ConocoPhillips - 10-K annual report

2003

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

OR

Commission file number 000-49987

ConocoPhillips

600 North Dairy Ashford
Houston, TX 77079
(Address of principal executive offices)

Registrant’s telephone number, including area code: 281-293-1000

_________________________

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   X   No       

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes   X   No       

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2003, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $54.80, was $37.2 billion. The registrant, solely for the purpose of this required presentation, had deemed its Board of Directors and the Compensation and Benefits Trust to be affiliates, and deducted their stockholdings of 369,905 and 26,035,094 shares, respectively, in determining the aggregate market value.

The registrant had 684,182,093 shares of common stock outstanding at January 31, 2004.

Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 5, 2004 (Part III)

TABLE OF CONTENTS

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.

Items 1 and 2. BUSINESS AND PROPERTIES

CORPORATE STRUCTURE

ConocoPhillips is a major, integrated, global energy company. ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger between Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips). The merger between Conoco and Phillips (the merger) was consummated on August 30, 2002, at which time Conoco and Phillips combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips. As a result of the merger, Conoco and Phillips each became wholly owned subsidiaries of ConocoPhillips. For accounting purposes, Phillips was designated as the acquirer of Conoco and ConocoPhillips was treated as the successor of Phillips. Accordingly, Phillips’ operations and results are presented in this Form 10-K for all periods prior to the close of the merger. From the merger date forward, the operations and results of ConocoPhillips reflect the combined operations of the two companies. Subsequent to the merger, Conoco was renamed ConocoPhillips Holding Company, and Phillips was renamed ConocoPhillips Company, but for ease of reference, those companies will be referred to respectively in this document as Conoco and Phillips.

Our business is organized into five operating segments:

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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 athttp://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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EXECUTIVE OFFICERS OF THE REGISTRANT

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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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Quarterly Common Stock Prices and Cash Dividends Per Share

ConocoPhillips’ common stock began trading on September 3, 2002, the first trading day after the effective date of the merger. ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”

Phillips Petroleum Company’s (predecessor to ConocoPhillips) stock was traded primarily on the New York, Pacific and Toronto stock exchanges. On August 30, 2002, it ceased trading.

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Item 6. SELECTED FINANCIAL DATA

See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance an understanding of this data. The following transactions affect the comparability of the amounts included in the table above:

Also, see Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for information on changes in accounting principles that affect the comparability of the amounts included in the table above.

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February 25, 2004

Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations, intentions, and resources that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “intends,” “believes,” “expects,” “plans,” “scheduled,” “anticipates,” “estimates,” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. 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.

RESULTS OF OPERATIONS

Merger of Conoco and Phillips

On August 30, 2002, Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips) combined their businesses by merging with wholly owned subsidiaries of a new company named ConocoPhillips (the merger). The merger was accounted for using the purchase method of accounting, with Phillips designated as the acquirer for accounting purposes. Because Phillips was designated as the acquirer, its operations and results are presented in this annual report for all periods prior to the close of the merger. From the merger date forward, the operations and results of ConocoPhillips reflect the combined operations of the two companies.

Business Environment and Executive Summary

Our overall earnings depend primarily upon the profitability of our Exploration and Production (E&P) and Refining and Marketing (R&M) segments. Our earnings normally are less impacted by results from the Midstream, Chemicals and Emerging Businesses segments.

Crude oil and natural gas prices, along with refining margins, play the most significant roles in our profitability. These prices and margins are driven by market factors over which we have no control. However, from a competitive perspective, there are other important factors that we must manage well to be successful, including:

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Many of our key performance indicators are shown in the statistical tables provided at the beginning of our operating segment sections that follow. These include crude oil and natural gas prices and production, natural gas liquids prices, refining capacity utilization, and refinery output. We also use the “return on capital employed” measure.

Other significant factors that can and/or do affect our profitability include:

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Segment Analysis
The E&P segment’s results are most closely linked to crude oil and natural gas prices. These are commodity products, the prices of which are subject to factors external to our company and over which we have no control. We benefited from favorable crude oil prices in 2003, which contributed significantly to what we view as strong results from this segment in 2003. For a discussion of factors impacting crude oil and natural gas prices in 2003, as well as our view of the potential movement of these prices into 2004, see the “Outlook” section. At year-end 2003, we estimated that a $1 per barrel change in crude oil prices would have an estimated $170 million annual impact on net income. For natural gas, the corresponding impact is approximately $40 million for a 10 cent per thousand cubic feet price change.

