Unless otherwise indicated, the company, we, our, us, 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 companys 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, goal, may,
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 companys
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 83.
Items 1 and 2. BUSINESS AND PROPERTIES
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
Our business is organized into five operating segments:
Exploration and Production (E&P)This segment primarily explores
for and produces crude oil, natural gas, and natural gas liquids on a
MidstreamThrough 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 our 30.3 percent equity investment in Duke Energy Field
Services, LLC, a joint venture with Duke Energy.
Refining and Marketing (R&M)This segment refines, markets and
transports crude oil and petroleum products, mainly in the United
States, Europe and Asia.
ChemicalsThis segment manufactures and markets petrochemicals and
plastics on a worldwide basis. The Chemicals segment consists of our
50 percent equity investment in Chevron Phillips Chemical Company LLC,
a joint venture with ChevronTexaco Corporation.
Emerging BusinessesThis segment encompasses the development of new
businesses beyond our traditional operations. Emerging Businesses
includes new technologies related to natural gas conversion into clean
fuels and related products (gas-to-liquids), technology solutions,
power generation, and emerging technologies.
At December 31, 2003, ConocoPhillips employed approximately 39,000 people.
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment information and geographic information, see Note
28Segment Disclosures and Related Information in the Notes to Consolidated
Financial Statements, which is incorporated herein by reference.
EXPLORATION AND PRODUCTION (E&P)
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,
2003, our E&P operations were producing in the United States, the Norwegian and
U.K. sectors of the North Sea, Canada, Nigeria, Venezuela, offshore Timor Lesté
in the Timor Sea, offshore Australia, offshore China, offshore the United Arab
Emirates, offshore Vietnam, Russia, and Indonesia.
The information listed below appears in the supplemental oil and gas operations
disclosures on pages 154 through 172 and is incorporated herein by reference:
Proved worldwide crude oil, natural gas and natural gas liquids reserves;
Net production of crude oil, natural gas and natural gas liquids;
Average sales prices of crude oil, natural gas and natural gas liquids;
Average production costs per barrel-of-oil-equivalent;
Net wells completed, wells in progress, and productive wells; and
Developed and undeveloped acreage.
In 2003, our worldwide production, including our share of equity affiliates
production, averaged 1,590,000 barrels-of-oil-equivalent (BOE) per day, a 49
percent increase from 1,069,000 BOE per day in 2002. During 2003, 674,000 BOE
per day were produced in the United States, a 15 percent increase from 587,000
BOE per day in 2002. Production from our international E&P operations
averaged 916,000 BOE per day in 2003, up 90 percent from 482,000 BOE per day in
2002. In addition, our Canadian Syncrude mining operations had net production
of 19,000 barrels per day in 2003, compared with 8,000 barrels per day in 2002.
The increased production mainly reflects the impact of the merger. We convert
our natural gas production to BOE based on a 6:1 ratio: six thousand cubic feet
of natural gas equals one barrel-of-oil-equivalent.
Our worldwide annual average crude oil sales price increased 14 percent in
2003, from $24.07 per barrel to $27.47 per barrel. Our annual average
worldwide natural gas sales price also increased, going from $2.77 per thousand
cubic feet in 2002 to $4.07 per thousand cubic feet in 2003.
Finding and development costs in 2003 were $5.35 per barrel-of-oil-equivalent,
compared with $5.57 in 2002. Over the last five years, our finding and
development costs averaged $4.29 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, 2003, ConocoPhillips, including its share of equity affiliates,
held a combined 52.6 million net developed and undeveloped acres, compared with
101.9 million net acres at year-end 2002. The decrease in acreage primarily
reflects the removal of acreage in Somalia, where operations had been suspended
by declarations of force majeure. At year-end 2003, we held acreage in 25
In 2003, U.S. E&P operations contributed 43 percent of our worldwide liquids
production and 42 percent of our worldwide natural gas production. Our U.S.
E&P operations are managed in two divisions: Alaska and the Lower 48 States.
We are a major producer of crude oil on Alaskas North Slope, and we produce
natural gas in the Cook Inlet. A brief summary of our major Alaska 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. We have a 36.1 percent
interest in all fields within the Greater Prudhoe Area, all of which are
operated by BP p.l.c. (BP).
The Prudhoe Bay field is the largest oil field on Alaskas 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 reinjects natural gas back into the
reservoir. Our net crude oil production from the Prudhoe Bay field averaged
121,500 barrels per day in 2003, compared with 130,800 barrels per day in 2002,
while natural gas liquids production averaged 23,000 barrels per day in 2003,
compared with 24,100 barrels per day in 2002. Normal field declines were the
main cause of the lower production rates in 2003.
Prudhoe Bay satellite fields Aurora, Borealis, Polaris, Midnight Sun, and Orion
produced 16,200 net barrels per day of crude oil in 2003, compared with 12,700
net barrels per day in 2002. Borealis contributed the biggest share in 2003,
producing 10,300 net barrels per day. All Prudhoe Bay satellite fields are
produced through Prudhoe Bay production facilities. Development options and
plans are being studied for other potential Prudhoe Bay satellites.
The Greater Point McIntyre Area (GPMA) is made up of the Point McIntyre,
Niakuk, Lisburne, West Beach, and North Prudhoe Bay State fields. The fields
within the GPMA are generally produced through the Lisburne Production Center.
Net crude oil production for GPMA averaged 18,200 barrels per day in 2003,
compared with 19,800 barrels per day in 2002. The bulk of this production came
from the Point McIntyre field, which is approximately seven miles north of the
Prudhoe Bay field and extends into the Beaufort Sea.
Greater Kuparuk Area
We operate the Greater Kuparuk Area, which is comprised of the Kuparuk field
and four satellite fields: Tarn, Tabasco, Meltwater, and West Sak. Our
ownership interest is 55.2 percent in the Kuparuk field, which is located about
40 miles west of Prudhoe Bay. Field installations include three central
production facilities that separate oil, natural gas and water. The natural
gas is either used for fuel or compressed for reinjection. Our net crude oil
production from the Kuparuk field averaged 78,600 barrels per day in 2003,
compared with 79,000 barrels per day in 2002. Natural production declines from
Kuparuk were offset by an average of 8,000 barrels per day of production from
the Palm discovery that extended the Kuparuk field to the west about three
miles. Development of the Palm discovery included the construction of a new
drill site and the drilling of 17 wells. Palm production began in November
Other fields in the Greater Kuparuk Area produced 21,800 net barrels per day of
crude oil in 2003, primarily from the Tarn, Tabasco, and Meltwater satellites.
We have a 55.3 percent interest in Tarn and Tabasco and a 55.4 percent interest
The Greater Kuparuk Area also includes the West Sak heavy-oil field. Annual
production rates increased from 3,300 net barrels per day in 2002 to 3,800 net
barrels per day in 2003. Progress was made in 2003 towards proving concepts
necessary for full-scale development of this field. Eight wells were drilled
during the year, increasing production from 3,300 net barrels per day in the
month of December 2002 to 5,000 net barrels per day in the month of December
2003. We have a 55.3 percent interest in this field.
Western North Slope
The Alpine field, located west of the Kuparuk field, began production in
November 2000. In 2003, the field produced at a net rate of 64,500 barrels of
oil per day, compared with 63,400 barrels per day in 2002. We are the operator
and hold a 78 percent interest in Alpine.
In May 2003, we announced plans to increase produced water and natural gas
handling capacities at our Alpine production facilities. Although we inject
seawater into the Alpine reservoir as a means of enhanced oil recovery, most
production has been almost 100 percent oil. Eventually, the injected water and
natural gas will start to break through into the producing wells, requiring an
increase in the amount of produced water and natural gas that needs to be
handled. The increase in water and natural gas handling capacities should
allow crude oil production to remain at or slightly above current production
rates for a longer period of time than could otherwise have been achieved.
Startup of the expanded facilities is planned to commence by the end of 2004.
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
Alpine 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, currently
expected in second half of 2004, and the appropriate permits have been granted.
Our assets in Alaska include the North Cook Inlet field, the Beluga River
natural gas field, and the Kenai liquefied natural gas facility.
We have a 100 percent interest in the North Cook Inlet field. Net production
in 2003 averaged 112 million cubic feet per day, compared with 125 million
cubic feet per day in 2002. All of the production from the North Cook Inlet
field is used to supply our share of gas to the Kenai liquefied natural gas
plant. The decline in production in 2003 was the result of well problems.
Well work completed in late 2003 and planned for 2004 is expected to improve
Our interest in the Beluga River field is 33 percent. Net production averaged
63 million cubic feet per day in 2003, compared with 41 million cubic feet per
day in 2002. Gas from the Beluga River field is sold to local utilities,
industrial consumers, and used as back-up supply to the Kenai liquefied natural
We have a 70 percent interest in the Kenai liquefied natural gas plant, which
supplies liquefied natural gas to two utility companies in Japan. Utilizing
two ships, the company transports the liquefied natural gas to Japan, where it
is reconverted to dry gas at the receiving terminal. We sold 44.0 billion
cubic feet of liquefied natural gas to Japan in 2003, compared with 44.4
billion cubic feet in 2002.
