106
Phillips 301 (32) 269
----------------------------------------------------------------------------------
Total $598 (223) 375
==================================================================================
*Purchase price adjustment.
The ending accrual balance is expected to be extinguished within one year,
except for $37 million, which is classified as long-term.
NOTE 6--ACQUISITION OF TOSCO CORPORATION
On September 14, 2001, Tosco was merged with a subsidiary of ConocoPhillips, as
a result of which ConocoPhillips became the owner of 100 percent of the
outstanding common stock of Tosco. Tosco's results of operations have been
included in ConocoPhillips' consolidated financial statements since that date.
Tosco's operations included seven U.S. refineries with a total crude oil
capacity of 1.31 million barrels per day; one 75,000-barrel-per-day refinery
located in Cork, Ireland; and various marketing, transportation, distribution
and corporate assets.
The primary reasons for ConocoPhillips' acquisition of Tosco, and the primary
factors that contributed to a purchase price that resulted in recognition of
goodwill, are:
o the Tosco operations would deliver earnings prospects, and potential
strategic and other benefits;
o combining the two companies' operations would provide significant
cost savings;
o adding Tosco to ConocoPhillips' Refining and Marketing (R&M)
operations would give the segment the size, scale and resources to
compete more effectively;
100
o the merger would transform ConocoPhillips into a stronger, more
integrated oil company with the benefits of increased size and
scale, improving the stability of the combined business' earnings in
varying economic and market climates;
o the combined company would have a stronger balance sheet, improving
its access to capital in the future; and
o the increased cash flow and access to capital resulting from the
Tosco acquisition would allow ConocoPhillips to pursue other
opportunities in the future.
Based on an exchange ratio of 0.8 shares of ConocoPhillips common stock for each
Tosco share, ConocoPhillips issued approximately 124.1 million common shares and
4.7 million vested employee stock options in the exchange, which increased
common stockholders' equity by approximately $7 billion. The common stock was
valued at $55.50 per share, which was ConocoPhillips' average common stock price
over the two-day trading period before and after the February 4, 2001, public
announcement of the transaction. The employee stock options were valued using
the Black-Scholes option pricing model, based on assumptions prevalent at the
February 2001 announcement date.
The allocation of the purchase price to specific assets and liabilities was
based, in part, upon an outside appraisal of Tosco's long-lived assets. Goodwill
and indefinite-lived intangible assets recorded in the acquisition are not
subject to amortization, but the goodwill and intangible assets will be tested
periodically for impairment as required by SFAS No. 142, "Goodwill and Other
Intangible Assets."
During the third quarter of 2002, the company concluded:
o the outside appraisal of the long-lived assets;
o the determination of the fair value of all other Tosco assets and
liabilities;
o the tax basis calculation of Tosco's assets and liabilities and the
related deferred tax liabilities; and
o the allocation of Tosco goodwill to reporting units within the R&M
operating segment.
The resulting adjustments to the purchase price allocation made in 2002
increased goodwill by $341 million. The more significant adjustments to goodwill
were a $247 million reduction in the value of refinery air emission permits to
reflect a more appropriate appraisal methodology, a $70 million liability
recorded for Tosco Long-Term Incentive Plan performance units, and a $69 million
increase in deferred tax liabilities, resulting primarily from an updated
analysis of the tax bases of Tosco's assets and liabilities. All other
adjustments in the aggregate reduced goodwill by $45 million.
Tosco Long-Term Incentive Plan performance units were derivative financial
instruments tied to ConocoPhillips' stock price and were marked-to-market each
reporting period. The resulting gains or losses from these mark-to-market
adjustments were reported in other income in the consolidated statement of
operations. In October 2002, the company and former Tosco executives negotiated
a complete cancellation of the performance units in exchange for a cash payment
to the former executives. During 2002, the company recorded gains totaling $38
million, after-tax, as this liability was marked-to-market each reporting period
and eventually settled.
101
The following table summarizes, based on the final purchase price allocation
described above, the fair values of the assets acquired and liabilities assumed
as of September 14, 2001:
Millions
of Dollars
----------
Cash and cash equivalents $ 103
Accounts and notes receivable 718
Inventories 1,965
Prepaid expenses and other current assets 154
Investments and long-term receivables 150
Properties, plants and equipment (including $1,720 million of land) 7,681
Goodwill 2,644
Intangibles 1,003
Other assets 11
----------------------------------------------------------------------------------------------
Total assets $14,429
==============================================================================================
Accounts payable $ 1,917
Accrued income and other taxes 350
Other accruals 206
Long-term debt 2,135
Accrued environmental costs 332
Deferred income taxes 1,824
Employee benefit obligations 177
Other liabilities and deferred credits 408
Common stockholders' equity 7,080
----------------------------------------------------------------------------------------------
Total liabilities and equity $14,429
==============================================================================================
Of the $1,003 million allocated to intangible assets, marketing tradenames
comprised $655 million, refinery air emission and operating permits totaled $315
million and other miscellaneous intangible assets amounted to $33 million. The
$1,003 million of intangible assets included $992 million allocated to
indefinite-lived intangible assets not subject to amortization and $11 million
allocated to intangible assets with a weighted-average amortization period of
seven years. In late 2002, the Circle K tradename ($429 million) was included
with the retail marketing operations that are held for sale at December 31,
2002, and included in the loss on disposal. See Note 4--Discontinued Operations.
ConocoPhillips finalized the required assignment of Tosco goodwill to specific
reporting units in 2002, with $1,944 million assigned to the refining reporting
unit and $700 million assigned to the marketing reporting unit. The goodwill was
assigned to the reporting units that were deemed to have benefited from the
synergies and strategic advantages of the merger. In late 2002, $257 million of
goodwill assigned to the marketing reporting unit was allocated to the retail
marketing operations held for sale at December 31, 2002, and included in the
loss on disposal. See Note 4--Discontinued Operations.
102
NOTE 7--INVENTORIES
Inventories at December 31 were:
Millions of Dollars
-------------------
2002 2001
-------------------
Crude oil and petroleum products $3,395 2,231
Canadian Syncrude (from mining operations) 4 --
Materials, supplies and other 446 221
---------------------------------------------------------------------------
$3,845 2,452
===========================================================================
Inventories valued on a LIFO basis totaled $3,349 million and $2,211 million at
December 31, 2002 and 2001, respectively. The remainder of the company's
inventories are valued under various other methods, including FIFO and weighted
average. The excess of current replacement cost over LIFO cost of inventories
amounted to $1,083 million and $2 million at December 31, 2002 and 2001,
respectively.
In the fourth quarter of 2001, the company recorded a $42 million before-tax,
$27 million after-tax, lower-of-cost-or-market write-down of its petroleum
products inventory. During 2000, certain inventory quantity reductions caused a
liquidation of LIFO inventory values. This liquidation increased net income by
$63 million, of which $60 million was attributable to ConocoPhillips' R&M
segment.
NOTE 8--INVESTMENTS AND LONG-TERM RECEIVABLES
Components of investments and long-term receivables at December 31 were:
Millions of Dollars
-------------------
2002 2001
-------------------
Investment in and advances to affiliated companies $5,900 2,788
Long-term receivables 526 241
Other investments 395 280
---------------------------------------------------------------------------
$6,821 3,309
===========================================================================
At December 31, 2002, retained earnings included $825 million related to the
undistributed earnings of affiliated companies, and distributions received from
affiliates were $313 million, $163 million and $2,180 million in 2002, 2001 and
2000, respectively.
EQUITY INVESTMENTS
The company owns or owned investments in chemicals, heavy-oil projects, oil and
gas transportation, coal mining and other industries. The affiliated companies
for which ConocoPhillips uses the equity method of accounting include, among
others, the following companies: Chevron Phillips Chemical Company LLC (CPChem)
(50 percent), Duke Energy Field Services, LLC (DEFS) (30.3 percent), Petrozuata
C.A. (50.1 percent non-controlling interest), Merey Sweeny L.P. (MSLP) (50
percent), Petrovera Resources Limited (46.7 percent), and Hamaca Holding LLC
(57.1 percent non-controlling interest). See Note 1--Accounting Policies for
additional information.
103
Summarized 100 percent financial information for DEFS, CPChem and all other
equity companies accounted for using the equity method follows:
2002 Millions of Dollars
-------------------------------------------------
Other Equity
DEFS CPChem Companies Total
------- ------- ------------ -------
Revenues $ 5,492 5,473 5,378 16,343
Income (loss) before income taxes (37) (24) 776 715
Net income (loss) (47) (30) 751 674
Current assets 1,123 1,561 5,783 8,467
Noncurrent assets 5,457 4,548 14,386 24,391
Current liabilities 1,426 1,051 4,696 7,173
Noncurrent liabilities 2,504 1,307 10,063 13,874
----------------------------------------------------------------------------------------
2001 Millions of Dollars
-------------------------------------------------
Other Equity
DEFS CPChem Companies Total
------- ------- ------------ -------
Revenues $ 8,025 6,010 1,555 15,590
Income (loss) before income taxes 367 (431) 607 543
Net income (loss) 364 (480) 414 298
Current assets 1,165 1,551 689 3,405
Noncurrent assets 5,465 4,309 3,949 13,723
Current liabilities 1,251 820 1,184 3,255
Noncurrent liabilities 2,426 1,606 1,960 5,992
----------------------------------------------------------------------------------------
2000 Millions of Dollars
-------------------------------------------------
Other Equity
DEFS* CPChem** Companies Total
------- ------- ------------ -------
Revenues $ 5,099 3,463 3,241 11,803
Income (loss) before income taxes 321 (213) 611 719
Net income (loss) 318 (241) 412 489
----------------------------------------------------------------------------------------
*For the period April 1, 2000, through December 31, 2000.
**For the period July 1, 2000, through December 31, 2000.
ConocoPhillips' share of income taxes incurred directly by the equity companies
is reported in equity in earnings of affiliates, and as such is not included in
income taxes in ConocoPhillips' consolidated financial statements.
DUKE ENERGY FIELD SERVICES, LLC
On March 31, 2000, ConocoPhillips combined its midstream gas gathering,
processing and marketing business with the gas gathering, processing, marketing
and natural gas liquids business of Duke Energy Corporation (Duke Energy)
forming a new company, DEFS. Duke Energy owns 69.7 percent of the company, which
it consolidates, while ConocoPhillips owns 30.3 percent, which it accounts for
using the equity method.
104
Duke Energy estimated the fair value of the ConocoPhillips' midstream business
at $1.9 billion in its purchase method accounting for the acquisition. The book
value of the midstream business contributed to DEFS was $1.1 billion, but no
gain was recognized in connection with the transaction because of
ConocoPhillips' and CPChem's long-term commitment to purchase the natural gas
liquids output from the former ConocoPhillips' natural gas processing plants
until December 31, 2014. This purchase commitment is on an "if-produced,
will-purchase" basis so it has no fixed production schedule, but has been, and
is expected to be, a relatively stable purchase pattern over the term of the
contract. Natural gas liquids are purchased under this agreement at various
published market index prices, less transportation and fractionation fees.
ConocoPhillips' consolidated results of operations include 100 percent of the
activity of the gas gathering, processing and marketing business contributed to
DEFS through March 31, 2000, and its 30.3 percent share of DEFS' earnings since
that date.
At December 31, 2002, the book value of ConocoPhillips' common investment in
DEFS was $67 million. ConocoPhillips' 30.3 percent share of the net assets of
DEFS was $743 million. This basis difference of $676 million, is being amortized
on a straight-line basis over 15 years, consistent with the remaining estimated
useful lives of the properties, plants and equipment contributed to DEFS.
Included in operating results for 2002, 2001 and 2000 was after-tax income of
$35 million, $36 million and $27 million, respectively, representing the
amortization of the basis difference.
On August 4, 2000, DEFS, Duke Energy and ConocoPhillips agreed to modify the
Limited Liability Company Agreement governing DEFS to provide for the admission
of a class of preferred members in DEFS. Subsidiaries of Duke Energy and
ConocoPhillips purchased new preferred member interests for $209 million and $91
million, respectively. The preferred member interests have a 30-year term, will
pay a distribution yielding 9.5 percent annually, and contain provisions that
require their redemption with any proceeds from an initial public offering. On
September 9, 2002, ConocoPhillips received $30 million return of preferred
member interest reducing its preferred interest to $61 million.
CHEVRON PHILLIPS CHEMICAL COMPANY LLC
On July 1, 2000, ConocoPhillips and ChevronTexaco Corporation, as successor to
Chevron Corporation (ChevronTexaco), combined their worldwide chemicals
businesses, excluding ChevronTexaco's Oronite business, into a new company,
CPChem. In addition to contributing the assets and operations included in the
company's Chemicals segment, ConocoPhillips also contributed the natural gas
liquids business associated with its Sweeny, Texas, complex. ConocoPhillips and
ChevronTexaco each own 50 percent of the voting and economic interests in
CPChem, and on July 1, 2000, ConocoPhillips began accounting for its investment
in CPChem using the equity method. Accordingly, ConocoPhillips' results of
operations include 100 percent of the activity of its chemicals business through
June 30, 2000, and its 50 percent share of CPChem's earnings since that date.
CPChem accounted for the combination using the historical bases of the assets
and liabilities contributed by ConocoPhillips and ChevronTexaco.
At December 31, 2002, the book value of ConocoPhillips' investment in CPChem was
$1,919 million. ConocoPhillips' 50 percent share of the total net assets of
CPChem was $1,747 million. This basis difference of $172 million is being
amortized over 20 years, consistent with the remaining estimated useful lives of
the properties, plants and equipment contributed to CPChem.
On July 1, 2002, ConocoPhillips purchased $125 million of Members' Preferred
Interests. Preferred distributions are cumulative at 9 percent per annum and
will be payable quarterly, upon declaration by CPChem's Board of Directors, from
CPChem's cash earnings. The securities have no stated maturity date and are
redeemable quarterly, in increments of $25 million, when CPChem's ratio of debt
to total capitalization falls below a stated level. The Members' Preferred
Interests are also redeemable at CPChem's sole option at any time.
105
NOTE 9--PROPERTIES, PLANTS AND EQUIPMENT, GOODWILL AND INTANGIBLES
The company's investment in properties, plants and equipment (PP&E), with
accumulated depreciation, depletion and amortization (DD&A), at December 31 was:
Millions of Dollars
----------------------------------------------------------------------------------
2002 2001
------------------------------------- -------------------------------------
Gross Net Gross Net
PP&E DD&A PP&E PP&E DD&A PP&E
------------------------------------- -------------------------------------
E&P $36,884 8,600 28,284 20,995 7,870 13,125
Midstream 903 16 887 49 34 15
R&M 15,605 2,765 12,840 11,553 2,804 8,749
Chemicals -- -- -- -- -- --
Emerging Businesses 690 5 685 -- -- --
Corporate and Other 477 143 334 493 249 244
-------------------------------------------------------------------------------------------------------------
$54,559 11,529 43,030 33,090 10,957 22,133
=============================================================================================================
Changes in the carrying amount of goodwill are as follows:
Millions of Dollars
----------------------------------------------------------
E&P R&M Corporate Total
----------------------------------------------------------
Balance at December 31, 2000 $ -- -- -- --
Acquired (primarily Tosco acquisition) 15 2,266 -- 2,281
-------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 15 2,266 -- 2,281
Acquired (merger of Conoco and Phillips)* -- -- 12,079 12,079
Valuation and other adjustments -- 341 -- 341
Allocated to discontinued operations -- (257) -- (257)
-------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 2002 $ 15 2,350 12,079 14,444
=============================================================================================================
*Has not yet been allocated to reporting units.
Information on the carrying value of intangible assets at December 31 follows:
Millions of Dollars
-------------------
2002 2001
-------------------
AMORTIZED INTANGIBLE ASSETS
Refining technology related $ 78 --
Other 44 11
------------------------------------------------------------------------------------------------------------
$122 11
============================================================================================================
UNAMORTIZED INTANGIBLE ASSETS
Tradenames $669 226
Refinery air and operating permits 315 562
Other 13 62
------------------------------------------------------------------------------------------------------------
$997 850
============================================================================================================
106
NOTE 10--IMPAIRMENTS
During 2002, 2001 and 2000, the company recognized the following before-tax
impairment charges:
Millions of Dollars
----------------------------
2002 2001 2000
----------------------------
E&P
United States $ 12 3 13
International 37 23 87
R&M
Tradenames 102 -- --
Retail site leasehold improvements 26 -- --
----------------------------------------------------------------------
$177 26 100
======================================================================
After-tax, the above impairment charges were $115 million in 2002, $25 million
in 2001, and $95 million in 2000.
The company's E&P segment recognized impairments of $49 million before-tax on
four fields in 2002. Impairment of the Janice field in the U.K. North Sea was
triggered by its sale, while the Viscount field in the U.K. North Sea was
impaired following an evaluation of development drilling results. Sales of
properties in Alaska and offshore California resulted in the remaining E&P
impairments in 2002.
The company initiated a plan in late 2002 to sell a substantial portion of its
R&M retail sites. The planned dispositions will result in a reduction of the
amount of gasoline volumes marketed under the company's "76" tradename. As a
result, the carrying value of the "76" tradename was impaired, with the $102
million impairment determined by an analysis of the discounted cash flows based
on the gasoline volumes projected to be sold under the brand name after the
planned dispositions, compared with the volumes being sold prior to the
dispositions. The company also impaired the carrying value of certain leasehold
improvements associated with leased retail sites that are held for use. The
impairment was triggered by a review of the leased-site guaranteed residual
values and was determined by comparing the guaranteed residual values and
leasehold improvements with current market values of the related assets.
See Note 4--Discontinued Operations for information regarding the impairments
recognized in 2002 in connection with the anticipated sale of certain assets
mandated by the FTC, and the planned sale of a substantial portion of the
company's retail marketing operations.
In the second quarter of 2001, the company committed to a plan to sell its 12.5
percent interest in the Siri oil field, offshore Denmark, triggering a
write-down of the field's assets to fair market value. The sale closed in early
2002. The company also recorded a property impairment on a crude oil tanker that
was sold in the fourth quarter of 2001.
The company recorded an impairment of its Ambrosio field, located in Lake
Maracaibo, Venezuela, in 2000. The Ambrosio field exploitation program did not
achieve originally premised results. The $87 million impairment charge was based
on the difference between the net book value of the property and the discounted
value of estimated future cash flows. The remaining property impairments in 2000
were related to fields in the United States, and were prompted by an evaluation
of drilling results or negative oil and gas reserve revisions.
107
NOTE 11--ACCRUED DISMANTLEMENT, REMOVAL AND ENVIRONMENTAL COSTS
ACCRUED DISMANTLEMENT AND REMOVAL COSTS
At December 31, 2002 and 2001, the company had accrued $1,065 million and $776
million, respectively, of dismantlement and removal costs, primarily related to
worldwide offshore production facilities and to production facilities in Alaska.
The increase in 2002 was primarily due to the merger and increased cost
estimates related to production facilities in Alaska. Estimated uninflated total
future dismantlement and removal costs at December 31, 2002, were $4,751
million, compared with $2,827 million in 2001. The increase was partially due to
the merger. The remaining increase was primarily attributable to changes in
future dismantlement and removal cost estimates. These costs are accrued
primarily on the unit-of-production method. Pursuant to SFAS No. 143,
"Accounting for Asset Retirement Obligations," the accounting for these costs
was changed effective January 1, 2003. See Note 27--New Accounting Standards for
additional information.
ENVIRONMENTAL COSTS
Total environmental accruals at December 31, 2002 and 2001, were $743 million
and $439 million, respectively. The 2002 increase in accrued environmental costs
was primarily the result of the merger. A large portion of these accrued
environmental costs were acquired in various business combinations and thus are
discounted obligations. For the discounted accruals, expected inflated
expenditures are: $112 million in 2003, $71 million in 2004, $58 million in
2005, $54 million in 2006, and $53 million in 2007. Remaining expenditures in
all future years after 2007 are expected to total $399 million. These expected
expenditures are discounted using a weighted-average 5 percent discount factor,
resulting in an accrued balance of $675 million at December 31, 2002.
ConocoPhillips had accrued environmental costs, primarily related to cleanup at
domestic refineries and underground storage tanks at U.S. service stations, and
remediation activities required by the state of Alaska at exploration and
production sites formerly owned by Atlantic Richfield Company, of $427 million
and $288 million at December 31, 2002 and 2001, respectively. ConocoPhillips had
also accrued at Corporate $236 million and $136 million of environmental costs
associated with non-operating sites at December 31, 2002 and 2001, respectively.
In addition, $70 million and $12 million were included at December 31, 2002 and
2001, respectively, for sites where the company has been named a potentially
responsible party under the Federal Comprehensive Environmental Response,
Compensation and Liability Act, the Federal Resource Conservation and Recovery
Act, or similar state laws. At December 31, 2002 and 2001, $10 million and $3
million, respectively, had been accrued for other environmental litigation.
Accrued environmental liabilities will be paid over periods extending up to 30
years.
Of the total $1,808 million and $1,215 million of accrued dismantlement, removal
and environmental costs at December 31, 2002 and 2001, $142 million and $156
million was classified as a current liability on the balance sheet, under the
caption "Other accruals."
108
NOTE 12--DEBT
Long-term debt at December 31 was:
Millions of Dollars
-------------------------
2002 2001
-------------------------
9 3/8% Notes due 2011 $ 350 350
8.86% Notes due 2022 -- 250
8.75% Notes due 2010 1,350 1,350
8.5% Notes due 2005 1,150 1,150
8.49% Notes due 2023 250 250
8.25% Mortgage Bonds due 2003 150 150
8.125% Notes due 2030 600 600
7.92% Notes due 2023 250 250
7.9% Notes due 2047 100 100
7.8% Notes due 2027 300 300
7.68% Notes due 2012 64 --
7.625% Notes due 2006 240 240
7.25% Notes due 2007 200 200
7.25% Notes due 2031 500 --
7.20% Notes due 2023 250 250
7.125% Debentures due 2028 300 300
7% Debentures due 2029 200 200
6.95% Notes due 2029 1,900 --
6.65% Notes due 2003 100 100
6.65% Debentures due 2018 300 300
6.375% Notes due 2009 300 300
6.35% Notes due 2011 1,750 --
6.35% Notes due 2009 750 --
5.90% Notes due 2004 1,350 --
5.90% Notes due 2032 600 --
5.45% Notes due 2006 1,250 --
4.75% Notes due 2012 1,000 --
3.625% Notes due 2007 400 --
Commercial paper and revolving debt due to banks and others
through 2006 at 1.46% - 1.94% at year end 2002 1,517 1,081
SRW Cogeneration Limited Partnership 180 --
Floating Rate Notes due 2003 500 --
Industrial Development bonds 153 55
Guarantee of LTSSP bank loan payable at 1.69% at year-end 2002 299 322
Note payable to Merey Sweeny, L.P. at 7% 131 133
Marine Terminal Revenue Refunding Bonds at 2.9% - 3.1% at year-end 2002 265 265
Other notes payable 68 49
--------------------------------------------------------------------------------------------------------
Debt at face value 19,067 8,545
Capitalized leases 23 --
Net unamortized premiums and discounts 676 109
--------------------------------------------------------------------------------------------------------
Total debt 19,766 8,654
Notes payable and long-term debt due within one year (849) (44)
--------------------------------------------------------------------------------------------------------
Long-term debt $ 18,917 8,610
========================================================================================================
109
Maturities inclusive of net unamortized premiums and discounts in 2003 through
2007 are: $849 million (included in current liabilities), $1,438 million, $1,229
million, $3,173 million and $654 million, respectively.
The company assumed $12,031 million of debt in connection with the merger.
In October 2002, ConocoPhillips entered into two new revolving credit facilities
and amended and restated a prior Phillips revolving credit facility to include
ConocoPhillips as a borrower. These credit facilities support the company's $4
billion commercial paper program, a portion of which may be denominated in euros
(limited to euro 3 billion). The company now has a $2 billion 364-day revolving
credit facility expiring on October 14, 2003, and two revolving credit
facilities totaling $2 billion expiring in October 2006. Effective with the
execution of the new facilities, the previously existing $2.5 billion in Conoco
facilities were terminated.
At December 31, 2002, ConocoPhillips had no debt outstanding under these credit
facilities, but had $1,517 million in commercial paper outstanding, which is
supported 100 percent by the long-term credit facilities. This amount
approximates fair value.
As of December 31, 2002, the company's wholly owned subsidiary, ConocoPhillips
Norway, had no outstanding debt under its two $300 million revolving credit
facilities expiring in June 2004.
Depending on the credit facility, borrowings may bear interest at a margin above
rates offered by certain designated banks in the London interbank market or at
margins above certificate of deposit or prime rates offered by certain
designated banks in the United States. The agreements call for commitment fees
on available, but unused, amounts. The agreements also contain early termination
rights if the company's current directors or their approved successors cease to
be a majority of the Board of Directors.
