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 92.
Items 1 and 2. BUSINESS AND PROPERTIES
ConocoPhillips is an international, integrated energy company. ConocoPhillips was incorporated in
the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger
between Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips). The merger between Conoco
and Phillips (the merger) was consummated on August 30, 2002, at which time Conoco and Phillips
combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips. As
a result of the merger, Conoco and Phillips each became wholly owned subsidiaries of
ConocoPhillips. For accounting purposes, Phillips was designated as the acquirer of Conoco and
ConocoPhillips was treated as the successor of Phillips. Accordingly, Phillips operations and
results are presented in this Form 10-K for all periods prior to the close of the merger. From the
merger date forward, the operations and results of ConocoPhillips reflect the combined operations
of the two companies. Subsequent to the merger, Conoco was renamed ConocoPhillips Holding Company,
and Phillips was renamed ConocoPhillips Company, but for ease of reference, those companies will be
referred to respectively in this document as Conoco and Phillips. Effective January 1, 2005,
ConocoPhillips Holding Company was merged into ConocoPhillips Company.
Our business is organized into six operating segments:
Exploration and Production (E&P)
This segment primarily explores for, produces and
markets crude oil, natural gas, and natural gas liquids on a worldwide basis.
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 purchases, refines, markets and transports
crude oil and petroleum products, mainly in the United States, Europe and Asia.
This segment consists of our equity investment in the ordinary shares
of LUKOIL, an international, integrated oil and gas company headquartered in Russia. Our
investment was 10 percent at December 31, 2004.
This 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.
This segment encompasses the development of new businesses beyond
our traditional operations, including new technologies related to natural gas conversion
into clean fuels and related products (e.g., gas-to-liquids), technology solutions, power
generation, and emerging technologies.
At December 31, 2004, ConocoPhillips employed approximately 35,800 people.
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 27Segment Disclosures and Related
Information in the Notes to Consolidated Financial Statements, which is incorporated herein by
EXPLORATION AND PRODUCTION (E&P)
This segment explores for, produces and markets 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. Operations to liquefy and transport natural gas are also
included in the E&P segment. At December 31, 2004, our E&P operations were producing in the United
States, Norway, the United Kingdom, Canada, Venezuela, Indonesia, offshore Timor Leste in the Timor
Sea, Australia, Vietnam, China, Nigeria, the United Arab Emirates, and Russia.
The E&P segment does not include the results or statistics from our equity investment in LUKOIL,
which are reported in a separate segment (LUKOIL Investment). As a result, references to results,
production, prices and other statistics throughout the E&P segment exclude those related to our
equity investment in LUKOIL.
The information listed below appears in the supplemental oil and gas operations disclosures on
pages 168 through 186 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.
Developed and undeveloped acreage.
In 2004, E&Ps worldwide production, including its share of equity affiliates production other
than LUKOIL, averaged 1,542,000 barrels-of-oil-equivalent (BOE) per day, a 3 percent decrease from
1,590,000 BOE per day in 2003. During 2004, 629,000 BOE per day were produced in the United
States, a 7 percent decrease from 674,000 BOE per day in 2003. Production from our international
E&P operations averaged 913,000 BOE per day in 2004, down slightly from 916,000 BOE per day in
2003. In addition, our Canadian Syncrude mining operations had net production of 21,000 barrels
per day in 2004, compared with 19,000 barrels per day in 2003. The decreased production mainly
reflects the impact of
asset dispositions during 2003 and 2004, as well as normal field production declines. The impact
of these items was partially offset by the ramp-up of oil production from the Su Tu Den field in
Vietnam since startup in late 2003, the ramp-up of liquids production from the Bayu-Undan field in
the Timor Sea since startup in February 2004, and the startup of the Hamaca upgrader in Venezuela
in the fourth quarter of 2004. 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.
E&Ps worldwide annual average crude oil sales price increased 31 percent in 2004, from $27.52 per
barrel to $36.06 per barrel. E&Ps annual average worldwide natural gas sales price also
increased, going from $4.08 per thousand cubic feet in 2003 to $4.61 per thousand cubic feet in
At December 31, 2004, E&P held, including its share of equity affiliates other than LUKOIL, a
combined 43.2 million net developed and undeveloped acres, compared with 52.6 million net acres at
year-end 2003. The decrease in acreage primarily reflects the assignment of our interests in
Barbados and Brazil, in addition to the sale of Petrovera. At year-end 2004, E&P held acreage in
22 countries, including acreage held by equity affiliates.
Our finding-and-development-cost-per-BOE metric reported in prior years was calculated by dividing
the net reserve change for each reporting 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. Due
to the timing of proved reserve additions and the timing of the related costs incurred to find and
develop such proved reserves, this metric often includes quantities of proved reserves for which a
majority of the costs of development have not yet been incurred. Conversely, the metric also often
includes costs to develop proved reserves that had been added in earlier years. Because this
metric may not necessarily represent total finding and development costs for projects under way or
may not be indicative of expected future finding and development costs, we discontinued reporting
it in our filings with the U.S. Securities and Exchange Commission.
In 2004, U.S. E&P operations contributed 40 percent of E&Ps worldwide liquids production, compared
with 43 percent in 2003. U.S. E&P contributed 42 percent of natural gas production in both years.
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.
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 operation, 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 109,600 barrels per day in 2004, compared with 121,500 barrels per day in 2003,
while natural gas liquids production averaged 23,100 barrels per day in 2004, compared with 23,000
barrels per day in 2003. Normal field production declines and facility maintenance were the main
causes of the lower production rates in 2004.
Prudhoe Bay satellite fields, including Aurora, Borealis, Polaris, Midnight Sun, and Orion,
produced 14,600 net barrels per day of crude oil in 2004, compared with 16,200 net barrels per day
in 2003. Borealis contributed the biggest share in 2004, producing 8,000 net barrels per day. All
Prudhoe Bay satellite fields produce through the Prudhoe Bay production facilities.
The Greater Point McIntyre Area (GPMA) primarily is made up of the Point McIntyre, Niakuk, and
Lisburne fields. The fields within the GPMA generally produce through the Lisburne Production
Center. Net crude oil production for GPMA averaged 17,800 barrels per day in 2004, compared with
18,200 barrels per day in 2003. 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
In January 2005, the Governor of Alaska announced that effective February 1, 2005, most satellite
fields surrounding the Prudhoe Bay field would no longer qualify for a state production tax
incentive that was intended to encourage development of these marginal deposits. Beginning in
February, these satellite fields bear the same production tax rate as Prudhoe Bay.
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 67,900 barrels per day in 2004, compared with 78,600 barrels per day in 2003.
Other fields within the Greater Kuparuk Area produced 19,300 net barrels per day of crude oil in
2004, compared with 21,800 net barrels per day 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 in Meltwater.
The Greater Kuparuk Area also includes the West Sak heavy-oil field. Our net crude oil production
from West Sak averaged 5,500 barrels per day in 2004, compared with 3,800 barrels per day in 2003.
We have a 52.2 percent interest in this field.
During 2004, we and our co-venturers announced plans for the expansion of the West Sak development.
The development program includes two drill sites: Drill Site 1E, which is an existing drill site,
and Drill Site 1J, which will be the first stand-alone West Sak drill site. Plans call for the
drilling of 13 wells at Drill Site 1E and 31 wells at Drill Site 1J. The development projects also
include expansion of facilities at Drill Site 1E, and the construction of new facilities, pipelines
and power lines for Drill Site 1J. Drill Site 1E, which started up in July 2004, is expected to
average 4,100 net barrels of oil per day in 2005. First production from Drill Site 1J, expected in
late 2005, is expected to add approximately 800 net barrels per day. Peak production from Drill
Site 1J is expected to occur in 2007.
Western North Slope
The Alpine field, located west of the Kuparuk field, began production in November 2000. In 2004,
the field produced at a net rate of 63,500 barrels of oil per day, compared with 64,500 barrels per
day in 2003. We are the operator and hold a 78 percent interest in Alpine.