We drilled or participated in three exploratory wells during 2003, on locations
near Alpine, the NPR-A and the Cook Inlet. Two of these wells are pending
further appraisal, and one was a dry hole. We plan to drill or participate in
four exploration wells in Alaska during 2004.
We transport the petroleum liquids we produce on the North Slope to market
through the Trans-Alaska Pipeline System (TAPS), an 800-mile pipeline, marine
terminal, spill response and escort vessel system that ties the North Slope of
Alaska to the port of Valdez in south-central Alaska.
In 2001, ConocoPhillips and the five other owners of TAPS completed and filed
state and federal applications for renewal of the pipelines 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
Regulatory approval was received in early 2003 for us to purchase an additional
1.5 percent interest in TAPS from Amerada Hess Corporation, thereby increasing
our ownership in TAPS to 28.3 percent. The purchase was effective January 24,
2003. We also have ownership interests in the Alpine, Kuparuk and Oliktok
pipelines on the North Slope.
We continue to evaluate a gas pipeline project to deliver natural gas from
Alaskas North Slope to the Lower 48. Given the size of the project and risk
associated with it, we continue to believe that risk mitigation mechanisms and
improvements in project economics are necessary before this project can
proceed. Activities in 2003 included promoting state and federal legislation
that would lower the economic risk of the project.
Our wholly owned subsidiary, Polar Tankers Inc., manages the marine
transportation of our Alaska North Slope production. Polar Tankers is based in
Long Beach, California, and operates six ships in the Alaskan trade, chartering
additional third-party-operated vessels as necessary. In 2001, Polar Tankers
into service; the
was brought into
service in 2002; and the
was brought into service in 2003.
These 125,000 deadweight-ton, double-hulled crude oil tankers are the first
three of five Endeavour Class tankers that we plan to add to our Alaska-trade
fleet. The fourth and fifth tankers are scheduled to enter the fleet in 2004
and 2005, respectively.
Our operations in the Lower 48 States are principally located in the following
Offshore: Gulf of Mexico
Onshore: various trends in Texas, New Mexico, Oklahoma, Louisiana,
Utah, Colorado, and Wyoming
Gulf of Mexico
Our current portfolio of producing properties in the Gulf of Mexico includes
three fields operated by us and six fields operated by other companies. The
number of fields declined in 2003 with the divestiture of properties as part of
our portfolio rationalization program. At December 31, 2003, we had 22 leases
in production or under development in the deepwater Gulf of Mexico.
We hold a 16 percent interest in the co-venturer-operated Ursa field. The Ursa
tension-leg platform was installed in late 1998 in approximately 3,900 feet of
water, with first production occurring in March 1999. Our net production in
2003 averaged 13,300 barrels per day of liquids and 13 million cubic feet per
day of natural gas.
The Princess field is a northern, subsalt extension of the Ursa field. It was
discovered in 2000, with first production beginning in late 2002 from an
extended-reach well from the Ursa platform. A three-well subsea tieback to the
Ursa platform was completed in 2003. Our net production in 2003 averaged 2,600
barrels per day of liquids and 7.3 million cubic feet per day of natural gas.
We hold a 16 percent interest in Princess.
We operate and hold a 75 percent interest in the Garden Banks 783 and 784
leases which contain the Magnolia field discovered in 1999. Installation of a
tension-leg platform, to be located in almost 4,700 feet of water, is expected
in mid-2004, with first oil scheduled for late 2004. Peak production of 49,000
net barrels-of-oil-equivalent per day is expected in 2005 from proved reserves.
We have a 16.8 percent interest in the K2 discovery. K2, located in Green
Canyon Block 562, was discovered in 1999, with appraisal drilling continuing in
2003. A development option under consideration would utilize a subsea tieback
to a nearby third-party platform. Project sanctioning is expected in the first
quarter of 2004.
In July 2003, we announced a discovery with the Lorien well in Green Canyon
Block 199. The well was drilled in 2,177 feet of water and encountered more
than 120 feet of hydrocarbons. The well has been suspended pending further
appraisal of the hydrocarbon zone. We are the operator with a 65 percent
During 2003, two deepwater exploratory wells did not encounter commercial
quantities of hydrocarbons: the Voss well in Keathley Canyon Block 511 and the
Yorick well in Green Canyon Block 435.
Our onshore Lower 48 production is primarily natural gas, with the majority of
the production located in 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. We also have oil and natural gas production from the Permian Basin
in West Texas and Southeast New Mexico. Other positions and production are
maintained in other parts of Texas and Oklahoma, the Arkansas/Louisiana/Texas
area, and onshore Gulf Coast area. In
addition, we hold coalbed methane acreage positions in the Powder River Basin
in Wyoming, the Uinta Basin in Utah, and the Black Warrior Basin in Alabama.
Activities in 2003 primarily were centered on continued optimization and
development of these mature assets. Combined production from Lower 48 onshore
fields in 2003 averaged a net 1,237 million cubic feet per day of natural gas
and 57,000 barrels per day of liquids.
In 2003, E&P operations in Northwest Europe contributed 30 percent of our
worldwide liquids production and 34 percent of our worldwide natural gas
production. Our Northwest Europe assets are principally located in the
Norwegian and U.K. sectors of the North Sea.
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
Ekofisk infrastructure. Net production in 2003 from the Ekofisk Area was
126,500 barrels of liquids per day and 127 million cubic feet of natural gas
per day, compared with 127,000 barrels of liquids per day and 133 million cubic
feet of natural gas per day in 2002. We are operator and hold a 35.1 percent
interest in Ekofisk.
In 2003, we and our co-venturers approved a plan for further development of the
Ekofisk Area. The project consists of two interrelated components. A new
platform, Ekofisk 2/4M, is anticipated to have 30 well slots, a high-pressure
separator and equipment for produced water treatment. The project also
includes modification on the existing Ekofisk Complex to increase process
capacity. Construction began in 2003 and production from the new platform is
projected to begin in the fall of 2005.
We also have ownership interests in other producing fields in the Norwegian
North Sea, including a 24.3 percent interest in the Heidrun field, a 10.3
percent interest in the Statfjord field, a 23.3 percent interest in the Huldra
field, a 1.6 percent interest in the Troll field, a 9.1 percent interest in the
Visund field, and a 2.4 percent interest in the Oseberg area. Production from
these and other fields in the Norwegian sector of the North Sea and the
Norwegian Sea averaged a net 93,300 barrels of liquids per day and 149 million
cubic feet of natural gas per day in 2003.
In September 2003, production began from the Grane field, in which we have a
6.4 percent interest. Peak production from this field is expected in 2005, and
is anticipated to be approximately 14,000 net barrels per day from proved
We also have interests in certain of the transportation and processing
infrastructure of the Norwegian North Sea, including a 35.1 percent interest in
the Norpipe Oil Pipeline System, a 2.3 percent interest in Gassled, which owns
most of the Norwegian gas transportation system, and a 1.6 percent interest in
the southern part of the planned Langeled gas pipeline.
We are the largest owner in, and the joint operator of, the Britannia natural
gas/condensate field, in which we have a 58.7 percent interest. Our net
production from Britannia averaged 391 million cubic feet of natural gas per
day and 14,500 barrels of liquids per day in 2003. Oil and gas production from
Britannia is delivered by pipeline to Scotland. Development drilling on
Britannia is expected to continue into the year 2006.
In December 2003, we approved a plan for the development of the Callanish and
Brodgar fields. These new Britannia satellite development projects will be
tied back to the Britannia facility, with first production targeted for 2007.
The development plan has been submitted for government approval. We have a 75
percent interest in the Brodgar field and an 83.5 percent interest in the
We operate and hold 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. We are the operator of and hold a 32.5 percent interest in
Jade. Together, these fields produced a net 18,100 barrels of liquids per day
and 118 million cubic feet of natural gas per day in 2003.
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 in respect of the J-Block gas sales
agreement, including outstanding amounts due for the period prior to the
appointment of the Administrator. We believe that Enron Capital will continue
to pay the amounts due for gas supplied by us in accordance with the terms of
the gas sales agreement. We do not currently expect that we 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 that the
arrangements for the processing of Enron Capitals gas are terminated or Enron
Capital goes into liquidation, there may be additional risk of production being
reduced or shut-in.
We have various ownership interests in 13 producing gas fields in the southern
North Sea, in the Rotliegendes and Carboniferous areas. These fields mostly
feed into the ConocoPhillips-operated Theddlethorpe gas processing facility
through three ConocoPhillips-operated pipeline systems. Net production in 2003
averaged 371 million cubic feet per day of natural gas and 2,000 barrels of
liquids per day.
During 2003 we continued the development of the CMS3 area in the southern
sector of the U.K. North Sea, which consists of five natural gas reservoirs
currently being developed by us as a single, unitized project. The McAdam and
Watt fields were brought onstream in 2003, following the Hawksley and Murdoch K
fields in 2002. Drilling operations on the final reservoir, Boulton H, are
ongoing into 2004. Collectively, these fields are known as CMS3 due to their
utilization of the production and transportation facilities of the
ConocoPhillips-operated Caister Murdoch System (CMS). We are the operator of
CMS3 and hold a 59.5 percent interest.