In October 2002, ConocoPhillips privately placed $2 billion of senior unsecured
debt securities, consisting of $400 million 3.625% notes due 2007, $1 billion
4.75% notes due 2012, and $600 million 5.90% notes due 2032, in each case fully
and unconditionally guaranteed by Conoco and Phillips. The $1,980 million
proceeds from the offering were used to reduce commercial paper, retire Conoco's
$500 million floating rate notes due October 15, 2002, and for general corporate
purposes.
ConocoPhillips redeemed the following notes during 2002 and early 2003 and
funded the redemptions with commercial paper:
o on May 15, 2002, its $250 million 8.86% notes due May 15, 2022, at
104.43 percent, resulting in a second quarter extraordinary loss
from the early retirement of debt of $13 million before-tax, $9
million after-tax;
o on November 26, 2002, its $171 million 7.443% senior unsecured notes
due 2004 resulting in a fourth quarter extraordinary loss from the
early retirement of debt of $3 million before-tax, $1 million
after-tax;
o on January 1, 2003, its $250 million 8.49% notes due January 1,
2023, at 104.245 percent; and
o on January 31, 2003, its $181 million SRW Cogeneration Limited
Partnership note which was assumed in September 2002 as a result of
acquiring its partners' interest in the partnership.
110
At December 31, 2002, $299 million was outstanding under the company's Long-Term
Stock Savings Plan (LTSSP) term loan, which will require annual installments
beginning in 2008 and continue through 2015. Under this bank loan, any
participating bank in the syndicate of lenders may cease to participate on
December 5, 2004, by giving not less than 180 days' prior notice to the LTSSP
and the company. If participating lenders give the cessation notice, the company
plans to resyndicate the loan.
Each bank participating in the LTSSP loan has the optional right, if the current
company directors or their approved successors cease to be a majority of the
Board, and upon not less than 90 days' notice, to cease to participate in the
loan. Under the above conditions, such banks' rights and obligations under the
loan agreement must be purchased by the company if not transferred to a bank of
the company's choice. See Note 20--Employee Benefit Plans for additional
discussion of the LTSSP.
NOTE 13--SALES OF RECEIVABLES
At December 31, 2002, ConocoPhillips sold certain credit card and trade
receivables to two Qualifying Special Purpose Entities (QSPEs) in
revolving-period securitization arrangements. These arrangements provide for
ConocoPhillips to sell, and the QSPEs to purchase, certain receivables and for
the QSPEs to then issue beneficial interests of up to $1.5 billion to five
bank-sponsored entities. The receivables sold have been sufficiently isolated
from ConocoPhillips to qualify for sales treatment. All five bank-sponsored
entities are multi-seller conduits with access to the commercial paper market
and purchase interests in similar receivables from numerous other companies
unrelated to ConocoPhillips. ConocoPhillips has no ownership in any of the
bank-sponsored entities and has no voting influence over any bank-sponsored
entity's operating and financial decisions. As a result, ConocoPhillips does not
consolidate any of these entities. Beneficial interests retained by
ConocoPhillips in the pool of receivables held by the QSPEs are subordinate to
the beneficial interests issued to the bank-sponsored entities and were measured
and recorded at fair value based on the present value of future expected cash
flows estimated using management's best estimates concerning the receivables
performance, including credit losses and dilution discounted at a rate
commensurate with the risks involved to arrive at present value. These
assumptions are updated periodically based on actual credit loss experience and
market interest rates. ConocoPhillips also retains servicing responsibility
related to the sold receivables. The fair value of the servicing responsibility
approximates adequate compensation for the servicing costs incurred.
ConocoPhillips' retained interest in the sold receivables at December 31, 2002
and 2001, was $1.3 billion and $450 million, respectively. Under accounting
principles generally accepted in the United States, the QSPEs are not
consolidated by ConocoPhillips. ConocoPhillips retained interest in sold
receivables is reported on the balance sheet in accounts and notes
receivable--related parties.
Total cash flows received from and paid under the securitization arrangements
were as follows:
Millions of Dollars
-------------------------
2002 2001
-------------------------
Receivables sold at beginning of year $ 940 500
Conoco receivables sold at August 30, 2002 400 --
Tosco receivables sold at September 14, 2001 -- 614
New receivables sold 18,613 8,907
Cash collections remitted (18,630) (9,081)
------------------------------------------------------------------------------------
Receivables sold at end of year $ 1,323 940
====================================================================================
Discounts and other fees paid on revolving balances $ 21 24
------------------------------------------------------------------------------------
111
At year-end, ConocoPhillips sold $264 million of receivables under a factoring
arrangement. ConocoPhillips also retains servicing responsibility related to the
sold receivables. The fair value of the servicing responsibility approximates
adequate compensation for the servicing costs incurred. At maturity of the
receivables, ConocoPhillips has a recourse obligation to repurchase uncollected
receivables. The fair value of this recourse obligation is not significant.
NOTE 14--GUARANTEES
At December 31, 2002, the company was liable for certain contingent obligations
under various contractual arrangements as described below.
CONSTRUCTION COMPLETION GUARANTEES
o The company has a construction completion guarantee related to debt
and bond financing arrangements secured by the Merey Sweeny, L.P.
(MSLP) joint-venture project in Texas. The maximum potential amount
of future payment under the guarantee, including joint-and-several
debt at its gross amount, is estimated to be $418 million assuming
that completion certification is not achieved. Of this amount, $209
million is attributable to Petroleos de Venezuela, S.A. (PDVSA),
because they are joint-and-severally liable for a portion of the
debt. If completion certification is not attained by 2004, the full
debt balance is due. The debt is non-recourse to ConocoPhillips upon
completion certification.
o The company has issued a construction completion guarantee related
to debt financing arrangements for the Hamaca Holding LLC joint
venture project in Venezuela. The maximum potential amount of future
payments under the guarantee is estimated to be $441 million, which
could be payable if the full debt financing capacity is utilized and
startup and completion of the Hamaca project is not achieved by
October 1, 2005. The project financing debt is non-recourse to
ConocoPhillips upon startup and completion certification.
GUARANTEED RESIDUAL VALUE ON LEASES
o The company leases ocean transport vessels, drillships, tank
railcars, corporate aircraft, service stations, computers, office
buildings, certain refining equipment, and other facilities and
equipment. Associated with these leases the company has guaranteed
approximately $1,821 million in residual values, which are due at
the end of the lease terms. However, those guaranteed amounts would
be reduced by the fair market value of the leased assets returned.
See Note 19--Non-Mineral Leases.
GUARANTEES OF JOINT-VENTURE DEBT
o At December 31, 2002, ConocoPhillips had guarantees of about $355
million outstanding for its portion of joint-venture debt
obligations. Of that amount, $176 million is associated with the
Polar Lights Company joint-venture project in Russia. Smaller
amounts and in some cases debt service reserves are associated with
Interconnector (UK) Ltd., Turcas Petrol, Malaysian Refining Company
Sdn. Bhd (Melaka), Hydroserve, Excel Paralubes, and Ingleside
Cogeneration Limited Partnership. The various debt obligations have
terms of up to 24 years.
112
OTHER GUARANTEES
o In addition to the construction completion guarantee explained
above, the MSLP agreement also requires the partners in the venture
to pay cash calls as required to meet minimum operating requirements
of the venture, in the event revenues do not cover expenses over the
next 18 years. The maximum potential future payments under the
agreement are estimated to be $258 million assuming MSLP does not
earn any revenue over the entire period. To the extent revenue was
generated by the venture, future required payments would be reduced
accordingly.
o The company has guaranteed certain potential payments related to its
interest in two drillships, which are operated by joint ventures.
Potential payments could be required for guaranteed residual value
amounts and amounts due under interest rate hedging agreements. The
maximum potential future payments under the agreements are estimated
to be approximately $193 million.
o During 2001, the company entered into a letter agreement authorizing
the charter, by an unaffiliated third party, of up to four LNG
vessels, which included an indemnity by the company in respect of
claims for charter hire and other charter payments. The indemnity
was subject to certain limitations and was to be applied net of
sub-charter rental income and other receipts of the unaffiliated
third party. In February 2003, the company entered into new
agreements which cancelled the 2001 letter agreement and established
separate guarantee facilities for $50 million each for two of the
LNG vessels. Under each such facility, the company may be required
to make payments should the charter revenue generated by the
relevant ship fall below certain specified minimum thresholds, and
the company will receive payments to the extent that such revenues
exceed those thresholds. The net maximum future payments over the 20
year terms of the agreements could be up to $100 million. In the
event the two ships are sold or a total loss occurs, the company
also may have recourse to the sales or insurance proceeds to recoup
payments made under the guarantee facilities.
o Other guarantees, consisting primarily of dealer and jobber loan
guarantees to support the company's marketing business, a guarantee
supporting a lease assignment on a corporate aircraft and guarantees
of lease payment obligations for a joint venture totaled $111
million. These guarantees generally extend up to 15 years and
payment would only be required if the dealer, jobber or lessee was
in default.
INDEMNIFICATIONS
o Over the years, the company has entered into various agreements to
sell ownership interests in certain corporations and joint ventures.
In addition, the company entered into a Tax Sharing Agreement in
1998 related to Conoco's separation from DuPont. These agreements
typically include indemnifications for additional taxes determined
to be due under the relevant tax law in connection with the
company's operations for years prior to the sale or separation.
Generally, the obligation extends until the related tax years are
closed. The maximum potential amount of future payments under the
indemnifications is the amount of additional tax determined to be
due under relevant tax law and the various agreements. There are no
material outstanding claims that have been asserted under these
agreements.
o As part of its normal ongoing business operations and consistent
with generally accepted and recognized industry practice,
ConocoPhillips enters into various agreements with other parties
(the Agreements). These Agreements apportion future risks between
the parties for the transaction(s) or relationship(s) governed by
such Agreements; one method of apportioning risk
113
between the company and the other contracting party is the inclusion
of provisions requiring one party to indemnify the other party
against losses that might otherwise be incurred by such other party
in the future (the Indemnity or Indemnities). Many of the company's
Agreements contain an Indemnity or Indemnities that require the
company to perform certain obligations as a result of the occurrence
of a triggering event or condition. In some instances the company
indemnifies third parties against losses resulting from certain
events or conditions that arise out of operations conducted by the
company's equity affiliates.
The nature of these indemnity obligations are diverse and too
numerous to list in this disclosure because of the thousands of
different Agreements to which the company is a party, each of which
may have a different term, business purpose, and triggering events
or conditions for an indemnity obligation. Consistent with customary
business practice, any particular indemnity obligation incurred by
the company is the result of a negotiated transaction or contractual
relationship for which the company has accepted a certain level of
risk in return for a financial or other type of benefit to the
company. In addition, the Indemnity or Indemnities in each Agreement
vary widely in their definitions of both the triggering event and
the resulting obligation, which is contingent on that triggering
event.
The company's risk management philosophy is to limit risk in any
transaction or relationship to the maximum extent reasonable in
relation to commercial and other considerations. Before accepting
any indemnity obligation, the company makes an informed risk
management decision considering, among other things, the remoteness
of the possibility that the triggering event will occur, the
potential costs to perform any resulting indemnity obligation,
possible actions to reduce the likelihood of a triggering event or
to reduce the costs of performing an indemnity obligation, whether
the company is in fact indemnified by an unrelated third party,
insurance coverage that may be available to offset the cost of the
indemnity obligation, and the benefits to the company from the
transaction or relationship.
Because many or most of the company's indemnity obligations are not
limited in duration or potential monetary exposure, the company
cannot calculate the maximum potential amount of future payments
that could be paid under the company's indemnity obligations
stemming from all its existing Agreements. The company has disclosed
contractual matters, including, but not limited to, indemnity
obligations, which will or could have a material impact on the
company's financial performance in quarterly, annual and other
reports required by applicable securities laws and regulations. The
company also accrues for contingent liabilities, including those
arising out of indemnity obligations, when a loss is probable and
the amounts can be reasonably estimated (see Note
15--Contingencies). The company is not aware of the occurrence of
any triggering event or condition that would have a material adverse
impact on the company's financial statements as a result of an
indemnity obligation relating to such triggering event or condition.
NOTE 15--CONTINGENCIES
The company is subject to various lawsuits and claims including but not limited
to: actions challenging oil and gas royalty and severance tax payments; actions
related to gas measurement and valuation methods; actions related to joint
interest billings to operating agreement partners; and claims for damages
resulting from leaking underground storage tanks, with related toxic tort
claims.
In the case of all known contingencies, the company accrues an undiscounted
liability when the loss is probable and the amount is reasonably estimable.
These liabilities are not reduced for potential insurance recoveries. If
applicable, undiscounted receivables are accrued for probable insurance or other
third-party
114
recoveries. Based on currently available information, the company believes that
it is remote that future costs related to known contingent liability exposures
will exceed current accruals by an amount that would have a material adverse
impact on the company's financial statements.
As facts concerning contingencies become known to the company, the company
reassesses its position both with respect to accrued liabilities and other
potential exposures. Estimates that are particularly sensitive to future changes
include contingent liabilities recorded for environmental remediation, tax and
legal matters. Estimated future environmental remediation costs are subject to
change due to such factors as the unknown magnitude of cleanup costs, the
unknown time and extent of such remedial actions that may be required, and the
determination of the company's liability in proportion to that of other
responsible parties. Estimated future costs related to tax and legal matters are
subject to change as events evolve and as additional information becomes
available during the administrative and litigation processes.
ENVIRONMENTAL--The company is subject to federal, state and local environmental
laws and regulations. These may result in obligations to remove or mitigate the
effects on the environment of the placement, storage, disposal or release of
certain chemical, mineral and petroleum substances at various sites. When the
company prepares its financial statements, accruals for environmental
liabilities are recorded based on management's best estimate using all
information that is available at the time. Loss estimates are measured and
liabilities are based on currently available facts, existing technology, and
presently enacted laws and regulations, taking into consideration the likely
effects of inflation and other societal and economic factors. Also considered
when measuring environmental liabilities are the company's prior experience in
remediation of contaminated sites, other companies' cleanup experience and data
released by the U.S. Environmental Protection Agency (EPA) or other
organizations. Unasserted claims are reflected in ConocoPhillips' determination
of environmental liabilities and are accrued in the period that they are both
probable and reasonably estimable.
Although liability of those potentially responsible for environmental
remediation costs is generally joint and several for federal sites and
frequently so for state sites, the company is usually only one of many companies
cited at a particular site. Due to the joint and several liabilities, the
company could be responsible for all of the cleanup costs related to any site at
which it has been designated as a potentially responsible party. If
ConocoPhillips were solely responsible, the costs, in some cases, could be
material to its, or one of its segments', operations, capital resources or
liquidity. However, settlements and costs incurred in matters that previously
have been resolved have not been materially significant to the company's results
of operations or financial condition. The company has been successful to date in
sharing cleanup costs with other financially sound companies. Many of the sites
at which the company is potentially responsible are still under investigation by
the EPA or the state agencies concerned. Prior to actual cleanup, those
potentially responsible normally assess the site conditions, apportion
responsibility and determine the appropriate remediation. In some instances,
ConocoPhillips may have no liability or attain a settlement of liability. Where
it appears that other potentially responsible parties may be financially unable
to bear their proportional share, this inability has been considered in
estimating the company's potential liability and accruals have been adjusted
accordingly.
Upon ConocoPhillips' acquisition of Tosco on September 14, 2001, the assumed
environmental obligations of Tosco, some of which are mitigated by
indemnification agreements, became contingencies reportable on a consolidated
basis by ConocoPhillips. Beginning with the acquisition of the Bayway refinery
in 1993, but excluding the Alliance refinery acquisition, Tosco negotiated, as
part of its acquisitions, environmental indemnification from the former owners
for remediating contamination that occurred prior to the respective acquisition
dates. Some of the environmental indemnifications are subject to caps and time
limits. No accruals have been recorded for any potential contingent liabilities
that will be funded by the prior owners under these indemnifications.
115
As part of Tosco's acquisition of Unocal's West Coast petroleum refining,
marketing, and related supply and transportation assets in March 1997, Tosco
agreed to pay the first $7 million per year of any environmental remediation
liabilities at the acquired sites arising out of, or relating to, the period
prior to the transaction's closing, plus 40 percent of any amount in excess of
$7 million per year, with Unocal paying the remaining 60 percent per year. The
indemnification agreement with Unocal has a 25-year term from inception, and, at
December 31, 2002, had a maximum cap of $131 million for environmental
remediation costs that ConocoPhillips would be required to fund during the
remainder of the agreement period. This maximum has been adjusted for amounts
paid through December 31, 2002.
The company is currently participating in environmental assessments and cleanups
at federal Superfund and comparable state sites. After an assessment of
environmental exposures for cleanup and other costs, the company makes accruals
on an undiscounted basis (except, if assumed in a purchase business combination,
such costs are recorded on a discounted basis) for planned investigation and
remediation activities for sites where it is probable that future costs will be
incurred and these costs can be reasonably estimated. See Note 11--Accrued
Dismantlement, Removal and Environmental Costs, for a summary of the company's
accrued environmental liabilities.
OTHER LEGAL PROCEEDINGS--ConocoPhillips is a party to a number of other legal
proceedings pending in various courts or agencies for which, in some instances,
no provision has been made.
OTHER CONTINGENCIES--ConocoPhillips has contingent liabilities resulting from
throughput agreements with pipeline and processing companies. Under these
agreements, ConocoPhillips may be required to provide any such company with
additional funds through advances and penalties for fees related to throughput
capacity not utilized by ConocoPhillips.
ConocoPhillips has various purchase commitments for materials, supplies,
services and items of permanent investment incident to the ordinary conduct of
business. Such commitments are not at prices in excess of current market.
Additionally, the company has obligations under an international contract to
purchase natural gas over a period of up to 17 years. These long-term purchase
obligations are at prices in excess of December 31, 2002, quoted market prices.
No material annual gain or loss is expected from these long-term commitments.
NOTE 16--FINANCIAL INSTRUMENTS AND DERIVATIVE CONTRACTS
DERIVATIVE INSTRUMENTS
The company and certain of its subsidiaries may use financial and
commodity-based derivative contracts to manage exposures to fluctuations in
foreign currency exchange rates, commodity prices, and interest rates, or to
exploit market opportunities. With the completion of the merger of Phillips and
Conoco on August 30, 2002, the derivatives policy adopted during the third
quarter of 2001 is no longer in effect; however, the ConocoPhillips Board of
Directors has approved an "Authority Limitations" document that prohibits the
use of highly leveraged derivatives or derivative instruments without sufficient
liquidity for comparable valuations without approval from the Chief Executive
Officer. The Authority Limitations document also authorizes the Chief Executive
Officer to establish the maximum Value at Risk (VaR) limits for the company.
Compliance with these limits is monitored daily. The function of the Risk
Management Steering Committee, monitoring the use and effectiveness of
derivatives, was assumed by the Chief Financial Officer for risks resulting from
foreign currency exchange rates and interest rates, and by the Executive Vice
President of Commercial, a new position that reports to the Chief Executive
Officer, for commodity price risk. ConocoPhillips' Commercial Group manages
commercial marketing,
116
optimizes the commodity flows and positions of the company, monitors related
risks of the company's upstream and downstream businesses and selectively takes
price risk to add value.
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as
amended (Statement No. 133 or SFAS No. 133), requires companies to recognize all
derivative instruments as either assets or liabilities on the balance sheet at
fair value. Assets and liabilities resulting from derivative contracts open at
December 31, 2002, were $197 million and $206 million, respectively, and appear
as accounts and notes receivables, other assets, accounts payable, or other
liabilities and deferred credits on the balance sheet.
The accounting for changes in fair value (i.e., gains or losses) of a derivative
instrument depends on whether it meets the qualifications for, and has been
designated as, a SFAS No. 133 hedge, and the type of hedge. At this time,
ConocoPhillips is not using SFAS No. 133 hedge accounting for commodity
derivative contracts, but the company is using hedge accounting for the
interest-rate derivatives noted below. All gains and losses, realized or
unrealized, from derivative contracts not designated as SFAS No. 133 hedges have
been recognized in the statement of operations. Gains and losses from derivative
contracts held for trading not directly related to the company's physical
business, whether realized or unrealized, have been reported net in other
income.
SFAS No. 133 also requires purchase and sales contracts for commodities that are
readily convertible to cash (e.g., crude oil, natural gas, and gasoline) to be
recorded on the balance sheet as derivatives unless the contracts are for
quantities expected to be used or sold by the company over a reasonable period
in the normal course of business (the normal purchases and normal sales
exception), among other requirements, and the company has documented its intent
to apply this exception. ConocoPhillips generally applies this exception to
eligible purchase and sales contracts; however, the company may elect not to
apply this exception (e.g., when another derivative instrument will be used to
mitigate the risk of the purchase or sale contract but hedge accounting will not
be applied). When this occurs, both the purchase or sales contract and the
derivative contract mitigating the resulting risk will be recorded on the
balance sheet at fair value in accordance with the preceding paragraphs.
INTEREST RATE DERIVATIVE CONTRACTS--On August 30, 2002, the company obtained a
number of fixed-to-floating and floating-to-fixed interest rate swaps from the
merger. ConocoPhillips designated these swaps as hedges, but by December 31,
2002, all of the fixed-to-floating rate swaps and a portion of the floating-
to-fixed rate swaps had been terminated. The floating-to-fixed interest rate
swaps still open at December 31, 2002, are as follows:
Millions of Dollars
-------------------------
Notional Fair
CASH FLOW HEDGES Amount Value
-------- -----
Maturing 2006 $ 166 (19)
Maturing in less than one year 500 (3)
--------------------------------------------------------------------------------
ConocoPhillips generally reports gains, losses, and ineffectiveness from
interest rate derivatives on the statement of operations in interest and debt
expense; however, when interest rate derivatives are used to hedge the interest
component of a lease, the resulting gains and losses are reported on the
statement of operations in production and operating expense. No portion of the
gain or loss from the swaps designated as interest rate hedges has been excluded
from the assessment of hedge ineffectiveness, which was immaterial for the
period from August 30 to December 31, 2002. In accordance with the hedge
accounting provisions of Statement No. 133, any realized gains or losses from
these derivative hedging
117
instruments will be recognized as income or expense in future periods concurrent
with the forecasted transactions. The company expects the amount of net
unrealized losses from interest rate hedges in accumulated other comprehensive
loss at December 31, 2002, that will be reclassified to earnings during the next
12 months to be immaterial.
CURRENCY EXCHANGE RATE DERIVATIVE CONTRACTS--During the third quarter of 2001,
ConocoPhillips used hedge accounting to record the results of using a forward
exchange contract to hedge the exposure to fluctuations in the exchange rate
between the U.S. dollar and Brazilian real, resulting from a firm commitment to
pay reals to acquire an exploratory lease. The hedge was closed in August 2001,
upon payment of the lease bonus. Results from the hedge appear in accumulated
other comprehensive loss on the balance sheet and will be reclassified into
earnings concurrent with the amortization or write-down of the lease bonus, but
no portion of this amount is expected to be reclassified during 2003. No
component of the hedge results was excluded from the assessment of hedge
effectiveness, and no gain or loss was recorded in the statement of operations
from hedge ineffectiveness.
After the merger, the company has foreign currency exchange rate risk resulting
from operations in over 40 countries. ConocoPhillips does not comprehensively
hedge the exposure to currency rate changes, although the company may choose to
selectively hedge exposures to foreign currency rate risk. Examples include firm
commitments for capital projects, certain local currency tax payments and
dividends, and cash returns from net investments in foreign affiliates to be
remitted within the coming year. Hedge accounting is not currently being used
for any of the company's foreign currency derivatives.
COMMODITY DERIVATIVE CONTRACTS--ConocoPhillips operates in the worldwide crude
oil, refined product, natural gas, natural gas liquids, and electric power
markets and is exposed to fluctuations in the prices for these commodities.
These fluctuations can affect the company's revenues as well as the cost of
operating, investing, and financing activities. Generally, ConocoPhillips'
policy is to remain exposed to market prices of commodity purchases and sales;
however, executive management may elect to use derivative instruments to
establish longer-term positions to hedge the price risk of the company's equity
crude oil and natural gas production, as well as refinery margins.
The ConocoPhillips Commercial Group use futures, forwards, swaps, and options in
various markets to optimize the value of the company's supply chain, which may
move the company's risk profile away from market average prices to accomplish
the following objectives:
o Balance physical systems. In addition to cash settlement prior to
contract expiration, exchange traded futures contracts may also be
settled by physical delivery of the commodity, providing another
source of supply to meet the company's refinery requirements or
marketing demand;
o Meet customer needs. Consistent with the company's policy to
generally remain exposed to market prices, the company uses swap
contracts to convert fixed-price sales contracts, which are often
requested by natural gas and refined product consumers, to a
floating market price;
o Manage the risk to the company's cash flows from price exposures on
specific crude oil, natural gas, refined product and electric power
transactions; and
o Enable the company to use the market knowledge gained from these
activities to do a limited amount of trading not directly related to
the company's physical business. For the 12 months ended December
31, 2002 and 2001, the gains or losses from this activity were not
material to the company's cash flows or income from continuing
operations.
