PART I

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 company’s plans, strategies, objectives, expectations, intentions, and resources, that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “forecasts,” “intends,” “believes,” “expects,” “plans,” “scheduled,” “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 company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 83.

At December 31, 2003, ConocoPhillips employed approximately 39,000 people.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment information and geographic information, see Note 28—Segment Disclosures and Related Information in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

EXPLORATION AND PRODUCTION (E&P)

This segment explores for and produces crude oil, natural gas, and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the bitumen and upgrade it into a synthetic crude oil. At December 31, 2003, our E&P operations were producing in the United States, the Norwegian and U.K. sectors of the North Sea, Canada, Nigeria, Venezuela, offshore Timor Lesté in the Timor Sea, offshore Australia, offshore China, offshore the United Arab Emirates, offshore Vietnam, Russia, and Indonesia.

The information listed below appears in the supplemental oil and gas operations disclosures on pages 154 through 172 and is incorporated herein by reference:

In 2003, our worldwide production, including our share of equity affiliates’ production, averaged 1,590,000 barrels-of-oil-equivalent (BOE) per day, a 49 percent increase from 1,069,000 BOE per day in 2002. During 2003, 674,000 BOE per day were produced in the United States, a 15 percent increase from 587,000 BOE per day in 2002. Production from our international E&P operations averaged 916,000 BOE per day in 2003, up 90 percent from 482,000 BOE per day in 2002. In addition, our Canadian Syncrude mining operations had net production of 19,000 barrels per day in 2003, compared with 8,000 barrels per day in 2002. The increased production mainly reflects the impact of the merger. We convert our natural gas production to BOE based on a 6:1 ratio: six thousand cubic feet of natural gas equals one barrel-of-oil-equivalent.

Our worldwide annual average crude oil sales price increased 14 percent in 2003, from $24.07 per barrel to $27.47 per barrel. Our annual average worldwide natural gas sales price also increased, going from $2.77 per thousand cubic feet in 2002 to $4.07 per thousand cubic feet in 2003.

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Finding and development costs in 2003 were $5.35 per barrel-of-oil-equivalent, compared with $5.57 in 2002. Over the last five years, our finding and development costs averaged $4.29 per barrel-of-oil-equivalent. Finding and development costs per barrel-of-oil-equivalent is calculated by dividing the net reserve change for the period (excluding production and sales) into the costs incurred for the period, as reported in the “Costs Incurred” disclosure required by Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities.”

At December 31, 2003, ConocoPhillips, including its share of equity affiliates, held a combined 52.6 million net developed and undeveloped acres, compared with 101.9 million net acres at year-end 2002. The decrease in acreage primarily reflects the removal of acreage in Somalia, where operations had been suspended by declarations of force majeure. At year-end 2003, we held acreage in 25 countries.

E&P—U.S. OPERATIONS

In 2003, U.S. E&P operations contributed 43 percent of our worldwide liquids production and 42 percent of our worldwide natural gas production. Our U.S. E&P operations are managed in two divisions: Alaska and the Lower 48 States.

Alaska
We are a major producer of crude oil on Alaska’s North Slope, and we produce natural gas in the Cook Inlet. A brief summary of our major Alaska producing fields, transportation infrastructure, and exploration activities follows.

Greater Prudhoe Area
The Greater Prudhoe Area is comprised of the Prudhoe Bay field and satellites, as well as the Greater Point McIntyre Area fields. We have a 36.1 percent interest in all fields within the Greater Prudhoe Area, all of which are operated by BP p.l.c. (BP).

The Prudhoe Bay field is the largest oil field on Alaska’s North Slope. It is the site of a large waterflood and enhanced oil recovery project, as well as a gas processing plant that processes and reinjects natural gas back into the reservoir. Our net crude oil production from the Prudhoe Bay field averaged 121,500 barrels per day in 2003, compared with 130,800 barrels per day in 2002, while natural gas liquids production averaged 23,000 barrels per day in 2003, compared with 24,100 barrels per day in 2002. Normal field declines were the main cause of the lower production rates in 2003.

Prudhoe Bay satellite fields Aurora, Borealis, Polaris, Midnight Sun, and Orion produced 16,200 net barrels per day of crude oil in 2003, compared with 12,700 net barrels per day in 2002. Borealis contributed the biggest share in 2003, producing 10,300 net barrels per day. All Prudhoe Bay satellite fields are produced through Prudhoe Bay production facilities. Development options and plans are being studied for other potential Prudhoe Bay satellites.

The Greater Point McIntyre Area (GPMA) is made up of the Point McIntyre, Niakuk, Lisburne, West Beach, and North Prudhoe Bay State fields. The fields within the GPMA are generally produced through the Lisburne Production Center. Net crude oil production for GPMA averaged 18,200 barrels per day in 2003, compared with 19,800 barrels per day in 2002. The bulk of this production came from the Point McIntyre field, which is approximately seven miles north of the Prudhoe Bay field and extends into the Beaufort Sea.

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Greater Kuparuk Area
We operate the Greater Kuparuk Area, which is comprised of the Kuparuk field and four satellite fields: Tarn, Tabasco, Meltwater, and West Sak. Our ownership interest is 55.2 percent in the Kuparuk field, which is located about 40 miles west of Prudhoe Bay. Field installations include three central production facilities that separate oil, natural gas and water. The natural gas is either used for fuel or compressed for reinjection. Our net crude oil production from the Kuparuk field averaged 78,600 barrels per day in 2003, compared with 79,000 barrels per day in 2002. Natural production declines from Kuparuk were offset by an average of 8,000 barrels per day of production from the Palm discovery that extended the Kuparuk field to the west about three miles. Development of the Palm discovery included the construction of a new drill site and the drilling of 17 wells. Palm production began in November 2002.

Other fields in the Greater Kuparuk Area produced 21,800 net barrels per day of crude oil in 2003, primarily from the Tarn, Tabasco, and Meltwater satellites. We have a 55.3 percent interest in Tarn and Tabasco and a 55.4 percent interest in Meltwater.

The Greater Kuparuk Area also includes the West Sak heavy-oil field. Annual production rates increased from 3,300 net barrels per day in 2002 to 3,800 net barrels per day in 2003. Progress was made in 2003 towards proving concepts necessary for full-scale development of this field. Eight wells were drilled during the year, increasing production from 3,300 net barrels per day in the month of December 2002 to 5,000 net barrels per day in the month of December 2003. We have a 55.3 percent interest in this field.

Western North Slope
The Alpine field, located west of the Kuparuk field, began production in November 2000. In 2003, the field produced at a net rate of 64,500 barrels of oil per day, compared with 63,400 barrels per day in 2002. We are the operator and hold a 78 percent interest in Alpine.

In May 2003, we announced plans to increase produced water and natural gas handling capacities at our Alpine production facilities. Although we inject seawater into the Alpine reservoir as a means of enhanced oil recovery, most production has been almost 100 percent oil. Eventually, the injected water and natural gas will start to break through into the producing wells, requiring an increase in the amount of produced water and natural gas that needs to be handled. The increase in water and natural gas handling capacities should allow crude oil production to remain at or slightly above current production rates for a longer period of time than could otherwise have been achieved. Startup of the expanded facilities is planned to commence by the end of 2004.

In January 2003, ConocoPhillips and the U.S. Department of Interior Bureau of Land Management signed a Memorandum of Understanding that provides for completion of an Environmental Impact Statement (EIS) for five prospective Alpine satellites: Fiord, Nanuq, Lookout, Spark, and Alpine West, as well as future potential developments in the northeast corner of the National Petroleum Reserve-Alaska (NPR-A) and near the Alpine oil field. A final decision to move forward on these projects will be made after the EIS is completed, currently expected in second half of 2004, and the appropriate permits have been granted.

Cook Inlet
Our assets in Alaska include the North Cook Inlet field, the Beluga River natural gas field, and the Kenai liquefied natural gas facility.

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We have a 100 percent interest in the North Cook Inlet field. Net production in 2003 averaged 112 million cubic feet per day, compared with 125 million cubic feet per day in 2002. All of the production from the North Cook Inlet field is used to supply our share of gas to the Kenai liquefied natural gas plant. The decline in production in 2003 was the result of well problems. Well work completed in late 2003 and planned for 2004 is expected to improve production.

Our interest in the Beluga River field is 33 percent. Net production averaged 63 million cubic feet per day in 2003, compared with 41 million cubic feet per day in 2002. Gas from the Beluga River field is sold to local utilities, industrial consumers, and used as back-up supply to the Kenai liquefied natural gas plant.

We have a 70 percent interest in the Kenai liquefied natural gas plant, which supplies liquefied natural gas to two utility companies in Japan. Utilizing two ships, the company transports the liquefied natural gas to Japan, where it is reconverted to dry gas at the receiving terminal. We sold 44.0 billion cubic feet of liquefied natural gas to Japan in 2003, compared with 44.4 billion cubic feet in 2002.

Exploration
We drilled or participated in three exploratory wells during 2003, on locations near Alpine, the NPR-A and the Cook Inlet. Two of these wells are pending further appraisal, and one was a dry hole. We plan to drill or participate in four exploration wells in Alaska during 2004.

Transportation
We transport the petroleum liquids we produce on the North Slope to market through the Trans-Alaska Pipeline System (TAPS), an 800-mile pipeline, marine terminal, spill response and escort vessel system that ties the North Slope of Alaska to the port of Valdez in south-central Alaska.

In 2001, ConocoPhillips and the five other owners of TAPS completed and filed state and federal applications for renewal of the pipeline’s right-of-way permit through 2034. The State of Alaska approved the 30-year right-of-way renewal in November 2002 and U.S. federal approval was received in January 2003.

Regulatory approval was received in early 2003 for us to purchase an additional 1.5 percent interest in TAPS from Amerada Hess Corporation, thereby increasing our ownership in TAPS to 28.3 percent. The purchase was effective January 24, 2003. We also have ownership interests in the Alpine, Kuparuk and Oliktok pipelines on the North Slope.

We continue to evaluate a gas pipeline project to deliver natural gas from Alaska’s North Slope to the Lower 48. Given the size of the project and risk associated with it, we continue to believe that risk mitigation mechanisms and improvements in project economics are necessary before this project can proceed. Activities in 2003 included promoting state and federal legislation that would lower the economic risk of the project.

Our wholly owned subsidiary, Polar Tankers Inc., manages the marine transportation of our Alaska North Slope production. Polar Tankers is based in Long Beach, California, and operates six ships in the Alaskan trade, chartering additional third-party-operated vessels as necessary. In 2001, Polar Tankers brought the Polar Endeavour into service; the Polar Resolution was brought into service in 2002; and the Polar Discovery was brought into service in 2003. These 125,000 deadweight-ton, double-hulled crude oil tankers are the first three of five Endeavour Class tankers that we plan to add to our Alaska-trade fleet. The fourth and fifth tankers are scheduled to enter the fleet in 2004 and 2005, respectively.

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Lower 48 States

Gulf of Mexico
Our current portfolio of producing properties in the Gulf of Mexico includes three fields operated by us and six fields operated by other companies. The number of fields declined in 2003 with the divestiture of properties as part of our portfolio rationalization program. At December 31, 2003, we had 22 leases in production or under development in the deepwater Gulf of Mexico.