We also have 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, an 11.5 percent interest in the Armada field,
and a 4.8 percent interest in the Statfjord field. Production from these and
the other remaining fields in the U.K. sector of the North Sea averaged a net
44,500 barrels of liquids per day and 61 million cubic feet of natural gas per
day in 2003.
We have a 24 percent interest in the Clair field development in the Atlantic
Margin. The Clair development is comprised of a conventional steel jacket
structure with minimum manned facilities topside. First production from Clair
is targeted for late 2004.
The Interconnector pipeline, which connects the United Kingdom and Belgium,
facilitates the marketing throughout Europe of the natural gas we produce in
the United Kingdom. Our 10 percent equity share of the Interconnector pipeline
allows us to ship approximately 200 million cubic feet of natural gas per day
to markets in continental Europe. We have multi-year contracts to supply
natural gas to Gasunie in the Netherlands and Wingas in Germany.
In Norway, we drilled or participated in six exploratory and appraisal wells
during 2003 in the deepwater Voring and More basins, the South Viking Graben
and the Central Graben. Of the six wells, three are moving forward with
development plans or pending further evaluation, and three were considered
non-commercial discoveries or dry holes. Four partner-operated exploration
wells are planned for 2004. One is a deepwater prospect in PL 283, and the
other three are near-field exploration wells in the Heidrun and Visund
In the U.K. sector of the North Sea, we drilled or participated in four
exploratory and appraisal wells during 2003 in the southern North Sea, the
central North Sea near the Jade and Britannia fields, and the West of Shetland
deepwater area. Of the four wells, two are moving forward with development
plans and two were dry holes. We plan to participate in three exploratory
wells in 2004, including two wells in the southern North Sea and one on a
structure adjacent to the Callanish field.
In 2003, E&P operations in Canada contributed 5 percent of our worldwide
liquids production and 13 percent of our 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. We separate our holdings in
western Canada into four geographic regions. The north region contains a mix
of oil and natural gas, and primarily is winter access. The central and west
regions produce mainly natural gas. The south region has shallow gas and
medium-to-heavy oil. Production from conventional oil and gas operations in
western Canada averaged a net 40,500 barrels per day of liquids and 435 million
cubic feet per day of natural gas in 2003.
We are working with three other energy companies, as members of the Mackenzie
Delta Producers Group (Group), on the development of the Mackenzie Valley
pipeline, which is proposed to transport onshore gas production from the
Mackenzie Delta in northern Canada to existing markets. Initial design
capacity for the Mackenzie Valley pipeline is proposed to be 1,200 million
cubic feet per day, but capacity would be expandable with additional
compression. We 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. Conceptual engineering commenced
in April 2002. Regulatory applications for the project are expected to be
submitted in mid-2004 and first gas production is currently targeted for late
We owned a 46.7 percent interest in Petrovera, a joint venture that combined a
substantial portion of our Canadian heavy-oil assets and certain associated
natural gas assets. The asset base of the joint venture was located mainly in
southwestern Saskatchewan. Net production in 2003 was 15,300 barrels of
petroleum liquids per day, and was included in equity affiliate production. On
February 18, 2004, we sold our interest in the joint venture.
We hold exploration acreage in three areas of Canada: offshore eastern Canada,
the foothills of western Alberta, and the Mackenzie Delta/Beaufort Sea. In
eastern Canada, we hold a 20 percent interest in deepwater Nova Scotia, EL
2359. After participating in the Newburn well in 2002, we are waiting on the
results from drilling in adjacent blocks. In deepwater Newfoundland, we are
working to convert our large Laurentian permit into specific exploration
licenses. We hope to complete this in 2004 and expect to
acquire seismic in 2005. In the foothills, two out of three exploratory wells
drilled in 2003 were successful. In the Mackenzie Delta/Beaufort Sea, we began
drilling a well in early 2004.
Other Canadian Operations
We have two oil sands projects in Canada: Syncrude Canada Ltd. and Surmont.
Syncrude Canada Ltd.
We own 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. 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 and the associated surface rights, of which our share is approximately
23,000 net acres. Our net share of production averaged 19,000 barrels per day
We continued with development of the Stage III expansion-mining project in
2003, which is expected to increase our Syncrude production. The Aurora Train
2 project (the new mine) was completed and started up in the fourth quarter of
2003. The expansion project is expected to bring various units onstream during
2004, while the completion of a new coker to service the expanded project is
anticipated in the second half of 2005.
The U.S. Securities and Exchange Commissions regulations define this project
as mining-related and not part of conventional oil and gas operations. As
such, Syncrude operations are not included in our proved oil and gas reserves
or production as reported in the supplemental oil and gas information.
The Surmont lease is located about 35 miles south of Fort McMurray, Alberta.
We own a 43.5 percent interest and are the operator. The project will use a
method called steam assisted gravity drainage, that involves the injection of
steam deep into the oil sands, effectively melting the bitumen, which is then
recovered and pumped to the surface for further processing. In May 2003, we
received regulatory approval to develop the oil sands from the Alberta Energy
and Utilities Board, and in late 2003 our Board of Directors approved the
project. Construction of the facilities is expected to begin in early 2004,
with first oil production scheduled for 2006.
In 2003, E&P operations in South America were comprised of interests in
Venezuela, Ecuador and Brazil. South American operations contributed 8 percent
of our worldwide liquids production in 2003.
We operate and have an interest in two heavy-oil projects in Venezuela:
Petrozuata and Hamaca. We also have an interest in and operate in the Gulf of
Paria, which contains the Corocoro conventional oil and gas discovery as well
as exploration opportunities. In addition, we have an interest in Plataforma
Deltana Block 2, a large natural gas discovery.
In December of 2002, civil unrest in Venezuela caused economic and other
disruptions that shut down most oil and gas operations in Venezuela, including
the companys Petrozuata and Hamaca operations. Production from these
operations resumed in the first quarter of 2003.
Petrozuata is a Venezuelan Corporation formed under a 35-year Association
Agreement between a wholly owned subsidiary of ConocoPhillips that has a 50.1
percent non-controlling equity interest and PDVSA Petroleo, a subsidiary of
Petroleos de Venezuela S.A. (PDVSA), the national oil company of Venezuela.
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. Associated by-products produced are liquefied
petroleum gas, sulfur, petroleum coke and heavy gas oil. The medium-grade
crude oil produced by Petrozuata is used as a feedstock for our Lake Charles,
Louisiana, refinery and the Cardon refinery in Venezuela operated by PDVSA.
Our net production was 51,600 barrels of heavy crude oil per day in 2003, and
is included in equity affiliate production.
We 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
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.
The Hamaca project also involves the development of heavy-oil reserves from the
Orinoco Oil Belt. ConocoPhillips owns a 40 percent interest in the Hamaca
project, which is operated by Petrolera Ameriven on behalf of the owners. The
other participants in Hamaca are PDVSA and ChevronTexaco Corporation. Our
interest is held through a joint limited liability company, Hamaca Holding LLC,
for which we use the equity method of accounting.
Net production averaged 22,100 barrels per day of heavy crude oil in 2003, and
is included in equity affiliate production. The joint-venture agreement has a
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 by
the end of 2004, at which time our net production from the Hamaca field is
expected to increase to approximately 71,000 barrels per day from proved
Gulf of Paria
In 1999 the Corocoro discovery in the Gulf of Paria West Block was made and
later confirmed with appraisal drilling in 2001 and 2002. In 2003, Venezuelan
authorities approved Phase I of the development plan for the Corocoro field.
We operate the field with a 32.2 percent interest. In accordance with the
profit sharing agreement that governs the block, a subsidiary of PDVSA elected
to acquire a 35 percent interest in the development, lowering our interest from
50 percent to 32.5 percent. In September 2003, we acquired a 37.5 percent
interest in the adjoining Gulf of Paria East Block, onto which a portion of the
Corocoro discovery extends.
Plataforma Deltana Block 2
We acquired a 40 percent interest in Plataforma Deltana Block 2 in 2003. The
block is co-venturer-operated and holds a gas discovery made by PDVSA in 1983.
Appraisal wells are planned in 2004. Contingent on the results of the
appraisal wells, development of the field may include a well platform in
approximately 300 feet of water, a 170-mile pipeline to shore, and a liquefied
natural gas plant. The liquefied natural gas would be shipped to the U.S.
We have concession agreements on two deepwater exploration blocks (BM-ES-11 and
BM-PAMA-3) offshore Brazil. These blocks were acquired in Brazils third bid
round held in June 2001. We entered into joint ventures on both blocks in late
2002, reducing our interest to 70 percent in BM-ES-11 and 65 percent in
BM-PAMA-3. In 2003, further evaluation led to the write-off of our leasehold
investment in BM-ES-11, and we initiated the process to exit the block.
Further evaluation of BM-PAMA-3 is planned for 2004.
We sold our 14 percent, non-operator interest in Block 16 and the associated
fields on December 5, 2003, with an effective date of January 1, 2003. We have
no other assets in Ecuador, and have exited the country.