118
At December 31, 2002, ConocoPhillips was not using hedge accounting for
commodity derivative contracts; however, during the first half of 2002, the
company did use hedge accounting for West Texas Intermediate (WTI) crude oil
futures designated as fair-value hedges of firm commitments to sell WTI crude
oil at Cushing, Oklahoma. The changes in the fair values of the futures and firm
commitments have been recognized in income. No component of the futures gain or
loss was excluded from the assessment of hedge effectiveness, and the amount
recognized in earnings during the year from ineffectiveness was immaterial.
CREDIT RISK
The company's financial instruments that are potentially exposed to
concentrations of credit risk consist primarily of cash equivalents,
over-the-counter derivative contracts, and trade receivables. ConocoPhillips'
cash equivalents, which are placed in high-quality money market funds and time
deposits with major international banks and financial institutions, are
generally not maintained at levels material to the company's financial position.
The credit risk from the company's over-the-counter derivative contracts, such
as forwards and swaps, derives from the counterparty to the transaction,
typically a major bank or financial institution. ConocoPhillips closely monitors
these credit exposures against predetermined credit limits, including the
continual exposure adjustments that result from market movements. Individual
counterparty exposure is managed within these limits, and includes the use of
cash-call margins when appropriate, thereby reducing the risk of significant
non-performance. ConocoPhillips also uses futures contracts, but futures have a
negligible credit risk because they are traded on the New York Mercantile
Exchange or the International Petroleum Exchange of London Limited.
The company's trade receivables result primarily from its petroleum operations
and reflect a broad national and international customer base, which limits the
company's exposure to concentrations of credit risk. The majority of these
receivables have payment terms of 30 days or less, and the company continually
monitors this exposure and the creditworthiness of the counterparties.
ConocoPhillips does not generally require collateral to limit the exposure to
loss; however, ConocoPhillips will sometimes use letters of credit, prepayments,
and master netting arrangements to mitigate credit risk with counterparties that
both buy from and sell to the company, as these agreements permit the amounts
owed by ConocoPhillips to be offset against amounts due to the company.
FAIR VALUES OF FINANCIAL INSTRUMENTS
The company used the following methods and assumptions to estimate the fair
value of its financial instruments:
Cash and cash equivalents: The carrying amount reported on the balance sheet
approximates fair value.
Accounts and notes receivable: The carrying amount reported on the balance sheet
approximates fair value.
Debt and mandatorily redeemable preferred securities: The carrying amount of the
company's floating-rate debt approximates fair value. The fair value of the
fixed-rate debt and mandatorily redeemable preferred securities is estimated
based on quoted market prices.
Swaps: Fair value is estimated based on forward market prices and approximates
the net gains and losses that would have been realized if the contracts had been
closed out at year-end. When forward market prices are not available, they are
estimated using the forward prices of a similar commodity with adjustments for
differences in quality or location.
119
Futures: Fair values are based on quoted market prices obtained from the New
York Mercantile Exchange or the International Petroleum Exchange of London
Limited.
Forward-exchange contracts: Fair value is estimated by comparing the contract
rate to the forward rate in effect on December 31 and approximates the net gains
and losses that would have been realized if the contracts had been closed out at
year-end.
Certain company financial instruments at December 31 were:
Millions of Dollars
----------------------------------------------
Carrying Amount Fair Value
-------------------- -------------------
2002 2001 2002 2001
-------------------- -------------------
Financial assets
Foreign currency derivatives $ 17 -- 17 --
Commodity derivatives 180 5 180 5
Financial liabilities
Total debt, excluding capital leases $19,743 8,654 20,844 9,175
Mandatorily redeemable other minority interests and
preferred securities 491 650 516 662
Interest rate derivatives 22 -- 22 --
Foreign currency derivatives 4 -- 4 --
Commodity derivatives 180 7 180 7
--------------------------------------------------------------------------------------------------------------------
NOTE 17--PREFERRED STOCK AND OTHER MINORITY INTERESTS
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF PHILLIPS 66
CAPITAL TRUSTS
During 1996 and 1997, the company formed two statutory business trusts, Phillips
66 Capital I (Trust I) and Phillips 66 Capital II (Trust II), in which the
company owns all common stock. The Trusts were created for the sole purpose of
issuing securities and investing the proceeds thereof in an equivalent amount of
subordinated debt securities of ConocoPhillips. ConocoPhillips established the
two trusts to raise funds for general corporate purposes.
On May 31, 2002, ConocoPhillips redeemed all of its outstanding 8.24% Junior
Subordinated Deferrable Interest Debentures due 2036 held by Trust I. This
triggered the redemption of $300 million of Trust I's 8.24% Trust Originated
Preferred Securities at par value, $25 per share. An extraordinary loss of $8
million before-tax, $6 million after-tax, was incurred during the second quarter
of 2002 as a result of the redemption.
Trust II has outstanding $350 million of 8% Capital Securities (Capital
Securities). The sole asset of Trust II is $361 million of the company's 8%
Junior Subordinated Deferrable Interest Debentures due 2037 (Subordinated Debt
Securities II) purchased by Trust II on January 17, 1997. The Subordinated Debt
Securities II are due January 15, 2037, and are redeemable in whole, or in part,
at the option of ConocoPhillips, on or after January 15, 2007, at a redemption
price of $1,000 per share, plus accrued and unpaid interest.
120
Subordinated Debt Securities II are unsecured obligations of ConocoPhillips,
equal in right of payment but subordinate and junior in right of payment to all
present and future senior indebtedness of ConocoPhillips.
The subordinated debt securities and related income statement effects are
eliminated in the company's consolidated financial statements. When the company
redeems the Subordinated Debt Securities II, Trust II is required to apply all
redemption proceeds to the immediate redemption of the Capital Securities.
ConocoPhillips fully and unconditionally guarantees Trust II's obligations under
the Capital Securities.
OTHER MANDATORILY REDEEMABLE MINORITY INTERESTS
The minority limited partner in Conoco Corporate Holdings L.P. is entitled to a
cumulative annual 7.86 percent priority return on its investment. The net
minority interest in Conoco Corporate Holdings held by the limited partner was
$141 million at December 31, 2002, and is mandatorily redeemable in 2019 or
callable without penalty beginning in the fourth quarter of 2004.
OTHER MINORITY INTERESTS
The minority interest owner in Ashford Energy Capital S.A. is entitled to a
cumulative annual preferred return on its investment, based on three-month LIBOR
rates plus 1.27 percent. The preferred return at December 31, 2002, was 2.70
percent. At December 31, 2002, the minority interest was $504 million.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities," and later in 2003, the FASB is expected to issue
SFAS No. 149, "Accounting for Certain Financial Instruments with Characteristics
of Liabilities and Equity." The company is evaluating these new pronouncements
to determine whether the above items currently presented in the mezzanine
section of the balance sheet will be required to be presented as debt or equity
on the balance sheet. See Note 27--New Accounting Standards and Note
28--Variable Interest Entities for more information.
PREFERRED STOCK
ConocoPhillips has 500 million shares of preferred stock authorized, par value
$.01 per share, none of which was issued or outstanding at December 31, 2002.
NOTE 18--PREFERRED SHARE PURCHASE RIGHTS
ConocoPhillips' Board of Directors authorized and declared a dividend of one
preferred share purchase right for each common share outstanding, and authorized
and directed the issuance of one right per common share for any newly issued
shares. The rights, which expire June 30, 2012, will be exercisable only if a
person or group acquires 15 percent or more of the company's common stock or
commences a tender offer that would result in ownership of 15 percent or more of
the common stock. Each right would entitle stockholders to buy one one-hundredth
of a share of preferred stock at an exercise price of $300. In addition, the
rights enable holders to either acquire additional shares of ConocoPhillips
common stock or purchase the stock of an acquiring company at a discount,
depending on specific circumstances. The company may redeem the rights in whole,
but not in part, for one cent per right.
121
NOTE 19--NON-MINERAL LEASES
The company leases ocean transport vessels, railroad tank cars, corporate
aircraft, service stations, computers, office buildings and other facilities and
equipment. Certain leases include escalation clauses for adjusting rentals to
reflect changes in price indices, as well as renewal options and/or options to
purchase the leased property for the fair market value at the end of the lease
term. There are no significant restrictions on ConocoPhillips imposed by the
leasing agreements in regards to dividends, asset dispositions or borrowing
ability. Leased assets under capital leases were not significant in any period
presented.
ConocoPhillips has leasing arrangements with several special purpose entities
(SPEs) that are third-party trusts established by a trustee and funded by
financial institutions. Other than the leasing arrangement, ConocoPhillips has
no other direct or indirect relationship with the trusts or their investors.
Each SPE from which ConocoPhillips leases assets is funded by at least 3 percent
substantive third-party residual equity capital investment, which is at-risk
during the entire term of the lease. ConocoPhillips does have various purchase
options to acquire the leased assets from the SPEs at the end of the lease term,
but those purchase options are not required to be exercised by ConocoPhillips.
See Note 28--Variable Interest Entities, for a discussion of how the accounting
for certain leasing arrangements with SPEs may change in 2003.
In connection with the committed plan to sell a major portion of the company's
owned retail stores, the company plans to exercise purchase option provisions of
various operating leases during 2003 involving approximately 900 store sites and
two office buildings. Depending upon the timing of when the company adopts FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities," and the
determination of whether or not the lessor entities in these leases are variable
interest entities, some or all of these lessor entities could become
consolidated subsidiaries of the company prior to the exercise of the purchase
options. See Note 27--New Accounting Standards, and Note 28--Variable Interest
Entities, for additional information on FASB Interpretation No. 46.
At December 31, 2002, future minimum rental payments due under non-cancelable
leases, including those associated with discontinued operations, were:
Millions
of Dollars
----------
2003 $ 649
2004 546
2005 479
2006 425
2007 367
Remaining years 1,635
-------------------------------------------------------------------------------
Total 4,101
Less income from subleases 641*
-------------------------------------------------------------------------------
Net minimum operating lease payments $3,460
===============================================================================
*Includes $164 million related to railroad cars subleased to CPChem, a
related party.
122
The above amounts exclude guaranteed residual value payments, including those
associated with discontinued operations, totaling $196 million in 2003, $219
million in 2004, $827 million in 2005, $145 million in 2006, and $434 million in
the remaining years, due at the end of lease terms, which would be reduced by
the fair market value of the leased assets returned. See Note 4--Discontinued
Operations regarding the company's commitment to exit certain retail sites and
the related accrual for probable deficiencies under the residual value
guarantees.
The company also expects to recognize probable guaranteed residual value
deficiencies associated with certain retail sites included in continuing
operations. The company plans to exercise its purchase options under these
leases in 2003, resulting in the recognition of a $142 million, $92 million
after-tax, loss.
ConocoPhillips has agreements with a shipping company for the long-term charter
of five crude oil tankers that are currently under construction. The charters
will be accounted for as operating leases upon delivery, which is expected in
the third and fourth quarters of 2003. If the completed tankers are not
delivered to ConocoPhillips before specified dates in 2004, the chartering
commitments are cancelable by ConocoPhillips. Upon delivery, the base term of
the charter agreements is 12 years, with certain renewal options by
ConocoPhillips. ConocoPhillips has options to cancel the charter agreements at
any time, including during construction or after delivery. After delivery, if
ConocoPhillips were to exercise its cancellation options, the company's maximum
commitment for the five tankers together would be $92 million. If ConocoPhillips
does not exercise its cancellation options, the total operating lease commitment
over the 12-year term for the five tankers would be $383 million on an estimated
bareboat basis.
Operating lease rental expense for the years ended December 31 was:
Millions of Dollars
----------------------------------
2002 2001 2000
----------------------------------
Total rentals* $541 271 128
Less sublease rentals 21 22 2
--------------------------------------------------------------------------------
$520 249 126
================================================================================
*Includes $12 million of contingent rentals in 2002. Contingent rentals in
2001 and 2000 were not significant.
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NOTE 20--EMPLOYEE BENEFIT PLANS
PENSION AND POSTRETIREMENT PLANS
An analysis of the projected benefit obligations for the company's pension plans
and accumulated benefit obligations for its postretirement health and life
insurance plans follows:
Millions of Dollars
-------------------------------------------------------------------
Pension Benefits Other Benefits
------------------------------------------- -------------------
2002 2001 2002 2001
------------------- ------------------- ------- -------
U.S. INT'L. U.S. Int'l.
------- ------- ------- -------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at January 1 $ 1,432 417 991 386 239 140
Service cost 75 32 40 15 9 4
Interest cost 133 48 82 24 31 11
Plan participant contributions -- 2 -- 1 15 11
Plan amendments (12) -- 6 -- 133 21
Actuarial (gain) loss 205 (21) 161 8 31 14
Acquisitions 1,349 908 277 -- 509 68
Benefits paid (159) (23) (131) (12) (47) (31)
Curtailment (36) -- -- (2) (4) --
Recognition of termination benefits 92 3 6 5 3 1
Foreign currency exchange rate change -- 135 -- (8) -- --
-----------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at December 31 $ 3,079 1,501 1,432 417 919 239
===================================================================================================================================
Accumulated benefit obligation portion of above at
December 31 $ 2,455 1,325 1,121 345
===========================================================================================================
CHANGE IN FAIR VALUE OF PLAN ASSETS
Fair value of plan assets at January 1 $ 732 381 696 401 21 20
Actual return on plan assets (85) (74) (91) (19) (5) 2
Acquisitions 600 594 166 -- -- 4
Company contributions 145 39 92 18 27 15
Plan participant contributions -- 2 -- 1 15 11
Benefits paid (159) (21) (131) (12) (47) (31)
Foreign currency exchange rate change -- 106 -- (8) -- --
-----------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at December 31 $ 1,233 1,027 732 381 11 21
===================================================================================================================================
124
Millions of Dollars
-------------------------------------------------------------------
Pension Benefits Other Benefits
------------------------------------------- -------------------
2002 2001 2002 2001
------------------- ------------------- ------- -------
U.S. INT'L. U.S. Int'l.
------- ------- ------- -------
FUNDED STATUS
Excess obligation $(1,846) (474) (700) (36) (908) (218)
Unrecognized net actuarial loss 697 171 418 61 60 30
Unrecognized prior service cost 30 5 57 7 131 18
-----------------------------------------------------------------------------------------------------------------------------------
Total recognized amount in the consolidated balance sheet $(1,119) (298) (225) 32 (717) (170)
===================================================================================================================================
Components of above amount:
Prepaid benefit cost $ -- 52 5 37 -- --
Accrued benefit liability (1,484) (400) (501) (15) (717) (170)
Intangible asset 43 3 57 4 -- --
Accumulated other comprehensive loss 322 47 214 6 -- --
-----------------------------------------------------------------------------------------------------------------------------------
Total recognized $(1,119) (298) (225) 32 (717) (170)
===================================================================================================================================
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31
Discount rate 6.75% 5.85 7.25 6.30 6.75 7.25
Expected return on plan assets 7.05 7.45 8.70 7.60 5.50 5.20
Rate of compensation increase 4.00 3.80 4.00 3.75 4.00 4.00
-----------------------------------------------------------------------------------------------------------------------------------
Pension plan funds are invested in a diversified portfolio of assets.
Approximately $198 million held in a participating annuity contract is not
available for meeting benefit obligations in the near term. At December 31,
2002, approximately 4,300 shares of company stock were included in plan assets.
At December 31, 2001, no company stock was included in plan assets. The
company's funding policy for U.S. plans is to contribute at least the minimum
required by the Employee Retirement Income Security Act of 1974. Contributions
to foreign plans are dependent upon local laws and tax regulations. In 2003, the
company expects to contribute approximately $340 million to its domestic
qualified pension plans and $50 million to its international qualified pension
plans.
The funded status of the plans was impacted in 2002 by changes in assumptions
used to calculate plan liabilities, the merger of Conoco and Phillips, and
negative asset performance.
During 2002, the company recorded charges to other comprehensive loss totaling
$149 million ($93 million net of tax), resulting in accumulated other
comprehensive loss due to minimum pension liability adjustments at December 31,
2002, of $369 million ($236 million net of tax).
125
Millions of Dollars
---------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
------------------------------------------------------------ ---------------------------
2002 2001 2000 2002 2001 2000
---------------- ---------------- ---------------- ----- ----- -----
U.S. INT'L. U.S. Int'l. U.S. Int'l.
----- ----- ----- ----- ----- ------
COMPONENTS OF NET PERIODIC
BENEFIT COST
Service cost $ 75 32 40 15 32 16 9 4 2
Interest cost 133 48 82 24 75 23 31 11 9
Expected return on plan assets (73) (49) (74) (30) (80) (29) (1) (1) (1)
Amortization of prior service cost 5 2 6 1 5 1 8 (1) (3)
Recognized net actuarial loss
(gain) 48 7 16 -- (5) -- 3 2 1
Amortization of net asset -- -- -- (1) (7) -- -- -- --
-----------------------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost $ 188 40 70 9 20 11 50 15 8
===================================================================================================================================
The company recorded curtailment losses of $23 million and $1 million in 2002
and 2000, respectively, and a curtailment gain of $2 million in 2001. The
company recorded settlement losses of $10 million in 2001.
In determining net pension and other postretirement benefit costs,
ConocoPhillips has elected to amortize net gains and losses on a straight-line
basis over 10 years. Prior service cost is amortized on a straight-line basis
over the average remaining service period of employees expected to receive
benefits under the plan.
For the company's tax-qualified pension plans with projected benefit obligations
in excess of plan assets, the projected benefit obligation, the accumulated
benefit obligation, and the fair value of plan assets were $4,288 million,
$3,542 million, and $2,259 million at December 31, 2002, respectively, and
$1,519 million, $1,211 million, and $886 million at December 31, 2001,
respectively.
For the company's unfunded non-qualified supplemental key employee pension
plans, the projected benefit obligation and the accumulated benefit obligation
were $260 million and $206 million, respectively, at December 31, 2002, and were
$109 million and $76 million, respectively, at December 31, 2001.
The company has multiple non-pension postretirement benefit plans for health and
life insurance. The health care plans are contributory, with participant and
company contributions adjusted annually; the life insurance plans are
non-contributory. For most groups of retirees, any increase in the annual health
care escalation rate above 4.5 percent is borne by the participant. The
weighted-average health care cost trend rate for those participants not subject
to the cap is assumed to decrease gradually from 10 percent in 2003 to 5 percent
in 2009.
126
The assumed health care cost trend rate impacts the amounts reported. A
one-percentage-point change in the assumed health care cost trend rate would
have the following effects on the 2002 amounts:
Millions of Dollars
---------------------------
One-Percentage-Point
---------------------------
Increase Decrease
-------- --------
Effect on total of service and interest cost components $ -- --
Effect on the postretirement benefit obligation 3 3
---------------------------------------------------------------------------------------
DEFINED CONTRIBUTION PLANS
At December 31, 2002, most employees (excluding retail service station
employees) were eligible to participate in either the company-sponsored Thrift
Plan of Phillips Petroleum Company, the Tosco Corporation Capital Accumulation
Plan, or the Thrift Plan for Employees of Conoco Inc. Employees could contribute
a portion of their salaries to various investment funds, including a company
stock fund, a percentage of which was matched by the company. In addition,
eligible participants in the Tosco Corporation Capital Accumulation Plan could
receive an additional company contribution in lieu of pension plan benefits.
Company contributions charged to expense in total for all three plans were $40
million in 2002, and $14 million in 2001 and $6 million in 2000.
The company's Long-Term Stock Savings Plan (LTSSP) was a leveraged employee
stock ownership plan. Prior to January 1, 2003, employees eligible for the
Thrift Plan of Phillips Petroleum Company could also elect to participate in the
LTSSP by contributing 1 percent of their salaries and receiving an allocation of
shares of common stock proportionate to their contributions. On January 1, 2003,
the Thrift Plan of Phillips Petroleum Company and the Tosco Corporation Capital
Accumulation Plan were merged into the LTSSP and the name was changed to the
ConocoPhillips Savings Plan (and the LTSSP became known as the Stock Savings
Feature within that plan). The ConocoPhillips Savings Plan replaced most
features available under the Thrift Plan of Phillips Petroleum Company and the
Tosco Corporation Capital Accumulation Plan. In addition to participating in the
Thrift Plan for Employees of Conoco Inc., on January 1, 2003, heritage Conoco
employees became eligible to participate in the Stock Savings Feature of the
ConocoPhillips Savings Plan.
In 1990, the LTSSP borrowed funds that were used to purchase previously unissued
shares of company common stock. Since the company guarantees the LTSSP's
borrowings, the unpaid balance is reported as a liability of the company and
unearned compensation is shown as a reduction of common stockholders' equity.
Dividends on all shares are charged against retained earnings. The debt is
serviced by the LTSSP from company contributions and dividends received on
certain shares of common stock held by the plan, including all unallocated
shares. The shares held by the LTSSP are released for allocation to participant
accounts based on debt service payments on LTSSP borrowings. In addition, during
the period from 2003 through 2007, when no debt principal payments are scheduled
to occur, the company has committed to make direct contributions of stock to the
LTSSP, or make prepayments on LTSSP borrowings, to ensure a certain minimum
level of stock allocation to participant accounts.
The company recognizes interest expense as incurred and compensation expense
based on the fair market value of the stock contributed or on the cost of the
unallocated shares released, using the shares-allocated method. The company
recognized total LTSSP expense of $39 million, $33 million and $40 million in
2002, 2001 and 2000, respectively, all of which was compensation expense. In
2002, 2001 and 2000, respectively, the company made cash contributions to the
LTSSP of $2 million, $17 million and
127
$23 million. In 2002, 2001 and 2000, the company contributed 771,479 shares,
292,857 shares and 508,828 shares, respectively, of company common stock from
the Compensation and Benefits Trust. The shares had a fair market value of $41
million, $17 million and $24 million, respectively. Dividends used to service
debt were $28 million, $28 million and $32 million in 2002, 2001 and 2000,
respectively.
These dividends reduced the amount of expense recognized each period. Interest
incurred on the LTSSP debt in 2002, 2001 and 2000 was $7 million, $17 million
and $26 million, respectively.
The total LTSSP shares as of December 31 were:
2002 2001
-------------------------------
Unallocated shares 7,717,710 8,379,924
Allocated shares 14,925,443 14,794,203
--------------------------------------------------------------------------------
Total LTSSP shares 22,643,153 23,174,127
================================================================================
The fair value of unallocated shares at December 31, 2002, and 2001, was $373
million and $505 million, respectively.
STOCK-BASED COMPENSATION PLANS
Under the company's Omnibus Securities Plan approved by shareholders in 1993,
stock options and stock awards for certain employees were authorized for up to
eight-tenths of 1 percent (0.8 percent) of the total outstanding shares as of
December 31 of the year preceding the awards. Any shares not issued in the
current year were available for future grant. Upon the adoption of the 2002
Omnibus Securities Plan discussed below, the number of shares available for
issuance under the Omnibus Securities Plan was limited to 700,000. The term of
the Omnibus Securities Plan ended on December 31, 2002.
In 2001, shareholders approved the 2002 Omnibus Securities Plan, which has a
term of five years, from January 1, 2002, through December 31, 2006, and which
is authorized to issue approximately 18,000,000 shares of company common stock.
The two plans also provided for non-stock-based awards.
Shares of company stock awarded under both plans were:
2002 2001 2000
-------------------------------------
Shares 1,090,082 237,849 319,726
Weighted-average fair value $ 57.84 56.23 46.98
--------------------------------------------------------------------------------
Stock options granted under provisions of the plans and earlier plans permit
purchase of the company's common stock at exercise prices equivalent to the
average market price of the stock on the date the options were granted. The
options have terms of 10 years and normally become exercisable in increments of
up to one-third on each anniversary date following the date of grant. Stock
Appreciation Rights (SARs) may, from time to time, be affixed to the options.
Options exercised in the form of SARs permit the holder to receive stock, or a
combination of cash and stock, subject to a declining cap on the exercise price.
128
The merger was a change-in-control event that resulted in a lapsing of
restrictions on, and payout of, stock and stock option awards under the plans.
ConocoPhillips offered to exchange certain stock awards under the plans with new
awards in the form of restricted stock units. These new restricted stock units
were converted, at the time of the merger, into awards based on the same number
of shares of ConocoPhillips common stock.
Conoco had several stock-based compensation plans that were assumed in the
merger: the 1998 Stock and Performance Incentive Plan; the 1998 Key Employee
Stock Performance Plan; the 1998 Global Performance Sharing Plan; and the 2001
Global Performance Sharing Plan. Upon the merger, outstanding stock options
under these plans were converted to ConocoPhillips stock options at the merger
exchange ratio of 0.4677.