We hold a 16 percent interest in the co-venturer-operated Ursa field. The Ursa tension-leg platform was installed in late 1998 in approximately 3,900 feet of water, with first production occurring in March 1999. Our net production in 2003 averaged 13,300 barrels per day of liquids and 13 million cubic feet per day of natural gas.

The Princess field is a northern, subsalt extension of the Ursa field. It was discovered in 2000, with first production beginning in late 2002 from an extended-reach well from the Ursa platform. A three-well subsea tieback to the Ursa platform was completed in 2003. Our net production in 2003 averaged 2,600 barrels per day of liquids and 7.3 million cubic feet per day of natural gas. We hold a 16 percent interest in Princess.

We operate and hold a 75 percent interest in the Garden Banks 783 and 784 leases which contain the Magnolia field discovered in 1999. Installation of a tension-leg platform, to be located in almost 4,700 feet of water, is expected in mid-2004, with first oil scheduled for late 2004. Peak production of 49,000 net barrels-of-oil-equivalent per day is expected in 2005 from proved reserves.

We have a 16.8 percent interest in the K2 discovery. K2, located in Green Canyon Block 562, was discovered in 1999, with appraisal drilling continuing in 2003. A development option under consideration would utilize a subsea tieback to a nearby third-party platform. Project sanctioning is expected in the first quarter of 2004.

In July 2003, we announced a discovery with the Lorien well in Green Canyon Block 199. The well was drilled in 2,177 feet of water and encountered more than 120 feet of hydrocarbons. The well has been suspended pending further appraisal of the hydrocarbon zone. We are the operator with a 65 percent interest.

During 2003, two deepwater exploratory wells did not encounter commercial quantities of hydrocarbons: the Voss well in Keathley Canyon Block 511 and the Yorick well in Green Canyon Block 435.

Onshore
Our onshore Lower 48 production is primarily natural gas, with the majority of the production located in the Lobo Trend in south Texas, the San Juan Basin of New Mexico, and the Guymon-Hugoton Trend in the panhandles of Texas and Oklahoma. We also have oil and natural gas production from the Permian Basin in West Texas and Southeast New Mexico. Other positions and production are maintained in other parts of Texas and Oklahoma, the Arkansas/Louisiana/Texas area, and onshore Gulf Coast area. In

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addition, we hold coalbed methane acreage positions in the Powder River Basin in Wyoming, the Uinta Basin in Utah, and the Black Warrior Basin in Alabama.

Activities in 2003 primarily were centered on continued optimization and development of these mature assets. Combined production from Lower 48 onshore fields in 2003 averaged a net 1,237 million cubic feet per day of natural gas and 57,000 barrels per day of liquids.

E&P—NORTHWEST EUROPE

In 2003, E&P operations in Northwest Europe contributed 30 percent of our worldwide liquids production and 34 percent of our worldwide natural gas production. Our Northwest Europe assets are principally located in the Norwegian and U.K. sectors of the North Sea.

Norway
The Ekofisk Area is located approximately 200 miles offshore Norway in the center of the North Sea. The Ekofisk Area is comprised of four producing fields: Ekofisk, Eldfisk, Embla, and Tor. Ekofisk serves as a hub for petroleum operations in the area, with surrounding developments utilizing the Ekofisk infrastructure. Net production in 2003 from the Ekofisk Area was 126,500 barrels of liquids per day and 127 million cubic feet of natural gas per day, compared with 127,000 barrels of liquids per day and 133 million cubic feet of natural gas per day in 2002. We are operator and hold a 35.1 percent interest in Ekofisk.

In 2003, we and our co-venturers approved a plan for further development of the Ekofisk Area. The project consists of two interrelated components. A new platform, Ekofisk 2/4M, is anticipated to have 30 well slots, a high-pressure separator and equipment for produced water treatment. The project also includes modification on the existing Ekofisk Complex to increase process capacity. Construction began in 2003 and production from the new platform is projected to begin in the fall of 2005.

We also have ownership interests in other producing fields in the Norwegian North Sea, including a 24.3 percent interest in the Heidrun field, a 10.3 percent interest in the Statfjord field, a 23.3 percent interest in the Huldra field, a 1.6 percent interest in the Troll field, a 9.1 percent interest in the Visund field, and a 2.4 percent interest in the Oseberg area. Production from these and other fields in the Norwegian sector of the North Sea and the Norwegian Sea averaged a net 93,300 barrels of liquids per day and 149 million cubic feet of natural gas per day in 2003.

In September 2003, production began from the Grane field, in which we have a 6.4 percent interest. Peak production from this field is expected in 2005, and is anticipated to be approximately 14,000 net barrels per day from proved reserves.

We also have interests in certain of the transportation and processing infrastructure of the Norwegian North Sea, including a 35.1 percent interest in the Norpipe Oil Pipeline System, a 2.3 percent interest in Gassled, which owns most of the Norwegian gas transportation system, and a 1.6 percent interest in the southern part of the planned Langeled gas pipeline.

United Kingdom
We are the largest owner in, and the joint operator of, the Britannia natural gas/condensate field, in which we have a 58.7 percent interest. Our net production from Britannia averaged 391 million cubic feet of natural gas per day and 14,500 barrels of liquids per day in 2003. Oil and gas production from Britannia is delivered by pipeline to Scotland. Development drilling on Britannia is expected to continue into the year 2006.

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In December 2003, we approved a plan for the development of the Callanish and Brodgar fields. These new Britannia satellite development projects will be tied back to the Britannia facility, with first production targeted for 2007. The development plan has been submitted for government approval. We have a 75 percent interest in the Brodgar field and an 83.5 percent interest in the 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 began production in the first quarter of 2002 from a wellhead platform and pipeline tied to the J-Block facilities. We are the operator of and hold a 32.5 percent interest in Jade. Together, these fields produced a net 18,100 barrels of liquids per day and 118 million cubic feet of natural gas per day in 2003.

ConocoPhillips continues to supply gas from J-Block to Enron Capital and Trade Resources Limited (Enron Capital), which was placed in Administration in the United Kingdom on November 29, 2001. ConocoPhillips has been paid all amounts currently due and payable by Enron Capital in respect of the J-Block gas sales agreement, including outstanding amounts due for the period prior to the appointment of the Administrator. We believe that Enron Capital will continue to pay the amounts due for gas supplied by us in accordance with the terms of the gas sales agreement. We do not currently expect that we will have to curtail sales of gas under the gas sales agreement or shut in production as a result of the Administration of Enron Capital. However, in the event that the arrangements for the processing of Enron Capital’s gas are terminated or Enron Capital goes into liquidation, there may be additional risk of production being reduced or shut-in.

We have various ownership interests in 13 producing gas fields in the southern North Sea, in the Rotliegendes and Carboniferous areas. These fields mostly feed into the ConocoPhillips-operated Theddlethorpe gas processing facility through three ConocoPhillips-operated pipeline systems. Net production in 2003 averaged 371 million cubic feet per day of natural gas and 2,000 barrels of liquids per day.

During 2003 we continued the development of the CMS3 area in the southern sector of the U.K. North Sea, which consists of five natural gas reservoirs currently being developed by us as a single, unitized project. The McAdam and Watt fields were brought onstream in 2003, following the Hawksley and Murdoch K fields in 2002. Drilling operations on the final reservoir, Boulton H, are ongoing into 2004. Collectively, these fields are known as CMS3 due to their utilization of the production and transportation facilities of the ConocoPhillips-operated Caister Murdoch System (CMS). We are the operator of CMS3 and hold a 59.5 percent interest.

We also have ownership interests in several other producing fields in the U.K. North Sea, including a 23.4 percent interest in the Alba field, a 40 percent interest in the MacCulloch field, an 11.5 percent interest in the Armada field, and a 4.8 percent interest in the Statfjord field. Production from these and the other remaining fields in the U.K. sector of the North Sea averaged a net 44,500 barrels of liquids per day and 61 million cubic feet of natural gas per day in 2003.

We have a 24 percent interest in the Clair field development in the Atlantic Margin. The Clair development is comprised of a conventional steel jacket structure with minimum manned facilities topside. First production from Clair is targeted for late 2004.

The Interconnector pipeline, which connects the United Kingdom and Belgium, facilitates the marketing throughout Europe of the natural gas we produce in the United Kingdom. Our 10 percent equity share of the Interconnector pipeline allows us to ship approximately 200 million cubic feet of natural gas per day to markets in continental Europe. We have multi-year contracts to supply natural gas to Gasunie in the Netherlands and Wingas in Germany.

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Exploration

In the U.K. sector of the North Sea, we drilled or participated in four exploratory and appraisal wells during 2003 in the southern North Sea, the central North Sea near the Jade and Britannia fields, and the West of Shetland deepwater area. Of the four wells, two are moving forward with development plans and two were dry holes. We plan to participate in three exploratory wells in 2004, including two wells in the southern North Sea and one on a structure adjacent to the Callanish field.

E&P—CANADA

In 2003, E&P operations in Canada contributed 5 percent of our worldwide liquids production and 13 percent of our worldwide natural gas production, excluding Syncrude production.

Conventional Oil and Gas Operations
Operations in western Canada encompass properties in Alberta, northeastern British Columbia and southwestern Saskatchewan. We separate our holdings in western Canada into four geographic regions. The north region contains a mix of oil and natural gas, and primarily is winter access. The central and west regions produce mainly natural gas. The south region has shallow gas and medium-to-heavy oil. Production from conventional oil and gas operations in western Canada averaged a net 40,500 barrels per day of liquids and 435 million cubic feet per day of natural gas in 2003.

We are working with three other energy companies, as members of the Mackenzie Delta Producers’ Group (Group), on the development of the Mackenzie Valley pipeline, which is proposed to transport onshore gas production from the Mackenzie Delta in northern Canada to existing markets. Initial design capacity for the Mackenzie Valley pipeline is proposed to be 1,200 million cubic feet per day, but capacity would be expandable with additional compression. We would hold a 16 percent interest in the pipeline and a 75 percent interest in the development of the Parsons Lake gas field. The Parsons Lake gas field would be one of the three primary fields in the Mackenzie Delta that would anchor the pipeline development. Conceptual engineering commenced in April 2002. Regulatory applications for the project are expected to be submitted in mid-2004 and first gas production is currently targeted for late 2009.

We owned a 46.7 percent interest in Petrovera, a joint venture that combined a substantial portion of our Canadian heavy-oil assets and certain associated natural gas assets. The asset base of the joint venture was located mainly in southwestern Saskatchewan. Net production in 2003 was 15,300 barrels of petroleum liquids per day, and was included in equity affiliate production. On February 18, 2004, we sold our interest in the joint venture.

Exploration
We hold exploration acreage in three areas of Canada: offshore eastern Canada, the foothills of western Alberta, and the Mackenzie Delta/Beaufort Sea. In eastern Canada, we hold a 20 percent interest in deepwater Nova Scotia, EL 2359. After participating in the Newburn well in 2002, we are waiting on the results from drilling in adjacent blocks. In deepwater Newfoundland, we are working to convert our large Laurentian permit into specific exploration licenses. We hope to complete this in 2004 and expect to

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acquire seismic in 2005. In the foothills, two out of three exploratory wells drilled in 2003 were successful. In the Mackenzie Delta/Beaufort Sea, we began drilling a well in early 2004.