In 2003, E&P operations in the Asia Pacific area contributed 6 percent of our
worldwide liquids production and 9 percent of our worldwide natural gas
Our combined net production of crude oil from the Xijiang facilities averaged
10,900 barrels per day in 2003. The Xijiang development consists of three
fields located approximately 80 miles from Hong Kong in the South China Sea.
The facilities include two manned platforms and a floating production, storage
and offloading facility.
Production from Phase I development of the Peng Lai 19-3 field in Bohai Bay
Block 11-05 began in late December 2002. In 2003, the field produced 14,800
net barrels of oil per day. We have 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
We continue to move forward with the design for Phase II of the Peng Lai 19-3
development. Phase II would include multiple wellhead platforms, and a larger
floating production, 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
Exploration activity continued in 2003 in Block 11-05, with two successful
wells announced. The Peng Lai 19-9-1 well, located about two miles east of the
Peng Lai 19-3 field, discovered the Peng Lai 19-9 field that will be part of
the Phase II development. Drilling of the Peng Lai 13-1-1 well, located about
18 miles north of the Peng Lai 19-3 field, was completed in March 2003.
We operate nine Production Sharing Contracts (PSCs) in Indonesia and have a
non-operator interest in four others. Our assets are concentrated in two core
areas: the West Natuna Sea and South Sumatra; with a potentially emerging area
offshore East Java. We are a party to five long-term U.S. dollar pipeline gas
contracts that have been signed in Indonesia. Production of natural gas from
Indonesia averaged a net 255 million cubic feet per day in 2003, while
production of crude oil averaged a net 16,000 barrels per day.
We operate three offshore PSCs: 1) South Natuna Sea Block B, 2) Nila, and 3)
Ketapang. We also hold a non-operator interest in the Pangkah PSC offshore
East Java. We participate in various natural gas marketing arrangements in
connection with these assets, including being a co-venturer in the West Natuna
Gas Supply Group (WNG). The WNG jointly markets natural gas from certain
fields in three South Natuna Sea PSCs to Singapore.
The Kakap PSC, adjacent to the South Natuna Sea Block B, was sold in September
2003. The property was selected for disposition because of its high operating
cost structure and limited further exploration potential. In addition, during
2003 we relinquished the Tobong PSC and sold the Sebuku PSC after concluding
that neither PSC had significant remaining exploration potential.
The South Natuna Sea Block B PSC has two currently producing mature oil fields
and 15 gas fields (some with recoverable oil volumes) in various phases of
development. The largest current development in Block B is the Belanak oil and
gas field, in which a floating production, storage and offloading vessel is
under construction. The vessel is expected to be completed, and oil production
to commence, in the first half of 2005. Two additional developments that would
produce into the Belanak infrastructure are scheduled for startup in 2006 and
We also have an active exploration program in both the Natuna Sea and East
Java. During 2003, two unsuccessful exploratory wells were drilled in the
Natuna Sea Nila Block. An additional well in the Nila Block is planned for
2004. During 2003, in the East Java offshore Ketapang Block, two appraisal
wells were drilled on the Bukit Tua oil field discovery, one of which was
successful, and one of which was unsuccessful. An additional appraisal well
and an exploration well are planned for 2004.
We operate six onshore PSCs: 1) Corridor TAC, 2) Corridor PSC, 3) South Jambi
B, 4) Sakakemang JOB (jointly operated with a co-venturer), 5) Block A PSC in
Aceh, and 6) Warim. We also hold non-operator interests in the Banyumas PSC in
Java and the Bentu and Korinci-Baru PSCs in Sumatra. The Tungkal PSC was sold
in December 2003. As with our offshore properties, we participate in various
gas marketing arrangements in connection with these fields. Exploration
efforts focus on locating additional natural gas reserves.
We announced in March 2003 the successful test of the Suban-8 delineation well
on the southwest flank of the Suban gas field, located in the Corridor PSC of
South Sumatra. In December 2003, we began an exploratory well in the Corridor
Block to test a gas prospect located close to other producing fields. We
continue to appraise and develop the Suban gas field. In addition, we
completed the successful test of the North Sumpal-1 well in the Sakakemang
Block located in South Sumatra, and continued on the construction of the South
Jambi gas project in the South Jambi B Block also located in South Sumatra.
We are a 35 percent owner of TransAsia Pipeline Company Pvt. Ltd., a consortium
company, which has a 40 percent ownership in PT Transportasi Gas Indonesia, an
Indonesian limited liability company, which owns and operates the Grissik to
Duri gas pipeline.
We have a 23.25 percent interest in Block 15-1 in the Cuu Long Basin in the
South China Sea. In 2001, the co-venturers 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. Production from Su Tu Den
Phase I began in the fourth quarter of 2003. The initial net
production rate was approximately 16,000 barrels of oil per day from seven
wells located in the Phase I area. The oil is being processed and stored in a
new floating production, storage and offloading vessel, which has a 1 million
barrel storage capacity and can initially process up to 65,000 gross barrels
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 being evaluated. In addition,
in the fourth quarter of 2003, a successful exploration well was drilled in the
Su Tu Trang (White Lion) area (southeast area of the block).
We have 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. During late 2003, field facilities
were upgraded to include a utilities/living quarters platform, and a central
processing platform with facilities to enable gas lift, gas export and water
injection. With the completion of these facilities, water injection became
possible on all three wellhead platforms and gas lift became possible on two of
the wellhead platforms. A successful appraisal step-out well, Rang Dong-12X,
was drilled in the central part of the field in late 2001, and a development
plan for this area of the field is being evaluated.
We also own 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.
Timor Sea and Australia
The unitized Bayu-Undan field, located in the Timor Sea, 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 back into the
reservoir. This phase began production in February 2004, and is expected to
average a net rate of 23,000 barrels of liquids per day from proved reserves in
In June 2003, we announced that the Gas Development Plan for the field had
received approval from the Timor Sea Designated Authority. This final approval
allowed Phase II, the development of the natural gas reserves, to proceed.
Phase II will involve a natural gas pipeline from the field to Darwin, and a
liquefied natural gas (LNG) facility located at Wickham Point, Darwin. In
March 2002, we announced that we had signed a Heads of Agreement (LNG HOA) with
The Tokyo Electric Power Company, Incorporated (TEPCO) and Tokyo Gas Co., Ltd.
(Tokyo Gas). Under the LNG HOA, TEPCO and Tokyo Gas would purchase 3 million
tons per year in total of LNG for a period of 17 years, utilizing natural gas
from the Bayu-Undan field. The approval of the Gas Development Plan by the
Timor Sea Designated Authority satisfied the remaining condition precedent
necessary for the LNG HOA to have a binding effect and for the project to
proceed. As a result of project approvals, we added 1.36 trillion cubic feet
of net proved natural gas reserves in 2003. The first LNG cargo is scheduled
for delivery in early 2006. We have a 56.7 percent controlling interest in the
We and our co-venturers continue to evaluate commercial development options and
LNG markets in the Asia Pacific region and the North American west coast for
the natural gas and condensate from the Greater Sunrise field. The development
options under consideration consist of an offshore floating LNG facility and an
onshore LNG facility located in Darwin, Australia. Efforts are under way to
market LNG into both the Asian and North American west coast markets. Further
engineering studies relating to design and development concepts also continue.
We have a 30 percent, non-operator interest in Greater Sunrise.
Our crude oil production from five leases in Nigeria averaged a net 36,900
barrels per day in 2003, while net natural gas production averaged 63 million
cubic feet per day. These five leases include four onshore Oil Mining Leases
(OML) and a shallow-water offshore OML. Continued development and exploratory
drilling is planned for 2004 on the onshore leases.
We also have production sharing contracts on deepwater Nigeria Oil Prospecting
Leases (OPLs), including OPL 318 with a 50 percent interest where we are the
operator, OPL 214 with a 20 percent interest and OPL 248 with a 40 percent
interest. We are planning to drill the first exploration well on OPL 248 in
We have a 20 percent interest in a 480-megawatt gas-fired power plant being
constructed to supply electricity to Nigerias national electricity supplier.
When operational, the plant will consume 68 million cubic feet per day of
natural gas sourced from within our Nigerian proved natural gas reserves. The
plant is expected to become operational in 2005.
In October 2003, ConocoPhillips, the Nigerian National Petroleum Corporation
(NNPC), Eni and ChevronTexaco signed a Heads of Agreement (HOA) to conduct
front-end engineering and design work for a new LNG facility that would be
constructed in Nigerias central Niger Delta. The co-venturers have agreed to
form an incorporated joint venture, to be known as Brass LNG Limited to
undertake the project. The front-end engineering and design work will be for
two trains, each nominally sized at 5 million metric tons per year. Natural
gas supplies for the facility would come from natural gas reserves within oil
and gas fields already operated by existing Nigerian Agip Oil Company and
ChevronTexaco joint ventures. The front-end studies are expected to be
completed in 2005, and the LNG facility is targeted to be operational in 2009.
We have 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 our investment in the block. The second exploration
well, drilled in late 2003, was also unsuccessful, leading to a write-off of
our remaining investment in the block.
In December 2002, we announced a successful test of 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 permit are held 50 percent by ConocoPhillips and 50 percent by
a subsidiary of Petronas Carigali (Petronas). We serve as the operator of the
consortium. We are currently analyzing well results, and developing plans to
evaluate the discovery and other identified exploration prospects.