The Conoco plans award stock options at exercise prices equivalent to the
average market price of the stock on the date the option was granted. Awards
have option terms of 10 years and become exercisable based on various formulas,
including those that become exercisable one year from date of grant, and those
that become exercisable in increments of one-third on each anniversary date
following date of grant. In total, there were 16 million shares of company stock
at December 31, 2002, available for issuance under the Conoco plans.
Stock-based compensation expense recognized by ConocoPhillips in connection with
all the plans discussed above was $60 million, $21 million and $23 million in
2002, 2001 and 2000, respectively.
Beginning in 2003, ConocoPhillips has elected to use the fair-value accounting
method provided for under SFAS No. 123, "Accounting for Stock-Based
Compensation." The company will use the prospective transition method provided
under SFAS 123, applying the fair-value accounting method and recognizing
compensation expense for all stock options granted, modified or settled after
December 31, 2002.
Employee stock options granted prior to 2003 will continue to be accounted for
under APB No. 25, "Accounting for Stock Issued to Employees," and related
Interpretations. Because the exercise price of ConocoPhillips employee stock
options equals the market price of the underlying stock on the date of grant, no
compensation expense is generally recognized under APB No. 25. The following
table displays pro forma information as if the provisions of SFAS No. 123 had
been applied to employee stock options granted since January 1, 1996:
2002 2001 2000
------------------------------------
Pro forma net income (loss) in millions $ (358) 1,644 1,850
Pro forma basic income (loss) per share (.74) 5.61 7.27
Pro forma diluted income (loss) per share (.74) 5.57 7.21
------------------------------------------------------------------------------------
Assumptions used
Risk-free interest rate 4.1% 4.5 5.9
Dividend yield 3.0% 2.5 2.5
Volatility factor 26.2% 27.0 26.0
Average grant date fair value of options $ 11.67 23.19 16.00
Expected life (years) 6 5 5
------------------------------------------------------------------------------------
129
In August 2002, ConocoPhillips issued 23.3 million vested stock options to
replace unexercised Conoco stock options at the time of the merger. These
options had a weighted-average exercise price of $47.65 per option, and a
Black-Scholes option-pricing model value of $16.50 per option. In September
2001, ConocoPhillips issued 4.7 million vested stock options to replace
unexercised Tosco stock options at the time of the acquisition. These options
had a weighted-average exercise price of $23.15 per option, and a Black-Scholes
option-pricing model value of $32.51 per option.
A summary of ConocoPhillips' stock option activity follows:
Weighted-Average
Options Exercise Price
---------- ----------------
Outstanding at December 31, 1999 9,844,524 $39.84
Granted 1,299,500 61.85
Exercised (1,223,779) 30.79
Forfeited (57,278) 47.06
------------------------------------------------------------------- ----------------
Outstanding at December 31, 2000 9,862,967 $43.82
Granted (including Tosco exchange) 9,038,571 38.81
Exercised (2,373,062) 22.36
Forfeited (96,126) 60.41
------------------------------------------------------------------- ----------------
Outstanding at December 31, 2001 16,432,350 $44.06
Granted (including the merger) 28,830,903 48.11
Exercised (2,032,232) 24.66
Forfeited (124,416) 57.78
------------------------------------------------------------------- ----------------
OUTSTANDING AT DECEMBER 31, 2002 43,106,605 $47.65
=================================================================== ----------------
OUTSTANDING AT DECEMBER 31, 2002
Weighted-Average
------------------------------------------
Exercise Prices Options Remaining Lives Exercise Price
---------------- ---------- --------------- --------------
$ 9.04 TO $31.44 5,067,979 2.18 YEARS $25.06
$31.52 TO $44.91 6,384,431 4.29 YEARS 39.88
$45.75 TO $66.72 31,654,195 7.67 YEARS 52.83
----------------------------------------------------------------------------------------------
EXERCISABLE AT DECEMBER 31
Weighted-Average
Exercise
Exercise Prices Options Price
--------------- ---------- ----------------
2002 $ 9.04 TO $31.44 5,067,979 $25.06
$31.52 TO $44.91 6,384,431 39.88
$45.75 TO $66.72 21,614,181 52.17
----------------------------------------------------------------------------------------------
2001 $ 9.04 to $31.44 3,056,009 $22.67
$31.52 to $44.91 3,075,354 38.06
$45.75 to $64.43 3,525,616 48.32
----------------------------------------------------------------------------------------------
2000 $22.57 to $31.44 1,754,047 $29.42
$32.25 to $44.91 1,674,129 37.49
$45.75 to $62.57 2,029,352 46.46
----------------------------------------------------------------------------------------------
130
COMPENSATION AND BENEFITS TRUST (CBT)
The CBT is an irrevocable grantor trust, administered by an independent trustee
and designed to acquire, hold and distribute shares of the company's common
stock to fund certain future compensation and benefit obligations of the
company. The CBT does not increase or alter the amount of benefits or
compensation that will be paid under existing plans, but offers the company
enhanced financial flexibility in providing the funding requirements of those
plans. ConocoPhillips also has flexibility in determining the timing of
distributions of shares from the CBT to fund compensation and benefits, subject
to a minimum distribution schedule. The trustee votes shares held by the CBT in
accordance with voting directions from eligible employees, as specified in a
trust agreement with the trustee.
The company sold 29.2 million shares of previously unissued company common stock
to the CBT in 1995 for $37 million of cash, previously contributed to the CBT by
ConocoPhillips, and a promissory note from the CBT to ConocoPhillips of $952
million. The CBT is consolidated by ConocoPhillips, therefore the cash
contribution and promissory note are eliminated in consolidation. Shares held by
the CBT are valued at cost and do not affect earnings per share or total common
stockholders' equity until after they are transferred out of the CBT. In 2002
and 2001, shares transferred out of the CBT were 771,479 and 292,857,
respectively. At December 31, 2002, 26.8 million shares remained in the CBT. All
shares are required to be transferred out of the CBT by January 1, 2021.
NOTE 21--TAXES
Taxes charged to income from continuing operations were:
Millions of Dollars
----------------------------------
2002 2001 2000
----------------------------------
TAXES OTHER THAN INCOME TAXES
Excise $ 6,246 2,177 1,781
Property 244 148 108
Production 303 328 278
Payroll 99 54 50
Environmental 5 14 12
Other 40 19 13
---------------------------------------------------------------------
$ 6,937 2,740 2,242
=====================================================================
INCOME TAXES
Federal
Current $ 71 133 470
Deferred 56 426 224
Foreign
Current 1,188 842 965
Deferred 114 126 127
State and local
Current 57 97 100
Deferred (36) 20 14
---------------------------------------------------------------------
$ 1,450 1,644 1,900
=====================================================================
131
Deferred income taxes reflect the net tax effect of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for tax purposes. Major components of deferred tax
liabilities and assets at December 31 were:
Millions of Dollars
--------------------
2002 2001
--------------------
DEFERRED TAX LIABILITIES
Properties, plants and equipment, and intangibles $10,147 4,750
Investment in joint ventures 1,013 522
Inventory 385 212
Other 144 74
--------------------------------------------------------------------------------
Total deferred tax liabilities 11,689 5,558
--------------------------------------------------------------------------------
DEFERRED TAX ASSETS
Benefit plan accruals 1,304 450
Accrued dismantlement, removal and environmental costs 724 452
Deferred state income tax 201 164
Other financial accruals and deferrals 311 182
Alternative minimum tax carryforwards 421 180
Operating loss and credit carryforwards 650 310
Other 394 107
--------------------------------------------------------------------------------
Total deferred tax assets 4,005 1,845
Less valuation allowance 608 263
--------------------------------------------------------------------------------
Net deferred tax assets 3,397 1,582
--------------------------------------------------------------------------------
Net deferred tax liabilities $ 8,292 3,976
================================================================================
Current assets, long-term assets, current liabilities and long-term liabilities
included deferred taxes of $68 million, $41 million, $40 million and $8,361
million, respectively, at December 31, 2002, and $47 million, $9 million, $17
million and $4,015 million, respectively, at December 31, 2001.
The company has operating loss and credit carryovers in multiple taxing
jurisdictions. These attributes generally expire between 2003 and 2009 with some
carryovers, including the alternative minimum tax, having indefinite
carryforward periods.
Valuation allowances have been established for certain operating loss and credit
carryforwards that reduce deferred tax assets to an amount that will, more
likely than not, be realized. Uncertainties that may affect the realization of
these assets include tax law changes and the future level of product prices and
costs. Based on the company's historical taxable income, its expectations for
the future, and available tax-planning strategies, management expects that the
net deferred tax assets will be realized as offsets to reversing deferred tax
liabilities and as offsets to the tax consequences of future taxable income.
The Conoco purchase price allocation for the merger resulted in net deferred tax
liabilities of $4,073 million. Included in this amount is a valuation allowance
for certain deferred tax assets of $251 million, for which subsequently
recognized tax benefits, if any, will be allocated to goodwill.
132
At December 31, 2002, and December 31, 2001, income considered to be permanently
reinvested in certain foreign subsidiaries and foreign corporate joint ventures
totaled approximately $569 million and $247 million, respectively. Deferred
income taxes have not been provided on this income, as the company does not plan
to initiate any action that would require the payment of income taxes. It is not
practicable to estimate the amount of additional tax that might be payable on
this foreign income if distributed.
The amounts of U.S. and foreign income from continuing operations before income
taxes, with a reconciliation of tax at the federal statutory rate with the
provision for income taxes, were:
Percent of
Millions of Dollars Pretax Income
----------------------------- ------------------------------
2002 2001 2000 2002 2001 2000
----------------------------- -------------------------------
Income from continuing operations before income taxes
United States $ 628 2,080 2,041 29.0% 63.9 54.4
Foreign 1,536 1,175 1,707 71.0 36.1 45.6
------------------------------------------------------------------------------------------------------------------------
$ 2,164 3,255 3,748 100.0% 100.0 100.0
========================================================================================================================
Federal statutory income tax $ 757 1,139 1,312 35.0% 35.0 35.0
Foreign taxes in excess of federal statutory rate 680 515 572 31.4 15.8 15.3
Domestic tax credits (77) (84) (53) (3.6) (2.6) (1.4)
Write-off of acquired in-process research and
development costs 86 -- -- 4.0 -- --
State income tax 14 76 74 .6 2.3 2.0
Other (10) (2) (5) (.4) -- (.2)
------------------------------------------------------------------------------------------------------------------------
$ 1,450 1,644 1,900 67.0% 50.5 50.7
========================================================================================================================
133
NOTE 22--OTHER COMPREHENSIVE INCOME (LOSS)
The components and allocated tax effects of other comprehensive income (loss)
follow:
Millions of Dollars
------------------------------------------
Tax Expense
Before-Tax (Benefit) After-Tax
-------------------------------------------
2002
Minimum pension liability adjustment $(149) (56) (93)
Unrealized loss on securities (3) -- (3)
Foreign currency translation adjustments 223 41 182
Hedging activities (1) -- (1)
Equity affiliates:
Foreign currency translation 40 -- 40
Derivatives related (34) -- (34)
---------------------------------------------------------------------------------------
Other comprehensive income $ 76 (15) 91
=======================================================================================
2001
Minimum pension liability adjustment $(220) (77) (143)
Unrealized loss on securities (3) (1) (2)
Foreign currency translation adjustments (14) -- (14)
Hedging activities (4) -- (4)
Equity affiliates:
Foreign currency translation (3) -- (3)
Derivatives related 17 6 11
---------------------------------------------------------------------------------------
Other comprehensive loss $(227) (72) (155)
=======================================================================================
2000
Unrealized loss on securities $ (2) (1) (1)
Foreign currency translation adjustments (53) -- (53)
Equity affiliates:
Foreign currency translation (15) -- (15)
---------------------------------------------------------------------------------------
Other comprehensive loss $ (70) (1) (69)
=======================================================================================
See Note 20--Employee Benefit Plans for more information on the minimum pension
liability adjustment.
Unrealized gains on securities relate to available-for-sale securities held by
irrevocable grantor trusts that fund certain of the company's domestic,
non-qualified supplemental key employee pension plans.
Deferred taxes have not been provided on temporary differences related to
foreign currency translation adjustments for investments in certain foreign
subsidiaries and foreign corporate joint ventures that are essentially permanent
in duration.
134
Accumulated other comprehensive loss in the equity section of the balance sheet
included:
Millions of Dollars
----------------------
2002 2001
----------------------
Minimum pension liability adjustment $(236) (143)
Foreign currency translation adjustments 98 (84)
Unrealized gain on securities 1 4
Deferred net hedging loss (5) (4)
Equity affiliates:
Foreign currency translation 1 (39)
Derivatives related (23) 11
----------------------------------------------------------------------------------------------------------------------------------
Accumulated other comprehensive loss $(164) (255)
==================================================================================================================================
NOTE 23--CASH FLOW INFORMATION
Millions of Dollars
----------------------------------
2002 2001 2000
----------------------------------
NON-CASH INVESTING AND FINANCING ACTIVITIES
The merger by issuance of stock $15,974 -- --
Acquisition of Tosco by issuance of stock -- 7,049 --
Note payable to purchase properties, plants and equipment -- 25 111
Investment in properties, plants and equipment of businesses through the assumption of
non-cash liabilities 181 125 472
Investment in equity affiliates through exchange of non-cash assets and liabilities* -- (15) 4,272
----------------------------------------------------------------------------------------------------------------------------------
CASH PAYMENTS
Interest $ 441 324 323
Income taxes 1,363 1,504 1,066
----------------------------------------------------------------------------------------------------------------------------------
*On March 31, 2000, ConocoPhillips combined its gas gathering, processing
and marketing business with the gas gathering, processing, marketing and
natural gas liquids business of Duke Energy into DEFS and on July 1, 2000,
ConocoPhillips and ChevronTexaco combined the two companies' worldwide
chemicals businesses into CPChem.
135
NOTE 24--OTHER FINANCIAL INFORMATION
Millions of Dollars
Except Per Share Amounts
------------------------------------
2002 2001 2000
------------------------------------
INTEREST
Incurred
Debt $ 740 524 511
Other 58 45 32
--------------------------------------------------------------------------------------------------------------
798 569 543
Capitalized (232) (231) (174)
--------------------------------------------------------------------------------------------------------------
Expensed $ 566 338 369
==============================================================================================================
RESEARCH AND DEVELOPMENT EXPENDITURES--expensed $ 355* 44 43
--------------------------------------------------------------------------------------------------------------
*Includes $246 million of in-process research and development expenses related to the merger
ADVERTISING EXPENSES* $ 37 56 43
--------------------------------------------------------------------------------------------------------------
*Deferred amounts at December 31 were immaterial in all three years
CASH DIVIDENDS paid per common share $ 1.48 1.40 1.36
--------------------------------------------------------------------------------------------------------------
FOREIGN CURRENCY TRANSACTION GAINS (LOSSES)--after-tax
E&P $ (34) 2 (10)
R&M 9 3 (3)
Chemicals -- -- (1)
Corporate and Other 21 (8) (25)
--------------------------------------------------------------------------------------------------------------
$ (4) (3) (39)
==============================================================================================================
NOTE 25--RELATED PARTY TRANSACTIONS
Significant transactions with related parties were:
Millions of Dollars
------------------------------------
2002 2001 2000
------------------------------------
Operating revenues (a) $ 1,554 935 1,573
Purchases (b) 1,545 1,110 1,347
Operating expenses and selling, general and
administrative expenses (c) 279 243 108
Net interest (income) expense (d) (6) 8 (3)
--------------------------------------------------------------------------------------------------------------
(a) ConocoPhillips' Exploration and Production (E&P) segment sells natural gas
to Duke Energy Field Services, LLC (DEFS) and crude oil to the Malaysian
Refining Company Sdn. Bhd (Melaka), among others, for processing and
marketing. Natural gas liquids, solvents and petrochemical feedstocks are
sold to Chevron Phillips Chemical Company LLC (CPChem) and refined
products are sold to CFJ Properties and GKG Mineraloelhandel GMbH & Co.
KG. Also, the company charges several of its affiliates including CPChem;
Merey Sweeny, L.P. (MSLP); Hamaca Holding LLC; and Venture
136
Coke Company for the use of common facilities, such as steam generators,
waste and water treaters, and warehouse facilities.
(b) ConocoPhillips purchases natural gas and natural gas liquids from DEFS and
CPChem for use in its refinery processes and other feedstocks from various
affiliates. ConocoPhillips purchases crude oil from Petrozuata C.A. and
refined products from Melaka and Ceska rafinerska, a.s. located in the
Czech Republic. Also, ConocoPhillips pays fees to various pipeline equity
companies for transporting finished refined products.
(c) ConocoPhillips pays processing fees to various affiliates, the most
significant being MSLP. Additionally, ConocoPhillips pays contract
drilling fees to two deepwater drillship affiliates. Fees are paid to
ConocoPhillips' pipeline equity companies for transporting crude oil.
Commissions are paid to the receivable monetization companies (see Note
13--Sales of Receivables for more information).
(d) ConocoPhillips pays and/or receives interest to/from various affiliates
including the receivable monetization companies and MSLP.
Elimination of the company's equity percentage share of profit or loss on the
above transactions was not material.
NOTE 26--SEGMENT DISCLOSURES AND RELATED INFORMATION
ConocoPhillips has organized its reporting structure based on the grouping of
similar products and services, resulting in five operating segments:
1) E&P--This segment explores for and produces crude oil, natural gas,
and natural gas liquids worldwide; and mines oil sands to extract
bitumen and upgrade it into synthetic crude oil. At December 31,
2002, E&P was producing in the United States; the Norwegian and U.K.
sectors of the North Sea; Canada; Nigeria; Venezuela; the Timor Sea;
offshore Australia and China; Indonesia; the United Arab Emirates;
Vietnam; Russia; and Ecuador. The E&P segment's U.S. and
international operations are disclosed separately for reporting
purposes.
2) Midstream--Through both consolidated and equity interests, this
segment gathers and processes natural gas produced by ConocoPhillips
and others, and fractionates and markets natural gas liquids,
primarily in the United States, Canada and Trinidad. The Midstream
segment includes ConocoPhillips' 30.3 percent equity investment in
DEFS.
3) R&M--This segment refines, markets and transports crude oil and
petroleum products, mostly in the United States, Europe and Asia. At
December 31, 2002, ConocoPhillips owned 12 refineries in the United
States (excluding two refineries treated as discontinued operations
and reported in Corporate and Other); one in the United Kingdom; one
in Ireland; and had equity interests in one refinery in Germany, two
in the Czech Republic, and one in Malaysia. The R&M segment's U.S.
and international operations are disclosed separately for reporting
purposes.
4) Chemicals--This segment manufactures and markets petrochemicals and
plastics on a worldwide basis. The Chemicals segment consists
primarily of ConocoPhillips' 50 percent equity investment in CPChem.
137
5) Emerging Businesses--This segment encompasses the development of new
businesses beyond the company's traditional operations. Emerging
Businesses includes new technologies related to carbon fibers,
natural gas conversion into clean fuels and related products
(gas-to-liquids), fuels technology, and power generation.
Corporate and Other includes general corporate overhead; all interest income and
expense; preferred dividend requirements of capital trusts; discontinued
operations; restructuring charges; goodwill resulting from the merger of Conoco
and Phillips that has not yet been allocated to the operating segments; certain
eliminations; and various other corporate activities. Corporate assets include
all cash and cash equivalents.
The company evaluates performance and allocates resources based on, among other
items, net income. Segment accounting policies are the same as those in Note
1--Accounting Policies. Intersegment sales are at prices that approximate
market.
138
ANALYSIS OF RESULTS BY OPERATING SEGMENT
Millions of Dollars
---------------------------------------
2002 2001 2000
---------------------------------------
SALES AND OTHER OPERATING REVENUES
E&P
United States $ 7,222 5,879 5,346
International 4,850 2,266 2,919
Intersegment eliminations-U.S (1,304) (534) (433)
Intersegment eliminations-international (484) -- (221)
---------------------------------------------------------------------------------------------------------------
E&P 10,284 7,611 7,611
---------------------------------------------------------------------------------------------------------------
Midstream
Total sales 2,049 1,193 1,819
Intersegment eliminations (510) (416) (665)
---------------------------------------------------------------------------------------------------------------
Midstream 1,539 777 1,154
---------------------------------------------------------------------------------------------------------------
R&M
United States 41,011 16,445 11,570
International 5,630 142 532
Intersegment eliminations-U.S (1,773) (92) (361)
Intersegment eliminations-international -- -- --
---------------------------------------------------------------------------------------------------------------
R&M 44,868 16,495 11,741
---------------------------------------------------------------------------------------------------------------
Chemicals
Total sales 13 -- 1,794
Intersegment eliminations -- -- (147)
---------------------------------------------------------------------------------------------------------------
Chemicals 13 -- 1,647
---------------------------------------------------------------------------------------------------------------
Emerging Businesses 36 7 --
Corporate and Other 8 2 2
---------------------------------------------------------------------------------------------------------------
Consolidated sales and other operating revenues $ 56,748 24,892 22,155
===============================================================================================================
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENTS
E&P
United States $ 999 817 552
International 735 324 487
---------------------------------------------------------------------------------------------------------------
Total E&P 1,734 1,141 1,039
---------------------------------------------------------------------------------------------------------------
Midstream 19 1 24
---------------------------------------------------------------------------------------------------------------
R&M
United States 564 203 139
International 50 1 --
---------------------------------------------------------------------------------------------------------------
Total R&M 614 204 139
---------------------------------------------------------------------------------------------------------------
Chemicals -- -- 54
Emerging Businesses 4 -- --
Corporate and Other 29 24 13
---------------------------------------------------------------------------------------------------------------
Consolidated depreciation, depletion, amortization and impairments $ 2,400 1,370 1,269
===============================================================================================================
139
Millions of Dollars
---------------------------------------
2002 2001 2000
---------------------------------------
EQUITY IN EARNINGS OF AFFILIATES
E&P
United States $ 29 9 15
International 162 19 16
---------------------------------------------------------------------------------------------------------------
Total E&P 191 28 31
---------------------------------------------------------------------------------------------------------------
Midstream 46 165 137
---------------------------------------------------------------------------------------------------------------
R&M
United States 43 88 28
International -- -- 8
---------------------------------------------------------------------------------------------------------------
Total R&M 43 88 36
---------------------------------------------------------------------------------------------------------------
Chemicals (16) (240) (90)
Emerging Businesses (3) -- --
Corporate and Other -- -- --
---------------------------------------------------------------------------------------------------------------
Consolidated equity in earnings of affiliates $ 261 41 114
===============================================================================================================
INCOME TAXES
E&P
United States $ 473 670 744
International 1,337 913 1,050
---------------------------------------------------------------------------------------------------------------
Total E&P 1,810 1,583 1,794
---------------------------------------------------------------------------------------------------------------
Midstream 42 73 91
---------------------------------------------------------------------------------------------------------------
R&M
United States 90 210 115
International (11) -- 10
---------------------------------------------------------------------------------------------------------------
Total R&M 79 210 125
---------------------------------------------------------------------------------------------------------------
Chemicals (18) (89) 21
Emerging Businesses (38) (7) --
Corporate and Other (425) (126) (131)
---------------------------------------------------------------------------------------------------------------
Consolidated income taxes $ 1,450 1,644 1,900
===============================================================================================================
NET INCOME (LOSS)
E&P
United States $ 1,156 1,342 1,388
International 593 357 557
---------------------------------------------------------------------------------------------------------------
Total E&P 1,749 1,699 1,945
---------------------------------------------------------------------------------------------------------------
Midstream 55 120 162
---------------------------------------------------------------------------------------------------------------
R&M
United States 138 395 209
International 5 2 29
---------------------------------------------------------------------------------------------------------------
Total R&M 143 397 238
---------------------------------------------------------------------------------------------------------------
Chemicals (14) (128) (46)
Emerging Businesses (310)* (12) --
Corporate and Other (1,918) (415) (437)
---------------------------------------------------------------------------------------------------------------
Consolidated net income (loss) $ (295) 1,661 1,862
===============================================================================================================
*Includes a non-cash $246 million write-off of acquired in-process research and development costs.