Other Canadian Operations
We have two oil sands projects in Canada: Syncrude Canada Ltd. and Surmont.

Syncrude Canada Ltd.
We own a 9.03 percent undivided interest in Syncrude Canada Ltd., a joint venture created by a number of energy companies for the purpose of mining shallow deposits of oil sands, extracting the bitumen, and upgrading it into a light sweet crude oil called Syncrude. The primary plant and facilities are located at Mildred Lake, about 25 miles north of Fort McMurray, Alberta, together with an auxiliary mining and extraction facility approximately 20 miles from the Mildred Lake plant. Syncrude Canada Ltd. holds eight oil sands leases and the associated surface rights, of which our share is approximately 23,000 net acres. Our net share of production averaged 19,000 barrels per day in 2003.

We continued with development of the Stage III expansion-mining project in 2003, which is expected to increase our Syncrude production. The Aurora Train 2 project (the new mine) was completed and started up in the fourth quarter of 2003. The expansion project is expected to bring various units onstream during 2004, while the completion of a new coker to service the expanded project is anticipated in the second half of 2005.

The U.S. Securities and Exchange Commission’s regulations define this project as mining-related and not part of conventional oil and gas operations. As such, Syncrude operations are not included in our proved oil and gas reserves or production as reported in the supplemental oil and gas information.

Surmont
The Surmont lease is located about 35 miles south of Fort McMurray, Alberta. We own a 43.5 percent interest and are the operator. The project will use a method called “steam assisted gravity drainage,” that involves the injection of steam deep into the oil sands, effectively melting the bitumen, which is then recovered and pumped to the surface for further processing. In May 2003, we received regulatory approval to develop the oil sands from the Alberta Energy and Utilities Board, and in late 2003 our Board of Directors approved the project. Construction of the facilities is expected to begin in early 2004, with first oil production scheduled for 2006.

E&P—SOUTH AMERICA

In 2003, E&P operations in South America were comprised of interests in Venezuela, Ecuador and Brazil. South American operations contributed 8 percent of our worldwide liquids production in 2003.

Venezuela

In December of 2002, civil unrest in Venezuela caused economic and other disruptions that shut down most oil and gas operations in Venezuela, including the company’s Petrozuata and Hamaca operations. Production from these operations resumed in the first quarter of 2003.

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Petrozuata
Petrozuata is a Venezuelan Corporation formed under a 35-year Association Agreement between a wholly owned subsidiary of ConocoPhillips that has a 50.1 percent non-controlling equity interest and PDVSA Petroleo, a subsidiary of Petroleos de Venezuela S.A. (PDVSA), the national oil company of Venezuela.

The project is an integrated operation that produces extra-heavy crude oil from reserves in the Zuata region of the Orinoco Oil Belt, transports it to the Jose industrial complex on the north coast of Venezuela, and upgrades it into medium-grade crude oil. Associated by-products produced are liquefied petroleum gas, sulfur, petroleum coke and heavy gas oil. The medium-grade crude oil produced by Petrozuata is used as a feedstock for our Lake Charles, Louisiana, refinery and the Cardon refinery in Venezuela operated by PDVSA. Our net production was 51,600 barrels of heavy crude oil per day in 2003, and is included in equity affiliate production.

We entered into an agreement to purchase up to 104,000 barrels per day of the Petrozuata upgraded crude oil for a market-based formula price over the term of the joint venture in the event that Petrozuata is unable to sell the production for higher prices. All upgraded crude oil sales are denominated in U.S. dollars. By-products produced by the upgrading facility are sold to a variety of domestic and foreign purchasers. The loading facilities at Jose transfer crude oil and some of the by-products to ocean vessels for export.

Hamaca
The Hamaca project also involves the development of heavy-oil reserves from the Orinoco Oil Belt. ConocoPhillips owns a 40 percent interest in the Hamaca project, which is operated by Petrolera Ameriven on behalf of the owners. The other participants in Hamaca are PDVSA and ChevronTexaco Corporation. Our interest is held through a joint limited liability company, Hamaca Holding LLC, for which we use the equity method of accounting.

Net production averaged 22,100 barrels per day of heavy crude oil in 2003, and is included in equity affiliate production. The joint-venture agreement has a 35-year term.

Construction of the heavy-oil upgrader, pipelines and associated production facilities at the Jose industrial complex began in 2000. The upgrader is expected to begin producing commercial quantities of medium-grade crude oil by the end of 2004, at which time our net production from the Hamaca field is expected to increase to approximately 71,000 barrels per day from proved reserves.

Gulf of Paria
In 1999 the Corocoro discovery in the Gulf of Paria West Block was made and later confirmed with appraisal drilling in 2001 and 2002. In 2003, Venezuelan authorities approved Phase I of the development plan for the Corocoro field. We operate the field with a 32.2 percent interest. In accordance with the profit sharing agreement that governs the block, a subsidiary of PDVSA elected to acquire a 35 percent interest in the development, lowering our interest from 50 percent to 32.5 percent. In September 2003, we acquired a 37.5 percent interest in the adjoining Gulf of Paria East Block, onto which a portion of the Corocoro discovery extends.

Plataforma Deltana Block 2
We acquired a 40 percent interest in Plataforma Deltana Block 2 in 2003. The block is co-venturer-operated and holds a gas discovery made by PDVSA in 1983. Appraisal wells are planned in 2004. Contingent on the results of the appraisal wells, development of the field may include a well platform in approximately 300 feet of water, a 170-mile pipeline to shore, and a liquefied natural gas plant. The liquefied natural gas would be shipped to the U.S. market.

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Brazil
We have concession agreements on two deepwater exploration blocks (BM-ES-11 and BM-PAMA-3) offshore Brazil. These blocks were acquired in Brazil’s third bid round held in June 2001. We entered into joint ventures on both blocks in late 2002, reducing our interest to 70 percent in BM-ES-11 and 65 percent in BM-PAMA-3. In 2003, further evaluation led to the write-off of our leasehold investment in BM-ES-11, and we initiated the process to exit the block. Further evaluation of BM-PAMA-3 is planned for 2004.

Ecuador
We sold our 14 percent, non-operator interest in Block 16 and the associated fields on December 5, 2003, with an effective date of January 1, 2003. We have no other assets in Ecuador, and have exited the country.

E&P—ASIA PACIFIC

In 2003, E&P operations in the Asia Pacific area contributed 6 percent of our worldwide liquids production and 9 percent of our worldwide natural gas production.

China
Our combined net production of crude oil from the Xijiang facilities averaged 10,900 barrels per day in 2003. The Xijiang development consists of three fields located approximately 80 miles from Hong Kong in the South China Sea. The facilities include two manned platforms and a floating production, storage and offloading facility.

Production from Phase I development of the Peng Lai 19-3 field in Bohai Bay Block 11-05 began in late December 2002. In 2003, the field produced 14,800 net barrels of oil per day. We have a 49 percent interest, with the remainder held by the China National Offshore Oil Corporation. The Phase I development utilizes one wellhead platform and a floating production, storage and offloading facility.

We continue to move forward with the design for Phase II of the Peng Lai 19-3 development. Phase II would include multiple wellhead platforms, and a larger floating production, storage and offloading facility. The Peng Lai 25-6 field, discovered in 2000 and located three miles east of Peng Lai 19-3, will be developed in conjunction with Phase II of the Peng Lai 19-3 development project.

Exploration activity continued in 2003 in Block 11-05, with two successful wells announced. The Peng Lai 19-9-1 well, located about two miles east of the Peng Lai 19-3 field, discovered the Peng Lai 19-9 field that will be part of the Phase II development. Drilling of the Peng Lai 13-1-1 well, located about 18 miles north of the Peng Lai 19-3 field, was completed in March 2003.

Indonesia
We operate nine Production Sharing Contracts (PSCs) in Indonesia and have a non-operator interest in four others. Our assets are concentrated in two core areas: the West Natuna Sea and South Sumatra; with a potentially emerging area offshore East Java. We are a party to five long-term U.S. dollar pipeline gas contracts that have been signed in Indonesia. Production of natural gas from Indonesia averaged a net 255 million cubic feet per day in 2003, while production of crude oil averaged a net 16,000 barrels per day.

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Offshore Assets
We operate three offshore PSCs: 1) South Natuna Sea Block B, 2) Nila, and 3) Ketapang. We also hold a non-operator interest in the Pangkah PSC offshore East Java. We participate in various natural gas marketing arrangements in connection with these assets, including being a co-venturer in the West Natuna Gas Supply Group (WNG). The WNG jointly markets natural gas from certain fields in three South Natuna Sea PSCs to Singapore.

The Kakap PSC, adjacent to the South Natuna Sea Block B, was sold in September 2003. The property was selected for disposition because of its high operating cost structure and limited further exploration potential. In addition, during 2003 we relinquished the Tobong PSC and sold the Sebuku PSC after concluding that neither PSC had significant remaining exploration potential.

The South Natuna Sea Block B PSC has two currently producing mature oil fields and 15 gas fields (some with recoverable oil volumes) in various phases of development. The largest current development in Block B is the Belanak oil and gas field, in which a floating production, storage and offloading vessel is under construction. The vessel is expected to be completed, and oil production to commence, in the first half of 2005. Two additional developments that would produce into the Belanak infrastructure are scheduled for startup in 2006 and 2008.

We also have an active exploration program in both the Natuna Sea and East Java. During 2003, two unsuccessful exploratory wells were drilled in the Natuna Sea Nila Block. An additional well in the Nila Block is planned for 2004. During 2003, in the East Java offshore Ketapang Block, two appraisal wells were drilled on the Bukit Tua oil field discovery, one of which was successful, and one of which was unsuccessful. An additional appraisal well and an exploration well are planned for 2004.

Onshore Assets
We operate six onshore PSCs: 1) Corridor TAC, 2) Corridor PSC, 3) South Jambi ‘B’, 4) Sakakemang JOB (jointly operated with a co-venturer), 5) Block A PSC in Aceh, and 6) Warim. We also hold non-operator interests in the Banyumas PSC in Java and the Bentu and Korinci-Baru PSCs in Sumatra. The Tungkal PSC was sold in December 2003. As with our offshore properties, we participate in various gas marketing arrangements in connection with these fields. Exploration efforts focus on locating additional natural gas reserves.

We announced in March 2003 the successful test of the Suban-8 delineation well on the southwest flank of the Suban gas field, located in the Corridor PSC of South Sumatra. In December 2003, we began an exploratory well in the Corridor Block to test a gas prospect located close to other producing fields. We continue to appraise and develop the Suban gas field. In addition, we completed the successful test of the North Sumpal-1 well in the Sakakemang Block located in South Sumatra, and continued on the construction of the South Jambi gas project in the South Jambi B Block also located in South Sumatra.

We are a 35 percent owner of TransAsia Pipeline Company Pvt. Ltd., a consortium company, which has a 40 percent ownership in PT Transportasi Gas Indonesia, an Indonesian limited liability company, which owns and operates the Grissik to Duri gas pipeline.