During 2004, the Alpine Capacity Expansion Phase I was completed. As a result, Alpines gross
crude oil production capacity increased approximately 5,000 barrels per day, along with an increase
in the sites produced-water capacity. Originally designed to process about 10,000 barrels per day
of produced water, the site can now process about 100,000 barrels per day. The completion of Phase
II is scheduled for 2005,
after which Alpines crude oil production capacity is expected to be further expanded by
approximately 30,000 gross barrels per day with increased seawater injection rates to boost
In January 2003, ConocoPhillips and the U.S. Department of Interior Bureau of Land Management (BLM)
signed a Memorandum of Understanding that provides for completion of an Environmental Impact
Statement (EIS) for Alpine satellites, as well as future potential developments in the northeast
corner of the National Petroleum Reserve-Alaska (NPR-A) and near the Alpine oil field. The BLM
issued a favorable EIS Record of Decision in November 2004. In December 2004, we and our
co-venturers announced that the companies approved the development of two Alpine satellite oil
fieldsFiord and Nanuq. The project will include two satellite drill sitesCD 3 on the Fiord oil
field, and CD 4 on the Nanuq oil fieldlocated within an 8-mile radius of the Alpine oil field.
Plans call for the drilling of approximately 40 wells, with first production scheduled for late
2006 and peak production in 2008. The oil will be processed through the existing Alpine
facilities. The companies intend to seek state, local and federal permits for additional Alpine
satellite developments in the NPR-A. A final decision to move forward on these satellite oil
fields is not expected to be made until the outcomes of remaining permits are known.
Our assets in Alaska also include the North Cook Inlet field, the Beluga River natural gas field,
and the Kenai liquefied natural gas (LNG) facility.
We have a 100 percent interest in the North Cook Inlet field. Net production in 2004 averaged 94
million cubic feet per day, compared with 112 million cubic feet per day in 2003. Production from
the North Cook Inlet field is used to supply our share of gas to the Kenai LNG plant (discussed
Our interest in the Beluga River field is 33 percent. Net production averaged 63 million cubic
feet per day in 2004, the same as in 2003. Gas from the Beluga River field is sold to local
utilities and industrial consumers, and used as back-up supply to the Kenai LNG plant.
We have a 70 percent interest in the Kenai LNG plant, which supplies LNG to two utility companies
in Japan. Using two tankers, the company transports the LNG to Japan, where it is reconverted to
dry gas at the receiving terminal. We sold 38.6 net billion cubic feet of LNG to Japan in 2004,
compared with 44.0 billion cubic feet in 2003.
During the 2004 winter drilling season, we drilled six North Slope exploration and appraisal wells.
This activity resulted in two successful appraisal wells in the NPR-A and
one successful appraisal well in the West Sak field. We expensed the other three wells
as dry holes. In addition, successful exploratory production tests were run in two wells, one each
in the Alpine and Prudhoe Bay fields. During 2004, we completed evaluation of six wells drilled in
prior drilling seasons, with five of those determined to be successful and one expensed as a dry
hole. We were also the successful bidder on 71 tracts covering over 808,000 gross acres
(approximately 484,000 net acres) at the June 2004 Bureau of Land Management oil and gas lease sale
for the Northwest Planning Area of the NPR-A. As a result of this additional acreage, we now have
under lease approximately 1.3 million net exploration acres in the NPR-A.
We transport the petroleum liquids that 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. We have a 28.3 percent ownership interest in TAPS. We also have ownership interests in
the Alpine, Kuparuk and Oliktok pipelines on the North Slope.
The owners of TAPS approved plans to upgrade the pipelines pump stations. The project is expected
to be substantially completed in 2005. The project is expected to reduce operating costs and
extend the economic life of the pipeline through increased efficiencies, while maintaining safety
and environmental performance standards.
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. The Alaska Natural Gas Pipeline Act was passed by Congress and signed by the
President in October 2004. This legislation was designed to help facilitate and streamline the
federal regulatory process and provides up to $18 billion in federal loan guarantees. Also
approved was tax legislation granting seven-year depreciation to the Alaska portion of the pipeline
and confirming the existing 15 percent enhanced oil recovery tax credit would apply to the gas
treating plant. This federal legislation, along with gaining a fiscal contract with the state of
Alaska, is an integral part of moving the project forward. Also in 2004, ConocoPhillips, along
with BP and ExxonMobil, entered into negotiations with the state of Alaska under the Stranded Gas
Development Act and submitted a detailed proposal to the state in December. These negotiations are
Our wholly owned subsidiary, Polar Tankers Inc., manages the marine transportation of our Alaska
North Slope production. Polar Tankers operates six ships in the Alaskan trade, chartering
additional third-party-operated vessels, as necessary. Beginning with the
Polar Tankers has brought into service a new Endeavour Class tanker each year since: the
in 2002; the
in 2003; and the
in 2004. These
125,000-deadweight-ton, double-hulled crude oil tankers are the first four of five Endeavour Class
tankers that we are adding to our Alaska-trade fleet. The fifth and final tanker is scheduled to
be in Alaska North Slope service by 2006.
Lower 48 States
Gulf of Mexico
At year-end 2004, our portfolio of producing properties in the Gulf of Mexico included four fields
operated by us and four fields operated by our co-venturers. At December 31, 2004, we had 28
leases in production or under development in the deepwater Gulf of Mexico.
We hold a 16 percent interest in the Ursa field located in the Mississippi Canyon area. Ursa
utilizes a tension-leg platform in approximately 3,900 feet of water. We also own a 16 percent
interest in the Princess field, a northern, subsalt extension of the Ursa field. Our total net
production from both fields in 2004 averaged 21,000 barrels per day of liquids and 30 million cubic
feet per day of natural gas, compared with 15,900 barrels per day of liquids and 20 million cubic
feet per day of natural gas in 2003.
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, located in
approximately 4,700 feet of water, was completed during 2004. First oil production began in
December 2004, with the remaining well completions scheduled through the first half of 2005. Peak
production of 48,000 net BOE per day is expected during 2005.
We have a 16.8 percent interest in the K2 discovery. K2, located in Green Canyon Block 562, was
company-sanctioned for development in the first quarter of 2004. The development will utilize a
subsea tieback to a nearby third-party platform. First production is expected in the second half
of 2005, with peak net production of 7,000 BOE per day expected during 2007.
During 2004, we sold our interest in the Lorien discovery located in Green Canyon Block 199.
Our onshore Lower 48 production primarily consists of 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 to our coalbed methane production from the San Juan
Basin, we also hold coalbed methane acreage positions in the Uinta Basin in Utah and the Black
Warrior Basin in Alabama. Our interest in the coalbed methane acreage position in the Powder River
Basin in Wyoming was sold in early 2005.
Activities in 2004 primarily were centered on continued optimization and development of these
assets. Combined production from Lower 48 onshore fields in 2004 averaged a net 1,184 million
cubic feet per day of natural gas and 54,100 barrels per day of liquids, compared with 1,237
million cubic feet per day of natural gas and 57,000 barrels per day of liquids in 2003.
In 2004, E&P operations in Northwest Europe contributed 29 percent of E&Ps worldwide liquids
production, compared with 30 percent in 2003. Our Northwest European assets are principally
located in the Norwegian and U.K. sectors of the North Sea. Northwest Europe operations
contributed 34 percent of natural gas production in both years.
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 2004 from the Ekofisk Area was 127,400 barrels of
liquids per day and 125 million cubic feet of natural gas per day, compared with 126,500 barrels of
liquids per day and 127 million cubic feet of natural gas per day in 2003. 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: construction of a new platform, Ekofisk 2/4M, and
modification of the existing Ekofisk Complex to increase processing capacity. Construction began
in 2003, and during 2004 the 2/4M platform progressed on schedule. 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, and
Norwegian 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, a 6.4 percent interest in the Grane 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 87,700 barrels of liquids
per day and 176 million cubic feet of natural gas per day in 2004, compared with 93,300 barrels of
liquids per day and 149 million cubic feet of natural gas per day in 2003.
We and our co-venturers received approval from Norwegian authorities in October 2004 for the
Alvheim North Sea development. The development plans include a floating production storage and
offloading vessel and subsea installations. Production from the field is expected to commence in
2007. We have a 20 percent interest in the project.
We have interests in the transportation and processing infrastructure in 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.
Three partner-operated exploration wells were drilled in 2004. All three were near-field
exploration wells in the Heidrun and Visund licenses. The drilling near Heidrun resulted in one
discovery and one dry hole. The well in the Visund area was a hydrocarbon discovery. In 2005,
seven to eight wells are planned to be drilled in Norway and Denmark.