140
Millions of Dollars
---------------------------------------
2002 2001 2000
---------------------------------------
INVESTMENTS IN AND ADVANCES TO AFFILIATES
E&P
United States $ 156 13 5
International 2,184 573 342
---------------------------------------------------------------------------------------------------------------
Total E&P 2,340 586 347
---------------------------------------------------------------------------------------------------------------
Midstream 318 166 43
---------------------------------------------------------------------------------------------------------------
R&M
United States 762 166 147
International 416 -- --
---------------------------------------------------------------------------------------------------------------
Total R&M 1,178 166 147
---------------------------------------------------------------------------------------------------------------
Chemicals 2,050 1,852 2,046
Emerging Businesses -- -- --
Corporate and Other 14 18 29
---------------------------------------------------------------------------------------------------------------
Consolidated investments in and advances to affiliates $ 5,900 2,788 2,612
===============================================================================================================
TOTAL ASSETS
E&P
United States $ 14,196 9,501 9,296
International 19,541 5,295 4,538
---------------------------------------------------------------------------------------------------------------
Total E&P 33,737 14,796 13,834
---------------------------------------------------------------------------------------------------------------
Midstream 1,931 196 145
---------------------------------------------------------------------------------------------------------------
R&M
United States 19,553 14,553 3,112
International 3,632 183 68
---------------------------------------------------------------------------------------------------------------
Total R&M 23,185 14,736 3,180
---------------------------------------------------------------------------------------------------------------
Chemicals 2,095 1,934 2,170
Emerging Businesses 737 2 --
Corporate and Other 15,151 3,553 1,180
---------------------------------------------------------------------------------------------------------------
Consolidated total assets $ 76,836 35,217 20,509
===============================================================================================================
CAPITAL EXPENDITURES AND INVESTMENTS*
E&P
United States $ 1,205 1,354 951
International 2,071 1,162 726
---------------------------------------------------------------------------------------------------------------
Total E&P 3,276 2,516 1,677
---------------------------------------------------------------------------------------------------------------
Midstream 5 -- 17
---------------------------------------------------------------------------------------------------------------
R&M
United States 676 423 217
International 164 5 --
---------------------------------------------------------------------------------------------------------------
Total R&M 840 428 217
---------------------------------------------------------------------------------------------------------------
Chemicals 60 6 67
Emerging Businesses 122 -- --
Corporate and Other 85 66 39
---------------------------------------------------------------------------------------------------------------
Consolidated capital expenditures and investments $ 4,388 3,016 2,017
===============================================================================================================
*Including dry hole costs.
141
Additional information on items included in Corporate and Other (on a before-tax
basis unless otherwise noted):
Millions of Dollars
---------------------------------------
2002 2001 2000
---------------------------------------
Interest income $ 40 13 28
Interest expense 566 338 369
Extraordinary losses, after-tax 16 10 --
Significant non-cash items
Impairments included in discontinued operations 1,048 -- --
Loss accruals related to retail site leases included in
discontinued operations 477 -- --
Restructuring charges, net of benefits paid 269 -- --
--------------------------------------------------------------------------------------------------------------------------
GEOGRAPHIC INFORMATION
Millions of Dollars
---------------------------------------------------------------------------------------
Other
United United Foreign Worldwide
States Norway Kingdom Canada Countries Consolidated
---------------------------------------------------------------------------------------
2002
Sales and Other Operating
Revenues* $46,674 1,850 3,387 997 3,840 56,748
--------------------------------------------------------------------------------------------------------------------------
Long-Lived Assets** $28,492 3,767 4,969 3,460 8,242 48,930
--------------------------------------------------------------------------------------------------------------------------
2001
Sales and Other Operating
Revenues* $22,466 1,322 380 42 682 24,892
--------------------------------------------------------------------------------------------------------------------------
Long-Lived Assets** $19,955 1,484 654 29 2,799 24,921
--------------------------------------------------------------------------------------------------------------------------
2000
Sales and Other Operating
Revenues* $18,700 231 2,183 175 866 22,155
--------------------------------------------------------------------------------------------------------------------------
Long-Lived Assets** $13,198 1,487 709 30 1,831 17,255
--------------------------------------------------------------------------------------------------------------------------
*Sales and other operating revenues are attributable to countries based on
the location of the operations generating the revenues.
**Defined as net properties, plants and equipment plus investments in and
advances to affiliates.
142
NOTE 27--NEW ACCOUNTING STANDARDS
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 was adopted by the company on January 1, 2003, and
requires major changes in the accounting for asset retirement obligations, such
as required decommissioning of oil and gas production platforms, facilities and
pipelines. SFAS No. 143 requires entities to record the fair value of a
liability for an asset retirement obligation in the period when it is incurred
(typically when the asset is installed at the production location). When the
liability is initially recorded, the entity capitalizes the cost by increasing
the carrying amount of the related property, plant and equipment. Over time, the
liability is accreted for the change in its present value each period, and the
initial capitalized cost is depreciated over the useful life of the related
asset. Upon adoption of SFAS No. 143, the company adjusted its recorded asset
retirement obligations to the new requirements using a cumulative-effect
approach as required. All transition amounts were measured using the company's
current information, assumptions, and credit-adjusted, risk-free interest rates.
While the original discount rates used to establish an asset retirement
obligation will not change in the future, changes in cost estimates or the
timing of expenditures will result in immediate adjustments to the recorded
liability, with an offsetting adjustment to properties, plants and equipment.
Application of the new rules, effective January 1, 2003, should result in an
increase in net properties, plants and equipment of approximately $1.2 billion,
an asset retirement obligation liability increase of approximately $1.1 billion,
and a cumulative after-tax effect of adoption gain that is expected to increase
net income and stockholders' equity by approximately $137 million. The estimated
after-tax impact on income before extraordinary items and cumulative effect of
changes in accounting principle for the year 2003 is an improvement of $33
million. The majority of the liability and asset increase is attributable to
assets acquired in the merger and production facilities in Alaska. Following
prevalent oil and gas industry practice for acquisitions completed prior to
January 1, 2003, ConocoPhillips did not record an initial liability for the
estimated cost of removing properties, plants and equipment at the end of their
useful lives. Instead, estimated removal costs were accrued on a
unit-of-production basis as an additional component of depreciation, building
the removal cost liability over the remaining useful lives of the properties,
plants and equipment. However, upon adoption of SFAS No. 143, these asset
retirement obligations are required to be recorded, significantly increasing
asset retirement liabilities on the balance sheet with an offsetting increase to
properties, plants and equipment.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities," (VIEs) in an effort to expand upon and strengthen
existing accounting guidance that addresses when a company should include in its
financial statements the assets, liabilities and activities of another entity.
In general, a VIE is a corporation, partnership, trust, or any other legal
structure used for business purposes that either (a) does not have equity
investors with voting rights or (b) has equity investors that do not provide
sufficient financial resources for the entity to support its activities.
Interpretation No. 46 requires a VIE to be consolidated by a company if that
company is subject to a majority of the risk of loss from the VIE's activities,
is entitled to receive a majority of the VIE's residual returns, or both. The
interpretation also requires disclosures about VIEs that the company is not
required to consolidate, but in which it has a significant variable interest.
The consolidation requirements of Interpretation No. 46 applied immediately to
variable interest entities created after January 31, 2003, and to older entities
no later than the third quarter of 2003. The company is studying the impact of
the interpretation on existing variable interest entities with which the company
is involved. Certain of the disclosure requirements are required in all
financial statements issued after January 31, 2003, regardless of when the
variable interest entity was established. These are included in Note
28--Variable Interest Entities.
143
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities," which addresses financial accounting and
reporting for costs associated with exit or disposal activities initiated after
December 31, 2002, and 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)." SFAS No. 146 requires that a liability for a cost associated
with an exit or disposal activity be recognized and measured initially at fair
value at the date the liability is incurred, rather than at the commitment date.
The company plans to apply the provisions of SFAS No. 146 prospectively for
restructuring activities initiated in 2003 and future years. However, for
restructuring activities initiated in 2002 the company will continue to apply
EITF Issue Nos. 94-3 and 95-3 until those identified restructuring activities
are completed. See Note 4--Discontinued Operations and Note 5--Restructuring for
more information.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others." For specified guarantees issued or modified after
December 31, 2002, the interpretation requires a guarantor to recognize, at the
inception of the guarantee, a liability for the fair value of all the
obligations it has undertaken in issuing the guarantee, including its ongoing
obligation to stand ready and make cash payments over the term of the guarantee
in the event that specified triggering events or conditions occur. The
measurement of the liability for the fair value of the guarantee obligation
should be based on the premium that would be required to issue the same
guarantee in a stand-alone arm's-length transaction with an unrelated party if
that information is available, or estimated using expected present value
measurement techniques. For specified guarantees existing as of December 31,
2002, the interpretation also requires a guarantor to disclose (a) the nature of
the guarantee, including how the guarantee arose and the events or circumstances
that would require the guarantor to perform under the guarantee; (b) the maximum
potential amount of future payments under the guarantee; (c) the carrying amount
of the liability; and (d) the nature and extent of any recourse provisions or
available collateral that would enable the guarantor to recover the amounts paid
under the guarantee. The required disclosures are included in Note
14--Guarantees.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections."
The rescission of SFAS No. 4 will require that gains and losses on
extinguishments of debt no longer be presented as extraordinary items in the
income statement, commencing in 2003. All prior periods will be restated to
reflect this change in presentation. See Note 2--Extraordinary Items and
Accounting Change.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure," an amendment of SFAS No. 123,
"Accounting for Stock-Based Compensation," to provide alternative methods of
transition for a voluntary change to the fair value method of accounting for
stock-based employee compensation. ConocoPhillips adopted the fair-value method
recommended by SFAS No. 123 on January 1, 2003, and is using the prospective
transition method. See Note 20--Employee Benefit Plans for more information on
this accounting change.
In 2003, the FASB is expected to issue SFAS No. 149, "Accounting for Certain
Financial Instruments with Characteristics of Liabilities and Equity," to
address the balance sheet classification of certain financial instruments that
have characteristics of both liabilities and equity. SFAS No. 149 is expected to
provide that mandatorily redeemable instruments meet the conceptual definition
of liabilities and must be presented as such on the balance sheet. The statement
is expected to be effective upon issuance for all contracts created or modified
after the issuance date and is otherwise effective on all previously existing
contracts no later than the third quarter of 2003. ConocoPhillips is currently
evaluating the impact of proposed SFAS No. 149, and it is likely that some or
all of currently reported mandatorily redeemable preferred stock and minority
interest securities will be reclassified as liabilities. See Note 17--Preferred
Stock and Other Minority Interests for more information.
144
NOTE 28--VARIABLE INTEREST ENTITIES
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities," which provides guidance related to identifying
variable interest entities and determining whether such entities should be
consolidated. See Note 27--New Accounting Standards for further explanation of
this new accounting standard.
As required, the company will immediately apply this interpretation to variable
interest entities created, or interests in variable interest entities obtained,
after January 31, 2003. For variable interest entities created before February
1, 2003, the company will initially apply the guidance in this interpretation in
the third quarter of 2003. At that time, if the company is determined to be the
primary beneficiary of a variable interest entity created before February 1,
2003, the company will consolidate that entity. This interpretation excludes the
QSPE's discussed in Note 13--Sales of Receivables.
The company is still evaluating the impact of this very recent, complex
interpretation on existing potential variable interest entities in which the
company is involved. Based on a preliminary review, when the company initially
applies the guidance of this interpretation in July 2003, it is reasonably
possible that the company will be required to begin consolidating entities in
the following areas:
o The company leases ocean transport vessels, drillships, corporate
aircraft, service stations, office buildings, and certain refining
equipment from special purpose entities (SPEs) that are third-party
trusts established by a trustee and principally funded by financial
institutions. If the company is required to consolidate all of these
entities, the assets of the entities and debt of approximately $2.4
billion would be required to be included in the consolidated
financial statements. The company's maximum exposure to loss as a
result of its involvement with the entities would be the debt of the
entity, less the fair value of the assets at the end of the lease
terms. Of the $2.4 billion debt that would be consolidated,
approximately $1.5 billion is associated with a major portion of the
company's owned retail stores that the company has announced it
plans to sell. As a result of the planned divestiture, the company
plans to exercise purchase option provisions during 2003 and
terminate various operating leases involving approximately 900 store
sites and two office buildings. In addition, see Note
4--Discontinued Operations for details regarding the provisions
recorded for losses and penalties in the fourth quarter of 2002 for
the planned divestiture. Depending upon the timing of the company's
exercise of these purchase options, and the determination of whether
or not the lessor entities in these operating leases are variable
interest entities requiring consolidation in 2003, some or all of
these lessor entities could become consolidated subsidiaries of the
company prior to the exercise of the purchase options and
termination of the leases. See Note 14--Guarantees and Note
19--Non-Mineral Leases.
o In December 2001, in order to raise funds for general corporate
purposes, Conoco and Cold Spring Finance S.a.r.l. formed Ashford
Energy Capital S.A. through the contribution of cash and a Conoco
subsidiary promissory note. Through its $504 million investment,
Cold Spring is entitled to a cumulative annual preferred return,
based on three-month LIBOR rates plus 1.27 percent. The preferred
return at December 31, 2002, was 2.70 percent. The company already
consolidates Ashford and reports Cold Spring's investment as a
minority interest. If it is determined that Cold Spring is a
variable interest entity, the company may have to consolidate Cold
Spring under Interpretation No. 46. If that were to occur, Cold
Spring's financing of approximately $500 million at December 31,
2002, could be reported as debt of ConocoPhillips.
145
--------------------------------------------------------------------------------
OIL AND GAS OPERATIONS (Unaudited)
Exploration and Production
In accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities," and regulations of the U.S. Securities and Exchange Commission, the
company is making certain supplemental disclosures about its oil and gas
exploration and production operations. While this information was developed with
reasonable care and disclosed in good faith, it is emphasized that some of the
data is necessarily imprecise and represents only approximate amounts because of
the subjective judgments involved in developing such information. Accordingly,
this information may not necessarily represent the current financial condition
of the company or its expected future results.
ConocoPhillips' disclosures by geographic areas include the United States
(U.S.), Norway, the United Kingdom (U.K.), Canada and Other Areas. Other Areas
include Nigeria, China, Australia, the Timor Sea, Indonesia, Vietnam, United
Arab Emirates, Ecuador and other countries. When the company uses equity
accounting for operations that have proved reserves, these oil and gas
operations are shown separately and designated as Equity Affiliates. In 2002,
these consisted of two heavy-oil projects in Venezuela, an oil development
project in northern Russia and a heavy-oil project in Canada. In 2001 and 2000
this consisted of a heavy-oil project in Venezuela.
Amounts in 2000 were impacted by ConocoPhillips' purchase of all of Atlantic
Richfield Company's (ARCO) Alaska businesses in late April 2000. Amounts in 2002
were impacted by the merger of Conoco and Phillips (the merger) in late August
2002.
CONTENTS--OIL AND GAS OPERATIONS PAGE
--------------------------------------------------------------------------------
Proved Reserves Worldwide 147
Results of Operations 153
Statistics 155
Costs Incurred 159
Capitalized Costs 160
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserve Quantities 161
146
o PROVED RESERVES WORLDWIDE
Years Ended CRUDE OIL
December 31 -----------------------------------------------------------------------------------------------------
Millions of Barrels
-----------------------------------------------------------------------------------------------------
Consolidated Operations
------------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total
-----------------------------------------------------------------------------------------------------
DEVELOPED AND UNDEVELOPED
End of 1999 33 109 142 521 57 12 232 964 -- 964
Revisions 9 12 21 73 3 (2) 1 96 -- 96
Improved recovery 31 -- 31 5 -- -- -- 36 -- 36
Purchases 1,594 1 1,595 -- -- -- -- 1,595 -- 1,595
Extensions and discoveries 12 3 15 -- -- 6 34 55 613 668
Production (75) (12) (87) (41) (9) (2) (19) (158) -- (158)
Sales -- (1) (1) -- -- (12) -- (13) -- (13)
----------------------------------------------------------------------------------------------------------------------------------
End of 2000 1,604 112 1,716 558 51 2 248 2,575 613 3,188
Revisions 77 (2) 75 51 (6) -- 4 124 48 172
Improved recovery 67 1 68 12 -- -- -- 80 -- 80
Purchases -- -- -- -- -- -- 17 17 -- 17
Extensions and discoveries 9 6 15 -- 2 -- 12 29 -- 29
Production (126) (12) (138) (43) (6) -- (19) (206) (1) (207)
Sales -- -- -- -- -- -- (3) (3) -- (3)
----------------------------------------------------------------------------------------------------------------------------------
End of 2001 1,631 105 1,736 578 41 2 259* 2,616 660 3,276
Revisions 32 (8) 24 (26) (5) 5 (32) (34) (27) (61)
Improved recovery 46 1 47 5 2 -- -- 54 -- 54
Purchases -- 132 132 262 143 101 223 861 733 1,594
Extensions and discoveries 14 6 20 3 3 1 22 49 4 53
Production (120) (14) (134) (58) (14) (5) (24) (235) (13) (248)
Sales -- (2) (2) (13) (7) (13) (1) (36) -- (36)
----------------------------------------------------------------------------------------------------------------------------------
END OF 2002 1,603 220 1,823 751 163 91 447** 3,275 1,357 4,632
==================================================================================================================================
DEVELOPED
End of 1999 25 93 118 433 37 10 114 712 -- 712
End of 2000 1,207 98 1,305 478 25 2 116 1,926 -- 1,926
End of 2001 1,275 91 1,366 513 21 2 96 1,998 47 2,045
END OF 2002 1,335 169 1,504 611 102 81 223 2,521 378 2,899
----------------------------------------------------------------------------------------------------------------------------------
*Includes proved reserves of 17 million barrels attributable to a
consolidated subsidiary in which there is a 13 percent minority interest.
**Includes proved reserves of 14 million barrels attributable to a
consolidated subsidiary in which there is a 10 percent minority interest.
147
o Purchases in 2002 were primarily related to the merger. Other Areas in
2002 includes 1 million barrels related to an operation that was
classified as discontinued following the merger, and was sold by year-end.
The amount for this operation was not included in the schedule of sources
of change in discounted future net cash flows, or as a part of the
company's per-unit finding and development cost calculation.
o At the end of 2000 and 1999, Other Areas included 2 million and 14 million
barrels, respectively, of reserves in Venezuela in which the company had
an economic interest through risk-service contracts. These properties were
sold in June 2001. Net production to the company was approximately 400,000
barrels in 2001; 1,200,000 barrels in 2000; and 600,000 barrels in 1999.
o In addition to conventional crude oil, natural gas and natural gas liquids
(NGL) proved reserves, ConocoPhillips has proven oil sands reserves in
Canada, associated with a Syncrude project totaling 272 million barrels at
the end of 2002. For internal management purposes, ConocoPhillips views
these reserves and their development as part of its total exploration and
production operations. However, U.S. Securities and Exchange Commission
regulations define these reserves as mining related. Therefore, they are
not included in the company's tabular presentation of proved crude oil,
natural gas and NGL reserves. These oil sand reserves are also not
included in the standardized measure of discounted future net cash flows
relating to proved oil and gas reserve quantities.
148
Years Ended NATURAL GAS
December 31 -----------------------------------------------------------------------------------------------------
Billions of Cubic Feet
-----------------------------------------------------------------------------------------------------
Consolidated Operations
------------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total
-----------------------------------------------------------------------------------------------------
DEVELOPED AND UNDEVELOPED
End of 1999 798 2,554 3,352 1,176 681 521 634 6,364 -- 6,364
Revisions 87 183 270 (162) 10 (200) 1 (81) -- (81)
Improved recovery -- -- -- 52 -- -- -- 52 -- 52
Purchases 2,448 193 2,641 -- -- -- -- 2,641 -- 2,641
Extensions and discoveries 7 211 218 -- -- 22 4 244 131 375
Production (103) (283) (386) (54) (79) (33) (14) (566) -- (566)
Sales -- (5) (5) -- -- (246) -- (251) -- (251)
----------------------------------------------------------------------------------------------------------------------------------
End of 2000 3,237 2,853 6,090 1,012 612 64 625 8,403 131 8,534
Revisions 60 9 69 (65) (59) (2) 64 7 14 21
Improved recovery -- -- -- 13 -- -- -- 13 -- 13
Purchases -- 12 12 -- 10 -- 10 32 -- 32
Extensions and discoveries 5 405 410 -- 23 -- 374 807 -- 807
Production (141) (261) (402) (53) (68) (7) (40) (570) -- (570)
Sales -- -- -- -- (8) -- -- (8) -- (8)
----------------------------------------------------------------------------------------------------------------------------------
End of 2001 3,161 3,018 6,179 907 510 55 1,033* 8,684 145 8,829
Revisions (27) (70) (97) 4 (24) 16 (75) (176) -- (176)
Improved recovery 5 1 6 13 1 -- -- 20 -- 20
Purchases -- 1,862 1,862 1,003 1,580 1,241 2,062 7,748 17 7,765
Extensions and discoveries 2 225 227 -- 43 21 420 711 1 712
Production (147) (340) (487) (68) (158) (59) (68) (840) (2) (842)
Sales (5) (1) (6) (1) (3) (97) (161) (268) -- (268)
----------------------------------------------------------------------------------------------------------------------------------
END OF 2002 2,989 4,695 7,684 1,858 1,949 1,177 3,211** 15,879 161 16,040
==================================================================================================================================
DEVELOPED
End of 1999 630 2,317 2,947 856 413 131 349 4,696 -- 4,696
End of 2000 2,969 2,564 5,533 738 321 54 336 6,982 -- 6,982
End of 2001 2,969 2,684 5,653 788 265 45 736 7,487 3 7,490
END OF 2002 2,806 4,302 7,108 1,544 1,734 1,098 1,349 12,833 28 12,861
----------------------------------------------------------------------------------------------------------------------------------
*Includes proved reserves of 10 billion cubic feet attributable to a
consolidated subsidiary in which there is a 13 percent minority interest.
**Includes proved reserves of 10 billion cubic feet attributable to a
consolidated subsidiary in which there is a 10 percent minority interest.
149
o Natural gas production may differ from gas production (delivered for sale)
in the company's statistics disclosure, primarily because the quantities
above include gas consumed at the lease, but omit the gas equivalent of
liquids extracted at any ConocoPhillips-owned, equity-affiliate, or
third-party processing plant or facility.
o Purchases in 2002 were related to the merger. Other Areas in 2002 includes
161 billion cubic feet related to an operation that was classified as
discontinued following the merger, and was sold by year-end. The amount
for this operation was not included in the schedule of sources of change
in discounted future net cash flows, or as a part of the company's
per-unit finding and development cost calculation.
o Extensions and discoveries in Other Areas in 2002 were primarily in
Nigeria.
o Sales in Other Areas in 2002 were for a discontinued operation. See note
on purchases above.
o Natural gas reserves are computed at 14.65 pounds per square inch absolute
and 60 degrees Fahrenheit.
150
Years Ended NATURAL GAS LIQUIDS
December 31 -----------------------------------------------------------------------------------------------------
Millions of Barrels
-----------------------------------------------------------------------------------------------------
Consolidated Operations
------------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total
-----------------------------------------------------------------------------------------------------
DEVELOPED AND UNDEVELOPED
End of 1999 1 91 92 29 4 4 78 207 -- 207
Revisions 57 11 68 7 -- (2) 2 75 -- 75
Purchases 147 -- 147 -- -- -- -- 147 -- 147
Extensions and discoveries -- 2 2 -- -- -- -- 2 -- 2
Production (7) (8) (15) (2) (1) -- (1) (19) -- (19)
Sales -- -- -- -- -- (2) (1) (3) -- (3)
----------------------------------------------------------------------------------------------------------------------------------
End of 2000 198 96 294 34 3 -- 78 409 -- 409
Revisions (25) 2 (23) -- -- -- 4 (19) -- (19)
Improved recovery -- -- -- 1 -- -- -- 1 -- 1
Purchases -- -- -- -- -- -- 10 10 -- 10
Extensions and discoveries -- 2 2 -- -- -- -- 2 -- 2
Production (9) (7) (16) (2) -- -- (1) (19) -- (19)
----------------------------------------------------------------------------------------------------------------------------------
End of 2001 164 93 257 33 3 -- 91* 384 -- 384
Revisions (4) 5 1 (3) 2 -- (11) (11) -- (11)
Improved recovery -- 1 1 -- -- -- -- 1 -- 1
Purchases -- 80 80 12 2 38 21 153 -- 153
Extensions and discoveries -- 4 4 -- -- 1 -- 5 -- 5
Production (9) (9) (18) (2) (1) (2) (1) (24) -- (24)
Sales -- -- -- -- -- (2) (1) (3) -- (3)
----------------------------------------------------------------------------------------------------------------------------------
END OF 2002 151 174 325 40 6 35 99** 505 -- 505
==================================================================================================================================
DEVELOPED
End of 1999 1 89 90 22 3 1 17 133 -- 133
End of 2000 197 94 291 27 2 1 17 338 -- 338
End of 2001 163 92 255 29 2 -- 16 302 -- 302
END OF 2002 151 166 317 34 6 30 15 402 -- 402
----------------------------------------------------------------------------------------------------------------------------------
*Includes proved reserves of 10 million barrels attributable to a
consolidated subsidiary in which there is a 13 percent minority interest.
**Includes proved reserves of 9 million barrels attributable to a
consolidated subsidiary in which there is a 10 percent minority interest.
151
o Natural gas liquids reserves include estimates of natural gas liquids to
be extracted from ConocoPhillips' leasehold gas at gas processing plants
or facilities. Estimates are based at the wellhead and assume full
extraction. Production above differs from natural gas liquids production
per day delivered for sale primarily due to:
(1) Natural gas consumed at the lease.