Vietnam
We have a 23.25 percent interest in Block 15-1 in the Cuu Long Basin in the South China Sea. In 2001, the co-venturers in Block 15-1 declared the southwest portion of the Su Tu Den (Black Lion) field commercial after a successful appraisal program. In addition, an appraisal well in the northeast portion of Su Tu Den was successfully drilled in 2002. The Su Tu Den Phase I development project was approved in December 2001. Production from Su Tu Den Phase I began in the fourth quarter of 2003. The initial net

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production rate was approximately 16,000 barrels of oil per day from seven wells located in the Phase I area. The oil is being processed and stored in a new floating production, storage and offloading vessel, which has a 1 million barrel storage capacity and can initially process up to 65,000 gross barrels per day.

An exploration discovery was also made on the nearby Su Tu Vang (Golden Lion) prospect in the third quarter of 2001. The potential commerciality of Su Tu Vang and the northeast portion of Su Tu Den are being evaluated. In addition, in the fourth quarter of 2003, a successful exploration well was drilled in the Su Tu Trang (White Lion) area (southeast area of the block).

We have a 36 percent interest in the Rang Dong field in Block 15-2 in the Cuu Long Basin. In the third quarter of 2002, production began from two new wellhead platforms in the Rang Dong field. During late 2003, field facilities were upgraded to include a utilities/living quarters platform, and a central processing platform with facilities to enable gas lift, gas export and water injection. With the completion of these facilities, water injection became possible on all three wellhead platforms and gas lift became possible on two of the wellhead platforms. A successful appraisal step-out well, Rang Dong-12X, was drilled in the central part of the field in late 2001, and a development plan for this area of the field is being evaluated.

We also own interests in offshore Blocks 16-2, 5-3, 133 and 134, as well as a 16.33 percent interest in the Nam Con Son gas pipeline.

Timor Sea and Australia
Bayu-Undan
The unitized Bayu-Undan field, located in the Timor Sea, is being developed in two phases. Phase I is a gas-recycle project, where condensate and natural gas liquids will be separated and removed and the dry gas reinjected back into the reservoir. This phase began production in February 2004, and is expected to average a net rate of 23,000 barrels of liquids per day from proved reserves in 2004.

In June 2003, we announced that the Gas Development Plan for the field had received approval from the Timor Sea Designated Authority. This final approval allowed Phase II, the development of the natural gas reserves, to proceed. Phase II will involve a natural gas pipeline from the field to Darwin, and a liquefied natural gas (LNG) facility located at Wickham Point, Darwin. In March 2002, we announced that we had signed a Heads of Agreement (LNG HOA) with The Tokyo Electric Power Company, Incorporated (TEPCO) and Tokyo Gas Co., Ltd. (Tokyo Gas). Under the LNG HOA, TEPCO and Tokyo Gas would purchase 3 million tons per year in total of LNG for a period of 17 years, utilizing natural gas from the Bayu-Undan field. The approval of the Gas Development Plan by the Timor Sea Designated Authority satisfied the remaining condition precedent necessary for the LNG HOA to have a binding effect and for the project to proceed. As a result of project approvals, we added 1.36 trillion cubic feet of net proved natural gas reserves in 2003. The first LNG cargo is scheduled for delivery in early 2006. We have a 56.7 percent controlling interest in the integrated project.

Greater Sunrise
We and our co-venturers continue to evaluate commercial development options and LNG markets in the Asia Pacific region and the North American west coast for the natural gas and condensate from the Greater Sunrise field. The development options under consideration consist of an offshore floating LNG facility and an onshore LNG facility located in Darwin, Australia. Efforts are under way to market LNG into both the Asian and North American west coast markets. Further engineering studies relating to design and development concepts also continue. We have a 30 percent, non-operator interest in Greater Sunrise.

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E&P—AFRICA AND THE MIDDLE EAST

Nigeria
Our crude oil production from five leases in Nigeria averaged a net 36,900 barrels per day in 2003, while net natural gas production averaged 63 million cubic feet per day. These five leases include four onshore Oil Mining Leases (OML) and a shallow-water offshore OML. Continued development and exploratory drilling is planned for 2004 on the onshore leases.

We also have production sharing contracts on deepwater Nigeria Oil Prospecting Leases (OPLs), including OPL 318 with a 50 percent interest where we are the operator, OPL 214 with a 20 percent interest and OPL 248 with a 40 percent interest. We are planning to drill the first exploration well on OPL 248 in 2004.

We have a 20 percent interest in a 480-megawatt gas-fired power plant being constructed to supply electricity to Nigeria’s national electricity supplier. When operational, the plant will consume 68 million cubic feet per day of natural gas sourced from within our Nigerian proved natural gas reserves. The plant is expected to become operational in 2005.

In October 2003, ConocoPhillips, the Nigerian National Petroleum Corporation (NNPC), Eni and ChevronTexaco signed a Heads of Agreement (HOA) to conduct front-end engineering and design work for a new LNG facility that would be constructed in Nigeria’s central Niger Delta. The co-venturers have agreed to form an incorporated joint venture, to be known as “Brass LNG Limited” to undertake the project. The front-end engineering and design work will be for two trains, each nominally sized at 5 million metric tons per year. Natural gas supplies for the facility would come from natural gas reserves within oil and gas fields already operated by existing Nigerian Agip Oil Company and ChevronTexaco joint ventures. The front-end studies are expected to be completed in 2005, and the LNG facility is targeted to be operational in 2009.

Angola
We have a 20 percent interest in exploratory activity in deepwater Block 34, offshore Angola. The first exploration well, completed in 2002, did not encounter commercial quantities of hydrocarbons, which led to a substantial financial impairment of our investment in the block. The second exploration well, drilled in late 2003, was also unsuccessful, leading to a write-off of our remaining investment in the block.

Cameroon
In December 2002, we announced a successful test of an exploratory well offshore Cameroon. The well, located in exploration permit PH 77, offshore in the Douala Basin, obtained a maximum flow rate of 3,000 barrels of oil per day and 1.8 million cubic feet of natural gas per day during the test. Contractor interests in the permit are held 50 percent by ConocoPhillips and 50 percent by a subsidiary of Petronas Carigali (Petronas). We serve as the operator of the consortium. We are currently analyzing well results, and developing plans to evaluate the discovery and other identified exploration prospects.

Dubai
In Dubai, United Arab Emirates, we are using horizontal drilling techniques and advanced reservoir drainage technology to enhance the efficiency of the offshore production operations and improve recovery rates from four fields that we operate.

Saudi Arabia
We had a 15 percent interest in Core Venture 1 and a 30 percent interest in Core Venture 3 of the Kingdom of Saudi Arabia’s natural gas initiative. Agreement could not be reached during the negotiation of the implementation agreement, leading to the termination of both projects.

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E&P—RUSSIA AND CASPIAN SEA REGION

Russia
We have a 50 percent ownership interest in Polar Lights Company, a Russian limited liability company established in January 1992 to develop the Ardalin field in the Timan-Pechora basin in Northern Russia. We account for our interest using the equity method. Polar Lights started producing oil in August 1994 from the Ardalin field. In June 2002, production commenced from the Oshkotyn field, the first of three satellite fields under development. In 2003, production began from the other two satellite fields: East Kolva and Dyusushev.

Our net production from Polar Lights averaged 13,600 barrels of petroleum liquids per day in 2003, and is included in equity affiliate production.

Caspian Sea
In the North Caspian Sea, we have an 8.33 percent interest in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement (NCPSA), which includes the Kashagan field. During 2003, we, along with four of the remaining five co-venturers, exercised our pre-emptive rights to acquire a proportionate share of BG International’s sale of their 16.67 percent interest in the project. Upon Republic of Kazakhstan approval of the transaction, our interest in the NCPSA will increase to 10.19 percent.

The exploration area consists of 10.5 blocks, totaling nearly 2,000 square miles. The initial production phase of the contract is for 20 years, with options to extend the agreement an additional 20 years. In June 2002, we and the other contracting companies, in conjunction with KazMunayGas, which represents the Government of the Republic of Kazakhstan, declared the Kashagan discovery commercial. In February 2004, the Kashagan Development Plan was approved by the Republic of Kazakhstan.

The contracting companies plan to continue to explore other structures within the North Caspian Sea license. In October 2002, we and our co-venturers announced a new hydrocarbon discovery on the Kalamkas More prospect located approximately 40 miles southwest of the Kashagan field. Exploratory drilling continued in 2003 with three additional wells drilled. The Aktote #1 and the Kashagan Southwest #1 were announced as discoveries in November 2003. Operations on the Kairan #1 well were suspended for the winter period and will resume in the spring of 2004.

In the South Caspian Sea offshore Azerbaijan, we have a 20 percent interest in the Zafar Mashal prospect. The first exploratory well began in late 2003 and is planned for completion in 2004.

E&P—OTHER

In July 2003, we signed a Heads of Agreement with Qatar Petroleum for the development of Qatargas 3, a large-scale liquefied natural gas (LNG) project located in Qatar and servicing the U.S. natural gas markets. The agreement provided the framework for the necessary project agreements and the completion of feasibility studies. Qatargas 3 is planned as an integrated project, jointly owned by ConocoPhillips (30 percent) and Qatar Petroleum. It would consist of the facilities to produce gas from Qatar’s offshore North Field, yielding approximately 7.5 million gross tons per year of LNG from a new facility located in Ras Laffan Industrial City. The LNG would be shipped from Qatar to the United States in a fleet of new LNG carriers. We would purchase the LNG and be responsible for regasification and marketing within the United States. The project could result in sales of natural gas up to 1 billion cubic feet per day. Startup of the Qatargas 3 project is estimated to be in the 2009 timeframe.

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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.

In late 2003, we signed an agreement with Freeport LNG Development, L.P. to participate in its proposed LNG receiving terminal in Quintana, Texas. This agreement gives us 1 billion cubic feet per day of regasification capacity in the terminal and a 50 percent interest in the general partnership managing the venture. The terminal will be designed with a storage capacity of 6.9 billion cubic feet and a send-out capacity of 1.5 billion cubic feet per day. Pending government approvals, construction is scheduled to begin in the second half of 2004, with commercial startup in mid-2007.

We are continuing with plans to develop a project to build a liquefied natural gas import terminal in northern Baja California to provide access to gas markets in that region. Although we wrote-off our investment in the proposed Rosarito LNG terminal, we continue working with federal, state, and local officials in Mexico to evaluate various other alternatives, which includes offshore options.

E&P—RESERVES

The company has not filed any information with any other federal authority or agency with respect to its estimated total proved reserves at December 31, 2003. No difference exists between the company’s estimated total proved reserves for year-end 2002 and year-end 2001, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2003.

DELIVERY COMMITMENTS

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.

We sell crude oil and natural gas from our E&P producing operations under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Our Commercial organization also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the spot market, or a combination of our reserves and the spot market. Worldwide, we are contractually committed to deliver approximately 4.8 trillion cubic feet of natural gas and 270 million barrels of crude oil in the future, including the minority interests of consolidated subsidiaries. These contracts have various expiration dates through the year 2025. The crude oil commitment and approximately 4.3 trillion cubic feet of the natural gas commitment are expected to come from proved reserves in the United States, the Timor Sea, Nigeria, and the United Kingdom. The remainder of the natural gas commitment will be purchased in the spot market.