In Dubai, United Arab Emirates, we are 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 that
We had a 15 percent interest in Core Venture 1 and a 30 percent interest in
Core Venture 3 of the Kingdom of Saudi Arabias natural gas initiative.
Agreement could not be reached during the negotiation of the implementation
agreement, leading to the termination of both projects.
We have 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. We account for our
interest using the equity method. Polar Lights 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. In
2003, production began from the other two satellite fields: East Kolva and
Our net production from Polar Lights averaged 13,600 barrels of petroleum
liquids per day in 2003, and is included in equity affiliate production.
In the North Caspian Sea, we have an 8.33 percent interest in the Republic of
Kazakhstans North Caspian Sea Production Sharing Agreement (NCPSA), which
includes the Kashagan field. During 2003, we, along with four of the remaining
five co-venturers, exercised our pre-emptive rights to acquire a proportionate
share of BG Internationals sale of their 16.67 percent interest in the
project. Upon Republic of Kazakhstan approval of the transaction, our interest
in the NCPSA will increase to 10.19 percent.
The exploration area consists of 10.5 blocks, totaling nearly 2,000 square
miles. The initial production phase of the contract is for 20 years, with
options to extend the agreement an additional 20 years. In June 2002, we and
the other contracting companies, in conjunction with KazMunayGas, which
represents the Government of the Republic of Kazakhstan, declared the Kashagan
discovery commercial. In February 2004, the Kashagan Development
Plan was approved by the Republic of Kazakhstan.
The contracting companies plan to continue to explore other structures within
the North Caspian Sea license. In October 2002, we and our co-venturers
announced a new hydrocarbon discovery on the Kalamkas More prospect located
approximately 40 miles southwest of the Kashagan field. Exploratory drilling
continued in 2003 with three additional wells drilled. The Aktote #1 and the
Kashagan Southwest #1 were announced as discoveries in November 2003.
Operations on the Kairan #1 well were suspended for the winter period and will
resume in the spring of 2004.
In the South Caspian Sea offshore Azerbaijan, we have a 20 percent interest in
the Zafar Mashal prospect. The first exploratory well began in late 2003 and
is planned for completion in 2004.
In July 2003, we signed a Heads of Agreement with Qatar Petroleum for the
development of Qatargas 3, a large-scale liquefied natural gas (LNG) project
located in Qatar and servicing the U.S. natural gas markets. The agreement
provided the framework for the necessary project agreements and the completion
of feasibility studies. Qatargas 3 is planned as an integrated project,
jointly owned by ConocoPhillips (30 percent) and Qatar Petroleum. It would
consist of the facilities to produce gas from Qatars offshore North Field,
yielding approximately 7.5 million gross tons per year of LNG from a new
facility located in Ras Laffan Industrial City. The LNG would be shipped from
Qatar to the United States in a fleet of new LNG carriers. We would purchase
the LNG and be responsible for regasification and marketing within the United
States. The project could result in sales of natural gas up to 1 billion cubic
feet per day. Startup of the Qatargas 3 project is estimated to be in the 2009
In December 2003, we signed a Statement of Intent with Qatar Petroleum
regarding the construction of a gas-to-liquids (GTL) plant in Ras Laffan,
Qatar. The agreement initiates the detailed technical and commercial
pre-front-end engineering and design studies and established principles for
negotiating a Heads of Agreement for an integrated reservoir-to-market GTL
In late 2003, we signed an agreement with Freeport LNG Development, L.P. to
participate in its proposed LNG receiving terminal in Quintana, Texas. This
agreement gives us 1 billion cubic feet per day of regasification capacity in
the terminal and a 50 percent interest in the general partnership managing the
venture. The terminal will be designed with a storage capacity of 6.9 billion
cubic feet and a send-out capacity of 1.5 billion cubic feet per day. Pending
government approvals, construction is scheduled to begin in the second half of
2004, with commercial startup in mid-2007.
We are 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. Although we wrote-off our investment in the proposed
Rosarito LNG terminal, we continue working with federal, state, and local
officials in Mexico to evaluate various other alternatives, which includes
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,
2003. No difference exists between the companys estimated total proved
reserves for year-end 2002 and year-end 2001, which are shown in this filing,
and estimates of these reserves shown in a filing with another federal agency
The Commercial organization optimizes the commodity flows of our E&P segment.
This group markets our crude oil and natural gas production, with commodity
buyers, traders and marketers in offices in Houston, London, Singapore and
We sell crude oil and natural gas from our E&P producing operations under a
variety of contractual arrangements, some of which specify the delivery of a
fixed and determinable quantity. Our Commercial organization also enters into
natural gas sales contracts where the source of the natural gas used to fulfill
the contract can be the spot market, or a combination of our reserves and the
spot market. Worldwide, we are contractually committed to deliver
approximately 4.8 trillion cubic feet of natural gas and 270 million barrels of
crude oil in the future, including the minority interests of consolidated
subsidiaries. These contracts have various expiration dates through the year
2025. The crude oil commitment and approximately 4.3 trillion cubic feet of
the natural gas commitment are expected to come from proved reserves in the
United States, the Timor Sea, Nigeria, and the United Kingdom. The remainder
of the natural gas commitment will be purchased in the spot market.
Our Midstream business is conducted through owned and operated assets as well
as through our 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 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
propaneand marketed as chemical feedstock, fuel, or blendstock. Total natural
gas liquids extracted in 2003, including our share of DEFS, was 219,000 barrels
per day, with 167,000 barrels per day of natural gas liquids fractionated.
DEFS markets 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 had,
and is expected over the remaining term of the contract to have, a relatively
stable purchase pattern. 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 our E&P
operations in the United States.
DEFS is headquartered in Denver, Colorado. At December 31, 2003, DEFS owned
and operated 56 natural gas liquids extraction plants, and owned an equity
interest in another 10. Also at year end, DEFS gathering and transmission
systems included approximately 58,000 miles of pipeline. In 2003, DEFS raw
natural gas throughput averaged 6.7 billion cubic feet per day, and natural gas
liquids extraction averaged 365,000 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, our U.S. Midstream assets are located primarily in New Mexico,
Texas and Louisiana. At December 31, 2003, these assets included seven fully
owned and operated natural gas liquids extraction plants, plus two additional
plants that we operate and in which we own a 95 percent and a 50 percent
interest. These nine plants have a combined natural gas net plant inlet
capacity of 762 million cubic feet per day. One of the plants in Louisiana
also includes a 10,500 barrel-per-day liquids fractionator. We also have minor
interests in two other natural gas liquids extraction plants, and we own
underground natural gas liquids storage facilities in Texas and Louisiana.
We own a 25,000 barrel-per-day capacity liquids fractionation plant in Gallup,
New Mexico; a 22.5 percent equity interest in Gulf Coast Fractionators, which
owns a natural gas liquids fractionating plant in Mt. Belvieu, Texas (with our
net share of capacity at 25,000 barrels per day); and a 40 percent interest in
a fractionation plant in Conway, Kansas (with our share of capacity at 42,000
barrels per day). We own a 700-mile intrastate natural gas and liquids
pipeline system in Louisiana and gas gathering and natural gas liquids
pipelines in several states.
Our Canadian natural gas liquids business includes the following assets:
A 92 percent operating interest in the 2.4
billion-cubic-feet-per-day Empress natural gas processing and
fractionation facilities near Medicine Hat, Alberta, with natural gas
liquids production capacity of 50,000 barrels per day;
A 580-mile Petroleum Transmission Company pipeline from Empress to
Winnipeg and six related pipeline terminals;
Two underground natural gas liquids storage facilities, comprised
of the Richardson caverns with a one million barrel capacity and the
Dewdney caverns with a three million barrel capacity along with 0.6
billion cubic feet of natural gas storage capacity; and
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
Canadian natural gas liquids extracted averaged 45,000 barrels per day in 2003.
We also own 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 Parks
facilities include a gas processing plant and a natural gas liquids
fractionator. Our share of natural gas liquids extracted averaged 11,100
barrels per day in 2003.
In early 2004, we approved
the disposal of some of our non-DEFS Midstream assets located in the
Lower 48 states that are not associated with our E&P operations.
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, selling
and transporting crude oil, and buying, transporting, distributing and
marketing petroleum products. R&M has operations in the United States, Europe
and Asia Pacific.
The Commercial organization optimizes the commodity flows of our R&M segment.
This organization selects and procures feedstocks for R&Ms refineries.
Commercial also supplies the gas and power needs of the R&M facilities.
Commercial has buyers, traders and marketers in offices in Houston, London,
Singapore and Calgary.
As a condition to the merger, the U.S. Federal Trade Commission (FTC) required
that we divest specified Conoco and Phillips assets, the most significant of
which were Phillips Woods Cross, Utah, refinery and associated motor fuel
marketing operations; Conocos Commerce City, Colorado, refinery and related
crude oil pipelines; and Phillips Colorado motor fuel marketing operations.
All FTC-mandated dispositions were completed in late-2002 or during 2003.
In addition, in December 2002, we committed to and initiated a plan to sell
approximately 3,200 marketing sites that did not fit into our long-range plans.