(2) Natural gas liquids production delivered for sale includes only
natural gas liquids extracted from ConocoPhillips' leasehold gas and
sold by ConocoPhillips' Exploration and Production (E&P) segment,
whereas the production above also includes natural gas liquids
extracted from ConocoPhillips' leasehold gas at equity-affiliate or
third-party facilities.
o Purchases in 2002 were related to the merger.
152
o RESULTS OF OPERATIONS
Years Ended Millions of Dollars
December 31 ----------------------------------------------------------------------------------------------------
Consolidated Operations
-----------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total
-----------------------------------------------------------------------------------------------------
2002
Sales $ 2,997 927 3,924 400 794 125 747 5,990 180 6,170
Transfers 102 401 503 1,285 30 235 -- 2,053 62 2,115
Other revenues (2) 3 1 35 28 7 21 92 12 104
-----------------------------------------------------------------------------------------------------------------------------------
Total revenues 3,097 1,331 4,428 1,720 852 367 768 8,135 254 8,389
Production costs 769 444 1,213 209 134 118 190 1,864 57 1,921
Exploration expenses 101 108 209 33 34 32 276* 584 -- 584
Depreciation, depletion and
amortization 552 334 886 206 274 105 85 1,556 30 1,586
Property impairments 4 8 12 -- 41 -- -- 53 -- 53
Transportation costs 681 87 768 75 50 -- 15 908 8 916
Other related expenses 23 16 39 60 15 14 12 140 12 152
-----------------------------------------------------------------------------------------------------------------------------------
967 334 1,301 1,137 304 98 190 3,030 147 3,177
Provision for income taxes 294 66 360 857 124 49 275 1,665 (18) 1,647
-----------------------------------------------------------------------------------------------------------------------------------
Results of operations for
producing activities 673 268 941 280 180 49 (85) 1,365 165 1,530
Other earnings 197 18 215 20 (10) 24** (6) 243 (24) 219
-----------------------------------------------------------------------------------------------------------------------------------
E&P net income (loss) $ 870 286 1,156 300 170 73 (91) 1,608 141 1,749
===================================================================================================================================
2001
Sales $ 3,020 1,178 4,198 175 371 31 478 5,253 8 5,261
Transfers 119 119 238 1,039 -- -- -- 1,277 -- 1,277
Other revenues 34 26 60 13 10 5 (4) 84 1 85
-----------------------------------------------------------------------------------------------------------------------------------
Total revenues 3,173 1,323 4,496 1,227 381 36 474 6,614 9 6,623
Production costs 784 328 1,112 124 41 6 92 1,375 2 1,377
Exploration expenses 61 69 130 20 11 -- 154 315 -- 315
Depreciation, depletion and
amortization 531 203 734 115 118 4 49 1,020 2 1,022
Property impairments -- -- -- -- -- -- 23 23 -- 23
Transportation costs 726 77 803 27 33 3 6 872 -- 872
Other related expenses 2 5 7 -- (8) 1 28 28 2 30
-----------------------------------------------------------------------------------------------------------------------------------
1,069 641 1,710 941 186 22 122 2,981 3 2,984
Provision for income taxes 392 173 565 729 50 7 139 1,490 -- 1,490
-----------------------------------------------------------------------------------------------------------------------------------
Results of operations for
producing activities 677 468 1,145 212 136 15 (17) 1,491 3 1,494
Other earnings 189 8 197 17 -- -- (9) 205 -- 205
-----------------------------------------------------------------------------------------------------------------------------------
E&P net income (loss) $ 866 476 1,342 229 136 15 (26) 1,696 3 1,699
===================================================================================================================================
2000
Sales $ 2,252 1,102 3,354 139 481 169 556 4,699 -- 4,699
Transfers 74 275 349 1,186 -- -- -- 1,535 -- 1,535
Other revenues 9 25 34 5 (1) 140 (2) 176 -- 176
-----------------------------------------------------------------------------------------------------------------------------------
Total revenues 2,335 1,402 3,737 1,330 480 309 554 6,410 -- 6,410
Production costs 494 308 802 118 42 35 100 1,097 -- 1,097
Exploration expenses 38 73 111 14 36 5 138 304 -- 304
Depreciation, depletion and
amortization 305 190 495 106 138 68 65 872 -- 872
Property impairments -- 13 13 -- -- -- 87 100 -- 100
Transportation costs 364 101 465 27 39 9 5 545 -- 545
Other related expenses (9) 4 (5) 21 (2) 4 32 50 -- 50
-----------------------------------------------------------------------------------------------------------------------------------
1,143 713 1,856 1,044 227 188 127 3,442 -- 3,442
Provision for income taxes 443 207 650 817 69 13 153 1,702 -- 1,702
-----------------------------------------------------------------------------------------------------------------------------------
Results of operations for
producing activities 700 506 1,206 227 158 175 (26) 1,740 -- 1,740
Other earnings 129 53 182 16 (1) -- 8 205 -- 205
-----------------------------------------------------------------------------------------------------------------------------------
E&P net income (loss) $ 829 559 1,388 243 157 175 (18) 1,945 -- 1,945
===================================================================================================================================
*Includes a $77 million leasehold impairment charge for an investment in
Angola.
**Includes $27 million for a Syncrude oil project in Canada that is defined
as a mining operation by U.S. Securities and Exchange Commission
regulations.
153
o Results of operations for producing activities consist of all the
activities within the E&P organization, except for pipeline and marine
operations, a liquefied natural gas operation, Syncrude operations, and
crude oil and gas marketing activities, which are included in Other
earnings. Also excluded are non-E&P activities, including ConocoPhillips'
Midstream segment, downstream petroleum and chemical activities, as well
as general corporate administrative expenses and interest.
o Transfers are valued at prices that approximate market.
o Other revenues include gains and losses from asset sales, certain amounts
resulting from the purchase and sale of hydrocarbons, and other
miscellaneous income.
o Production costs consist of costs incurred to operate and maintain wells
and related equipment and facilities used in the production of petroleum
liquids and natural gas. These costs also include taxes other than income
taxes, depreciation of support equipment and administrative expenses
related to the production activity. Excluded are depreciation, depletion
and amortization of capitalized acquisition, exploration and development
costs.
o Exploration expenses include dry hole, leasehold impairment, geological
and geophysical expenses and the cost of retaining undeveloped leaseholds.
Also included are taxes other than income taxes, depreciation of support
equipment and administrative expenses related to the exploration activity.
o Exploration expenses in 2002 included $77 million for the impairment of a
substantial portion of the company's investment in deepwater Block 34,
offshore Angola. Initial results released in early May 2002 indicated that
the first exploratory well drilled in Block 34 was a dry hole, resulting
in ConocoPhillips' reassessment of the fair value of the remainder of the
block.
o Depreciation, depletion and amortization (DD&A) in Results of Operations
differs from that shown for total E&P in Note 26--Segment Disclosures and
Related Information in the Notes to Consolidated Financial Statements,
mainly due to depreciation of support equipment being reclassified to
production or exploration expenses, as applicable, in Results of
Operations. In addition, Other earnings include certain E&P activities,
including their related DD&A charges.
o Transportation costs include costs to transport oil, natural gas or
natural gas liquids to their points of sale. The profit element of
transportation operations in which the company has an ownership interest
are deemed to be outside the oil and gas producing activity. The net
income of the transportation operations is included in Other earnings.
o Other related expenses include foreign currency gains and losses, and
other miscellaneous expenses.
o The provision for income taxes is computed by adjusting each country's
income before income taxes for permanent differences related to the oil
and gas producing activities that are reflected in the company's
consolidated income tax expense for the period, multiplying the result by
the country's statutory tax rate and adjusting for applicable tax credits.
o Other earnings consist of activities within the E&P segment that are not a
part of the "Results of operations for producing activities." These
non-producing activities include pipeline and marine operations, liquefied
natural gas operations, Syncrude operations, and crude oil and gas
marketing activities.
154
o STATISTICS
NET PRODUCTION 2002 2001 2000
----------------------------
Thousands of Barrels Daily
----------------------------
CRUDE OIL
Alaska 331 339 207
Lower 48 40 34 34
---------------------------------------------------------------------------------
United States 371 373 241
Norway 157 117 114
United Kingdom 39 19 25
Canada 13 1 6
Other areas 67 51 51
---------------------------------------------------------------------------------
Total consolidated 647 561 437
Equity affiliates 35 2 --
---------------------------------------------------------------------------------
682 563 437
=================================================================================
NATURAL GAS LIQUIDS*
Alaska 24 25 19
Lower 48 8 1 1
---------------------------------------------------------------------------------
United States 32 26 20
Norway 6 5 5
United Kingdom 2 2 2
Canada 4 -- 1
Other areas 2 2 1
---------------------------------------------------------------------------------
46 35 29
=================================================================================
*Represents amounts extracted attributable to E&P operations (see natural gas
liquids reserves for further discussion). Includes for 2002, 2001 and 2000,
14,000, 15,000 and 12,000 barrels daily in Alaska, respectively, that were sold
from the Prudhoe Bay lease to the Kuparuk lease for reinjection to enhance
crude oil production.
Millions of Cubic Feet Daily
-----------------------------
NATURAL GAS*
Alaska 175 177 158
Lower 48 928 740 770
---------------------------------------------------------------------------------
United States 1,103 917 928
Norway 171 130 136
United Kingdom 424 178 214
Canada 165 18 83
Other areas 180 92 33
---------------------------------------------------------------------------------
Total consolidated 2,043 1,335 1,394
Equity affiliates 4 -- --
---------------------------------------------------------------------------------
2,047 1,335 1,394
=================================================================================
*Represents quantities available for sale. Excludes gas equivalent of natural
gas liquids shown above.
155
2002 2001 2000
-------------------------------
AVERAGE SALES PRICES
CRUDE OIL PER BARREL
Alaska $ 23.75 23.60 28.87
Lower 48 24.48 23.27 28.57
United States 23.83 23.57 28.83
Norway 25.21 24.02 28.27
United Kingdom 25.33 24.52 28.19
Canada 22.87 26.96 28.21
Other areas 25.33 24.30 28.87
Total international 25.14 24.16 28.42
Total consolidated 24.38 23.77 28.65
Equity affiliates 18.41 12.36 --
Worldwide 24.07 23.74 28.65
----------------------------------------------------------------------------------------------
NATURAL GAS LIQUIDS PER BARREL
Alaska $ 23.48 23.61 28.97
Lower 48 15.66 22.47 22.97
United States 20.00 23.49 27.94
Norway 16.51 16.55 14.13
United Kingdom 20.61 18.49 20.57
Canada 20.39 18.77 25.49
Other areas 7.23 7.22 7.18
Total international 17.47 14.61 15.14
Worldwide 18.93 19.74 21.20
----------------------------------------------------------------------------------------------
NATURAL GAS (LEASE) PER THOUSAND CUBIC FEET
Alaska $ 1.85 1.75 1.40
Lower 48 2.79 3.68 3.56
United States 2.75 3.56 3.47
Norway 3.20 3.53 2.56
United Kingdom 2.92 2.88 2.61
Canada 3.03 3.80 3.26
Other areas 1.90 .50 .50
Total international 2.79 2.60 2.56
Total consolidated 2.77 3.23 3.13
Equity affiliates 2.71 -- --
Worldwide 2.77 3.23 3.13
----------------------------------------------------------------------------------------------
AVERAGE PRODUCTION COSTS PER BARREL OF OIL EQUIVALENT
Alaska $ 5.48 5.46 5.35
Lower 48 6.00 5.67 5.15
United States 5.66 5.52 5.27
Norway 2.99 2.36 2.28
United Kingdom 3.29 2.22 1.83
Canada 7.26 4.08 4.59
Other areas 5.26 3.69 4.75
Total international 3.99 2.70 2.85
Total consolidated 4.94 4.60 4.29
Equity affiliates 4.38 2.74 --
Worldwide 4.92 4.60 4.29
----------------------------------------------------------------------------------------------
156
2002 2001 2000
-------------------------------
DEPRECIATION, DEPLETION AND AMORTIZATION
PER BARREL OF OIL EQUIVALENT
Alaska $ 3.94 3.70 3.30
Lower 48 4.52 3.51* 3.18
United States 4.14 3.58 3.25
Norway 2.95 2.19 2.04
United Kingdom 6.73 6.38 6.02
Canada 6.46 2.72 8.91
Other areas 2.35 1.96 3.09
Total international 4.11 2.94 3.64
Total consolidated 4.13 3.37 3.41
Equity affiliates 2.30 2.74 --
Worldwide 4.06 3.37 3.41
----------------------------------------------------------------------------------------------
*Includes a $12 million charge related to an asset transfer.
----------------------------------------------------------------------------------------------
NET WELLS COMPLETED* Productive Dry
---------------------- ----------------------
2002 2001 2000 2002 2001 2000
---------------------- ----------------------
EXPLORATORY
Alaska -- 1 -- 4 1 1
Lower 48 29 63 45 6 3 4
----------------------------------------------------------------------------------------------
United States 29 64 45 10 4 5
Norway -- ** ** ** -- --
United Kingdom ** ** 1 2 1 1
Canada 19 -- 3 2 -- 1
Other areas 2 2 6 7 1 6
----------------------------------------------------------------------------------------------
Total consolidated 50 66 55 21 6 13
Equity affiliates 3 -- -- 1 -- --
----------------------------------------------------------------------------------------------
53 66 55 22 6 13
==============================================================================================
DEVELOPMENT
Alaska 48 47 52 1 2 1
Lower 48 283 333 208 14 11 8
----------------------------------------------------------------------------------------------
United States 331 380 260 15 13 9
Norway 4 3 1 -- -- --
United Kingdom 7 1 1 -- -- --
Canada 20 5 8 1 -- 1
Other areas 13 2 6 ** -- --
----------------------------------------------------------------------------------------------
Total consolidated 375 391 276 16 13 10
Equity affiliates 49 20 -- 1 -- --
----------------------------------------------------------------------------------------------
424 411 276 17 13 10
==============================================================================================
*Includes wildcat and production step-out wells. Excludes farmout
arrangements.
**ConocoPhillips' total proportionate interest was less than one.
157
WELLS AT YEAR-END 2002 Productive**
---------------------------------------
In Progress* Oil Gas
----------------- ----------------- -----------------
Gross Net Gross Net Gross Net
----------------- ----------------- -----------------
Alaska 25 15 1,680 735 24 15
Lower 48 101 61 11,801 2,826 15,534 7,586
------------------------------------------------------------------------------------
United States 126 76 13,481 3,561 15,558 7,601
Norway 13 2 519 85 60 7
United Kingdom 14 5 189 37 288 87
Canada 7 5 3,395 2,408 5,359 3,463
Other areas 33 16 943 321 76 31
------------------------------------------------------------------------------------
Total consolidated 193 104 18,527 6,412 21,341 11,189
Equity affiliates 4 2 2,095 875 161 63
------------------------------------------------------------------------------------
197 106 20,622 7,287 21,502 11,252
====================================================================================
*Includes wells that have been temporarily suspended.
**Includes 3,205 gross and 1,554 net multiple completion wells.
ACREAGE AT DECEMBER 31, 2002
Thousands of Acres
------------------------
Gross Net
------------------------
DEVELOPED
Alaska 878 431
Lower 48 5,219 3,142
------------------------------------------------------------------------------------
United States 6,097 3,573
Norway 430 47
United Kingdom 1,496 465
Canada 4,764 2,343
Other areas 5,147 2,128
------------------------------------------------------------------------------------
Total consolidated 17,934 8,556
Equity affiliates 490 151
------------------------------------------------------------------------------------
18,424 8,707
====================================================================================
UNDEVELOPED
Alaska 2,467 1,422
Lower 48 3,494 2,115
------------------------------------------------------------------------------------
United States 5,961 3,537
Norway 5,243 1,309
United Kingdom 3,298 1,379
Canada 13,631 7,716
Other areas* 118,115 78,324
------------------------------------------------------------------------------------
Total consolidated 146,248 92,265
Equity affiliates 2,118 943
------------------------------------------------------------------------------------
148,366 93,208
====================================================================================
*Includes two Somalia concessions where operations have been suspended by
declarations of force majeure totaling 33,905 thousand gross and net acres.
158
o COSTS INCURRED
Millions of Dollars
----------------------------------------------------------------------------------------------------
Consolidated Operations
-----------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total
----------------------------------------------------------------------------------------------------
2002
Acquisition $ 9 3,735 3,744 1,348 3,050 2,562 2,064 12,768 1,671 14,439
Exploration 94 112 206 33 28 58 309 634 1 635
Development 433 409 842 174 232 46 857 2,151 467 2,618
-----------------------------------------------------------------------------------------------------------------------------------
$ 536 4,256 4,792 1,555 3,310 2,666 3,230 15,553 2,139 17,692
===================================================================================================================================
2001
Acquisition $ 17 37 54 -- -- -- 228 282 -- 282
Exploration 93 57 150 26 18 -- 223 417 -- 417
Development 610 312 922 94 75 3 401 1,495 420 1,915
-----------------------------------------------------------------------------------------------------------------------------------
$ 720 406 1,126 120 93 3 852 2,194 420 2,614
===================================================================================================================================
2000
Acquisition $5,787 151 5,938 36 -- 33 5 6,012 3 6,015
Exploration 32 66 98 17 36 6 213 370 -- 370
Development 422 218 640 71 50 42 192 995 135 1,130
-----------------------------------------------------------------------------------------------------------------------------------
$6,241 435 6,676 124 86 81 410 7,377 138 7,515
===================================================================================================================================
o Costs incurred include capitalized and expensed items.
o Acquisition costs include the costs of acquiring proved and unproved oil
and gas properties. The amounts in 2002 relate primarily to the merger.
Acquisition costs included proved properties of $3,420 million, $13
million and $87 million in the Lower 48 for 2002, 2001, and 2000,
respectively. The 2002 amounts in Norway and the U.K. included $1,255
million and $2,464 million for proved properties, respectively. The 2002
and 2000 amounts in Canada included proved properties of $2,003 million
and $33 million, respectively. The 2002 and 2001 amounts in Other Areas
included $1,493 million and $63 million for proved properties. The 2002
amount for Equity Affiliates of $1,671 million is for proved properties.
The 2000 amount in Alaska included $5,125 million for proved properties.
o Exploration costs include geological and geophysical expenses, the cost of
retaining undeveloped leaseholds, and exploratory drilling costs.
o Development costs include the cost of drilling and equipping development
wells and building related production facilities for extracting, treating,
gathering and storing petroleum liquids and natural gas.
159
o CAPITALIZED COSTS
At December 31 Millions of Dollars
----------------------------------------------------------------------------------------------------
Consolidated Operations
-----------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total
----------------------------------------------------------------------------------------------------
2002
Proved properties $7,037 7,737 14,774 5,422 4,178 2,023 3,832 30,229 2,847 33,076
Unproved properties 849 489 1,338 142 622 546 1,556 4,204 -- 4,204
-----------------------------------------------------------------------------------------------------------------------------------
7,886 8,226 16,112 5,564 4,800 2,569 5,388 34,433 2,847 37,280
Accumulated depreciation,
depletion and amortization 1,636 2,891 4,527 2,224 1,033 182 661 8,627 37 8,664
-----------------------------------------------------------------------------------------------------------------------------------
$6,250 5,335 11,585 3,340 3,767 2,387 4,727 25,806 2,810 28,616
===================================================================================================================================
2001
Proved properties $6,646 4,552 11,198 2,889 1,773 104 1,752 17,716 708 18,424
Unproved properties 772 181 953 40 41 3 768 1,805 -- 1,805
-----------------------------------------------------------------------------------------------------------------------------------
7,418 4,733 12,151 2,929 1,814 107 2,520 19,521 708 20,229
Accumulated depreciation,
depletion and amortization 1,097 3,238 4,335 1,529 1,161 79 540 7,644 4 7,648
-----------------------------------------------------------------------------------------------------------------------------------
$6,321 1,495 7,816 1,400 653 28 1,980 11,877 704 12,581
===================================================================================================================================
o Capitalized costs include the cost of equipment and facilities for oil and
gas producing activities. These costs include the activities of
ConocoPhillips' E&P organization, excluding pipeline and marine
operations, the Kenai liquefied natural gas operation, Syncrude
operations, and crude oil and natural gas marketing activities.
o Proved properties include capitalized costs for oil and gas leaseholds
holding proved reserves; development wells and related equipment and
facilities (including uncompleted development well costs); and support
equipment.
o Unproved properties include capitalized costs for oil and gas leaseholds
under exploration (including where petroleum liquids and natural gas were
found but determination of the economic viability of the required
infrastructure is dependent upon further exploratory work under way or
firmly planned) and for uncompleted exploratory well costs, including
exploratory wells under evaluation.
160
o STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED OIL AND GAS RESERVE QUANTITIES
Amounts are computed using year-end prices and costs (adjusted only for existing
contractual changes), appropriate statutory tax rates and a prescribed 10
percent discount factor. Continuation of year-end economic conditions also is
assumed. The calculation is based on estimates of proved reserves, which are
revised over time as new data become available. Probable or possible reserves,
which may become proved in the future, are not considered. The calculation also
requires assumptions as to the timing of future production of proved reserves,
and the timing and amount of future development and production costs.
While due care was taken in its preparation, the company does not represent that
this data is the fair value of the company's oil and gas properties, or a fair
estimate of the present value of cash flows to be obtained from their
development and production.
161
DISCOUNTED FUTURE NET CASH FLOWS
At December 31 Millions of Dollars
----------------------------------------------------------------------------------------------------
Consolidated Operations
-----------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total
----------------------------------------------------------------------------------------------------
2002
Future cash inflows $54,497 28,679 83,176 29,571 11,709 8,076 22,654 155,186 32,983 188,169
Less:
Future production and
transportation costs 26,035 7,763 33,798 4,598 3,376 1,885 5,403 49,060 4,992 54,052
Future development costs 2,927 1,168 4,095 1,762 1,227 617 2,249 9,950 1,698 11,648
Future income tax
provisions 7,665 5,349 13,014 16,998 3,077 2,361 6,912 42,362 8,501 50,863
-----------------------------------------------------------------------------------------------------------------------------------
Future net cash flows 17,870 14,399 32,269 6,213 4,029 3,213 8,090 53,814 17,792 71,606
10 percent annual discount 9,097 7,405 16,502 2,515 1,483 1,422 3,730 25,652 11,585 37,237
-----------------------------------------------------------------------------------------------------------------------------------
Discounted future net cash
flows $ 8,773 6,994 15,767 3,698 2,546 1,791 4,360* 28,162 6,207 34,369
===================================================================================================================================
2001
Future cash inflows $33,138 9,441 42,579 14,278 2,143 174 6,712 65,886 11,581 77,467
Less:
Future production and
transportation costs 20,541 4,241 24,782 2,117 357 52 1,426 28,734 3,483 32,217
Future development costs 3,071 530 3,601 627 248 9 1,079 5,564 1,282 6,846
Future income tax
provisions 1,797 1,253 3,050 8,762 389 8 2,596 14,805 2,133 16,938
-----------------------------------------------------------------------------------------------------------------------------------
Future net cash flows 7,729 3,417 11,146 2,772 1,149 105 1,611 16,783 4,683 21,466
10 percent annual discount 3,297 1,821 5,118 1,247 360 44 1,019 7,788 3,687 11,475
-----------------------------------------------------------------------------------------------------------------------------------
Discounted future net cash
flows $ 4,432 1,596 6,028 1,525 789 61 592** 8,995 996 9,991
===================================================================================================================================
2000
Future cash inflows $39,554 29,027 68,581 16,002 3,012 537 7,792 95,924 14,812 110,736
Less:
Future production and
transportation costs 20,338 3,996 24,334 2,060 426 105 1,379 28,304 2,519 30,823
Future development costs 2,916 479 3,395 679 372 1 1,024 5,471 1,684 7,155
Future income tax
provisions 3,772 8,206 11,978 10,103 592 160 2,316 25,149 2,546 27,695
-----------------------------------------------------------------------------------------------------------------------------------
Future net cash flows 12,528 16,346 28,874 3,160 1,622 271 3,073 37,000 8,063 45,063
10 percent annual discount 5,660 8,684 14,344 1,429 571 113 1,761 18,218 6,428 24,646
-----------------------------------------------------------------------------------------------------------------------------------
Discounted future net cash
flows $ 6,868 7,662 14,530 1,731 1,051 158 1,312 18,782 1,635 20,417
===================================================================================================================================
*Includes $139 million attributable to a consolidated subsidiary in which
there is a 10 percent minority interest.
**Includes $17 million attributable to a consolidated subsidiary in which
there is a 13 percent minority interest.
Excludes discounted future net cash flows from Canadian Syncrude of $869
million.