MIDSTREAM

Our Midstream business is conducted through owned and operated assets as well as through our 30.3 percent equity investment in Duke Energy Field Services, LLC (DEFS). The Midstream businesses purchase raw natural gas from producers and gather natural gas through extensive pipeline gathering systems. The gathered natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining

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“residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated-separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel, or blendstock. Total natural gas liquids extracted in 2003, including our share of DEFS, was 219,000 barrels per day, with 167,000 barrels per day of natural gas liquids fractionated.

DEFS markets a substantial portion of its natural gas liquids to ConocoPhillips and Chevron Phillips Chemical Company LLC (a joint venture between ConocoPhillips and ChevronTexaco) under a supply agreement that continues until December 31, 2014. This purchase commitment is on an “if-produced, will-purchase” basis and so it has no fixed production schedule, but has had, and is expected over the remaining term of the contract to have, a relatively stable purchase pattern. Under this agreement, natural gas liquids are purchased at various published market index prices, less transportation and fractionation fees. DEFS also purchases raw natural gas from our E&P operations in the United States.

DEFS is headquartered in Denver, Colorado. At December 31, 2003, DEFS owned and operated 56 natural gas liquids extraction plants, and owned an equity interest in another 10. Also at year end, DEFS’ gathering and transmission systems included approximately 58,000 miles of pipeline. In 2003, DEFS’ raw natural gas throughput averaged 6.7 billion cubic feet per day, and natural gas liquids extraction averaged 365,000 barrels per day. DEFS’ assets are primarily located in the Gulf Coast area, West Texas, Oklahoma, the Texas Panhandle, the Rocky Mountain area, and western Canada.

Outside of DEFS, our U.S. Midstream assets are located primarily in New Mexico, Texas and Louisiana. At December 31, 2003, these assets included seven fully owned and operated natural gas liquids extraction plants, plus two additional plants that we operate and in which we own a 95 percent and a 50 percent interest. These nine plants have a combined natural gas net plant inlet capacity of 762 million cubic feet per day. One of the plants in Louisiana also includes a 10,500 barrel-per-day liquids fractionator. We also have minor interests in two other natural gas liquids extraction plants, and we own underground natural gas liquids storage facilities in Texas and Louisiana.

We own a 25,000 barrel-per-day capacity liquids fractionation plant in Gallup, New Mexico; a 22.5 percent equity interest in Gulf Coast Fractionators, which owns a natural gas liquids fractionating plant in Mt. Belvieu, Texas (with our net share of capacity at 25,000 barrels per day); and a 40 percent interest in a fractionation plant in Conway, Kansas (with our share of capacity at 42,000 barrels per day). We own a 700-mile intrastate natural gas and liquids pipeline system in Louisiana and gas gathering and natural gas liquids pipelines in several states.

Our Canadian natural gas liquids business includes the following assets:

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Canadian natural gas liquids extracted averaged 45,000 barrels per day in 2003.

We also own a 39 percent equity interest in Phoenix Park Gas Processors Limited, a joint venture with the National Gas Company of Trinidad and Tobago Limited, which processes gas in Trinidad and markets natural gas liquids throughout the Caribbean and into the U.S. Gulf Coast. Phoenix Park’s facilities include a gas processing plant and a natural gas liquids fractionator. Our share of natural gas liquids extracted averaged 11,100 barrels per day in 2003.

In early 2004, we approved the disposal of some of our non-DEFS Midstream assets located in the Lower 48 states that are not associated with our E&P operations.

REFINING AND MARKETING (R&M)

R&M operations encompass refining crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels), buying, selling and transporting crude oil, and buying, transporting, distributing and marketing petroleum products. R&M has operations in the United States, Europe and Asia Pacific.

The Commercial organization optimizes the commodity flows of our R&M segment. This organization selects and procures feedstocks for R&M’s refineries. Commercial also supplies the gas and power needs of the R&M facilities. Commercial has buyers, traders and marketers in offices in Houston, London, Singapore and Calgary.

As a condition to the merger, the U.S. Federal Trade Commission (FTC) required that we divest specified Conoco and Phillips assets, the most significant of which were Phillips’ Woods Cross, Utah, refinery and associated motor fuel marketing operations; Conoco’s Commerce City, Colorado, refinery and related crude oil pipelines; and Phillips’ Colorado motor fuel marketing operations. All FTC-mandated dispositions were completed in late-2002 or during 2003.

In addition, in December 2002, we committed to and initiated a plan to sell approximately 3,200 marketing sites that did not fit into our long-range plans. In the third quarter of 2003, we concluded the sale of all of the Exxon-branded marketing assets in New York and New England, including contracts with independent dealers and marketers. Approximately 230 of the 3,200 sites were included in this package. In the fourth quarter of 2003, we concluded the sale of our Circle K subsidiary, representing approximately 1,660 sites, as well as the assignment of the franchise relationship with more than 350 franchised and licensed stores. Other, smaller dispositions also occurred during 2003. In January 2004, we signed agreements to sell our Mobil-branded marketing assets on the East Coast in two separate transactions. Assets in the packages include 104 company-owned and operated sites, and 352 dealer sites. Each of the transactions is expected to close in the second quarter of 2004. Discussions are under way with potential buyers for the remaining sites, and we expect to complete the sales of these assets during 2004.

Both the FTC-required dispositions and the retail site dispositions were classified as discontinued operations for financial reporting purposes, and are included in Corporate and Other. Accordingly, they are excluded from the descriptions of R&M’s continuing operations contained in this section. See Note 4—Discontinued Operations, in the Notes to Consolidated Financial Statements, for additional information.

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UNITED STATES

Refining

At December 31, 2003, we owned and operated 12 crude oil refineries in the United States, having an aggregate rated crude oil refining capacity at year-end 2003 of 2,168,000 barrels per day. The average purchase cost of a barrel of crude delivered to our U.S. refineries in 2003 was $29.10, compared to $24.92 in 2002.

East Coast Region
Bayway Refinery
Located on the New York Harbor in Linden, New Jersey, Bayway has a crude oil processing capacity of 250,000 barrels per day and processes mainly light low-sulfur crudes. Crude oil is supplied to the refinery by tanker, primarily from the North Sea and West Africa. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel along with home heating oil. Other products include petrochemical feedstocks (propylene) and residual fuel oil. The facility distributes its refined products to East Coast customers through pipelines, barges, railcars and trucks. The mix of products produced changes to meet seasonal demand. Gasoline is in higher demand during the summer, while in winter, the refinery optimizes operations to increase heating oil production. A 775 million-pound-per-year polypropylene plant became operational in March 2003.

Trainer Refinery
The Trainer refinery is located in Trainer, Pennsylvania, about 10 miles southwest of the Philadelphia airport on the Delaware River. The refinery has a crude oil processing capacity of 180,000 barrels per day and processes mainly light low-sulfur crudes. The Bayway and Trainer refineries are operated in coordination with each other by sharing crude oil cargoes, moving feedstocks between the facilities, and sharing certain personnel. Trainer 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
Alliance Refinery
The Alliance refinery, located in Belle Chasse, Louisiana, on the Mississippi River, is about 25 miles south of New Orleans and 63 miles north of the Gulf of Mexico. The refinery has a crude oil processing capacity of 250,000 barrels per day and processes mainly light low-sulfur crudes. Alliance receives domestic crude oil via pipeline, and crude oil from the North Sea and West Africa via pipeline connected to the Louisiana Offshore Oil Port. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel along with home heating oil. Other products include petrochemical feedstocks (benzene) and anode petroleum coke. The majority of the refined products are distributed to customers through the Colonial and Plantation pipeline systems.

Lake Charles Refinery
The Lake Charles refinery is located in Westlake, Louisiana. The refinery has a crude oil processing capacity of 252,000 barrels per day. The refinery receives domestic and international crude oil and processes heavy, high-sulfur, low-sulfur and acidic crude oil. While the sources of international crude oil can vary, the majority is Venezuelan and Mexican heavy crudes delivered via tanker. The refinery produces a high percentage of transportation fuels such as gasoline, off-road diesel, and jet fuel along with heating oil. The majority of the refined products are distributed to customers by truck, railcar or major common-carrier pipelines. In addition, refined products can be sold into export markets through the refinery’s marine terminal.

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The Lake Charles facilities also include a specialty coker and calciner that manufactures graphite and anode petroleum cokes supplied to the steel and aluminum industries, and provides a substantial increase in light oils production by breaking down the heaviest part of the crude barrel to allow additional production of diesel fuel and gasoline.

The Lake Charles refinery supplies feedstocks to Excel Paralubes, Penreco and Venture Coke Company (Venco), all joint ventures that are part of our Specialty Businesses function within R&M.

Sweeny Refinery
The Sweeny refinery is located in Old Ocean, Texas, about 65 miles southwest of Houston. The refinery has a crude oil processing capacity of 215,000 barrels per day. The refinery primarily receives crude oil through 100 percent owned and jointly owned terminals on the Gulf Coast, including a deepwater terminal at Freeport, Texas. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel along with home heating oil. Other products include petrochemical feedstocks (benzene) and petroleum (fuel) coke. Refined products are distributed throughout the Midwest and southeastern United States through pipeline, barge and railcar.

ConocoPhillips has a 50 percent interest in Merey Sweeny, L.P., a limited partnership that owns a 58,000 barrel-per-day delayed coker and related facilities at the Sweeny refinery. PDVSA, which owns the remaining 50 percent interest, supplies the refinery with up to 165,000 barrels per day of Venezuelan Merey, or equivalent, crude oil. We are the operating partner.

Central Region
Wood River Refinery
The Wood River refinery is located in Roxana, Illinois, about 15 miles north of St. Louis, Missouri, on the east side of the Mississippi River. It is our largest refinery, with a crude oil processing capacity of 286,000 barrels per day. The refinery can process a mix of both light low-sulfur and heavy high-sulfur crudes, which it receives from domestic and foreign sources by pipeline. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel along with home heating oil. Other products include petrochemical feedstocks (benzene) and asphalt. Through an off-take agreement, a significant portion of its gasoline, diesel and jet fuel is sold to a third party at the refinery for delivery via pipelines into the upper Midwest, including the Chicago, Illinois, and Milwaukee, Wisconsin, metropolitan areas. Remaining refined products are distributed to customers in the Midwest by pipeline, truck, barge and railcar.

During 2003, we purchased certain assets at Premcor’s Hartford, Ill., refinery. The purchase included the coker, crude unit, catalytic cracker, alkylation unit, isomerization unit, a portion of the site utilities and a portion of the storage tanks at the Premcor facility. The overall production of the Wood River refinery will only increase slightly, but the purchase will enable the refinery to process heavier, lower cost crude oil.

Ponca City Refinery
Our refinery located in Ponca City, Oklahoma, has a crude oil processing capacity of 194,000 barrels per day. Both foreign and domestic crudes are delivered by pipeline from the Gulf of Mexico, Oklahoma, Kansas, Texas and Canada. The refinery’s facilities include fluid catalytic cracking, delayed coking and hydrodesulfurization units, which enable it to produce high ratios of gasoline and diesel fuel from crude oil. Finished petroleum products are shipped by truck, railcar and company-owned and common-carrier pipelines to markets throughout the Midcontinent region.

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Borger Refinery
The Borger refinery is located in Borger, Texas, in the Texas Panhandle about 50 miles north of Amarillo. It includes a natural gas liquids fractionation facility. The crude oil processing capacity is 148,000 barrels per day, and the natural gas liquids fractionation capacity is 95,000 barrels per day. The refinery processes mainly heavy high-sulfur crudes. The refinery receives crude oil and natural gas liquids feedstocks through 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.