We are a joint operator of the Britannia natural gas/condensate field, in which we have a 58.7
percent interest. Our net production from Britannia averaged 347 million cubic feet of natural gas
per day and 15,500 barrels of liquids per day in 2004, compared with 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 in the Britannia field is
expected to continue into the year 2007.
In December 2003, we approved a plan for the development of two new Britannia satellite fields: the
Callanish and Brodgar fields. The U.K. government approved the development plan in early 2004.
The development plan involves producing the fields via subsea manifolds and two new pipelines to
Britannia. A new platform, bridge-linked to Britannia, will also be installed to separate
production prior to processing on the Britannia platform. Drilling began in the second half of
2004, with the pipelines, manifolds and installation of the bridge-linked platform anticipated for
2006. First production is targeted for 2007. We have a 75 percent interest in the Brodgar field
and an 83.5 percent interest in the Callanish field.
We operate and hold a 36.5 percent interest in the Judy/Joanne fields, which together comprise
J-Block. Additionally, the Jade field produces 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 14,100 barrels of liquids per day and 118 million cubic feet of natural
gas per day in 2004, compared with 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. 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. Net production in 2004 averaged 306 million cubic feet per
day of natural gas and 1,400 barrels of liquids per day, compared with 371 million cubic feet per
day of natural gas and 2,000 barrels per day of liquids in 2003.
The Valkyrie development was brought into production in 2004. This is a single well development
drilled from a nearby platform. We are the operator with a 50 percent interest.
During 2004, we received approval from the U.K. government for development of the Saturn Unit Area
in the southern North Sea. First gas production from the Saturn Unit Area is expected in the
fourth quarter of 2005, with net production expected to increase to a maximum rate of approximately
73 million cubic feet per day within a year following startup. Initially, the development will
consist of three wells from a six-slot wellhead platform. We are the operator of the Saturn Unit
Area and have an interest of 42.9 percent.
During 2004, we concluded the development of the CMS3 area in the southern sector of the U.K. North
Sea with the completion of the Boulton H-1 well. This development consists of five natural gas
reservoirs developed as a single, unitized project. 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
Also during 2004, we received internal and co-venturer approvals for the Munro development, and are
working toward U.K. governmental approval in the first quarter of 2005. Munro is a single well
development which would tie into the Hawksley subsea manifold (part of CMS3). We are the operator
of Munro with a 46 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, a 30
percent interest in the Miller 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 38,800 barrels of liquids per day and 47 million
cubic feet of natural gas per day in 2004, compared with 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. First
production from Clair is expected in early 2005, with plateau production expected in 2006
at a net rate of 14,400 BOE per day.
The Interconnector pipeline, which connects the United Kingdom and Belgium, facilitates marketing
natural gas produced in the United Kingdom throughout Europe. Our 10 percent equity share of the
Interconnector pipeline allows us to ship approximately 200 million net cubic feet of natural gas
per day to markets in continental Europe.
We operate two terminals in the United Kingdom: the Teesside oil terminal (in which we have a 29.3
percent interest) and the Theddlethorpe gas terminal (in which we have a 50 percent interest).
In the U.K. sector of the North Sea, we participated in two wells in the southern North Sea and one
well on a structure adjacent to the Callanish field in the central North Sea during 2004. All
three of these wells were successful in locating commercial quantities of hydrocarbons. The
planned drilling program for 2005 includes seven to eight exploration and appraisal wells.
In 2004, E&P operations in Canada contributed 4 percent of E&Ps worldwide liquids production
(excluding Syncrude production), compared with 5 percent in 2003. Canadian operations contributed
13 percent of natural gas production in both years.
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 accessible only
in the winter. The central and west regions mainly produce natural gas. The south region has
shallow gas and medium-to-heavy oil. Production from these oil and gas operations in western
Canada averaged a net 35,000 barrels per day of liquids and 433 million cubic feet per day of
natural gas in 2004, compared with 30,300 barrels per day of liquids and 435 million cubic feet per
day of natural gas in 2003.
In February 2004, we sold our 46.7 percent interest in Petrovera, a joint venture that produced
The Surmont lease is located about 35 miles south of Fort McMurray, Alberta. We own a 43.5 percent
interest and are the operator. In May 2003, we received regulatory approval to develop the Surmont
project from the Alberta Energy and Utilities Board and in late 2003, our Board of Directors
approved the project. In 2003, we classified 223 million barrels as proved crude oil reserves from
our Canadian operations, the majority of which related to the Surmont heavy-oil project.
Consistent with our practice and in accordance with U.S. Securities and Exchange Commission
guidelines that require the use of year-end prices for reserve estimation, due to low December 31,
2004, Canadian bitumen values, we removed all of the crude oil reserves for the Surmont project
from the proved category at year-end 2004. Despite this revision, the Surmont project remains an
economically viable and important component of our E&P project portfolio.
The Surmont project uses an enhanced thermal oil recovery method called steam assisted gravity
drainage. This process involves heating the oil by the injection of steam deep into the oil sands
through a horizontal well bore, effectively lowering the viscosity and enhancing the flow of the
oil, which is then recovered via gravity drainage into a lower horizontal well bore and pumped to
the surface. Over the life of this 30+ year project, we anticipate that approximately 500
production and steam-injection well pairs will be drilled. Construction of the facilities and
development drilling began in 2004. Commercial production is expected to begin in late 2006, with
peak production expected in 2012. We anticipate using our share of the heavy oil produced as a
feedstock in our U.S. refineries.
We are working with three other energy companies, as members of the Mackenzie Delta Producers
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 established markets in North America.
Initial design capacity for the Mackenzie Valley pipeline is proposed to be 1.2 billion 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 primary fields in the Mackenzie Delta that
would anchor the pipeline development. Regulatory applications for the project were submitted in
2004, and first gas production is currently targeted for the 2009 timeframe.
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. As part of our evaluation, we are waiting on the
results from drilling on adjacent blocks. In deepwater Newfoundland, we converted our large
Laurentian permit into specific exploration licenses. Exploration of these licenses began in 2004
with a 2D seismic survey, and a larger
3D seismic program is planned for 2005. In the foothills, we drilled four wildcat exploratory
wells in 2004. One was successful, and the other three are being tested. In the Mackenzie
Delta/Beaufort Sea, we participated in the Umiak well. This well will be tested during the first
quarter of 2005 and an appraisal well is also planned.
Other Canadian Operations
Syncrude Canada Ltd.
We own a 9.03 percent 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 21,000 barrels per
day in 2004, compared with 19,000 barrels per day in 2003.
The development of the Stage III expansion-mining project continued in 2004, which is expected to
increase our Syncrude production. The new mine was completed and started up in the fourth quarter
of 2003. The upgrader expansion project is expected to be fully operational by mid-2006.
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 our supplemental oil and gas
In 2004, E&P operations in South America were comprised of interests in Venezuela and Brazil.
South American operations contributed 9 percent of E&Ps worldwide liquids production in 2004,
compared with 8 percent in 2003.
Petrozuata and Hamaca
Petrozuata is a Venezuelan Corporation formed under an Association Agreement between a wholly owned
subsidiary of ConocoPhillips that has a 50.1 percent non-controlling equity interest and a
subsidiary of Petroleos de Venezuela S.A. (PDVSA), the national oil company of Venezuela. The
Association Agreement has a term of 35 years, that began in 2001.
The project is an integrated operation that produces 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 heavy, processed crude oil and light, processed crude oil.
Associated products produced are liquefied petroleum gas, sulfur, petroleum coke and heavy gas oil.
The processed crude oil produced by Petrozuata is used as a feedstock for our Lake Charles,
Louisiana, refinery, as well as the Cardon refinery in Venezuela operated by PDVSA. Our net
production was 59,600 barrels of heavy crude oil per day in 2004, compared with 51,600 barrels per
day in 2003, and is included in equity affiliate production.
In 1997, 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.
The Hamaca project also involves the development of heavy-oil reserves from the Orinoco Oil Belt.
We own a 40 percent interest in the Hamaca project, which has a 35-year term, beginning in 2004,
and 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 32,600 barrels per day of heavy crude oil in 2004, compared with 22,100 barrels per day in
2003, and is included in equity affiliate production.
Construction of the heavy-oil upgrader, pipelines and associated production facilities for the
Hamaca project at the Jose industrial complex began in 2000. In the fourth quarter of 2004, we
began producing on-specification medium-grade crude oil for export at the planned ramp-up capacity
of the plant. Our net oil production from the Hamaca field is expected to be approximately 56,100
barrels per day in 2005.