In the third quarter of 2003, we concluded the sale of all of the
Exxon-branded marketing assets in New York and New England, including contracts
with independent dealers and marketers. Approximately 230 of the 3,200 sites
were included in this package. In the fourth quarter of 2003, we concluded the
sale of our Circle K subsidiary, representing approximately 1,660 sites, as
well as the assignment of the franchise relationship with more than 350
franchised and licensed stores. Other, smaller dispositions also occurred
during 2003. In January 2004, we signed agreements to sell our Mobil-branded
marketing assets on the East Coast in two separate transactions. Assets in the
packages include 104 company-owned and operated sites, and 352 dealer sites.
Each of the transactions is expected to close in the second quarter of 2004.
Discussions are under way with potential buyers for the remaining sites, and we
expect to complete the sales of these assets during 2004.
Both the FTC-required dispositions and the retail site dispositions were
classified as discontinued operations for financial reporting purposes, and are
included in Corporate and Other. Accordingly, they are excluded from the
descriptions of R&Ms continuing operations contained in this section. See
Note 4Discontinued Operations, in the Notes to Consolidated Financial
Statements, for additional information.
At December 31, 2003, we owned and operated 12 crude oil refineries in the
United States, having an aggregate rated crude oil refining capacity at
year-end 2003 of 2,168,000 barrels per day. The average purchase cost of a
barrel of crude delivered to our U.S. refineries in 2003 was $29.10, compared
to $24.92 in 2002.
East Coast Region
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. The mix of products
produced 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.
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 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 residual fuel oil and liquefied
petroleum gas. Refined products are distributed to customers in Pennsylvania,
New York and New Jersey via pipeline, barge, railcar and truck.
Gulf Coast Region
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 anode petroleum coke. The majority of the refined
products are distributed to customers through the Colonial and Plantation
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, railcar
or major common-carrier pipelines. In addition, refined products can be sold
into export markets through the refinerys 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 our Specialty
Businesses function within R&M.
The Sweeny refinery is located in Old Ocean, Texas, about 65 miles southwest of
Houston. The refinery has a crude oil processing capacity of 215,000 barrels
per day. The refinery primarily receives crude oil through 100 percent owned
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 has a 50 percent interest in Merey Sweeny, L.P., a limited
partnership that owns a 58,000 barrel-per-day delayed coker and related
facilities at the Sweeny refinery. PDVSA, which owns the remaining 50 percent
interest, supplies the refinery with up to 165,000 barrels per day of
Venezuelan Merey, or equivalent, crude oil. We are the operating partner.
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 our
largest refinery, with a crude oil processing capacity of 286,000 barrels per
day. The refinery can process a mix of both light low-sulfur and heavy
high-sulfur crudes, which it receives from domestic and foreign sources 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.
During 2003, we purchased certain assets at Premcors Hartford, Ill., refinery.
The purchase included the coker, crude unit, catalytic cracker, alkylation
unit, isomerization unit, a portion of the site utilities and a portion of the
storage tanks at the Premcor facility. The overall production of the Wood
River refinery will only increase slightly, but the purchase will enable the
refinery to process heavier, lower cost crude oil.
Ponca City Refinery
Our 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 refinerys 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, railcar and company-owned and common-carrier pipelines to
markets throughout the Midcontinent region.
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 our pipelines from west
Texas, the Texas Panhandle and Wyoming. The Borger refinery can also receive
foreign crude oil via our 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, and
the Midcontinent region.
The Billings refinery is located in Billings, Montana, and 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, and diesel, as
well as fuel grade petroleum coke. Finished petroleum products from the
refinery are delivered via company-owned pipelines, railcars, and trucks.
Pipelines transport most of the refined products to markets in Montana,
Wyoming, Utah, and Washington.
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 the 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 (CARB) gasoline using ethanol, which we use to replace methyl
tertiary-butyl ether (MTBE) 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 refinerys 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 calcine and fuel grade petroleum coke. The refinery
produces CARB gasoline using ethanol, which we use to replace MTBE to meet
federally mandated oxygenate requirements. Refined products are distributed by
pipeline, railcar, truck and barge.
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 primarily receives
crude oil 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 Terasen 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 to increase the yield of transportation fuel, and a new S Zorb
unit that reduces the sulfur in gasoline, both became fully operational in
2003. Most refined products are distributed by pipeline and barge to major
markets in the northwest United States.
In the United States, we market gasoline, diesel fuel, and aviation fuel
through approximately 14,300 outlets in 44 states. The majority of these sites
utilize the Conoco, Phillips 66 or 76 brands.
In our wholesale operations, we utilize a network of marketers and dealers
operating approximately 13,300 outlets. We place a strong emphasis on the
wholesale channel of trade because of its lower capital requirements and higher
return on capital. Our refineries and transportation systems provide strategic
support to these operations. We also buy and sell petroleum products in spot
markets. Our refined products are marketed on both a branded and unbranded
In addition to automotive gasoline and diesel fuel, we produce and market
aviation gasoline, which is used by smaller, piston-engine aircraft. Aviation
gasoline and jet fuel are sold through independent marketers at approximately
570 Phillips 66 branded locations in the United States.
In our retail operations, we own and operate approximately 330 sites under the
Phillips 66, Conoco and 76 brands. Company-operated retail operations are
focused in 10 states, mainly in the Midcontinent, Rocky Mountains, and West
Coast regions. Most of these outlets market merchandise through the Kicks 66,
Breakplace, or Circle K brand convenience stores.
At December 31, 2003, CFJ Properties, our 50/50 joint venture with Flying J,
owned and operated 97 truck travel plazas that carry the Conoco and/or Flying J
brands. The merger of Conoco and Phillips triggered change of control
provisions in the joint venture agreement, giving Flying J the option to
purchase our interest in CFJ Properties at fair value. A third party is
determining the fair value of the joint venture. Once that binding appraised
value is determined, Flying J will have 30 days to exercise their purchase
option. Assuming Flying J does not exercise its purchase option, we plan to
continue as a co-venturer in CFJ Properties.
Pipelines and Terminals
At December 31, 2003, we had approximately 32,800 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. We also
owned and/or operated 76 finished product terminals, eight liquefied petroleum
gas terminals, 11 crude oil terminals and one coke exporting facility.
At December 31, 2003, we had under charter 13 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 our U.S. refineries.
We also had 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 companys
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.
We manufacture and sell a variety of 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, Phillips 66, 76 Lubricants and
Kendall Motor Oil brands. The distribution network consists of over 900
outlets, including 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 lubricant base oil
manufacturing facility, located adjacent to our Lake Charles refinery, and is
50 percent owned by us. 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. We purchase 50 percent of
the joint ventures output, and market it to third parties.
We have 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
We manufacture 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 we have a 50 percent interest. Base
green petroleum coke volumes are supplied to Vencos Lake Charles calcining
facility from our Alliance, Lake Charles, and Ponca City refineries.
At December 31, 2003, we owned or had an interest in six refineries outside the
United States with an aggregate rated crude oil capacity of 442,000 net barrels
per day. The average purchase cost of crude oil delivered to the companys
international refineries in 2003 was $28.94 per barrel, compared with $24.55
per barrel in 2002.
Our wholly owned Humber refinery is located in North Lincolnshire, United
Kingdom. The refinerys crude oil processing capacity is 234,000 barrels per
day. 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
refinerys 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 60 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.
The Whitegate refinery is located in Cork, Ireland, and in 2003 had a crude oil
processing capacity of 72,000 barrels per day. Effective January 1, 2004, the
rated processing capacity was increased to 75,000 barrels per day due to
incremental debottlenecking. 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. We also
operate a deepwater crude oil and products storage complex with a 7.5 million
barrel capacity in Bantry Bay, Cork, Ireland.
The Mineraloel Raffinerie Oberrhein GmbH (MiRO) refinery in Karlsruhe, Germany,
is a joint-venture refinery with a crude oil processing capacity of 283,000
barrels per day. We have an 18.75 percent interest in MiRO, giving us a net
capacity share of 53,000 barrels per day. Approximately 60 percent of the
refinerys 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
Through our participation in Ceská rafinérská, a.s.
(CRC), we have a 16.33 percent ownership in two refineries in the Czech Republic, giving us a net
capacity share of 27,000 barrels per day. Effective January 1, 2004, the rated
crude oil processing capacity was increased to 28,000 barrels per day for our
share, due to incremental debottlenecking. The refinery at Litvinov has a
crude oil processing capacity of 109,200 barrels per day and processes low cost
Russian export blend crude oil delivered from Russia by pipeline.
includes both hydrocracking and visbreaking, producing a high yield of
transport fuels and petrochemical feedstocks and only a small amount of fuel
oil. The Kralupy refinery has a crude oil processing capacity of 60,800
barrels per day and processes low sulfur crude, mostly from the Mediterranean.
Kralupy has a new fluidized catalytic cracking unit, which gives the refinery a
high yield of transport fuels. The two refineries complement each other and
are run on an overall optimized basis, with certain intermediate streams moving
between the two plants. CRC processes crude and other feedstocks supplied by
ConocoPhillips and the other partners, with each partner receiving their
proportionate share of the resulting products. We market our share of these
finished products in both the Czech Republic and in neighboring markets.