Billings Refinery
The Billings refinery is located in Billings, Montana, and has a crude oil processing capacity of 60,000 barrels per day, processing a mixture of about 95 percent Canadian heavy high-sulfur crude plus domestic high-sulfur and low-sulfur crudes, all delivered by pipeline. A delayed coker converts heavy high-sulfur residue into higher value light oils. The refinery produces a high percentage of transportation fuels such as gasoline, jet fuel, and diesel, as well as fuel grade petroleum coke. Finished petroleum products from the refinery are delivered via company-owned pipelines, railcars, and trucks. Pipelines transport most of the refined products to markets in Montana, Wyoming, Utah, and Washington.

West Coast Region
Los Angeles Refinery
The Los Angeles refinery is composed of two linked facilities located about five miles apart in Carson and Wilmington, California, about 15 miles southeast of the Los Angeles International airport. Carson serves as the front-end of the refinery by processing crude oil, and Wilmington serves as the back-end by upgrading products. The refinery has a crude oil processing capacity of 132,000 barrels per day and processes mainly heavy high-sulfur crudes. The refinery receives domestic crude oil via pipeline from California and foreign and domestic crude oil by tanker through company-owned and third-party terminals in the Port of Los Angeles. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel. Other products include fuel-grade petroleum coke. The refinery produces California Air Resources Board (CARB) gasoline using ethanol, which we use to replace methyl tertiary-butyl ether (MTBE) to meet federally mandated oxygenate requirements. Refined products are distributed to customers in southern California, Nevada and Arizona by pipeline and truck.

San Francisco Area Refinery
The San Francisco Area refinery is composed of two linked facilities located about 200 miles apart. The Santa Maria facility is located in Arroyo Grande, California, about 200 miles south of San Francisco, while the Rodeo facility is in the San Francisco Bay area. The refinery’s crude oil processing capacity is 109,000 barrels per day of mainly heavy high-sulfur crudes. Both the Santa Maria and Rodeo facilities have calciners to upgrade the value of the coke that is produced. The refinery receives crude oil from central California, including the Elk Hills oil field, and foreign crude oil by tanker. Semi-refined liquid products from the Santa Maria facility are sent by pipeline to the Rodeo facility for upgrading to finished petroleum products. The refinery produces transportation fuels such as gasoline, diesel, and jet fuel. Other products include calcine and fuel grade petroleum coke. The refinery produces CARB gasoline using ethanol, which we use to replace MTBE to meet federally mandated oxygenate requirements. Refined products are distributed by pipeline, railcar, truck and barge.

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Ferndale Refinery
The Ferndale refinery in Ferndale, Washington, is about 20 miles south of the United States-Canada border on Puget Sound. The refinery has a crude oil processing capacity of 92,000 barrels per day. The refinery 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.

Marketing

In the United States, we market gasoline, diesel fuel, and aviation fuel through approximately 14,300 outlets in 44 states. The majority of these sites utilize the Conoco, Phillips 66 or 76 brands.

Wholesale
In our wholesale operations, we utilize a network of marketers and dealers operating approximately 13,300 outlets. We place a strong emphasis on the wholesale channel of trade because of its lower capital requirements and higher return on capital. Our refineries and transportation systems provide strategic support to these operations. We also buy and sell petroleum products in spot markets. Our refined products are marketed on both a branded and unbranded 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.

Retail
In our retail operations, we own and operate approximately 330 sites under the Phillips 66, Conoco and 76 brands. Company-operated retail operations are focused in 10 states, mainly in the Midcontinent, Rocky Mountains, and West Coast regions. Most of these outlets market merchandise through the Kicks 66, Breakplace, or Circle K brand convenience stores.

At December 31, 2003, CFJ Properties, our 50/50 joint venture with Flying J, owned and operated 97 truck travel plazas that carry the Conoco and/or Flying J brands. The merger of Conoco and Phillips triggered change of control provisions in the joint venture agreement, giving Flying J the option to purchase our interest in CFJ Properties at fair value. A third party is determining the fair value of the joint venture. Once that binding appraised value is determined, Flying J will have 30 days to exercise their purchase option. Assuming Flying J does not exercise its purchase option, we plan to continue as a co-venturer in CFJ Properties.

Transportation

Pipelines and Terminals
At December 31, 2003, we had approximately 32,800 miles of common-carrier crude oil, raw natural gas liquids and products pipeline systems in the United States, including those partially owned and/or operated by affiliates. We also owned and/or operated 76 finished product terminals, eight liquefied petroleum gas terminals, 11 crude oil terminals and one coke exporting facility.

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Tankers
At December 31, 2003, we had under charter 13 double-hulled crude oil tankers, with capacities ranging in size from 650,000 to 1,100,000 barrels. These tankers are utilized to transport feedstocks to certain of our U.S. refineries. We also had an ocean-going barge under charter, as well as a domestic fleet of both owned and chartered boats and barges providing inland waterway transportation. The information above excludes the operations of the company’s subsidiary, Polar Tankers Inc., which is discussed in the E&P section, as well as an owned tanker on lease to a third party for use in the North Sea.

Specialty Businesses

We manufacture and sell a variety of lubricants and specialty products including petroleum cokes, lubes (such as automotive and industrial lubricants), solvents, and pipeline flow improvers to commercial, industrial and wholesale accounts worldwide.

Lubricants are marketed under the Conoco, Phillips 66, 76 Lubricants and Kendall Motor Oil brands. The distribution network consists of over 900 outlets, including mass merchandise stores, fast lubes, tire stores, automotive dealers, and convenience stores. Lubricants are also sold to industrial customers in many markets.

Excel Paralubes is a joint-venture hydrocracked lubricant base oil manufacturing facility, located adjacent to our Lake Charles refinery, and is 50 percent owned by us. Excel Paralubes’ lube oil facility produces approximately 20,000 barrels per day of high-quality, clear hydrocracked base oils. Hydrocracked base oils are second in quality only to synthetic base oils, but are produced at a much lower cost. The Lake Charles refinery supplies Excel Paralubes with gas-oil feedstocks. We purchase 50 percent of the joint venture’s output, and market it to third parties.

We have a 50 percent interest in Penreco, a fully integrated specialties company, which manufactures and markets highly refined specialty petroleum products, including solvents, waxes, petrolatums and white oils, for global 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 Venco’s Lake Charles calcining facility from our Alliance, Lake Charles, and Ponca City refineries.

INTERNATIONAL

Refining

At December 31, 2003, we owned or had an interest in six refineries outside the United States with an aggregate rated crude oil capacity of 442,000 net barrels per day. The average purchase cost of crude oil delivered to the company’s international refineries in 2003 was $28.94 per barrel, compared with $24.55 per barrel in 2002.

Humber Refinery
Our wholly owned Humber refinery is located in North Lincolnshire, United Kingdom. The refinery’s crude oil processing capacity is 234,000 barrels per day. Crude oil processed at the refinery is supplied primarily from the North Sea and includes lower-cost, acidic crudes. The refinery also processes other

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intermediate feedstocks, mostly vacuum gas oils and residual fuel oil. The refinery’s location on the east coast of England provides for cost-effective North Sea crude imports and product exports to European and world markets.

The Humber refinery is a fully integrated refinery that produces a full slate of light products and minimal fuel oil. The refinery also has two coking units with associated calcining plants, which upgrade the heavy “bottoms” and imported feedstocks into light-oil products and high-value graphite and anode petroleum cokes. Approximately 60 percent of the light oils produced in the refinery are marketed in the United Kingdom, while the other products are exported to the rest of Europe and the United States.

Whitegate Refinery
The Whitegate refinery is located in Cork, Ireland, and in 2003 had a crude oil processing capacity of 72,000 barrels per day. Effective January 1, 2004, the rated processing capacity was increased to 75,000 barrels per day due to incremental debottlenecking. Crude oil processed by the refinery is light sweet crude sourced mostly from the North Sea. The refinery primarily produces transportation fuels and fuel oil, which are distributed to the inland market via truck and sea, as well as being exported to the European market. We also operate a deepwater crude oil and products storage complex with a 7.5 million barrel capacity in Bantry Bay, Cork, Ireland.

MiRO Refinery
The Mineraloel Raffinerie Oberrhein GmbH (MiRO) refinery in Karlsruhe, Germany, is a joint-venture refinery with a crude oil processing capacity of 283,000 barrels per day. We have an 18.75 percent interest in MiRO, giving us a net capacity share of 53,000 barrels per day. Approximately 60 percent of the refinery’s crude oil feedstock is low-cost, high-sulfur crude. The MiRO complex is a fully integrated refinery producing gasoline, middle distillates, and specialty products along with a small amount of residual fuel oil. The refinery has a high capacity to convert lower-cost feedstocks into higher value products, primarily with a fluid catalytic cracker and delayed coker. The refinery produces both fuel grade and specialty calcined cokes. The refinery processes crude and other feedstocks supplied by each of the partners in proportion to their respective ownership interests.

Czech Republic Refineries
Through our participation in Ceská rafinérská, a.s. (CRC), we have a 16.33 percent ownership in two refineries in the Czech Republic, giving us a net capacity share of 27,000 barrels per day. Effective January 1, 2004, the rated crude oil processing capacity was increased to 28,000 barrels per day for our share, due to incremental debottlenecking. The refinery at Litvinov has a crude oil processing capacity of 109,200 barrels per day and processes low cost Russian export blend crude oil delivered from Russia by pipeline. 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 60,800 barrels per day and processes low sulfur crude, mostly from the Mediterranean. Kralupy has a new fluidized catalytic cracking unit, which gives the refinery a high yield of transport fuels. The two refineries complement each other and are run on an overall optimized basis, with certain intermediate streams moving between the two plants. CRC processes crude and other feedstocks supplied by ConocoPhillips and the other partners, with each partner receiving their proportionate share of the resulting products. We market our share of these finished products in both the Czech Republic and in neighboring markets.

Melaka Refinery
The refinery in Melaka, Malaysia, is a joint venture with Petronas, the Malaysian state oil company. We own a 47 percent interest in the joint venture. In 2003, the refinery had a rated crude oil processing capacity of 120,000 barrels per day, of which our share was 56,000 barrels per day. Effective January 1,

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2004, our share of the rated crude oil processing capacity was increased to 57,500 barrels per day due to incremental debottlenecking. Crude oil processed by the refinery is sourced mostly from the Middle East. The refinery produces a full range of refined petroleum products. The refinery capitalizes on our proprietary coking technology to upgrade low-cost feedstocks to higher-margin products. Our share of refined products is distributed by truck to the company’s “ProJET” retail sites in Malaysia, or transported by sea primarily to Asian markets.

Marketing

We have marketing operations in 15 European countries. Our European marketing strategy is to sell primarily through owned, leased or joint-venture retail sites using a low-cost, high-volume, low-price strategy. We also market aviation fuels, liquid petroleum gases, heating oils, transportation fuels and marine bunkers to commercial customers and into the bulk or spot market.