In October 2004, the President of Venezuela made a public statement that the reduction in the
royalty rate to 1 percent from 16.67 percent for a period of nine years, or until revenues exceed
three times the initial investment, would no longer apply to extra-heavy crude oil producing and
processing projects. This statement was later confirmed in writing by the Ministry of Energy and
Mines (MEM) to the Petrozuata and Hamaca project representatives. Consequently, Petrozuata and
Hamaca began paying royalties at the higher rate effective October 2004. As a result, 2005
production estimates were reduced by approximately 20,000 net barrels per day and our proved
reserves at year-end 2004 were reduced 46 million barrels.
Gulf of Paria
In 2003, the Venezuelan authorities approved the original development plan for Phase I of the
Corocoro field. Venezuelan authorities did not approve a development plan addendum submitted in
2004. However, in early 2005 verbal agreement of requirements to progress the project was
achieved. We will be working with the Venezuelan government and co-venturers to finalize the terms
agreed and move the project forward to development. We operate the field with a 32.2 percent
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. Two appraisal wells were completed in
2004, and a third was completed in January 2005. All appraisal wells indicated that the target
zones were natural gas bearing. In addition, a new natural gas/condensate discovery was made in a
deeper zone. Development of the field may include a well platform, a 170-mile pipeline to shore,
and an LNG plant. The LNG would be shipped to the U.S. market.
Wildcat exploratory activity in both the Gulf of Paria East and West Blocks was commercially
unsuccessful in 2004, which resulted in a full impairment of our leasehold investment in these
blocks. However, we are still pursuing evaluation plans to assess future potential.
We had concession agreements on two deepwater exploration blocks (BM-ES-11 and BM-PAMA-3) offshore
Brazil. During 2003 and 2004, further evaluation led to the write-off of our leasehold investments
in both blocks. By the end of 2004, we had ceased all operations in Brazil and exited the country.
In 2004, E&P operations in the Asia Pacific area contributed 10 percent of E&Ps worldwide liquids
production, compared with 6 percent in 2003. Asia Pacific operations contributed 9 percent of
natural gas production in both years.
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 onshore
South Sumatra. A potentially emerging area is offshore East Java. We are a party to five
long-term, U.S.-dollar-denominated natural gas contracts that are based on oil price benchmarks.
In addition, in 2004 we began supplying natural gas to markets on the Indonesian island of Batam
and new contracts were signed to supply natural gas to domestic markets in West Java and East Java.
These are U.S.-dollar-denominated, fixed-price contracts. Production from Indonesia in 2004 averaged a net 250 million cubic feet per day of natural gas and
15,400 barrels per day of oil, compared with 255 million cubic feet per day of natural gas and
16,000 barrels per day of oil in 2003.
We operate three offshore PSCs: South Natuna Sea Block B, Nila, and Ketapang. We also hold a
non-operator interest in the Pangkah PSC offshore East Java.
The South Natuna Sea Block B PSC, in which we have a 40 percent interest, has two currently
producing oil fields and 16 gas fields in various stages of development (seven of which have
recoverable oil or condensate volumes). In late 2004, oil production began from the Belanak oil
and gas field through a new floating production, storage and offloading (FPSO) vessel and related
facilities. Also in Block B, we began development of the Kerisi and Hiu fields, with construction
contract awards under way, and we began the preliminary engineering phase of the North Belut field
In the Pangkah PSC, in which we have a 22 percent interest, the development of the Ujung Pangkah
field was approved by the Indonesian government in late 2004 following the signing of contracts for
the supply of natural gas to markets in East Java.
We operate six onshore PSCs. Four are in South Sumatra: Corridor PSC, Corridor TAC, South Jambi
B, and Sakakemang JOB. We also operate Block A PSC in Aceh, and Warim in Papua. We hold
non-operator interests in the Banyumas PSC in Java and the Bentu and Korinci-Baru PSCs in Sumatra.
The Corridor PSC is located onshore South Sumatra and we have a 54 percent interest. We operate
six oil fields and six natural gas fields, and supply natural gas from the Grissik and Suban gas
processing plants to the Duri steamflood in central Sumatra operated by Caltex and to markets in
Singapore and Batam.
In August 2004, we announced the signing of a gas sales agreement with PT Perusahaan Gas Negara
(Persero) Tbk. (PGN), the Indonesian state-owned gas transportation company, to supply natural gas
for delivery to the industrial markets in West Java and Jakarta. The agreement calls for us to
supply approximately 850 billion net cubic feet of gas over a 17-year period commencing in the
first quarter of 2007. At the contracted rates, initial gas deliveries are about 65 million net
cubic feet per day, ramping up to approximately 140 million net cubic feet per day in 2012, and
continuing at that level until the contract terminates in 2023.
Following the execution of the West Java gas sales agreement with PGN in August, we began the
development of the Suban Phase II project, which is an expansion of the existing Suban gas plant in
the Corridor PSC.
The South Jambi B PSC is also located in South Sumatra, and we have a 45 percent interest. In
2004, we completed the construction of the South Jambi shallow gas project for supply of natural
gas to Singapore from the South Jambi B Block, with first production occurring in June 2004.
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, and Grissik to Singapore, natural gas pipelines.
In Indonesia, a total of 11 exploration and appraisal wells were drilled during 2004, of which five
were successful. In the Pangkah PSC, two appraisal wells confirmed a western extension of the
Ujung Pangkah field. In the Ketapang PSC, an appraisal well of the Bukit Tua field provided data
for progressing a development plan in 2005. In Sumatra, two appraisal wells were successful in
finding additional gas volumes in both the Korinci-Baru and the Bentu PSCs.
Our combined net production of crude oil from the Xijiang facilities averaged 10,400 barrels per
day in 2004, compared with 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 FPSO facility.
Production from Phase I development of the Peng Lai 19-3 field in Bohai Bay Block 11-05 began in
late 2002. In 2004, the field produced 15,000 net barrels of oil per day, compared with 14,800
barrels per day in 2003. 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
In December 2004, our Board of Directors approved the second phase of development of the Peng Lai
19-3 field, as well as concurrent development through the same facilities of the nearby Peng Lai
25-6 field. The Overall Development Program for both fields was submitted to the Chinese
government in November 2004, and was approved in January 2005. Construction activities have since
begun. The second phase will include multiple wellhead platforms and a larger FPSO facility.
We have a 23.25 percent interest in Block 15-1 in the Cuu Long Basin in the South China Sea. First
production from Block 15-1 began in the fourth quarter of 2003 with the startup of the Su Tu Den
development. Net production in 2004 was 20,800 barrels of oil per day. The oil is being processed
through a 1 million barrel FPSO vessel.
We have a 36 percent interest in the Rang Dong field in Block 15-2 in the Cuu Long Basin. All
wellhead platforms produce into a FPSO vessel. Net production in 2004 was 11,800 barrels of
liquids per day and 16 million cubic feet per day of natural gas. Development of the central part
of the field is under way, with two additional platforms and additional production and injection
wells expected to be completed in the third quarter of 2005.
We own a 16.33 percent interest in the Nam Con Son gas pipeline. This 242-mile transportation
system links gas supplies from the Nam Con Son Basin to gas markets in southern Vietnam.
An oil discovery was made on the Su Tu Vang prospect in Block 15-1 in the third quarter of 2001,
with successful appraisal drilling conducted in 2004. Development scenarios are currently under
evaluation, with preliminary engineering commencing in early 2005. The commerciality of the
northeast portion of Su Tu Den is also being evaluated, with additional appraisal drilling planned
for 2005. In addition to these areas, a successful exploration well was drilled in the Su Tu Trang
southeast area of the block in the fourth quarter of 2003. A 3D seismic study was conducted on
this area in 2004 and is currently under interpretation. Additional appraisal drilling is
scheduled for 2005 to further define this gas condensate discovery. We also own interests in
offshore Blocks 5-3, 133 and 134. Our interest in Block 16-2 was relinquished in April 2004 after
unsuccessful exploratory activity.
Timor Sea and Australia
We are the operator and hold a 56.7 percent interest in the unitized Bayu-Undan field, located in
the Timor Sea, which is being developed in two phases. Phase I is a gas-recycle project, where
condensate and natural gas liquids are separated and removed and the dry gas reinjected back into
the reservoir. This phase began production in February 2004, and averaged a net rate of 28,100
barrels of liquids per day in 2004.