The Midstream segment’s results are most closely linked to natural gas liquids prices. The most important factor on the profitability of this segment is the results from our 30.3 percent equity investment in Duke Energy Field Services, LLC (DEFS). Higher natural gas liquids prices improved results from this segment 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 margins, refinery utilization, cost control, and marketing margins primarily drive the R&M segment’s results. Refining margins are subject to movements in the cost of crude oil and other feedstocks, and the sales prices for refined products, which are subject to market factors over which we have no control. Refining margins in 2003 were much improved over 2002, resulting in improved R&M profitability. See the “Outlook” section for further discussion of refining margins in 2003 and our view of their potential movement into 2004. At year-end 2003, we estimated that a 25 cent per barrel change in refining margins would have an estimated $125 million annual impact on net income. For wholesale marketing margins, the corresponding impact is approximately $100 million for a 1 cent per gallon margin change. Our refineries operated at 94 percent of rated capacity in 2003, and our goal in 2004 is to operate at about the same level.

The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem). The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on market factors over which CPChem has little or no control. The chemicals and plastics industry has been in a cyclical downturn for the last several years. In this difficult market environment, CPChem has placed great emphasis on safety, cost control and managing its capacity utilization. In addition, CPChem is investing in feedstock-advantaged areas in the Middle East with access to large, growing markets, such as Asia. With its low cost structure, we feel CPChem is well positioned to benefit from improved margins when the chemicals industry emerges from its downturn.

The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. We do not expect the results from this segment to be material to our consolidated results. However, the businesses in this segment allow us to support our primary segments by staying current on new technologies that could become important drivers of profitability in future years.

At December 31, 2003, we had a debt-to-capital ratio of 34 percent. We have made a priority of using funds available after paying dividends and capital spending to reduce debt. We reduced our debt by $4.8 billion in 2003. We feel that by lowering our debt-to-capital ratio over the next several years to about 30 percent, we can improve our cost of capital and further position ourselves for growth opportunities in the future.

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Consolidated Results

A summary of the company’s net income (loss) by business segment follows:

2003 vs. 2002

Net income was $4,735 million in 2003, compared with a net loss of $295 million in 2002. The improved results in 2003 were primarily due to:

See the “Segment Results” section for additional information on our E&P and R&M results, as well as our other reporting segments.

2002 vs. 2001

We incurred a net loss of $295 million in 2002, compared with net income of $1,661 million in 2001. The decrease was primarily attributable to recognizing impairments and loss accruals totaling $1,077 million after-tax associated with our retail and wholesale marketing operations that were classified as discontinued operations in late 2002, as well as merger-related costs totaling $557 million after-tax. Also negatively impacting results for 2002 were other asset impairments totaling $192 million after-tax, lower refining

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margins, lower natural gas sales prices, decreased equity earnings from Duke Energy Field Services, LLC (DEFS), and higher interest expense. These factors were partially offset by improved results from Chemicals and higher production volumes in E&P after the merger.

Income Statement Analysis

2003 vs. 2002

The merger affects the comparability of the 2003 and 2002 periods. 2003 includes a full year of ConocoPhillips’ operations, while 2002 includes only four months of combined operations. Prior to August 30, 2002, our results reflect Phillips’ operations only. Accordingly, the merger significantly increased:

In addition to the merger impact, sales and other operating revenues and purchase costs increased because of higher prices for key products such as crude oil, natural gas, automotive gasoline and distillates. These are commodity products and their price levels are determined by market factors.

Our share of earnings from affiliates acquired in the merger accounted for the majority of the increase in the equity earnings. Of these, the E&P joint ventures in Canada (Petrovera) and Venezuela (Petrozuata), along with CFJ Properties in our R&M segment, provided the largest equity earnings. On February 18, 2004, we sold our interest in the Petrovera joint venture. Of the equity affiliates held prior to the merger, our equity earnings from DEFS improved on higher natural gas liquids prices, and our earnings from Hamaca, an E&P heavy-oil joint venture in Venezuela, increased due to higher crude oil production.

A higher net gain on asset sales was primarily responsible for the increase in other income in 2003. During 2003 we sold several E&P operations that did not fit into our long-term growth strategy. In addition, 2003 included gains attributable to insurance demutualization benefits. See the Corporate and Other section of “Segment Results” for additional information on these insurance benefits.

Selling, general and administrative expenses in 2002 included a $246 million charge for the write-off of in-process research and development costs acquired in the merger. The absence of such a significant charge in the 2003 period reduced the impact of the merger on this line item.

Property impairments increased by $75 million in 2003, compared with 2002. The 2003 impairments were recorded as a result of asset status changes from held-for-use to held-for-sale, producing properties that failed to meet recoverability tests, and tax law changes in Norway affecting asset removal costs. During 2002, property impairments were triggered by asset dispositions and the impairment of tradenames. See Note 12—Property Impairments, in the Notes to Financial Statements, for additional information.