We use the “JET” brand name to market retail and wholesale products in our wholly owned operations in Austria, Belgium, the Czech Republic, Denmark, Finland, Germany, Hungary, Luxembourg, Norway, Poland, Slovakia, Sweden and the United Kingdom. In addition, various joint ventures in which we have an equity interest market products in Switzerland and Turkey under the “Coop” and “Tabas” or “Turkpetrol” brand names, respectively.

As of December 31, 2003, we had approximately 2,100 marketing outlets in our European operations, of which about 1,200 were company-owned, and 900 were dealer-owned. Through our joint venture operations in Turkey and Switzerland, we also have interests in approximately 800 additional sites.

The company’s largest branded site networks are in Germany and the United Kingdom, which account for approximately 60 percent of our total European branded units.

As of December 31, 2003, we had approximately 140 marketing outlets in our wholly owned Thailand operations in Asia. In addition, through a joint venture in Malaysia with Sime Darby Bhd., a company that has a major presence in the Malaysian business sector, we also have an interest in another approximately 40 retail sites. In Thailand and Malaysia, retail products are marketed under the “JET” and “ProJET” brands, respectively.

CHEMICALS

On July 1, 2000, ConocoPhillips and ChevronTexaco combined their worldwide chemicals businesses, excluding ChevronTexaco’s Oronite business, into a new company, Chevron Phillips Chemical Company LLC (CPChem). In addition to contributing the assets and operations included in our Chemicals segment, we also contributed the natural gas liquids business associated with our Sweeny, Texas, complex. ConocoPhillips and ChevronTexaco each own 50 percent of CPChem. We use the equity method of accounting for our investment in CPChem.

CPChem, headquartered in The Woodlands, Texas, has 32 production facilities and six research and technology centers. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals such as ethylene, propylene, styrene, benzene and paraxylene. These products are then marketed and sold, or used as feedstocks to produce plastics and commodity chemicals, such as polyethylene, polystyrene, and cyclohexane.

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CPChem’s domestic production facilities are located at Baytown, Borger, Conroe, La Porte, Orange, Pasadena, Port Arthur and Old Ocean, Texas; St. James, Louisiana; Pascagoula, Mississippi; Marietta, Ohio; and Guayama, Puerto Rico. CPChem also has nine plastic pipe plants and one pipe fittings plant in eight states.

Major international production facilities are located in Belgium, China, Saudi Arabia, Singapore, South Korea and Qatar. There is one plastic pipe plant in Mexico.

CPChem has research facilities in Oklahoma, Ohio and Texas, as well as in Singapore and Belgium.

Construction of a major olefins and polyolefins complex in Mesaieed, Qatar, named Q-Chem I, was completed in 2003. The facility, which is operating and in the final stages of performance testing, has an annual capacity of approximately 1.1 billion pounds of ethylene, 1 billion pounds of polyethylene and 100 million pounds of 1-hexene. CPChem has a 49 percent interest, with a Qatar state firm owning the remaining 51 percent interest.

CPChem has also signed an agreement for the development of a second complex to be built in Mesaieed, Qatar, named Q-Chem II. The facility will be designed to produce polyethylene and normal alpha olefins, on a site adjacent to the newly-constructed Q-Chem I complex. CPChem and Qatar Petroleum, through the Q-Chem II joint venture, entered into a separate agreement with Atofina and Qatar Petrochemical Company to jointly develop an ethane cracker in northern Qatar at Ras Laffan Industrial City. Final approval of the Q-Chem II projects by CPChem’s Board of Directors is expected to be requested in 2005, with startup expected in 2008.

CPChem announced plans in 2002 for a 50 percent-owned joint venture project in Al Jubail, Saudi Arabia. The project includes the construction of an integrated olefins, ethyl benzene and styrene monomer facility on a site adjacent to the existing aromatics complex owned by Saudi Chevron Phillips Company, a 50 percent-owned CPChem joint venture. The project also includes the expansion of Saudi Chevron Phillips Company’s benzene facility. This additional benzene capacity will be used to provide feedstock for the new facility. Final approval of the project by CPChem’s Board of Directors is expected to be requested in 2004, with operational startup expected in 2007.

A brief description of CPChem’s major product lines follows.

Olefins and Polyolefins
Ethylene: Ethylene is a basic building block for plastics and also a raw material for chemicals used to make paints, detergents and antifreeze. Ethylene is produced at Old Ocean, Port Arthur and Baytown, Texas, as well as in Qatar. CPChem’s net annual capacity at December 31, 2003, was approximately 8.1 billion pounds.

Polyethylene: Polyethylene is used to make a wide variety of plastic products, including various containers, shopping and trash bags, and plastic films. Polyethylene is produced at Pasadena, Baytown, and Orange, Texas, as well as in China, Singapore and Qatar. CPChem’s net annual capacity at December 31, 2003, was approximately 5.9 billion pounds.

Plastic Pipe: Polyethylene plastic pipe is produced at nine plants in the United States and one plant in Mexico. Pipe fittings are produced at one plant in the United States. CPChem’s net annual capacity at December 31, 2003, was approximately 564 million pounds.

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Normal Alpha Olefins: Normal alpha olefins can be custom blended for special applications and are used extensively as polyethylene comonomers and are also used in synthetic lubricants and additives. Normal alpha olefins are produced at Baytown, Texas and in Qatar. CPChem’s net annual capacity at December 31, 2003, was approximately 1.5 billion pounds.

Aromatics and Styrenics
Styrene: Styrene, produced from benzene and ethylene, is used as a feedstock for polystyrene and is also used to produce a variety of polymers with end-uses that include packaging, rubber products, automotive and other applications. Styrene is produced at St. James, Louisiana. CPChem’s net annual capacity at December 31, 2003, was approximately 2.1 billion pounds.

Polystyrene: Polystyrene is a thermoplastic polymer used to make packing materials, cups, toys, furniture, and housewares. It is produced at Marietta, Ohio, and in China. CPChem’s net annual capacity at December 31, 2003, was approximately 990 million pounds.

Benzene: Benzene is a building block chemical used in the production of ethylbenzene, cumene, and cyclohexane. Benzene is produced at Pascagoula, Mississippi and in Saudi Arabia. CPChem’s net annual capacity at December 31, 2003, was approximately 2.1 billion pounds.

Cyclohexane: Cyclohexane is a derivative of benzene that is predominantly used in intermediates for the manufacture of nylon. It is produced at Port Arthur, Texas, and in Saudi Arabia. CPChem’s net annual capacity at December 31, 2003, was approximately 1.2 billion pounds. This includes the capacity of a new plant in Port Arthur that commenced operations in February 2004, and excludes the capacity of a plant, also in Port Arthur, that was shut down. In addition, CPChem markets cyclohexane production from ConocoPhillips’ Sweeny and Borger complexes.

K-Resin ^® : K-Resin ^® is a styrene-butadiene copolymer used to produce a clear, shatter-resistant resin. It is produced at Pasadena, Texas, and in South Korea. CPChem’s net annual capacity at December 31, 2003, was approximately 269 million pounds.

Paraxylene: Paraxylene is an aromatic used as a feedstock for polyester and certain plastics. It is currently produced at Pascagoula, Mississippi. The Pascagoula plant’s annual capacity at December 31, 2003, was approximately 1.0 billion pounds. A plant in Guayama, Puerto Rico, with an annual capacity at December 31, 2003, of approximately 715 million pounds, was reconfigured in 2003 and is currently idled. Operations at the Puerto Rico plant could resume when market conditions improve.

Specialty Products
Specialty Chemicals: CPChem manufactures, markets and distributes organosulfur, paraffinic, olefinic and aromatic specialty chemicals as well as a complete line of natural gas odorants, specialty catalysts, specialty fuels, mining chemicals and oilfield drilling additives, enhancers and cements. These products are manufactured and processed in Borger and Conroe, Texas, and Tessenderlo, Belgium.

Ryton ^® Polyphenylene Sulfide: CPChem produces high-performance polyphenylene sulfide polymers (PPS) sold under the trademark Ryton ^® , which is produced at Borger, Texas. CPChem’s annual capacity of Ryton PPS at December 31, 2003, was 22 million pounds. Ryton PPS compounds are produced at La Porte, Texas, as well as in Belgium and Singapore. These facilities have a net annual capacity of approximately 44 million pounds of Ryton PPS compounds in the aggregate.

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EMERGING BUSINESSES

Emerging Businesses encompass the development of new businesses beyond our traditional operations. As a result of market, operating and technological uncertainties, we terminated our carbon fibers project during 2003.

GAS-TO-LIQUIDS (GTL)

The GTL process refines natural gas into a wide range of transportable products. Our GTL research facility is located in Ponca City, Oklahoma, and includes laboratories, pilot plants, and a demonstration plant to facilitate technology advancements. The 400 barrel-per-day demonstration plant, designed to produce clean fuels from natural gas, was completed in April 2003. The plant has been commissioned and operations started, with thorough testing scheduled throughout 2004.

TECHNOLOGY SOLUTIONS

Our Technology Solutions businesses provide technologies and services that can be used in our operations or licensed to third parties. Downstream, major product lines include sulfur removal technologies (S Zorb), alkylation technologies (ReVAP), and delayed coking technologies. For upstream and downstream, Technology Solutions offers analytical services, pilot plant, and industrial hygiene services.

POWER GENERATION

The focus of our power business is on developing integrated projects in support of the company’s E&P and R&M strategies and business objectives. The projects that enable these strategies are included within the respective E&P and R&M segments. The projects and assets that have a significant merchant component are included in the Emerging Businesses segment.

The power business is developing a 730-megawatt gas-fired combined heat and power plant in North Lincolnshire, United Kingdom. The facility will provide steam and electricity to the Humber refinery and steam to a neighboring refinery, as well as market power into the U.K. market. Construction began in 2002, with commercial operation anticipated in 2004.

We also own or have an interest in gas-fired cogeneration plants in Orange and Corpus Christi, Texas, and a petroleum coke-fired plant in Lake Charles, Louisiana.

EMERGING TECHNOLOGY

Emerging Technology focuses on developing new business opportunities designed to provide growth options for ConocoPhillips well into the future. Example areas of interest include renewable energy, advanced hydrocarbon processes, energy conversion technologies and new petroleum-based products.

COMPETITION

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.

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Upstream, our E&P segment competes with numerous other companies in the industry to locate and obtain new sources of supply, and to produce oil and natural gas in an efficient, cost-effective manner. Based on reserves statistics published in the September 15, 2003, issue of the Oil and Gas Journal , we had the eighth-largest total of worldwide reserves of non-government-controlled companies. We deliver our oil and natural gas production into the worldwide oil and natural gas commodity markets. The principal methods of competing include geological, geophysical and engineering research and technology; experience and expertise; and economic analysis in connection with property acquisitions.

The Midstream segment, through our equity investment in DEFS and our consolidated operations, competes with numerous other integrated petroleum companies, as well as natural gas transmission and distribution companies, to deliver the components of natural gas to end users in the commodity natural gas markets. DEFS is one of the largest producers of natural gas liquids in the United States, based on the November 17, 2003, Gas Processors Report . 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 22, 2003, issue of the Oil and Gas Journal , we had the largest U.S. refining capacity of about 15 large refiners of petroleum products. Worldwide, we ranked fourth among non-government-controlled companies. In the Chemicals segment, through our equity investment, CPChem generally ranks within the top 10 producers of its major product lines, based on average 2003 production capacity, as published by Chemical Market Associates Inc. Petroleum products, petrochemicals and plastics are delivered into the worldwide commodity markets. Elements of downstream competition include product improvement, new product development, low-cost structures, and manufacturing and distribution systems. In the marketing portion of the business, competitive factors include product properties and processibility, reliability of supply, customer service, price and credit terms, advertising and sales promotion, and development of customer loyalty to ConocoPhillips’ or CPChem’s branded products.