Phase II involves the installation of a natural gas pipeline from the field to Darwin, and
construction of an LNG facility located at Wickham Point, Darwin, to meet gross contracted sales of
up to 3 million tons of LNG per year for a period of 17 years to customers in Japan. During 2004,
construction of the LNG facility proceeded, as did the laying of the pipeline. The first LNG cargo
is scheduled for delivery in early 2006. We have a 56.7 percent controlling interest in the
pipeline and LNG facility. Our net share of natural gas production from the Bayu-Undan field is
expected to be approximately 100 million cubic feet per day initially, then ramping up to
approximately 260 net million cubic feet per day by 2009.
We and our co-venturers evaluated commercial development options and LNG markets in the Asia
Pacific region and the North American West Coast during 2004. The focus in 2004 was on an onshore
LNG facility located at Darwin, although other alternatives, such as a floating LNG facility and an
onshore plant in Timor-Leste, were also considered. Further progress on the project will require
resolution of the maritime border dispute between Australia and Timor-Leste and ratification of the
International Unitization Agreement by Timor-Leste. We have a 30 percent, non-operator interest in
A cooperative field development agreement for the Athena/Perseus (WA-17-L) gas field, located
offshore western Australia, was executed in early 2001. In 2004, our net share of production was
35 million cubic feet of natural gas per day.
In 2000, we acquired interests in deepwater Blocks G and J located off the east Malaysian state of
Sabah. We participated in four exploration wells in the blocks. The Gumusut 1 well, in which we
have a 40 percent interest, was drilled in Block J in 2003 and resulted in an oil discovery.
Further exploratory drilling is planned. In September 2004, we successfully completed the drilling
of the Malikai discovery, in which we have a 35 percent interest, in Block G. Appraisal of the
Malikai discovery is anticipated in 2005. In addition, we plan to acquire a 40 percent interest in
the Kebabangan discovery in early 2005. Appraisal work is planned for 2005.
At year-end 2004, we were producing from four onshore Oil Mining Leases (OMLs), in which we have a
20 percent non-operator interest. Our interest in a shallow-water offshore OML was sold in the
second quarter of 2004. Together, in 2004 these leases produced a net 30,100 barrels of oil per
day and 71 million cubic feet of natural gas per day, compared with 36,900 barrels per day and 63
million cubic feet per day in 2003. In 2004, we continued development of projects in the onshore
OMLs to supply feedstock natural gas under a gas sales contract with Nigeria LNG Limited, which
owns an LNG facility on Bonny Island.
We have a 20 percent interest in a 480-megawatt gas-fired power plant being constructed in Kwale,
Nigeria, to supply electricity to Nigerias national electricity supplier under a 20-year
agreement. When operational, the plant is expected to consume 68 million gross cubic feet per day
of natural gas, sourced from proved natural gas reserves in the OMLs. The plant is targeted to
become fully operational in 2005.
In October 2003, ConocoPhillips, the Nigerian National Petroleum Corporation (NNPC), Eni and
ChevronTexaco signed a Heads of Agreement 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
agreed to form an incorporated joint venture, Brass LNG Limited, to undertake the project. These
front-end studies are expected to be completed in 2006, and the LNG facility is targeted to become
operational in 2010.
We also have production sharing contracts on deepwater Nigeria Oil Prospecting Licenses (OPLs),
including OPL 318 with a 50 percent interest, OPL 248 with a 28.8 percent interest, OPL 220 with a
47.5 percent interest, OPL 214 with a 20 percent interest, and OPL 250 with a 6.375 percent
interest. We drilled the first exploration wells on both OPL 248 and OPL 250 in 2004. Neither of
these wells encountered significant hydrocarbons and were classified as dry holes. The first
exploration wells on both OPL 214 and OPL 318 are planned for 2005.
In December 2002, we announced a successful test of an exploratory well offshore Cameroon. The
Coco Marine No. 1 well was located in exploration permit PH 77, offshore in the Douala Basin.
Contractor interests in the permit are held 50 percent by ConocoPhillips and 50 percent by a
subsidiary of Petronas Carigali. We serve as the operator of the consortium. Seismic data was
analyzed during 2004, and we plan an appraisal well and further exploratory drilling in 2005.
We are participating in discussions with our co-venturers and Libyan authorities regarding terms in
connection with our anticipated re-entry into the country.
In July 2003, we signed a Heads of Agreement with Qatar Petroleum for the development of Qatargas
3, a large-scale 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, both of which were advanced in 2004. 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 7.8 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 of 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 project.
Negotiations on more definitive agreements and progress on the studies continued in 2004.
In Dubai, United Arab Emirates, we operate Dubais four large, offshore oil fields. We are using
advanced horizontal drilling techniques and advanced reservoir drainage technology to enhance the
recovery rates and efficiencies in these late-life fields.
We, along with LUKOIL, will cooperate with the Iraqi government to confirm LUKOILs rights under
its production sharing agreement (PSA) relating to the West Qurna field in Iraq. Subject to
confirmation and the consents of governmental authorities and the parties to the contract, we
expect to enter into further agreements regarding the assignment of a 17.5 percent interest in the
PSA to us by LUKOIL.
E&PRUSSIA AND CASPIAN SEA REGION
We have a 50 percent ownership interest in Polar Lights Company, a Russian limited liability
company established in January 1992 to develop fields in the Timan-Pechora basin in Northern
Russia. Our net production from Polar Lights averaged 13,300 barrels of oil per day in 2004,
compared with 13,600 barrels per day in 2003, and is included in equity affiliate production.
LUKOIL Joint Venture
We have entered into an arrangement with LUKOIL under which it is anticipated that we will acquire
a 30 percent economic interest and a 50 percent voting interest in a joint venture to develop oil
and gas resources in the northern part of Russias Timan-Pechora province. We anticipate that our
acquisition of a 30 percent interest will be completed in the first half of 2005. While this joint venture
will be included in our E&P segment, our equity investment in LUKOIL is reflected in the LUKOIL Investment segment.
In late 2004 we signed a Memorandum of Understanding with Gazprom to undertake a joint study on the
development of the Shtokman gas field in the Barents Sea. The cooperative study will include the
evaluation of LNG feasibility and transportation to the United States and European markets.
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 exercised our pre-emptive rights to acquire a proportionate share of BG Internationals 16.67
percent interest in the project. Discussions continue with the Republic of Kazakhstan government
to conclude the sale.
Detailed design, procurement and construction activities continued on the Kashagan oil field
development following approval by the Republic of Kazakhstan for the development plan and budget in
February 2004. First commercial production is targeted for 2008. The initial production phase of
the contract is for 20 years, with options to extend the agreement an additional 20 years.
The contracting companies plan to continue to explore other structures within the North Caspian Sea
license. The exploration area consists of 10.5 blocks, totaling nearly 2,000 square miles. In
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.
During 2004, the successful completion of the first offshore exploration well on the Kairan
prospect was announced. Data analysis and additional studies are being conducted to evaluate the
discovery. The testing of the Kairan-1 exploration well brings the Exploration Period under the
NCPSA to a close. During 2004, appraisal of the Aktote discovery began with the successful
drilling of the Aktote-2 appraisal well.
In the South Caspian Sea offshore Azerbaijan, we have a 20 percent interest in the Zafar Mashal
prospect. The first exploratory well was completed in the third quarter of 2004 and the prospect
In late 2003, we signed an agreement with Freeport LNG Development, L.P. (Freeport LNG) 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.
Freeport LNG received conditional approval in June 2004 from the Federal Energy Regulatory
Commission (FERC) to construct and operate the facility. Final approval from FERC was received in
January 2005. Construction began in early 2005, and commercial startup is expected in 2008.
We are pursuing three other proposed LNG regasification terminals. The Beacon Port Terminal would be
located in federal waters in the Gulf of Mexico, 56 miles south of the Louisiana mainland. Also in
the Gulf of Mexico is the proposed Compass Port Terminal, to be located approximately 11 miles
offshore Alabama. The third proposed facility would be a joint venture located in
the Port of Long Beach, California. Each of these projects are in the initial regulatory
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 Calgary.