162
SOURCES OF CHANGE IN DISCOUNTED FUTURE NET CASH FLOWS
Millions of Dollars
----------------------------------------------------------------------------------------
Consolidated Operations Equity Affiliates Total
---------------------------- --------------------------- ---------------------------
2002 2001 2000 2002 2001 2000 2002 2001 2000
---------------------------- --------------------------- ---------------------------
Discounted future net cash flows at
the beginning of the year $ 8,995 18,782 6,205 996 1,635 -- 9,991 20,417 6,205
---------------------------------------------------------------------------------------------------------------------------------
Changes during the year
Revenues less production and
transportation costs for the year (5,271) (4,283) (4,592) (177) (6) -- (5,448) (4,289) (4,592)
Net change in prices, and production
and transportation costs 15,566 (14,668) 10,396 2,734 (1,552) -- 18,300 (16,220) 10,396
Extensions, discoveries and improved
recovery, less estimated future
costs 1,284 757 1,817 22 -- 2,402 1,306 757 4,219
Development costs for the year 2,151 1,495 995 467 420 135 2,618 1,915 1,130
Changes in estimated future
development costs (1,790) (1,011) (775) (108) (17) (135) (1,898) (1,028) (910)
Purchases of reserves in place, less
estimated future costs 22,161 130 8,168 4,781 -- -- 26,942 130 8,168
Sales of reserves in place, less
estimated future costs (563) (9) (1,037) (16) -- -- (579) (9) (1,037)
Revisions of previous quantity
estimates* (185) 15 1,750 (712) 38 -- (897) 53 1,750
Accretion of discount 1,540 2,877 1,217 177 260 -- 1,717 3,137 1,217
Net change in income taxes (15,726) 4,909 (5,360) (1,957) 218 (767) (17,683) 5,127 (6,127)
Other -- 1 (2) -- -- -- -- 1 (2)
---------------------------------------------------------------------------------------------------------------------------------
Total changes 19,167 (9,787) 12,577 5,211 (639) 1,635 24,378 (10,426) 14,212
---------------------------------------------------------------------------------------------------------------------------------
Discounted future net cash flows at
year-end $ 28,162 8,995 18,782 6,207 996 1,635 34,369 9,991 20,417
=================================================================================================================================
*Includes amounts resulting from changes in the timing of production.
o The net change in prices, and production and transportation costs is the
beginning-of-the-year reserve-production forecast multiplied by the net
annual change in the per-unit sales price, and production and
transportation cost, discounted at 10 percent.
o Purchases and sales of reserves in place, along with extensions,
discoveries and improved recovery, are calculated using production
forecasts of the applicable reserve quantities for the year multiplied by
the end-of-the-year sales prices, less future estimated costs, discounted
at 10 percent.
o The accretion of discount is 10 percent of the prior year's discounted
future cash inflows, less future production, transportation and
development costs.
o The net change in income taxes is the annual change in the discounted
future income tax provisions.
163
--------------------------------------------------------------------------------
SELECTED QUARTERLY FINANCIAL DATA
Millions of Dollars Per Share of Common Stock
------------------------------------------------------- ----------------------------------------------------
Income (Loss)
Before
Extraordinary Income (loss) Before
Income from Items and Extraordinary Items
Continuing Cumulative and Cumulative
Sales and Operations Effect of Effect of Change in
Other Before Change in Net Accounting Principle Net Income (loss)
Operating Income Accounting Income ---------------------- ----------------------
Revenues* Taxes* Principle (Loss) Basic Diluted Basic Diluted
-------------------------------------------------------- ------- ------- ------- -------
2002
First $ 8,431 51 (102) (102) (.27) (.27) (.27) (.27)
Second 10,414 678 366 351 .95 .95 .91 .91
Third 14,557 312 (116) (116) (.24) (.24) (.24) (.24)
Fourth 23,346 1,123 (427) (428) (.63) (.63) (.63) (.63)
------------------------------------------------------------------------------------------------------------------------------
2001
First $ 5,160 1,019 488 516 1.91 1.90 2.02 2.01
Second 5,179 1,198 619 619 2.42 2.40 2.42 2.40
Third 5,808 699 374 364 1.35 1.34 1.31 1.30
Fourth 8,745 339 162 162 .42 .42 .42 .42
------------------------------------------------------------------------------------------------------------------------------
*Restated to exclude discontinued operations. See Management's Discussion and
Analysis and Note 4--Discontinued Operations in the Notes to Consolidated
Financial Statements for additional information. Sales and other operating
revenues include excise taxes on petroleum products sales.
164
CONDENSED CONSOLIDATING FINANCIAL INFORMATION
In connection with the merger of ConocoPhillips Holding Company (formerly named
Conoco Inc.) and ConocoPhillips Company (formerly named Phillips Petroleum
Company) with wholly owned subsidiaries of ConocoPhillips, and to simplify the
company's credit structure, the companies have established various cross
guarantees. With the new organizational structure, ConocoPhillips Company is the
direct or indirect parent of former Conoco and Phillips subsidiaries and is
wholly owned by ConocoPhillips Holding Company, which is wholly owned by
ConocoPhillips. ConocoPhillips and ConocoPhillips Holding Company have fully and
unconditionally guaranteed the payment obligations of ConocoPhillips Company
with respect to its publicly held debt securities. Similarly, ConocoPhillips and
ConocoPhillips Company have fully and unconditionally guaranteed the payment
obligations of ConocoPhillips Holding Company with respect to the publicly held
debt securities of ConocoPhillips Holding Company. In addition, ConocoPhillips
Company and ConocoPhillips Holding Company have fully and unconditionally
guaranteed the payment obligations of ConocoPhillips with respect to its
publicly held debt securities. All guarantees are joint and several. The
following condensed consolidating financial statements present the results of
operations, financial position and cash flows for:
o ConocoPhillips, ConocoPhillips Company, ConocoPhillips Holding
Company (in each case, reflecting investments in subsidiaries
utilizing the equity method of accounting);
o All other non-guarantor subsidiaries of ConocoPhillips Holding
Company and ConocoPhillips Company; and
o The consolidating adjustments necessary to present ConocoPhillips'
results on a consolidated basis.
These condensed consolidating financial statements should be read in conjunction
with the company's accompanying consolidated financial statements.
165
Millions of Dollars
----------------------------------------------------------------------------------------
Year Ended December 31, 2002
----------------------------------------------------------------------------------------
ConocoPhillips Consoli-
Holding ConocoPhillips All Other dating Total
STATEMENT OF OPERATIONS ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated
-------------- -------------- -------------- ------------- ----------- ------------
REVENUES
Sales and other operating revenues $ -- -- 16,744 40,004 -- 56,748
Equity in earnings (losses) of
affiliates (646) (682) 352 255 982 261
Other income -- -- (48) 263 -- 215
Intercompany revenues -- 191 2,800 3,123 (6,114) --
-----------------------------------------------------------------------------------------------------------------------------------
Total revenues (646) (491) 19,848 43,645 (5,132) 57,224
-----------------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Purchased crude oil and products -- -- 15,595 27,854 (5,626) 37,823
Production and operating expenses -- 9 1,438 3,573 (32) 4,988
Selling, general and administrative
expenses 3 -- 980 681 (4) 1,660
Exploration expenses -- -- 165 427 -- 592
Depreciation, depletion and amortization -- -- 584 1,639 -- 2,223
Impairments -- -- -- 177 -- 177
Taxes other than income taxes -- -- 785 6,152 -- 6,937
Accretion on discounted liabilities -- -- (1) 23 -- 22
Interest and debt expense 29 120 745 124 (452) 566
Foreign currency transaction losses -- -- 8 16 -- 24
Preferred dividend requirements of
capital trusts and minority
interests -- -- -- 48 -- 48
-----------------------------------------------------------------------------------------------------------------------------------
Total Costs and Expenses 32 129 20,299 40,714 (6,114) 55,060
-----------------------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing
operations before income taxes (678) (620) (451) 2,931 982 2,164
Provision for income taxes (11) 26 (202) 1,637 -- 1,450
-----------------------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing
operations (667) (646) (249) 1,294 982 714
Income (loss) from discontinued
operations -- -- (70) (923) -- (993)
-----------------------------------------------------------------------------------------------------------------------------------
Income (loss) before extraordinary items (667) (646) (319) 371 982 (279)
Extraordinary items -- -- (14) (2) -- (16)
-----------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ (667) (646) (333) 369 982 (295)
===================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary
of ConocoPhillips Company and included in All Other Subsidiaries. On January
1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this
merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company
assumed all of Tosco's properties, rights and obligations.
166
Millions of Dollars
------------------------------------------------------------------------------------
Year Ended December 31, 2001
------------------------------------------------------------------------------------
ConocoPhillips Consoli-
Holding ConocoPhillips All Other dating Total
STATEMENT OF OPERATIONS ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated
-------------- -------------- -------------- ------------- ----------- ------------
REVENUES
Sales and other operating revenues $ - - 12,457 12,435 - 24,892
Equity in earnings (losses) of affiliates - - 1,583 222 (1,764) 41
Other income - - (1) 112 - 111
Intercompany revenues - - 1,308 1,985 (3,293) -
-----------------------------------------------------------------------------------------------------------------------------------
Total revenues - - 15,347 14,754 (5,057) 25,044
-----------------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Purchased crude oil and products - - 9,015 7,290 (2,597) 13,708
Production and operating expenses - - 1,166 1,746 (269) 2,643
Selling, general and administrative expenses - - 540 90 (17) 613
Exploration expenses - - 139 222 (55) 306
Depreciation, depletion and amortization - - 379 965 - 1,344
Impairments - - - 26 - 26
Taxes other than income taxes - - 1,874 866 - 2,740
Accretion on discounted liabilities - - 2 5 - 7
Interest and debt expense - - 551 142 (355) 338
Foreign currency transaction losses (gains) - - (1) 12 - 11
Preferred dividend requirements of capital
trusts and minority interests - - - 53 - 53
-----------------------------------------------------------------------------------------------------------------------------------
Total Costs and Expenses - - 13,665 11,417 (3,293) 21,789
-----------------------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations
before income taxes - - 1,682 3,337 (1,764) 3,255
Provision for income taxes - - 50 1,594 - 1,644
-----------------------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations - - 1,632 1,743 (1,764) 1,611
Income from discontinued operations - - 11 21 - 32
-----------------------------------------------------------------------------------------------------------------------------------
Income (loss) before extraordinary items and
cumulative effect of change in accounting
principle - - 1,643 1,764 (1,764) 1,643
Extraordinary items - - (10) - - (10)
Cumulative effect of change in accounting
principle - - 28 - - 28
------------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ - - 1,661 1,764 (1,764) 1,661
====================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary
of ConocoPhillips Company and included in All Other Subsidiaries. On January
1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this
merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company
assumed all of Tosco's properties, rights and obligations.
167
Millions of Dollars
---------------------------------------------------------------------------------------
Year Ended December 31, 2000
---------------------------------------------------------------------------------------
ConocoPhillips Consoli-
Holding ConocoPhillips All Other dating Total
STATEMENT OF OPERATIONS ConocoPhillips Company Company Subsidiaries Adjustments Consolidated
-------------- -------------- -------------- ------------ ----------- ------------
REVENUES
Sales and other operating revenues $ - - 15,252 6,903 - 22,155
Equity in earnings (losses) of affiliates - - 1,471 218 (1,575) 114
Other income - - 292 (22) - 270
Intercompany revenues - - 1,663 2,319 (3,982) -
------------------------------------------------------------------------------------------------------------------------------------
Total revenues - - 18,678 9,418 (5,557) 22,539
------------------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Purchased crude oil and products - - 11,924 3,173 (3,303) 11,794
Production and operating expenses - - 1,244 1,160 (268) 2,136
Selling, general and administrative expenses - - 563 42 (34) 571
Exploration expenses - - 112 208 (22) 298
Depreciation, depletion and amortization - - 391 778 - 1,169
Impairments - - 13 87 - 100
Taxes other than income taxes - - 1,939 303 - 2,242
Interest and debt expense - - 575 149 (355) 369
Foreign currency transaction losses - - - 58 - 58
Preferred dividend requirements of capital
trusts and minority interests - - - 54 - 54
------------------------------------------------------------------------------------------------------------------------------------
Total Costs and Expenses - - 16,761 6,012 (3,982) 18,791
------------------------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations
before income taxes - - 1,917 3,406 (1,575) 3,748
Provision for income taxes - - 70 1,830 - 1,900
------------------------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations - - 1,847 1,576 (1,575) 1,848
Income (loss) from discontinued operations - - 15 (1) - 14
------------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ - - 1,862 1,575 (1,575) 1,862
====================================================================================================================================
168
Millions of Dollars
--------------------------------------------------------------------------------------
At December 31, 2002
--------------------------------------------------------------------------------------
ConocoPhillips Consoli-
Holding ConocoPhillips All Other dating Total
BALANCE SHEET ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated
-------------- -------------- -------------- ------------- ----------- ------------
ASSETS
Cash and cash equivalents $ -- -- 113 194 -- 307
Accounts and notes receivable 8 -- 15,655 13,921 (25,204) 4,380
Inventories -- -- 1,321 2,524 -- 3,845
Prepaid expenses and other current assets 5 -- 153 543 65 766
Assets of discontinued operations held
for sale -- -- 263 1,342 -- 1,605
-----------------------------------------------------------------------------------------------------------------------------------
Total Current Assets 13 -- 17,505 18,524 (25,139) 10,903
Investments and long-term receivables 32,301 35,538 44,011 23,124 (128,153) 6,821
Net properties, plants and equipment -- -- 8,893 34,137 -- 43,030
Goodwill** -- -- -- 14,444 -- 14,444
Intangibles -- -- 6 1,113 -- 1,119
Other assets 14 19 110 376 -- 519
-----------------------------------------------------------------------------------------------------------------------------------
Total 32,328 35,557 70,525 91,718 (153,292) 76,836
===================================================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable 5,840 3,291 14,071 8,254 (25,204) 6,252
Notes payable and long-term debt due
within one year -- 526 164 159 -- 849
Accrued income and other taxes (1) 53 255 1,684 -- 1,991
Other accruals 21 58 1,242 1,754 -- 3,075
Liabilities of discontinued operations
held for sale -- -- 126 523 -- 649
-----------------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 5,860 3,928 15,858 12,374 (25,204) 12,816
Long-term debt 3,509 4,054 5,553 5,801 -- 18,917
Accrued dismantlement, removal and
environmental costs -- -- 247 1,419 -- 1,666
Deferred income taxes -- (41) 766 7,644 (8) 8,361
Employee benefit obligations -- -- 1,213 1,542 -- 2,755
Other liabilities and deferred credits -- 3,729 34,081 32,100 (68,107) 1,803
-----------------------------------------------------------------------------------------------------------------------------------
Total Liabilities 9,369 11,670 57,718 60,880 (93,319) 46,318
Trust Preferred Securities and other
minority interests -- (12) -- 1,013 -- 1,001
Retained earnings (937) (1,349) 7,331 8,792 (8,216) 5,621
Other stockholders' equity 23,896 25,248 5,476 21,033 (51,757) 23,896
-----------------------------------------------------------------------------------------------------------------------------------
Total $ 32,328 35,557 70,525 91,718 (153,292) 76,836
===================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary
of ConocoPhillips Company and included in All Other Subsidiaries. On January
1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this
merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company
assumed all of Tosco's properties, rights and obligations.
**ConocoPhillips has not yet determined the assignment of Conoco goodwill to
specific reporting units and related subsidiaries. Currently, Conoco goodwill
is reported as part of the Corporate and Other reporting segment in All Other
Subsidiaries.
169
Millions of Dollars
----------------------------------------------------------------------------------------
At December 31, 2001
----------------------------------------------------------------------------------------
ConocoPhillips Consoli-
Holding ConocoPhillips All Other dating Total
BALANCE SHEET ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated
-------------- -------------- -------------- ------------- ----------- ------------
ASSETS
Cash and cash equivalents $ -- -- 19 123 -- 142
Accounts and notes receivable -- -- 1,535 2,232 (2,538) 1,229
Inventories -- -- 307 2,145 -- 2,452
Prepaid expenses and other current assets -- -- 93 200 -- 293
Assets of discontinued operations
held for sale -- -- 184 2,198 -- 2,382
-----------------------------------------------------------------------------------------------------------------------------------
Total Current Assets -- -- 2,138 6,898 (2,538) 6,498
Investments and long-term receivables -- -- 25,381 10,148 (32,220) 3,309
Net properties, plants and equipment -- -- 3,879 18,254 -- 22,133
Goodwill -- -- -- 2,281 -- 2,281
Intangibles -- -- 59 802 -- 861
Other assets -- -- 68 67 -- 135
-----------------------------------------------------------------------------------------------------------------------------------
Total -- -- 31,525 38,450 (34,758) 35,217
===================================================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable -- -- 1,939 3,190 (2,507) 2,622
Notes payable and long-term debt due
within one year -- -- 4 40 -- 44
Accrued income and other taxes -- -- (31) 928 -- 897
Other accruals -- -- 238 482 -- 720
Liabilities of discontinued operations
held for sale -- -- 34 504 -- 538
-----------------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities -- -- 2,184 5,144 (2,507) 4,821
Long-term debt -- -- 7,282 1,328 -- 8,610
Accrued dismantlement, removal and
environmental costs -- -- 356 703 -- 1,059
Deferred income taxes -- -- 467 3,556 (8) 4,015
Employee benefit obligations -- -- 725 223 -- 948
Other liabilities and deferred credits -- -- 6,175 3,072 (8,478) 769
-----------------------------------------------------------------------------------------------------------------------------------
Total Liabilities -- -- 17,189 14,026 (10,993) 20,222
Trust Preferred Securities and other
minority interests -- -- -- 655 -- 655
Retained earnings -- -- 7,197 23,889 (23,889) 7,197
Other stockholders' equity -- -- 7,139 (120) 124 7,143
-----------------------------------------------------------------------------------------------------------------------------------
Total $ -- -- 31,525 38,450 (34,758) 35,217
===================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary
of ConocoPhillips Company and included in All Other Subsidiaries. On January
1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this
merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company
assumed all of Tosco's properties, rights and obligations.
170
Millions of Dollars
----------------------------------------------------------------------------------------
Year Ended December 31, 2002
----------------------------------------------------------------------------------------
ConocoPhillips Consoli-
Holding ConocoPhillips All Other dating Total
STATEMENT OF CASH FLOWS ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated
-------------- -------------- -------------- ------------- ----------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by (used in)
continuing operations $ 1,120 2,859 1,060 1,887 (2,159) 4,767
Net cash provided by (used in)
discontinued operations -- -- (7) 209 -- 202
-----------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in)
Operating Activities 1,120 2,859 1,053 2,096 (2,159) 4,969
-----------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions, net of cash acquired -- -- (81) 1,261 -- 1,180
Capital expenditures and investments,
including dry holes -- (346) (618) (3,897) 473 (4,388)
Proceeds from asset dispositions -- -- (179) 794 200 815
Long-term advances to affiliates and
other investments (4,344) (1,200) (12,154) (2,030) 19,636 (92)
-----------------------------------------------------------------------------------------------------------------------------------
Net cash used in continuing operations (4,344) (1,546) (13,032) (3,872) 20,309 (2,485)
Net cash used in discontinued operations -- -- (6) (93) -- (99)
-----------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (4,344) (1,546) (13,038) (3,965) 20,309 (2,584)
-----------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of debt 3,502 3,012 15,350 1,274 (19,636) 3,502
Repayment of debt -- (3,006) (1,680) (215) 309 (4,592)
Redemption of preferred stock of
subsidiaries -- -- -- (300) -- (300)
Issuance of company common stock 7 -- 37 -- -- 44
Dividends paid on common stock (271) (1,200) (1,621) 1,231 1,177 (684)
Other (14) (119) (7) (50) -- (190)
-----------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in)
Financing Activities 3,224 (1,313) 12,079 1,940 (18,150) (2,220)
-----------------------------------------------------------------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS -- -- 94 71 -- 165
Cash and cash equivalents at beginning
of year -- -- 19 123 -- 142
-----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of
Year $ -- -- 113 194 -- 307
===================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary
of ConocoPhillips Company and included in All Other Subsidiaries. On January
1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this
merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company
assumed all of Tosco's properties, rights and obligations.
171
Millions of Dollars
----------------------------------------------------------------------------------------
Year Ended December 31, 2001
----------------------------------------------------------------------------------------
ConocoPhillips Consoli-
Holding ConocoPhillips All Other dating Total
STATEMENT OF CASH FLOWS ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated
-------------- -------------- -------------- ------------- ----------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by (used in)
continuing operations $ -- -- 2,302 1,628 (401) 3,529
Net cash provided by discontinued
operations -- -- 25 8 -- 33
-----------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in)
Operating Activities -- -- 2,327 1,636 (401) 3,562
-----------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions, net of cash acquired -- -- (23) 103 -- 80
Capital expenditures and investments,
including dry holes -- -- (814) (2,343) 141 (3,016)
Proceeds from asset dispositions -- -- 17 245 -- 262
Long-term advances to affiliates and
other investments -- -- (670) 446 196 (28)
-----------------------------------------------------------------------------------------------------------------------------------
Net cash used in continuing operations -- -- (1,490) (1,549) 337 (2,702)
Net cash used in discontinued operations -- -- (8) (60) -- (68)
-----------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities -- -- (1,498) (1,609) 337 (2,770)
-----------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of debt -- -- 566 643 (643) 566
Repayment of debt -- -- (1,050) (342) 447 (945)
Issuance of company common stock -- -- 51 -- -- 51
Dividends paid on common stock -- -- (403) (259) 259 (403)
Other -- -- (13) (56) 1 (68)
-----------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in)
Financing Activities -- -- (849) (14) 64 (799)
-----------------------------------------------------------------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS -- -- (20) 13 -- (7)
Cash and cash equivalents at beginning
of year -- -- 39 110 -- 149
-----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of
Year $ -- -- 19 123 -- 142
===================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary
of ConocoPhillips Company and included in All Other Subsidiaries. On January
1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this
merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company
assumed all of Tosco's properties, rights and obligations.
172
Millions of Dollars
---------------------------------------------------------------------------------------
Year Ended December 31, 2000
---------------------------------------------------------------------------------------
ConocoPhillips Consoli-
Holding ConocoPhillips All Other dating Total
STATEMENT OF CASH FLOWS ConocoPhillips Company Company Subsidiaries Adjustments Consolidated
-------------- -------------- -------------- ------------ ----------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by (used in)
continuing operations $ - - 1,684 3,893 (1,593) 3,984
Net cash provided by discontinued
operations - - 30 - - 30
----------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in)
Operating Activities - - 1,714 3,893 (1,593) 4,014
----------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions, net of cash acquired - - (6,443) - - (6,443)
Capital expenditures and investments,
including dry holes - - (1,342) (1,825) 1,150 (2,017)
Proceeds from contributing assets to
joint ventures - - 841 1,220 - 2,061
Proceeds from asset dispositions - - 313 854 (317) 850
Long-term advances to affiliates and
other investments - - (349) (3,251) 3,392 (208)
----------------------------------------------------------------------------------------------------------------------------------
Net cash used in continuing operations - - (6,980) (3,002) 4,225 (5,757)
Net cash used in discontinued operations - - (5) - - (5)
----------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities - - (6,985) (3,002) 4,225 (5,762)
----------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of debt - - 5,675 269 (3,392) 2,552
Repayment of debt - - (39) (321) - (360)
Issuance of company common stock - - 31 - - 31
Dividends paid on common stock - - (346) (761) 761 (346)
Other - - (53) (64) (1) (118)
----------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in)
Financing Activities - - 5,268 (877) (2,632) 1,759
----------------------------------------------------------------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS - - (3) 14 - 11
Cash and cash equivalents at beginning
of year - - 42 96 - 138
----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of
Year $ - - 39 110 - 149
==================================================================================================================================
173
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
174
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information presented under the headings "Election of Directors and Director
Biographies" and "Stock Ownership--Section 16(a) Beneficial Ownership Reporting
Compliance" in the company's definitive proxy statement for the Annual Meeting
of Stockholders on May 6, 2003 (2003 Proxy Statement), is incorporated herein by
reference.* Information regarding the executive officers appears in Part I of
this report on pages 32 and 33.
ITEM 11. EXECUTIVE COMPENSATION
Information presented under the following headings in the 2003 Proxy Statement
is incorporated herein by reference:
"Board of Directors Information--How are Directors Compensated?"
"Executive Compensation--Compensation Tables"
"Executive Compensation--Employment Agreements"
"Executive Compensation--Severance Arrangements"
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
Information presented under the headings "Stock Ownership--Holdings of Major
Stockholders," "--Holdings of Officers and Directors" and "Executive
Compensation--Compensation Tables--Equity Compensation Plan Information" in the
2003 Proxy Statement is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
----------
*Except for information or data specifically incorporated herein by
reference under Items 10 through 13, other information and data appearing
in the 2003 Proxy Statement are not deemed to be a part of this Annual
Report on Form 10-K or deemed to be filed with the Commission as a part of
this report.