The refinery in Melaka, Malaysia, is a joint venture with Petronas, the
Malaysian state oil company. We own a 47 percent interest in the joint
venture. In 2003, the refinery had a rated crude oil processing capacity of
120,000 barrels per day, of which our share was 56,000 barrels per day.
Effective January 1,
2004, our share of the rated crude oil processing capacity was increased to
57,500 barrels per day due to incremental debottlenecking. 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 our
proprietary coking technology to upgrade low-cost feedstocks to higher-margin
products. Our share of refined products is distributed by truck to the
companys ProJET retail sites in Malaysia, or transported by sea primarily to
We have marketing operations in 15 European countries. Our European marketing
strategy is to sell primarily through owned, leased or joint-venture retail
sites using a low-cost, high-volume, low-price strategy. We also market
aviation fuels, liquid petroleum gases, heating oils, transportation fuels and
marine bunkers to commercial customers and into the bulk or spot market.
We use the JET brand name to market retail and wholesale products in our
wholly owned operations in Austria, Belgium, the Czech Republic, Denmark,
Finland, Germany, Hungary, Luxembourg, Norway, Poland, Slovakia, Sweden and the
United Kingdom. In addition, various joint ventures in which we have an equity
interest market products in Switzerland and Turkey under the Coop and Tabas
or Turkpetrol brand names, respectively.
As of December 31, 2003, we had approximately 2,100 marketing outlets in our
European operations, of which about 1,200 were company-owned, and 900 were
dealer-owned. Through our joint venture operations in Turkey and Switzerland,
we also have interests in approximately 800 additional sites.
The companys largest branded site networks are in Germany and the United
Kingdom, which account for approximately 60 percent of our total European
As of December 31, 2003, we had approximately 140 marketing outlets in our
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, we also have an interest in another approximately 40
retail sites. In Thailand and Malaysia, retail products are marketed under the
JET and ProJET brands, respectively.
On July 1, 2000, ConocoPhillips and ChevronTexaco combined their worldwide
chemicals businesses, excluding ChevronTexacos Oronite business, into a new
company, Chevron Phillips Chemical Company LLC (CPChem). In addition to
contributing the assets and operations included in our Chemicals segment, we
also contributed the natural gas liquids business associated with our Sweeny,
Texas, complex. ConocoPhillips and ChevronTexaco each own 50 percent of CPChem.
We use the equity method of accounting for our 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 commodity chemicals, such as polyethylene,
polystyrene, and cyclohexane.
CPChems domestic production 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
Major international production facilities are located in Belgium, China, Saudi
Arabia, Singapore, South Korea and Qatar. There is one plastic pipe plant in
CPChem has research facilities in Oklahoma, Ohio and Texas, as well as in
Singapore and Belgium.
Construction of a major olefins and polyolefins complex in Mesaieed, Qatar,
named Q-Chem I, was completed in 2003. The facility, which is operating and in
the final stages of performance testing, has an annual capacity of
approximately 1.1 billion pounds of ethylene, 1 billion pounds of polyethylene
and 100 million pounds of 1-hexene. CPChem has a 49 percent interest, with a
Qatar state firm owning the remaining 51 percent interest.
CPChem has also signed an agreement for the development of a second complex to
be built in Mesaieed, Qatar, named Q-Chem II. The facility will be designed to
produce polyethylene and normal alpha olefins, on a site adjacent to the
newly-constructed Q-Chem I complex. CPChem and Qatar Petroleum, through the
Q-Chem II joint venture, entered into a separate agreement with Atofina and
Qatar Petrochemical Company to jointly develop an ethane cracker in northern
Qatar at Ras Laffan Industrial City. Final approval of the Q-Chem II projects
by CPChems Board of Directors is expected to be requested in 2005, with
startup expected in 2008.
CPChem announced plans in 2002 for a 50 percent-owned joint venture project in
Al Jubail, Saudi Arabia. The project includes the construction of an integrated
olefins, ethyl benzene and styrene monomer facility on a site adjacent to the
existing aromatics complex owned by Saudi Chevron Phillips Company, a 50
percent-owned CPChem joint venture. The project also includes the expansion of
Saudi Chevron Phillips Companys benzene facility. This additional benzene
capacity will be used to provide feedstock for the new facility. Final
approval of the project by CPChems Board of Directors is expected to be
requested in 2004, with operational startup expected in 2007.
A brief description of CPChems major product lines follows.
Olefins and Polyolefins
Ethylene is a basic building block for plastics and also a raw
material for chemicals used to make paints, detergents and antifreeze.
Ethylene is produced at Old Ocean, Port Arthur and Baytown, Texas, as well as
in Qatar. CPChems net annual capacity at December 31, 2003, was approximately
8.1 billion pounds.
Polyethylene is used to make a wide variety of plastic products,
including various containers, shopping and trash bags, and plastic films.
Polyethylene is produced at Pasadena, Baytown, and Orange, Texas, as well as in
China, Singapore and Qatar. CPChems net annual capacity at December 31, 2003,
was approximately 5.9 billion pounds.
Polyethylene 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. CPChems net annual capacity at December 31, 2003, was
approximately 564 million pounds.
Normal Alpha Olefins:
Normal alpha olefins can be custom blended for special
applications and are used extensively as polyethylene comonomers and are also
used in synthetic lubricants and additives. Normal alpha olefins are produced
at Baytown, Texas and in Qatar. CPChems net annual capacity at December 31,
2003, was approximately 1.5 billion pounds.
Aromatics and Styrenics
Styrene, produced from benzene and ethylene, is used as a feedstock
for polystyrene and is also used to produce a variety of polymers with end-uses
that include packaging, rubber products, automotive and other applications.
Styrene is produced at St. James, Louisiana. CPChems net annual capacity at
December 31, 2003, was approximately 2.1 billion pounds.
Polystyrene is a thermoplastic polymer used to make packing
materials, cups, toys, furniture, and housewares. It is produced at Marietta,
Ohio, and in China. CPChems net annual capacity at December 31, 2003, was
approximately 990 million pounds.
Benzene is a building block chemical used in the production of
ethylbenzene, cumene, and cyclohexane. Benzene is produced at Pascagoula,
Mississippi and in Saudi Arabia. CPChems net annual capacity at December 31,
2003, was approximately 2.1 billion pounds.
Cyclohexane is a derivative of benzene that is predominantly used
in intermediates for the manufacture of nylon. It is produced at Port Arthur,
Texas, and in Saudi Arabia. CPChems net annual capacity at December 31, 2003,
was approximately 1.2 billion pounds. This includes the capacity of a new
plant in Port Arthur that commenced operations in February 2004, and excludes
the capacity of a plant, also in Port Arthur, that was shut down. In addition,
CPChem markets cyclohexane production from ConocoPhillips Sweeny and Borger
is a styrene-butadiene copolymer used to produce a clear,
shatter-resistant resin. It is produced at Pasadena, Texas, and in South
Korea. CPChems net annual capacity at December 31, 2003, was approximately
269 million pounds.
Paraxylene is an aromatic used as a feedstock for polyester and
certain plastics. It is currently produced at Pascagoula, Mississippi. The
Pascagoula plants annual capacity at December 31, 2003, was approximately 1.0
billion pounds. A plant in Guayama, Puerto Rico, with an annual capacity at
December 31, 2003, of approximately 715 million pounds, was reconfigured in
2003 and is currently idled. Operations at the Puerto Rico plant could resume
when market conditions improve.
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
CPChem produces high-performance polyphenylene
sulfide polymers (PPS) sold under the trademark Ryton
, which is produced at
Borger, Texas. CPChems annual capacity of Ryton PPS at December 31, 2003, was
22 million pounds. Ryton PPS compounds are produced at La Porte, Texas, as
well as in Belgium and Singapore. These facilities have a net annual capacity
of approximately 44 million pounds of Ryton PPS compounds in the aggregate.
Emerging Businesses encompass
the development of new businesses beyond our traditional operations. As a result of market, operating and
technological uncertainties, we terminated our carbon fibers project during
The GTL process refines natural gas into a wide range of transportable
products. Our GTL research facility is located in Ponca City, Oklahoma, and
includes laboratories, pilot plants, and a demonstration plant to facilitate
technology advancements. The 400 barrel-per-day demonstration plant, designed
to produce clean fuels from natural gas, was completed in April 2003. The
plant has been commissioned and operations started, with thorough testing
scheduled throughout 2004.
Our Technology Solutions businesses provide technologies and services that can
be used in our 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, Technology Solutions offers analytical services, pilot plant, and
industrial hygiene services.
The focus of our power business is on developing integrated projects in support
of the companys 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 Businesses 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.
We also own or have an interest in gas-fired cogeneration plants in Orange and
Corpus Christi, Texas, and a petroleum coke-fired plant in Lake Charles,
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.
We compete with private, public and state-owned companies in all facets of the
petroleum and chemicals businesses. Some of our competitors are larger and
have greater resources. Each of the segments in which we operate is highly
competitive. No single competitor, or small group of competitors, dominates
any of our business lines.