Natural Gas Pricing
Compared with the more global nature of crude oil commodity pricing, natural gas prices have
historically varied more in different regions of the world. We produce natural gas from regions
around the world that have significantly different supply, demand and regulatory circumstances,
typically resulting in significantly lower average sales prices than in the Lower 48 region of the
United States. Moreover,
excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate
the relatively high-price conditions in the U.S. Lower 48 states and other markets because of a
lack of infrastructure and because of the difficulties in transporting the natural gas. We, along
with other companies in the oil and gas industry, are planning long-term projects in regions of
excess supply to install the infrastructure required to produce and liquefy natural gas for
transportation by tanker and subsequent regasification in regions where market demand is strong,
such as to the U.S. Lower 48 states or certain parts of Asia, but where supplies are not as
plentiful. Due to the significance of the overall investment in these long-term projects, the
natural gas sales prices (to a third-party LNG facility) or transfer prices (to a company-owned LNG
facility) in the areas of excess supply are expected to remain well below sales prices for natural
gas that is produced closer to areas of high demand and which can be transferred to existing
natural gas pipeline networks, such as in the U.S. Lower 48.
We have not filed any information with any other federal authority or agency with respect to our
estimated total proved reserves at December 31, 2004. No difference exists between our estimated
total proved reserves for year-end 2003 and year-end 2002, which are shown in this filing, and
estimates of these reserves shown in a filing with another federal agency in 2004.
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 5.4
trillion cubic feet of natural gas and 167 million barrels of crude oil in the future, including
1.0 trillion cubic feet related to the minority interests of consolidated subsidiaries. These
contracts have various expiration dates through the year 2025. Although these delivery commitments
could be fulfilled utilizing proved reserves in the United States, the Timor Sea, Nigeria,
Indonesia, and the United Kingdom, we anticipate that some of them will be fulfilled with purchases
in the spot market. A portion of the natural gas delivery commitment relates to proved undeveloped
reserves in the Timor Sea and Indonesia. The Timor Sea reserves are expected to convert from
proved undeveloped to proved developed in 2006 upon completion of the liquefied natural gas
infrastructure in the region. A portion of the Indonesian reserves are expected to convert to
proved developed in 2007, when additional wells are drilled and the expansion of the Suban gas
plant is completed.
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. The remaining
residue gas is marketed to electrical utilities, industrial users, and gas marketing companies.
Most of the natural gas liquids are fractionatedseparated into individual components like ethane,
butane and propaneand marketed as chemical feedstock, fuel, or blendstock. Total natural gas
liquids extracted in 2004, including our share of DEFS, was 194,000 barrels per day, compared with
215,000 barrels per day in 2003.
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 is headquartered in Denver, Colorado. At December 31, 2004, DEFS owned and operated 55
natural gas liquids extraction plants, owned an equity interest in another nine, and had two
classified in discontinued operations. Also at year end, DEFS gathering and transmission systems
included approximately 59,000 miles of pipeline. In 2004, DEFS raw natural gas throughput
averaged 6.4 billion cubic feet per day, and natural gas liquids extraction averaged 363,000
barrels per day, compared with 6.6 billion cubic feet per day and 353,000 barrels per day,
respectively, in 2003. 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. natural gas liquids business included the following assets as of December
A 50 percent interest in a natural gas liquids extraction plant in San Juan County, New
Mexico, with a gross plant inlet capacity of 500 million cubic feet per day. We also have
minor interests in two other natural gas liquids extraction plants.
A 25,000-barrel-per-day capacity natural gas liquids fractionation plant in Gallup, New
A 22.5 percent equity interest in Gulf Coast Fractionators, which owns a natural gas
liquids fractionation plant in Mont Belvieu, Texas (with our net share of capacity at
25,000 barrels per day).
A 40 percent interest in a fractionation plant in Conway, Kansas (with our net share of
capacity at 42,000 barrels per day).
During 2004, we sold certain Midstream assets located primarily in Texas, Louisiana and New Mexico.
This reflected our strategy to divest properties that did not support our natural gas production,
while focusing on DEFS as the most effective vehicle for generating income from the processing of
third-party natural gas. Included in the dispositions was a 700-mile intrastate natural gas and
liquids pipeline system in Louisiana.
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 100 percent interest in a 580-mile Petroleum Transmission Company pipeline from
Empress to Winnipeg and five related pipeline terminals.
Two underground natural gas liquids storage facilities, comprised of the Richardson
caverns with an approximate one-million-barrel capacity and the Dewdney caverns with an
approximate three-million-barrel capacity, along with 800 million cubic feet of natural gas
A 10 percent interest in the 1,902-mile Cochin liquefied petroleum gas pipeline, originating in
Edmonton, Alberta, and ending in Sarnia, Ontario, and a terminal storage system that transports
propane, ethane and ethylene was sold in the fourth quarter of 2004.
Canadian natural gas liquids extracted averaged 45,000 barrels per day in 2004, the same as 2003.
We also own a 39 percent equity interest in Phoenix Park Gas Processors Limited, a joint venture
primarily 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 1.35-billion-cubic-feet-per-day gas processing plant and a
46,000-barrel-per-day natural gas liquids fractionator. Our share of natural gas liquids extracted
averaged 6,000 barrels per day in 2004.
In Syria, we have a service contract with the Syrian Petroleum Company that expires on December 31,
2005. Our current plan is to honor that contract to its termination date. We expect our presence
in Syria to end in 2006, once the formalities of closing out the service contract are accomplished.
We have no plans to seek additional business in Syria.
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 R&M segment does not include the results or statistics from our equity investment in LUKOIL,
which are reported in a separate segment (LUKOIL Investment). As a result, references to results,
refinery crude oil throughput capacities and other statistics throughout the R&M segment exclude
those related to our equity investment in LUKOIL.
The Commercial organization optimizes the commodity flows of our R&M segment. This organization
selects and procures feedstocks for R&Ms refineries. Commercial also facilitates supplying a
portion of the gas and power needs of the R&M facilities. Commercial has buyers, traders and
marketers in offices in Houston, London, Singapore and Calgary.
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. During the second quarter of 2004, we sold our Mobil-branded marketing assets on the
East Coast in two separate transactions. Assets in the packages included approximately 100
company-owned-and-operated sites, and 350 dealer sites. The majority of the remaining sites are
under contracts expected to close in 2005.
During the second quarter of 2004, we performed a review of the crude oil refining capacities for
our worldwide refining operations. We utilize a barrels-per-calendar-day methodology, which
includes allowances for maintenance turnarounds, regulatory constraints, crude oil quality and
reliability. As a result of this review, effective July 1, 2004, R&Ms total U.S. crude oil
capacity was revised downward slightly, from 2,168,000 barrels per day to 2,160,000 barrels per
day, while R&Ms international refining capacity decreased from 447,000 barrels per day to 428,000
barrels per day.
At December 31, 2004, we owned and operated 12 crude oil refineries in the United States, having an
aggregate crude oil refining capacity of 2,160,000 barrels per day.
At December 31, 2004.
East Coast Region
Located on the New York Harbor in Linden, New Jersey, Bayway has a crude oil processing capacity of
238,000 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. The complex also includes a 775-million-pound-per-year polypropylene plant
that 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
185,000 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 247,000 barrels per day and processes mainly light low-sulfur crudes.
Alliance receives domestic crude oil from the Gulf of Mexico 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 major
common-carrier pipeline systems.
Lake Charles Refinery
The Lake Charles refinery is located in Westlake, Louisiana. The refinery has a crude oil
processing capacity of 239,000 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
its 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 its 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 include a specialty coker and calciner that manufacture graphite
petroleum coke, which is supplied to the steel and aluminum industries. The coker and calciner
also provide 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 216,000 barrels per day, and processes mainly
heavy, high-sulfur crude oil, but also processes light, low-sulfur crude oil. 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 by pipeline, barge
ConocoPhillips has a 50 percent interest in Merey Sweeny, L.P., a limited partnership that owns a
65,000-barrel-per-day delayed coker and related facilities at the Sweeny refinery. PDVSA, which
owns the other 50 percent interest, supplies the refinery with Venezuelan Merey, or equivalent
Venezuelan, 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 R&Ms largest refinery, with a crude
oil processing capacity of 306,000 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
During 2003, we purchased certain assets at Premcors Hartford, Illinois, 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 integration
of these units into the refinery was completed during the second quarter of 2004, enabling the
refinery to process heavier, lower-cost crude oil.