175
ITEM 14. CONTROLS AND PROCEDURES
Within the 90 days prior to the date of this annual report, ConocoPhillips
carried out an evaluation, under the supervision, and with the participation of,
the company's Management, including the company's President and Chief Executive
Officer, and its Executive Vice President Finance and Chief Financial Officer,
of the effectiveness of ConocoPhillips' disclosure controls and procedures
pursuant to Rule 13a-14 under the Securities Exchange Act of 1934, as amended.
Based upon that evaluation, the company's President and Chief Executive Officer
and its Executive Vice President Finance and Chief Financial Officer concluded
that ConocoPhillips' disclosure controls and procedures are effective, in all
material respects, with respect to the recording, processing, summarizing and
reporting, within the time periods specified in the Securities and Exchange
Commission's rules and forms, of information required to be disclosed by the
issuer in the reports that it files or submits under the Exchange Act.
There were no significant changes in ConocoPhillips' internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of the evaluation referred to above.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1. Financial Statements and Financial Statement Schedules
------------------------------------------------------
The financial statements and schedule listed in the Index to Financial
Statements and Financial Statement Schedules, which appears on page 82
are filed as part of this annual report.
2. Exhibits
--------
The exhibits listed in the Index to Exhibits, which appears on pages
178 through 181, are filed as a part of this annual report.
(b) Reports on Form 8-K
-------------------
During the three months ended December 31, 2002, the company filed the
following Current Reports on Form 8-K:
o Amendment No. 1, filed October 1, 2002, to the Current Report on
Form 8-K filed August 30, 2002, providing audited financial
statements and pro forma financial information related to the
merger of Conoco and Phillips.
o Filed on October 8, 2002, to report in Item 5 the private placement
of $2 billion of various types of Notes and to report the company's
third-quarter 2002 interim update of market and operating
conditions.
o Filed on December 20, 2002, to report in Item 5 that the company was
restating its audited financial statements included in its Annual
Report on Form 10-K for the year ended December 31, 2001, to reflect
discontinued operations and a segment realignment.
176
CONOCOPHILLIPS
(CONSOLIDATED)
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars
-----------------------------------------------------------------------------------
Additions
---------------------------
Balance At Charged to Balance At
Description January 1 Expense Other Deductions December 31
------------------------------------------------------------------------------------------------------------------------------------
(a) (b)
2002
Deducted from asset accounts:
Allowance for doubtful accounts and notes
receivable $ 33 21 13 19(c) 48
Deferred tax asset valuation allowance 263 102 251(f) 8 608
Included in other liabilities:
Employee termination benefits -- 301 297(f) 223(g) 375
------------------------------------------------------------------------------------------------------------------------------------
2001
Deducted from asset accounts:
Allowance for doubtful accounts and notes
receivable $ 18 13 18 16(c) 33
Deferred tax asset valuation allowance 315 14 (47) 19 263
Included in other liabilities:
Reserve for maintenance turnarounds 47 -- -- 47(e) --
------------------------------------------------------------------------------------------------------------------------------------
2000
Deducted from asset accounts:
Allowance for doubtful accounts and notes
receivable $ 19 8 -- 9*(c) 18
Deferred tax asset valuation allowance 328 (11) (2) -- 315
Included in other liabilities:
Reserve for maintenance turnarounds 88 52 -- 93(d) 47
------------------------------------------------------------------------------------------------------------------------------------
*Includes $2 million transferred to joint-venture companies.
(a) Amounts charged to income less reversal of amounts previously charged to
income.
(b) Represents acquisitions/dispositions and the effect of translating foreign
financial statements.
(c) Amounts charged off less recoveries of amounts previously charged off.
(d) Includes $24 million transferred to an equity-affiliate company on July 1,
2000.
(e) Effective January 1, 2001, ConocoPhillips changed its method of accounting
for the costs of major maintenance turnarounds from the accrue-in-advance
method to the expense-as-incurred method.
(f) Included in the merger purchase price allocation.
(g) Benefit payments.
177
CONOCOPHILLIPS
INDEX TO EXHIBITS
Exhibit
Number Description
------ -----------
2 Agreement and Plan of Merger, dated as of November 18, 2001, by and
among ConocoPhillips Company (formerly named Phillips Petroleum
Company) ("CPCo"), ConocoPhillips (formerly named CorvettePorsche
Corp.), P Merger Corp. (formerly named Porsche Merger Corp.), C Merger
Corp. (formerly named Corvette Merger Corp.) and ConocoPhillips
Holding Company (formerly named Conoco Inc.) ("Holding") (incorporated
by reference to Annex A to the Joint Proxy Statement/Prospectus
included in ConocoPhillips' Registration Statement on Form S-4;
Registration No. 333-74798 (the "Form S-4")).
3.1 Restated Certificate of Incorporation of ConocoPhillips (incorporated
by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on
Form 8-K filed on August 30, 2002; File No. 000-49987 (the "Form
8-K")).
3.2 Certificate of Designations of Series A Junior Participating Preferred
Stock of ConocoPhillips (incorporated by reference to Exhibit 3.2 to
the Form 8-K).
3.3 By-Laws of ConocoPhillips (incorporated by reference to Exhibit 3.3 to
the Form 8-K).
4.1 Rights agreement, dated as of June 30, 2002, between ConocoPhillips
and Mellon Investor Services LLC, as rights agent, which includes as
Exhibit A the form of Certificate of Designations of Series A Junior
Participating Preferred Stock, as Exhibit B the form of Rights
Certificate and as Exhibit C the Summary of Rights to Purchase
Preferred Stock (incorporated by reference to Exhibit 4.1 to the Form
8-K).
ConocoPhillips and its subsidiaries are parties to several debt
instruments under which the total amount of securities authorized does
not exceed 10% of the total assets of ConocoPhillips and its
subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A)
of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a
copy of such instruments to the SEC upon request.
MATERIAL CONTRACTS
10.1 Trust Agreement dated June 23, 1995, between CPCo and WestStar Bank,
as Trustee of the Deferred Compensation Plan for Non-Employee
Directors of Phillips Petroleum Company Trust.
10.2 Trust Agreement dated December 12, 1995, between CPCo and Vanguard
Fiduciary Trust Company, as Trustee of the Phillips Petroleum Company
Compensation and Benefits Arrangements Stock Trust (incorporated by
reference to Exhibit 10(c) to the Annual Report of CPCo on Form 10-K
for the year ended December 31, 1995; File No. 1-720).
10.3 Contribution Agreement, dated as of December 16, 1999, by and among
CPCo, Duke Energy Corporation and Duke Energy Field Services, LLC
(incorporated by reference to Exhibit 99.1 to the Current Report of
CPCo on Form 8-K, filed December 22, 1999; File No. 1-720).
178
Exhibit
Number Description
------ -----------
10.4 Governance Agreement, dated as of December 16, 1999, by and among
CPCo, Duke Energy Corporation and Duke Energy Field Services, LLC
(incorporated by reference to Exhibit 99.2 to the Current Report of
CPCo on Form 8-K, filed December 22, 1999; File No. 1-720).
10.5 Amended and Restated Limited Liability Company Agreement of Duke
Energy Field Services, LLC, dated as of March 31, 2000, by and between
Phillips Gas Company and Duke Energy Field Services Corporation
(incorporated by reference to Exhibit 99.1 to the Current Report of
CPCo on Form 8-K, filed April 13, 2000; File No. 1-720).
10.6 Parent Company Agreement, dated as of March 31, 2000, by and among
CPCo, Duke Energy Corporation, Duke Energy Field Services, LLC, and
Duke Energy Field Services Corporation (incorporated by reference to
Exhibit 99.2 to the Current Report of CPCo on Form 8-K, filed April
13, 2000; File No. 1-720).
10.7 Contribution Agreement, dated as of May 23, 2000, by and among CPCo,
Chevron Corporation and Chevron Phillips Chemical Company LLC
(incorporated by reference to Exhibit 2.1 to the Current Report of
CPCo on Form 8-K, filed June 1, 2000; File No. 1-720).
10.8 Amended and Restated Limited Liability Company Agreement of Chevron
Phillips Chemical Company LLC, dated as of July 1, 2000, by and
between CPCo, Chevron Corporation, Chevron U.S.A. Inc., Chevron
Overseas Petroleum Inc., Chevron Pipe Line Company, Drilling
Specialties Co., WesTTex 66 Pipeline Co., and Phillips Petroleum
International Corporation (incorporated by reference to Exhibit 99.1
to the Current Report of CPCo on Form 8-K filed July 14, 2000; File
No. 1-720).
10.9 Master Purchase and Sale Agreement dated as of March 15, 2000, as
amended as of April 6, 2000, among Atlantic Richfield Company,
CH-Twenty, Inc., BP Amoco p.l.c. and CPCo (incorporated by reference
to Exhibit 2 to the Current Report of CPCo on Form 8-K, filed April
18, 2000; File No. 1-720).
10.10 Trust Agreement dated June 1, 1998, between CPCo and Wachovia Bank,
N.A., as Trustee of the Phillips Petroleum Company Grantor Trust.
MANAGEMENT CONTRACTS AND COMPENSATORY PLANS OR ARRANGEMENTS
10.11 1986 Stock Plan of Phillips Petroleum Company.
10.12 1990 Stock Plan of Phillips Petroleum Company.
10.13 Annual Incentive Compensation Plan of Phillips Petroleum Company.
10.14 Incentive Compensation Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10(g) to the Annual Report of
CPCo on Form 10-K for the year ended December 31, 1999; File No.
1-720).
179
Exhibit
Number Description
------ -----------
10.15 Principal Corporate Officers Supplemental Retirement Plan of Phillips
Petroleum Company (incorporated by reference to Exhibit 10(h) to the
Annual Report of CPCo on Form 10-K for the year ended December 31,
1995; File No. 1-720)
10.16 Phillips Petroleum Company Supplemental Executive Retirement Plan
(incorporated by reference to Exhibit 10(n) to the Annual Report of
CPCo on Form 10-K for the year ended December 31, 2000; File No.
1-720).
10.17 Key Employee Deferred Compensation Plan of Phillips Petroleum Company.
10.18 Non-Employee Director Retirement Plan of Phillips Petroleum Company.
10.19 Omnibus Securities Plan of Phillips Petroleum Company.
10.20 Deferred Compensation Plan for Non-Employee Directors of Phillips
Petroleum Company.
10.21 Key Employee Missed Credited Service Retirement Plan of Phillips
Petroleum Company (incorporated by reference to Exhibit 10(s) to the
Annual Report of CPCo on Form 10-K for the year ended December 31,
2000; File No. 1-720).
10.22 Phillips Petroleum Company Stock Plan for Non-Employee Directors.
10.23 Key Employee Supplemental Retirement Plan of Phillips Petroleum
Company.
10.24 Defined Contribution Makeup Plan of ConocoPhillips.
10.25 Phillips Petroleum Company Executive Severance Plan (incorporated by
reference to Exhibit 10(a) to the Quarterly Report of CPCo on Form
10-Q for the quarter ended June 30, 1999; File No. 1-720).
10.26 2002 Omnibus Securities Plan of Phillips Petroleum Company.
10.27 1998 Stock and Performance Incentive Plan of ConocoPhillips.
10.28 1998 Key Employee Stock Performance Plan of ConocoPhillips.
10.29 Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips.
10.30 Conoco Inc. Key Employee Severance Plan (incorporated by reference to
Exhibit 10.6 to the Annual Report of Holding on Form 10-K for the year
ended December 31, 2001; File No. 1-14521).
10.31 Conoco Inc. Salary Deferral and Savings Restoration Plan.
10.32 Conoco Inc. Directors' Charitable Gift Plan.
10.33 Phillips Petroleum Company Director Charitable Contribution Plan.
180
Exhibit
Number Description
------ -----------
10.34 ConocoPhillips Form Indemnity Agreement with Directors.
10.35 Employment Agreement, dated as of November 18, 2001, by and among
ConocoPhillips, CPCo and J. J. Mulva (incorporated by reference to
Exhibit 10.1 to the Form S-4).
10.36 Employment Agreement, dated as of November 18, 2001, by and among
ConocoPhillips, Holding and Archie W. Dunham (incorporated by
reference to Exhibit 10.2 to the Form S-4).
10.36.1 Letter Agreement, dated as of July 22, 2002, by and among Holding and
Archie W. Dunham.
10.37 Letter Agreement, dated as of April 12, 2002, between Holding and
Robert E. McKee III (incorporated by reference to Exhibit 10.1 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly
period ended September 30, 2002; File No. 000-49987 (the "Form
10-Q")).
10.38 Letter Agreement, dated as of April 12, 2002, between Holding and Jim
W. Nokes (incorporated by reference to Exhibit 10.2 to the Form 10-Q).
10.39 Rabbi Trust Agreement dated December 17, 1999 (incorporated by
reference to Exhibit 10.11 of Holding's Form 10-K for the year ended
December 31, 1999, File No. 001-14521).
10.39.1 Amendment to Rabbi Trust Agreement dated February 25, 2002.
12 Computation of Ratio of Earnings to Fixed Charges.
21 List of Principal Subsidiaries of ConocoPhillips.
23 Consent of Independent Auditors.
99.1 Certification pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 Certification pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.3 Unaudited Pro Forma Combined Statement of Operations for the Year
Ended December 31, 2002.
181
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.
CONOCOPHILLIPS
March 24, 2003 /s/ J. J. Mulva
-------------------------------------
J. J. Mulva
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed on behalf of the registrant by the following officers in the
capacity indicated and by a majority of directors in response to Instruction D
to Form 10-K on March 24, 2003.
SIGNATURE TITLE
/s/ Archie W. Dunham Chairman of the Board of Directors
--------------------------------
Archie W. Dunham
/s/ J. J. Mulva President and Chief Executive Officer
-------------------------------- (Principal executive officer)
J. J. Mulva
/s/ John A. Carrig Executive Vice President, Finance,
-------------------------------- and Chief Financial Officer
John A. Carrig (Principal financial officer)
/s/ Rand C. Berney Vice President and Controller
-------------------------------- (Principal accounting officer)
Rand C. Berney
182
/s/ Kenneth M. Duberstein Director and Member of
-------------------------------- Audit and Compliance Committee
Kenneth M. Duberstein
/s/ Ruth R. Harkin Director and Member of
-------------------------------- Audit and Compliance Committee
Ruth R. Harkin
/s/ Larry D. Horner Director and Member of
-------------------------------- Audit and Compliance Committee
Larry D. Horner
/s/ Frank A. McPherson Director and Chairperson of
-------------------------------- Audit and Compliance Committee
Frank A. McPherson
/s/ J. Stapleton Roy Director and Member of
-------------------------------- Audit and Compliance Committee
J. Stapleton Roy
/s/ Victoria J. Tschinkel Director and Chairperson of
-------------------------------- Public Policy Committee
Victoria J. Tschinkel
/s/ Kathryn C. Turner Director and Member of
-------------------------------- Audit and Compliance Committee
Kathryn C. Turner
183
CERTIFICATIONS
I, J.J. Mulva, certify that:
1. I have reviewed this annual report on Form 10-K of ConocoPhillips;
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 registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officers 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 registrant and
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, 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;
b) evaluated the effectiveness of the registrant'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
c) 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 registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers 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.
Date: March 24, 2003
/s/ J. J. Mulva
--------------------------------------
J. J. Mulva
President and Chief Executive Officer
184
I, John A. Carrig, certify that:
1. I have reviewed this annual report on Form 10-K of ConocoPhillips;
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 registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officers 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 registrant and
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, 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;
b) evaluated the effectiveness of the registrant'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
c) 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 registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers 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.
Date: March 24, 2003
/s/ John A. Carrig
---------------------------------------------
John A. Carrig
Executive Vice President, Finance, and Chief
Financial Officer
185
CONOCOPHILLIPS
INDEX TO EXHIBITS
Exhibit
Number Description
------ -----------
2 Agreement and Plan of Merger, dated as of November 18, 2001, by and
among ConocoPhillips Company (formerly named Phillips Petroleum
Company) ("CPCo"), ConocoPhillips (formerly named CorvettePorsche
Corp.), P Merger Corp. (formerly named Porsche Merger Corp.), C Merger
Corp. (formerly named Corvette Merger Corp.) and ConocoPhillips
Holding Company (formerly named Conoco Inc.) ("Holding") (incorporated
by reference to Annex A to the Joint Proxy Statement/Prospectus
included in ConocoPhillips' Registration Statement on Form S-4;
Registration No. 333-74798 (the "Form S-4")).
3.1 Restated Certificate of Incorporation of ConocoPhillips (incorporated
by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on
Form 8-K filed on August 30, 2002; File No. 000-49987 (the "Form
8-K")).
3.2 Certificate of Designations of Series A Junior Participating Preferred
Stock of ConocoPhillips (incorporated by reference to Exhibit 3.2 to
the Form 8-K).
3.3 By-Laws of ConocoPhillips (incorporated by reference to Exhibit 3.3 to
the Form 8-K).
4.1 Rights agreement, dated as of June 30, 2002, between ConocoPhillips
and Mellon Investor Services LLC, as rights agent, which includes as
Exhibit A the form of Certificate of Designations of Series A Junior
Participating Preferred Stock, as Exhibit B the form of Rights
Certificate and as Exhibit C the Summary of Rights to Purchase
Preferred Stock (incorporated by reference to Exhibit 4.1 to the Form
8-K).
ConocoPhillips and its subsidiaries are parties to several debt
instruments under which the total amount of securities authorized does
not exceed 10% of the total assets of ConocoPhillips and its
subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A)
of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a
copy of such instruments to the SEC upon request.
MATERIAL CONTRACTS
10.1 Trust Agreement dated June 23, 1995, between CPCo and WestStar Bank,
as Trustee of the Deferred Compensation Plan for Non-Employee
Directors of Phillips Petroleum Company Trust.
10.2 Trust Agreement dated December 12, 1995, between CPCo and Vanguard
Fiduciary Trust Company, as Trustee of the Phillips Petroleum Company
Compensation and Benefits Arrangements Stock Trust (incorporated by
reference to Exhibit 10(c) to the Annual Report of CPCo on Form 10-K
for the year ended December 31, 1995; File No. 1-720).
10.3 Contribution Agreement, dated as of December 16, 1999, by and among
CPCo, Duke Energy Corporation and Duke Energy Field Services, LLC
(incorporated by reference to Exhibit 99.1 to the Current Report of
CPCo on Form 8-K, filed December 22, 1999; File No. 1-720).
Exhibit
Number Description
------ -----------
10.4 Governance Agreement, dated as of December 16, 1999, by and among
CPCo, Duke Energy Corporation and Duke Energy Field Services, LLC
(incorporated by reference to Exhibit 99.2 to the Current Report of
CPCo on Form 8-K, filed December 22, 1999; File No. 1-720).
10.5 Amended and Restated Limited Liability Company Agreement of Duke
Energy Field Services, LLC, dated as of March 31, 2000, by and between
Phillips Gas Company and Duke Energy Field Services Corporation
(incorporated by reference to Exhibit 99.1 to the Current Report of
CPCo on Form 8-K, filed April 13, 2000; File No. 1-720).
10.6 Parent Company Agreement, dated as of March 31, 2000, by and among
CPCo, Duke Energy Corporation, Duke Energy Field Services, LLC, and
Duke Energy Field Services Corporation (incorporated by reference to
Exhibit 99.2 to the Current Report of CPCo on Form 8-K, filed April
13, 2000; File No. 1-720).
10.7 Contribution Agreement, dated as of May 23, 2000, by and among CPCo,
Chevron Corporation and Chevron Phillips Chemical Company LLC
(incorporated by reference to Exhibit 2.1 to the Current Report of
CPCo on Form 8-K, filed June 1, 2000; File No. 1-720).
10.8 Amended and Restated Limited Liability Company Agreement of Chevron
Phillips Chemical Company LLC, dated as of July 1, 2000, by and
between CPCo, Chevron Corporation, Chevron U.S.A. Inc., Chevron
Overseas Petroleum Inc., Chevron Pipe Line Company, Drilling
Specialties Co., WesTTex 66 Pipeline Co., and Phillips Petroleum
International Corporation (incorporated by reference to Exhibit 99.1
to the Current Report of CPCo on Form 8-K filed July 14, 2000; File
No. 1-720).
10.9 Master Purchase and Sale Agreement dated as of March 15, 2000, as
amended as of April 6, 2000, among Atlantic Richfield Company,
CH-Twenty, Inc., BP Amoco p.l.c. and CPCo (incorporated by reference
to Exhibit 2 to the Current Report of CPCo on Form 8-K, filed April
18, 2000; File No. 1-720).
10.10 Trust Agreement dated June 1, 1998, between CPCo and Wachovia Bank,
N.A., as Trustee of the Phillips Petroleum Company Grantor Trust.
MANAGEMENT CONTRACTS AND COMPENSATORY PLANS OR ARRANGEMENTS
10.11 1986 Stock Plan of Phillips Petroleum Company.
10.12 1990 Stock Plan of Phillips Petroleum Company.
10.13 Annual Incentive Compensation Plan of Phillips Petroleum Company.
10.14 Incentive Compensation Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10(g) to the Annual Report of
CPCo on Form 10-K for the year ended December 31, 1999; File No.
1-720).
Exhibit
Number Description
------ -----------
10.15 Principal Corporate Officers Supplemental Retirement Plan of Phillips
Petroleum Company (incorporated by reference to Exhibit 10(h) to the
Annual Report of CPCo on Form 10-K for the year ended December 31,
1995; File No. 1-720)
10.16 Phillips Petroleum Company Supplemental Executive Retirement Plan
(incorporated by reference to Exhibit 10(n) to the Annual Report of
CPCo on Form 10-K for the year ended December 31, 2000; File No.
1-720).
10.17 Key Employee Deferred Compensation Plan of Phillips Petroleum Company.
10.18 Non-Employee Director Retirement Plan of Phillips Petroleum Company.
10.19 Omnibus Securities Plan of Phillips Petroleum Company.
10.20 Deferred Compensation Plan for Non-Employee Directors of Phillips
Petroleum Company.
10.21 Key Employee Missed Credited Service Retirement Plan of Phillips
Petroleum Company (incorporated by reference to Exhibit 10(s) to the
Annual Report of CPCo on Form 10-K for the year ended December 31,
2000; File No. 1-720).
10.22 Phillips Petroleum Company Stock Plan for Non-Employee Directors.
10.23 Key Employee Supplemental Retirement Plan of Phillips Petroleum
Company.
10.24 Defined Contribution Makeup Plan of ConocoPhillips.
10.25 Phillips Petroleum Company Executive Severance Plan (incorporated by
reference to Exhibit 10(a) to the Quarterly Report of CPCo on Form
10-Q for the quarter ended June 30, 1999; File No. 1-720).
10.26 2002 Omnibus Securities Plan of Phillips Petroleum Company.
10.27 1998 Stock and Performance Incentive Plan of ConocoPhillips.
10.28 1998 Key Employee Stock Performance Plan of ConocoPhillips.
10.29 Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips.
10.30 Conoco Inc. Key Employee Severance Plan (incorporated by reference to
Exhibit 10.6 to the Annual Report of Holding on Form 10-K for the year
ended December 31, 2001; File No. 1-14521).
10.31 Conoco Inc. Salary Deferral and Savings Restoration Plan.
10.32 Conoco Inc. Directors' Charitable Gift Plan.
10.33 Phillips Petroleum Company Director Charitable Contribution Plan.
Exhibit
Number Description
------ -----------
10.34 ConocoPhillips Form Indemnity Agreement with Directors.
10.35 Employment Agreement, dated as of November 18, 2001, by and among
ConocoPhillips, CPCo and J. J. Mulva (incorporated by reference to
Exhibit 10.1 to the Form S-4).
10.36 Employment Agreement, dated as of November 18, 2001, by and among
ConocoPhillips, Holding and Archie W. Dunham (incorporated by
reference to Exhibit 10.2 to the Form S-4).
10.36.1 Letter Agreement, dated as of July 22, 2002, by and among Holding and
Archie W. Dunham.
10.37 Letter Agreement, dated as of April 12, 2002, between Holding and
Robert E. McKee III (incorporated by reference to Exhibit 10.1 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly
period ended September 30, 2002; File No. 000-49987 (the "Form
10-Q")).
10.38 Letter Agreement, dated as of April 12, 2002, between Holding and Jim
W. Nokes (incorporated by reference to Exhibit 10.2 to the Form 10-Q).
10.39 Rabbi Trust Agreement dated December 17, 1999 (incorporated by
reference to Exhibit 10.11 of Holding's Form 10-K for the year ended
December 31, 1999, File No. 001-14521).
10.39.1 Amendment to Rabbi Trust Agreement dated February 25, 2002.
12 Computation of Ratio of Earnings to Fixed Charges.
21 List of Principal Subsidiaries of ConocoPhillips.
23 Consent of Independent Auditors.
99.1 Certification pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 Certification pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.3 Unaudited Pro Forma Combined Statement of Operations for the Year
Ended December 31, 2002.