GENERAL

At the end of 2003, we held a total of 1,918 active patents in 68 countries worldwide, including 733 active U.S. patents. During 2003, we received 57 patents in the United States and 136 foreign patents. Our products and processes generated licensing revenues of $35 million in 2003. The overall profitability of any business segment is not dependent on any single patent, trademark, license, franchise or concession.

Company-sponsored research and development activities charged against earnings were $136 million, $355 million and $44 million in 2003, 2002 and 2001, respectively.

The environmental information contained in Management’s Discussion and Analysis on pages 72 through 75 under the caption, “Environmental” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2003 and those expected for 2004 and 2005.

Like all major international oil companies, we have for many years operated in countries that are subject to U.S. government restrictions or prohibitions on business activities by U.S. companies. In some cases, business is permitted if we have received a license from the Office of Foreign Assets Control (OFAC). The regulations implementing the restrictions are complicated and subject to interpretation by OFAC. We have programs designed to ensure compliance with the restrictions and believe that our present operations comply with applicable laws and regulations.

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In view of recent political, diplomatic and military developments in the Middle East, and throughout the world, we have reexamined our policies and procedures in order to prevent any actions that would violate the letter, or even the spirit of the restrictions. These developments may affect prices, production levels, allocation and distribution of raw materials and products, including their import, export and ownership; the amount of tax and timing of payment; and the cost of compliance with environmental regulations.

Following the events of September 11, 2001, a number of institutional investors and state governmental agencies have questioned the appropriateness of U.S. companies transacting business in or with any country that has reportedly been linked to terrorism, even if the country is not subject to legal restrictions. We have reexamined our policies and business ventures to ensure that our activities in or with certain countries are consistent with the U.S. government’s policy, interests and objectives in such countries.

Web Site Access to SEC Reports

Our Internet Web site address is http://www.conocophillips.com . 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 SEC’s Internet Web site at http://www.sec.gov.

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Item 3. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the fourth quarter of 2003 and those matters previously reported in ConocoPhillips’ 2002 Form 10-K and our first-, second- and third-quarter 2003 Forms 10-Q that have not been resolved. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceeding was decided adversely to ConocoPhillips, there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the United States Securities and Exchange Commission’s regulations.

In December 2003, we entered into an Administrative Consent Order and Notice of Noncompliance with the Massachusetts Department of Environmental Protection for alleged violations of State II and Hazardous Waste requirements at various retail gasoline outlets formerly owned by us. This Consent Agreement provides for the payment of a civil administrative penalty in the amount of $106,250.

In November 2003, the U.S. Environmental Protection Agency (EPA) issued us a notice of violation for alleged violations of the gasoline Reid Vapor Pressure rules in 1999, 2000 and 2001 at our Wood River and Billings refineries. The notice of violation seeks a proposed penalty of $127,000. We are currently working with EPA toward a negotiated resolution of this matter.

On September 17, 2003, U.S. EPA Region 10 notified ConocoPhillips of its intent to assess civil penalties for alleged National Pollution Discharge Elimination System (NPDES) permit violations at our Tyonek offshore platform located near Cook Inlet, Alaska. The alleged violations arise from our July 2003 NPDES self-disclosure report to EPA Region 10. On February 10, 2004, EPA Region 10 issued to us a proposed Complaint for Civil Penalties and a proposed Consent Decree for the alleged permit violations. The proposed consent decree provides for the payment of a $450,000 civil penalty. We are currently working with the EPA and the U.S. Department of Justice (DOJ) on the terms of the agreements and expect the matter to be finalized by the end of the second quarter of 2004.

On August 24, 2003, the Contra Costa County District Attorney’s Office in California issued a demand letter to ConocoPhillips seeking civil penalties in the amount of $524,000 for 31 alleged violations of the Bay Area Air Quality Management District regulations at our Rodeo facility of the San Francisco area refinery. The demand has been reduced to $361,000. These alleged violations cover the period from mid-2001 through August 2003. We are currently working with the Contra Costa County District Attorney’s Office toward a negotiated resolution of this matter.

In August of 2003, EPA Region 6 issued a Show Cause Order alleging violations of the Clean Water Act at the Borger refinery. The alleged violations relate primarily to discharges of selenium and reported exceedances of permit limits for whole effluent toxicity. We met with EPA staff on October 29, 2003, to discuss the allegations. We believe the EPA staff is evaluating the information presented at the meeting. The EPA has not yet proposed a penalty 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 are currently working with TCEQ toward a negotiated resolution of this matter.

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On December 17, 2002, the DOJ notified ConocoPhillips of various alleged violations of the NPDES permit for the Sweeny refinery. DOJ asserts that these alleged violations occurred at various times during the period beginning January 1997 through July 2002. We have reached a tentative agreement with the DOJ that will require us to pay a civil penalty and/or perform certain work valued at $700,000.

In December 2002, the Louisiana Department of Environmental Quality (LDEQ) notified ConocoPhillips of its intent to assess civil penalties for over 120 alleged regulatory violations at various Circle K stores in the Baton Rouge, Louisiana area. On October 6, 2003, the LDEQ notified ConocoPhillips that the civil penalty assessment for these alleged violations is $189,659. This matter was settled in November 2003.

On November 14, 2002, the TCEQ issued a proposed agreed Findings Order to resolve alleged water discharge violations of the Texas Water Code and Commission Rules at the Sweeny refinery for the period beginning March 2000 through July 2002. The proposed order assesses a penalty in the amount of $488,125. We have agreed with the TCEQ to settlement terms that are expected to be finalized during the first quarter of 2004.

On July 15, 2002, the United States filed a Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) cost recovery action against ConocoPhillips alleging that the United States has incurred unreimbursed oversight costs at the Lowry Superfund Site located in Arapahoe County, Colorado. The United States seeks recovery of approximately $12.3 million in past oversight costs and a declaratory judgment for future CERCLA response cost liability. Pursuant to the terms of a prior settlement agreement between us, Waste Management, Inc. and others, Waste Management has assumed our defense for this matter and it is our position that Waste Management should indemnify us for any liability arising from this action.

We have responded to information requests from EPA regarding New Source Review compliance at our Alliance, Bayway, Borger, Ferndale, Los Angeles, Sweeny, Trainer, and Wood River refineries; and the Rodeo and Santa Maria units of our San Francisco refinery. Although we have not been notified of any formal findings or violations arising from these information requests, we have been informed that the EPA is contemplating the filing of a civil proceeding against us for alleged violations of the Clean Air Act. We are currently seeking a negotiated resolution of these matters, which will likely result in increased environmental capital expenditures and governmental monetary sanctions.

All significant litigation arising from the March 27, 2000, explosion and fire that occurred in an out-of-service butadiene storage tank at the K-Resin ^® styrene-butadiene copolymer plant has now been resolved.

In June of 1997, we experienced pipeline spills on our Seminole pipeline at Banner, Wyoming, and Lodge Grass, Montana. In response to these spills, the DOJ advised us in August 2000 that the United States is contemplating a legal proceeding under the Clean Water Act against us. We and DOJ have reached a tentative agreement that will require us to pay a $465,000 civil penalty.

Additionally, we are subject to various lawsuits and claims including, but not limited to: actions challenging oil and gas royalty and severance tax payments; actions related to gas measurement and valuation methods; actions related to joint interest billings to operating agreement partners; and claims for damages resulting from leaking underground storage tanks or other accidental releases, with related toxic tort claims. As a result of Conoco’s separation agreement with DuPont in October 1998, we also have assumed responsibility for current and future claims related to certain discontinued chemicals and agricultural chemicals businesses operated by Conoco in the past. In general, the effect on future financial results is not subject to reasonable estimation because considerable uncertainty exists. The ultimate liabilities resulting from such lawsuits and claims may be material to results of operations in the period in which they are recognized.

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Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

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There is no family relationship among the officers named above. Each officer of the company is elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as appropriate. Each officer of the company holds office from date of election until the first meeting of the directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the next annual meeting is May 5, 2004. Set forth below is information concerning the executive officers.

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Rand C. Berney was appointed Vice President and Controller of ConocoPhillips upon completion of the merger. Prior to the merger, he was Phillips’ Vice President and Controller since 1997.

William B. Berry was appointed Executive Vice President, Exploration and Production of ConocoPhillips on January 1, 2003, having previously served as President of ConocoPhillips’ Asia Pacific operations since completion of the merger. Prior to the merger, he was Phillips’ Senior Vice President E&P Eurasia-Middle East operations since 2001; and Phillips’ Vice President E&P Eurasia operations since 1998.

John A. Carrig was appointed Executive Vice President, Finance, and Chief Financial Officer of ConocoPhillips upon completion of the merger. Prior to the merger, he was Phillips’ Senior Vice President and Chief Financial Officer since 2001; Phillips’ Senior Vice President, Treasurer and Chief Financial Officer since 2000; and Phillips’ Vice President and Treasurer since 1996.

Archie W. Dunham was appointed Chairman of the Board of Directors of ConocoPhillips upon completion of the merger. Prior to the merger, he was Conoco’s Chairman of the Board, President and Chief Executive Officer since 1999; and Conoco’s President and Chief Executive Officer since 1996.

Philip L. Frederickson was appointed Executive Vice President, Commercial of ConocoPhillips upon completion of the merger. Prior to the merger, he was Conoco’s Senior Vice President of Corporate Strategy and Business Development since 2001; and Conoco’s Vice President of Business Development since 1998.

Stephen F. Gates was appointed Senior Vice President, Legal, and General Counsel of ConocoPhillips effective May 1, 2003. Prior to joining ConocoPhillips, he was a partner at Mayer, Brown, Rowe & Maw. Previously, he served as senior vice president and general counsel of FMC Corporation in 2000 and 2001. Prior to that, he served at BP Amoco (now BP plc) where he was executive vice president and group chief of staff after serving as vice president and general counsel of Amoco.

John E. Lowe was appointed Executive Vice President, Planning, Strategy and Corporate Affairs of ConocoPhillips upon completion of the merger. Prior to the merger, he was Phillips’ Senior Vice President, Corporate Strategy and Development since 2001; Phillips’ Senior Vice President of Planning and Strategic Transactions since 2000; Phillips’ Vice President of Planning and Strategic Transactions since 1999; and Phillips’ Manager of Strategic Growth Projects since earlier in 1999.

J. J. Mulva was appointed President and Chief Executive Officer of ConocoPhillips upon completion of the merger. Prior to the merger, he was Phillips’ Chairman of the Board of Directors and Chief Executive Officer since 1999; and Phillips’ Vice Chairman of the Board of Directors, President, and Chief Executive Officer since earlier in 1999.

J. W. Nokes was appointed Executive Vice President, Refining, Marketing, Supply and Transportation of ConocoPhillips upon completion of the merger. Prior to the merger, he was Conoco’s Executive Vice President, Worldwide Refining, Marketing, Supply and Transportation since 1999.

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