Ponca City Refinery
The Ponca City refinery is located in Ponca City, Oklahoma. It has a crude oil processing capacity
of 187,000 barrels per day, and processes light and medium weight, low-sulfur crude oil. 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 146,000 barrels per day, and the natural gas liquids fractionation capacity is 45,000
barrels per day. The natural gas liquids capacity was reduced during 2004 as part of a
reconfiguration project. 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.
West Coast Region
The Billings refinery is located in Billings, Montana, and has a crude oil processing capacity of
58,000 barrels per day, processing a mixture of 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,
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
139,000 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 to meet federally mandated oxygenate requirements. Refined products are
distributed to customers in Southern California, Nevada and Arizona by pipeline and truck.
San Francisco Refinery
The San Francisco 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 106,000 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 calcined and
fuel-grade petroleum coke. The refinery produces CARB gasoline using ethanol to meet federally
mandated oxygenate requirements. Refined products are distributed by pipeline, railcar, truck and
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 93,000 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, R&M markets gasoline, diesel fuel, and aviation fuel through approximately
13,300 outlets in 46 states. The majority of these sites utilize the Conoco, Phillips 66 or 76
In our wholesale operations, we utilize a network of marketers and dealers operating approximately
12,300 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 the spot
market. Our refined products are marketed on both a branded and unbranded basis.
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 Mountain, and West Coast regions. Most of these outlets market merchandise
through the Kicks 66, Breakplace, or Circle K brand convenience stores.
At December 31, 2004, CFJ Properties, our 50/50 joint venture with Flying J, owned and operated 98
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. Flying J elected not to exercise
their purchase option. As a result, we plan to continue as a co-venturer in CFJ Properties.
Pipelines and Terminals
At December 31, 2004, we had approximately 32,500 miles of common-carrier crude oil, raw natural
gas liquids and products pipeline systems in the United States, including those partially owned
and/or operated by affiliates. We also owned and/or operated 66 finished product terminals, 10
liquefied petroleum gas terminals, seven crude oil terminals and one coke exporting facility.
At December 31, 2004, we had under charter 16 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 have a domestic fleet of both owned and
chartered boats and barges providing inland and ocean-going 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
We manufacture and sell a variety of 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 5,000 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 blend the base oil into finished
lubricants or market it to third parties.
We have a 50 percent interest in Penreco, a specialties company, which manufactures and markets
highly refined specialty petroleum products, including solvents, waxes, petrolatums and white oils,
for global markets.
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, 2004, R&M owned or had an interest in six refineries outside the United States with
an aggregate crude oil capacity of 428,000 net barrels per day.
ConocoPhillips share at December 31, 2004.
Our wholly owned Humber refinery is located in North Lincolnshire, United Kingdom. The refinerys
crude oil processing capacity is 221,000 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
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 70 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
The Whitegate refinery is located in Cork, Ireland, and has a crude oil processing capacity of
71,000 barrels per day. Crude oil processed by the refinery is light sweet crude sourced mostly
from the North Sea. The refinery primarily produces transportation fuels and fuel oil, which are
distributed to the inland market via truck and sea, as well as being exported to the European
market. 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 45
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 a 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
Czech Republic Refineries
Through our participation in Èeská 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. The
refinery at Litvinov has a crude oil processing capacity of 103,000 barrels per day and processes
Russian export blend crude oil delivered by pipeline. Litvinov 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 63,000
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. The refinery has a rated crude oil
processing capacity of 119,000 barrels per day, of which our share is 56,000 barrels per day.
Crude oil processed by the refinery is sourced mostly from the Middle East. The refinery produces
a full range of refined petroleum products. The refinery capitalizes on 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 Asian markets.
R&M has marketing operations in 15 European countries. R&Ms 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, 2004, R&M had approximately 2,100 marketing outlets in its European operations,
of which about 1,480 were company-owned, and 620 were dealer-owned. Through our joint venture
operations in Turkey and Switzerland, we also have interests in approximately 810 additional sites.
The companys largest branded site networks are in Germany and the United Kingdom, which account
for approximately 63 percent of our total European branded units.
As of December 31, 2004, R&M had 143 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 43 retail
sites. In Thailand and Malaysia, retail products are marketed under the JET and ProJET brands,
In September 2004, we made a joint announcement with LUKOIL, an international integrated oil and
gas company headquartered in Russia, of an agreement to form a broad-based strategic alliance,
whereby we would become a strategic equity investor in LUKOIL. Together, we also announced our
intention to form a joint venture between the two companies to develop resources in the northern
part of Russias Timan-Pechora oil and gas province and the intention of the two companies to
jointly seek the right to develop the West Qurna oil field in Iraq.
In the announcement, we disclosed that we were the successful bidder in an auction of 7.6 percent
of LUKOILs authorized and issued ordinary shares held by the Russian government. The transaction
closed on October 7, 2004. By year-end 2004, we had increased our ownership in LUKOIL to 10
percent. Under the Shareholder Agreement between the two companies, we had the right to nominate a
representative to the LUKOIL Board of Directors (Board). In January 2005, our nominee was elected
to the LUKOIL Board, and certain amendments to LUKOILs corporate charter that require unanimous
Board consent for certain key decisions were approved. In addition, the Shareholder Agreement
allows us to increase our ownership interest in LUKOIL to 20 percent and limits our ability to sell
our LUKOIL shares for a period of four years, except in certain circumstances. Once we reach 12.5
percent ownership, we have the right to nominate a second representative to the LUKOIL Board. We
use the equity method of accounting for our investment in LUKOIL. We estimate that our net share
of LUKOILs proved reserves at December 31, 2004, was 880 million barrels of oil equivalent.
As reported in LUKOILs 2003 annual report, the majority of its upstream production is sourced
within Russia, with 68 percent from the western Siberia region, 14 percent from the Timan-Pechora
region and 13 percent from the Urals region. Outside of Russia, LUKOIL has projects in Azerbaijan,
Kazakhstan, Egypt and Iraq. Downstream, LUKOIL has seven refineries with a net crude oil
throughput capacity of approximately 1.2 million barrels daily. In addition, LUKOIL has an
interest in approximately 4,600 retail sites in Russia and Europe, and another approximately 2,000
in the northeast United States.
Chevron Phillips Chemical Company LLC (CPChem) is a 50/50 joint venture with ChevronTexaco
Corporation. We use the equity method of accounting for our investment in CPChem.
CPChem is headquartered in The Woodlands, Texas. 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 one pipe fittings plant and nine plastic
pipe plants in eight states.
Major international production facilities, including CPChems joint-venture facilities, are located
in Belgium, China, Saudi Arabia, Singapore, South Korea and Qatar. In addition, there is one
plastic pipe plant in Mexico.
CPChem has research and technical facilities in Oklahoma, Ohio and Texas, as well as in Singapore
Construction of a major olefins and polyolefins complex in Mesaieed, Qatar, called Q-Chem I, was
completed in 2003. The facility completed performance testing and became fully operational in
2004. It 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, called 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 entered into a separate agreement with Atofina (now Total Petrochemical) and Qatar
Petrochemical Company to jointly develop an ethane cracker in northern Qatar at Ras Laffan
Industrial City. Request for final approval of the Q-Chem II projects by CPChems Board of
Directors is expected in 2005, with startup anticipated in 2008.
In 2003, CPChem formed a 50 percent-owned joint venture company to develop an integrated styrene
facility in Al Jubail, Saudi Arabia. The facility, to be built on a site adjacent to the existing
aromatics complex owned by Saudi Chevron Phillips Company (SCP), another 50 percent-owned CPChem
joint venture, will include feed fractionation, an olefins cracker, and ethylbenzene and styrene
monomer processing units. Construction of the facility will be in conjunction with an expansion of
SCPs benzene plant. Construction began in the fourth quarter of 2004 and operational startup is
anticipated in late 2007.
Emerging Businesses encompass the development of new businesses beyond our traditional operations.
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, operated during 2004 as planned. The
plant will be operated in 2005 as necessary to obtain technical data for commercial applications.
Our Technology Solutions businesses provide both upstream and downstream 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 SRT), alkylation technologies (ReVAP), and delayed
coking (ThruPlus) technologies. We also offer a gasification technology (E-Gas) that uses
petroleum coke, coal,
and other low-value hydrocarbon as feedstock, resulting in high-value synthesis gas that can be
used for a slate of products, including power, hydrogen and chemicals.