Upstream, our 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 15, 2003, issue of the
Oil and Gas
, we had the eighth-largest total of worldwide reserves of
non-government-controlled companies. We deliver our 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 Midstream segment, through our equity investment in DEFS and our
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 17, 2003,
Gas Processors Report
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, our R&M segment competes primarily in the United States, Europe and
the Asia Pacific region. Based on the statistics published in the December 22,
2003, issue of the
Oil and Gas Journal
, we had the largest U.S. refining
capacity of about 15 large refiners of petroleum products. Worldwide, we
ranked fourth among non-government-controlled companies. In the Chemicals
segment, through our equity investment, CPChem generally ranks within the top
10 producers of its major product lines, based on average 2003 production
capacity, as published by Chemical Market Associates Inc. Petroleum products,
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 CPChems branded products.
At the end of 2003, we held a total of 1,918 active patents in 68 countries
worldwide, including 733 active U.S. patents. During 2003, we received 57
patents in the United States and 136 foreign patents. Our products and
processes generated licensing revenues of $35 million in 2003. 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 $136 million, $355 million and $44 million in 2003, 2002 and 2001,
The environmental information contained in Managements Discussion and Analysis
on pages 72 through 75 under the caption, Environmental is incorporated
herein by reference. It includes information on expensed and capitalized
environmental costs for 2003 and those expected for 2004 and 2005.
Like all major international oil companies, we have 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
we have received a license from the Office of Foreign Assets Control (OFAC).
The regulations implementing the restrictions are complicated and subject to
interpretation by OFAC. We have programs designed to ensure compliance with
the restrictions and believe that our present operations comply with applicable
laws and regulations.
In view of recent political, diplomatic and military developments in the Middle
East, and throughout the world, we have reexamined our 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.
Following the events of September 11, 2001, 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.
We have reexamined our policies and business ventures to ensure that our
activities in or with certain countries are consistent with the U.S.
governments policy, interests and objectives in such countries.
Web Site Access to SEC Reports
Our Internet Web site address is
contained on our Internet Web site is not part of this report on Form 10-K.
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current
Reports on Form 8-K and any amendments to these reports filed or furnished
pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are
available on our Web site, free of charge, as soon as reasonably practicable
after such reports are filed with, or furnished to, the SEC. Alternatively,
you may access these reports at the SECs Internet Web site at
The following is a description of reportable legal proceedings including those
involving governmental authorities under federal, state and local laws
regulating the discharge of materials into the environment for this reporting
period. The following proceedings include those matters that arose during the
fourth quarter of 2003 and those matters previously reported in ConocoPhillips
2002 Form 10-K and our first-, second- and third-quarter 2003 Forms 10-Q that
have not been resolved. While it is not possible to accurately predict the
final outcome of these pending proceedings, if any one or more of such
proceeding was decided adversely to ConocoPhillips, there would be no material
effect on our consolidated financial position. Nevertheless, such proceedings
are reported pursuant to the United States Securities and Exchange Commissions
In December 2003, we entered into an Administrative Consent Order and Notice of
Noncompliance with the Massachusetts Department of Environmental Protection for
alleged violations of State II and Hazardous Waste requirements at various
retail gasoline outlets formerly owned by us. This Consent Agreement provides
for the payment of a civil administrative penalty in the amount of $106,250.
In November 2003, the U.S. Environmental Protection Agency (EPA) issued us a
notice of violation for alleged violations of the gasoline Reid Vapor Pressure
rules in 1999, 2000 and 2001 at our Wood River and Billings refineries. The
notice of violation seeks a proposed penalty of $127,000. We are currently
working with EPA toward a negotiated resolution of this matter.
On September 17, 2003, U.S. EPA Region 10 notified ConocoPhillips of its intent
to assess civil penalties for alleged National Pollution Discharge Elimination
System (NPDES) permit violations at our Tyonek offshore platform located near
Cook Inlet, Alaska. The alleged violations arise from our July 2003 NPDES
self-disclosure report to EPA Region 10. On February 10, 2004, EPA Region 10
issued to us a proposed Complaint for Civil Penalties and a proposed Consent
Decree for the alleged permit violations. The proposed consent decree provides
for the payment of a $450,000 civil penalty. We are currently working with the
EPA and the U.S. Department of Justice (DOJ) on the terms of the agreements and
expect the matter to be finalized by the end of the second quarter of 2004.
On August 24, 2003, the Contra Costa County District Attorneys Office in
California issued a demand letter to ConocoPhillips seeking civil penalties in
the amount of $524,000 for 31 alleged violations of the Bay Area Air Quality
Management District regulations at our Rodeo facility of the San Francisco area
refinery. The demand has been reduced to $361,000. These alleged violations
cover the period from mid-2001 through August 2003. We are currently working
with the Contra Costa County District Attorneys Office toward a negotiated
resolution of this matter.
In August of 2003, EPA Region 6 issued a Show Cause Order alleging violations
of the Clean Water Act at the Borger refinery. The alleged violations relate
primarily to discharges of selenium and reported exceedances of permit limits
for whole effluent toxicity. We met with EPA staff on October 29, 2003, to
discuss the allegations. We believe the EPA staff is evaluating the
information presented at the meeting. The EPA has not yet proposed a penalty
On December 31, 2002, we 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 our Borger 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.
We are currently working with TCEQ toward a negotiated resolution of this
On December 17, 2002, the DOJ notified ConocoPhillips of various alleged
violations of the 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. We have reached a tentative agreement with the
DOJ that will require us to pay a civil penalty and/or perform certain work
valued at $700,000.
In December 2002, the Louisiana Department of Environmental Quality (LDEQ)
notified ConocoPhillips of its intent to assess civil penalties for over 120
alleged regulatory violations at various Circle K stores in the Baton Rouge,
Louisiana area. On October 6, 2003, the LDEQ notified ConocoPhillips that the
civil penalty assessment for these alleged violations is $189,659. This matter
was settled in November 2003.
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. We have agreed with the TCEQ to settlement terms that are expected
to be finalized during the first quarter of 2004.
On July 15, 2002, the United States filed a Comprehensive Environmental
Response, Compensation and Liability Act (CERCLA) cost recovery action against
ConocoPhillips 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 us,
Waste Management, Inc. and others, Waste Management has assumed our defense for
this matter and it is our position that Waste Management should indemnify us
for any liability arising from this action.
We have responded to information requests from EPA regarding New Source Review
compliance at our Alliance, Bayway, Borger, Ferndale, Los Angeles, Sweeny,
Trainer, and Wood River refineries; and the Rodeo and Santa Maria units of our
San Francisco refinery. Although we have not been notified of any formal
findings or violations arising from these information requests, we have been
informed that the EPA is contemplating the filing of a civil proceeding against
us for alleged violations of the Clean Air Act. We are currently seeking a
negotiated resolution of these matters, which will likely result in increased
environmental capital expenditures and governmental monetary sanctions.
All significant litigation
arising from the March 27, 2000, explosion and fire
that occurred in an out-of-service butadiene storage tank at the K-Resin
styrene-butadiene copolymer plant has now been resolved.
In June of 1997, we experienced pipeline spills on our Seminole pipeline at
Banner, Wyoming, and Lodge Grass, Montana. In response to these spills, the
DOJ advised us in August 2000 that the United States is contemplating a legal
proceeding under the Clean Water Act against us. We and DOJ have reached a
tentative agreement that will require us to pay a $465,000 civil penalty.
Additionally, we are 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 or other accidental releases,
with related toxic tort claims. As a result of Conocos separation agreement
with DuPont in October 1998, we also have 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
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.
Executive Vice President, Exploration and Production
John A. Carrig
Executive Vice President, Finance, and Chief Financial Officer
Archie W. Dunham
Chairman of the Board of Directors
Philip L. Frederickson
Executive Vice President, Commercial
Stephen F. Gates
Senior Vice President, Legal, and General Counsel
John E. Lowe
Executive Vice President, Planning, Strategy and Corporate Affairs
J. J. Mulva
President and Chief Executive Officer
J. W. Nokes
Executive Vice President, Refining, Marketing, Supply and
*On March 1, 2004.
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 5, 2004. Set
forth below is information concerning the executive officers.
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
Conocos Chairman of the Board, President and Chief Executive Officer since
1999; and Conocos 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
Conocos Senior Vice President of Corporate Strategy and Business Development
since 2001; and Conocos Vice President of Business Development since 1998.
Stephen F. Gates
was appointed Senior Vice President, Legal, and General
Counsel of ConocoPhillips effective May 1, 2003. Prior to joining
ConocoPhillips, he was a partner at Mayer, Brown, Rowe & Maw. Previously, he
served as senior vice president and general counsel of FMC Corporation in 2000
and 2001. Prior to that, he served at BP Amoco (now BP plc) where he was
executive vice president and group chief of staff after serving as vice
president and general counsel of Amoco.
John E. Lowe
was appointed Executive Vice President, Planning, Strategy and
Corporate Affairs 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; and Phillips Manager of Strategic Growth
Projects since earlier in 1999.
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; and Phillips Vice Chairman of the Board of Directors, President, and
Chief Executive Officer since earlier in 1999.
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 Conocos Executive Vice President, Worldwide Refining,
Marketing, Supply and Transportation since 1999.