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 their 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 completed development of a 730-megawatt, gas-fired combined heat and power plant
in North Lincolnshire, United Kingdom. The facility provides steam and electricity to the Humber
refinery and steam to a neighboring refinery, as well as merchant power into the U.K. market.
Construction began in 2002, and the project was placed in commercial operations in October 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, Louisiana.
Emerging Technology focuses on developing new business opportunities designed to provide growth
options for ConocoPhillips well into the future. Example areas of interest include advanced
hydrocarbon processes, energy conversion technologies, new petroleum-based products, and renewable
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 13, 2004, issue of the
Oil and Gas
, our E&P segment had, on a BOE basis, 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 a large producer of natural gas liquids in the United States. DEFS
principle methods of competing include economically securing the right to purchase raw natural gas
into its gathering systems, managing the pressure of those systems, operating efficient natural gas
liquids processing plants, and securing markets for the products produced.
Downstream, our R&M segment competes primarily in the United States, Europe and the Asia Pacific
region. Based on the statistics published in the December 20, 2004, issue of the
Oil and Gas
, our R&M segment had the largest U.S. refining capacity of 14 large refiners of petroleum
Worldwide, it ranked fifth among non-government-controlled companies. In the Chemicals segment,
through our equity investment, CPChem generally ranks within the top 10 producers of many of its
major product lines, based on average 2004 production capacity, as published by industry sources.
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 2004, we held a total of 1,692 active patents in 70 countries worldwide, including
697 active U.S. patents. During 2004, we received 51 patents in the United States and 121 foreign
patents. Our products and processes generated licensing revenues of $28 million in 2004. 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 $126 million, $136 million and $355 million in 2004, 2003 and 2002,
The environmental information contained in Managements Discussion and Analysis on pages 77 through
80 under the caption, Environmental is incorporated herein by reference. It includes information
on expensed and capitalized environmental costs for 2004 and those expected for 2005 and 2006.
International and domestic political developments and government regulation at all levels are prime
factors that may materially affect our operations. Such political developments and regulation may
affect prices; production levels; asset ownership; 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 and compliance for environmental protection. The occurrences and effects of such
events are not predictable.
Our Internet Web site address is
. Information 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 2004 and those matters previously reported in
ConocoPhillips 2003 Form 10-K and our first-, second- and third-quarter 2004 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 U.S. Securities and Exchange Commissions regulations.
In December 2004, the Puget Sound Clean Air Agency (PSCAA) notified us of their intent to seek
civil penalties in the amount of $203,000 for alleged violations of various PSCAA regulations at
our Tacoma Terminal in the state of Washington. We are currently assessing these allegations and
expect to work with the PSCAA towards a resolution of this matter.
In December 2004, the San Luis Obispo Air Pollution Control District (SLOAPCD) notified us of their
intent to seek civil penalties in the amount of $2,700,000 for alleged violations of various
SLOAPCD regulations at the Santa Maria facility of our San Francisco refinery. We are currently
assessing these allegations and expect to work with the SLOAPCD towards a resolution of this
We participated in negotiations throughout 2004 with the U.S. Environmental Protection Agency
(EPA), U.S. Department of Justice (DOJ), the states of Louisiana, Illinois, Pennsylvania, New
Jersey, and the Northwest Clean Air Agency (the state of Washington) to settle allegations arising
out of the EPAs national enforcement initiative, as well as other related Clean Air Act regulation
issues. In January 2005, we entered into a consent decree with the United States and the local
agency and states named above. In the consent decree, we agreed to reduce air emissions from
refineries in Washington, California, Texas, Louisiana, Illinois, Pennsylvania, and New Jersey by
approximately 47,000 tons per year over the next eight years. We plan to spend an estimated $525
million over that time period to install control technology and equipment to reduce emissions from
stacks, vents, valves, heaters, boilers, and flares. The consent decree requires us to pay a civil
penalty of $4.5 million in addition to at least $10 million to be spent on supplemental
environmental projects in Illinois, Pennsylvania, Louisiana, Washington, and New Jersey.
The U.S. Coast Guard and Washington State Department of Ecology are investigating the possible
sources of an alleged oil spill in Puget Sound. In November 2004, the U.S. Attorney and the U.S.
Coast Guard offices in Seattle, Washington, issued subpoenas to Polar Tankers, Inc., a subsidiary
of ConocoPhillips Company, for records related to the vessel Polar Texas. On December 23, 2004,
the Governor of the state of Washington and the U.S. Coast Guard publicly announced that they
believed the Polar Texas was the source of the alleged spill. Based on everything presently known
by the company, we do not believe that we are the source of the alleged spill. The company is
fully cooperating with the governmental authorities.
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 (BAAQMD) regulations at the Rodeo
facility of our San Francisco refinery. On October 12, 2004, we entered into a settlement with the
BAAQMD to resolve the alleged violations. We paid a civil penalty of $350,000 to the BAAQMD.
In August 2004 Polar Tankers, Inc., a subsidiary of ConocoPhillips Company, self-reported to the
U.S. Coast Guard that a company employee had disclosed to management potential environmental
violations onboard the vessel Polar Alaska. The potential violations related to allegations that
certain actions may have resulted in one or more wastewater streams being discharged potentially
having concentrations of oil exceeding an applicable regulatory limit of 15 parts per million. On
September 1, 2004, the United States Attorneys office in Anchorage issued a subpoena to
ConocoPhillips Company and Polar Tankers, Inc. for records relating to the companys report of
potential violations. The company is fully cooperating with the governmental authorities.
On March 2, 2004, the BAAQMD notified us of their intent to seek civil penalties in the amount of
$750,000 for 17 alleged violations of various BAAQMD regulations at our Rodeo facility and carbon
plant located in the San Francisco area. We are currently assessing these allegations and expect
to work with the BAAQMD towards a negotiated resolution of this matter.
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 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
alleged violations have been resolved as part of the January 2005 consent decree we entered into
with the United States and other parties named above.
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 the EPA staff on
several occasions to discuss the allegations. We believe the EPA staff is evaluating the
information presented at the meetings. The EPA has not yet proposed a penalty amount.
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 agreed to resolve this
matter for $410,000.
On December 17, 2002, the DOJ notified ConocoPhillips of various alleged violations of the National
Pollution Discharge Elimination System permit for the Sweeny refinery. DOJ asserts that these
alleged violations occurred at various times during the period beginning January 1997 through July
2002. A consent decree was lodged with the U.S. District Court for the Southern District of Texas,
Houston Division on October 4, 2004, proposing a civil penalty of $610,000 and a Supplemental
Environmental Project (SEP) valued at approximately $90,000. Under the SEP, ConocoPhillips will
donate approximately 128 acres of land it owns near the Sweeny refinery to the U.S. Fish and
Wildlife Service for inclusion in the San Bernard National Wildlife Refuge. We await the courts
approval and entry of the consent decree.
On July 15, 2002, the United States filed a Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA) cost recovery action against Conoco Inc. and seven other defendants alleging
that the United States had incurred unreimbursed response costs at the Lowry Superfund Site located
in Arapahoe County, Colorado. The United States seeks recovery of approximately $12.3 million in
past response costs and a declaratory judgment for future CERCLA response cost liability. The
defendants filed counterclaims seeking declaratory relief that certain response actions taken by
the government were inconsistent with the National Contingency Plan. The defendants
counterclaims, if successful, will reduce the total amount of response costs that are reimbursable
to the government.
Executive Vice President, Exploration and Production
John A. Carrig
Executive Vice President, Finance, and Chief Financial Officer
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
Chairman, President and Chief Executive Officer
J. W. Nokes
Executive Vice President, Refining, Marketing, Supply and
*On March 1, 2005.
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, 2005. Set forth below
is information about 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 effective 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; and Phillips Senior Vice President, Treasurer
and Chief Financial Officer since 2000.
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
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 p.l.c. (now BP p.l.c.) 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; and Phillips Senior Vice President of
Planning and Strategic Transactions since 2000.
J. J. Mulva
was appointed Chairman of the Board of Directors, President and Chief Executive Officer
of ConocoPhillips effective October 1, 2004, having previously served as ConocoPhillips President
and Chief Executive Officer since completion of the merger. Prior to the merger, he was Phillips
Chairman of the Board of Directors and Chief Executive Officer since 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.