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Accretion on discounted liabilities increased $123 million in 2003, reflecting accretion expense on environmental liabilities assumed in the merger and discounted obligations associated with the retirement and removal of long-lived assets that became effective January 1, 2003, with the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” See Note 2—Changes in Accounting Principles, in the Notes to Financial Statements, for additional information on SFAS No. 143.

In addition to the merger impact, interest and debt expense also increased in 2003 because of the adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities,” (FIN 46). The adoption of FIN 46 for variable interest entities involving synthetic leases and certain other financing structures, effective January 1, 2003, resulted in increased balance sheet debt, which resulted in higher interest expense in 2003. See Note 2—Changes in Accounting Principles, and Note 14 – Debt, in the Notes to Consolidated Financial Statements, for additional information.

During 2003, we recognized a $28 million gain on subsidiary equity transactions related to our E&P Bayu-Undan development in the Timor Sea. See Note 7—Subsidiary Equity Transactions, in the Notes to Consolidated Financial Statements, for additional information.

Our effective tax rate in 2003 was 45 percent, compared with 67 percent in 2002. The lower effective tax rate in 2003 primarily was the result of a higher proportion of income in lower-tax-rate jurisdictions and the one-time impact of tax law changes in certain international jurisdictions. Contributing to the higher effective tax rate in 2002 was a write-off of in-process research and development costs, as well as the partial impairment of an exploration prospect, both without corresponding tax benefits in 2002.

Our discontinued operations had income of $237 million in 2003, compared with a net loss of $993 million in 2002. The net loss in 2002 reflected charges totaling $1,008 million after-tax related to the impairment of properties, plants and equipment; goodwill; intangible assets; and provisions for losses associated with various operating lease commitments. For additional information about our discontinued operations, see Note 4—Discontinued Operations, in the Notes to Consolidated Financial Statements.

We adopted SFAS No. 143 effective January 1, 2003, resulting in the recognition of a benefit of $145 million for the cumulative effect of this accounting change. Also effective January 1, 2003, we adopted FIN 46 for variable interest entities involving synthetic leases and certain other financing structures created prior to February 1, 2003. This resulted in a charge of $240 million for the cumulative effect of this accounting change. Together, these resulted in a net charge of $95 million. For additional information on these accounting changes, see Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements.

2002 vs. 2001

In addition to the merger of Conoco and Phillips on August 30, 2002, ConocoPhillips closed on the $7 billion acquisition of Tosco Corporation on September 14, 2001. Together, these transactions significantly increased operating revenues; equity earnings; other income; purchase costs; operating expenses; selling, general and administrative expenses; depreciation, depletion and amortization; taxes other than income taxes; accretion on discounted liabilities; and interest and debt expense in 2002, compared with 2001.

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Restructuring Accruals

As a result of the merger, we began a restructuring program in September 2002 to capture the benefits of combining Conoco and Phillips by eliminating redundancies, consolidating assets, and sharing common services and functions across regions. We expect the restructuring program to be completed by the end of the first quarter of 2004. From September 2002 through December 31, 2003, approximately 3,900 positions worldwide had been identified for elimination. Of this total, approximately 3,000 employees had been terminated by December 31, 2003. The information in Note 5—Restructuring, in the Notes to Consolidated Financial Statements, is incorporated herein by reference.

Segment Results

E&P

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2003 vs. 2002

The E&P 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.

Net income from the E&P segment increased 146 percent in 2003, compared with 2002. The improvement reflects higher production volumes, primarily due to the merger; higher crude oil and natural gas prices; and an increased net gain on asset sales. These items were partially offset by higher production and operating expenses; depreciation, depletion and amortization; and taxes other than income taxes, all the result of the larger size and scope of our operations following the merger.

In addition, 2003 included benefits of $233 million in our international E&P operations from changes in income tax and site restoration laws, as well as an equity realignment of certain Australian operations. Also, the cumulative effect of the adoption of SFAS No. 143 and the adoption of FIN 46 for variable interest entities involving synthetic leases and certain other financing structures increased E&P’s net income by $142 million in 2003.

Our average worldwide crude oil sales price was $27.47 per barrel in 2003, compared with $24.07 in 2002. We also benefited from higher natural gas prices in 2003, with our average worldwide price increasing from $2.77 per thousand cubic feet in 2002 to $4.07 in 2003. If crude oil and natural gas prices in 2004 do not remain at the historically strong levels experienced in 2003, E&P’s earnings will be negatively impacted in 2004. See the “Outlook” section for additional discussion of crude oil and natural gas prices.

ConocoPhillips’ proved reserves at year-end 2003 were 7.85 billion barrels of oil equivalent, a slight increase over 7.81 billion barrels at year-end 2002. Our Canadian Syncrude mining operations had an additional 265 million barrels of proved oil sands reserves at the end of 2003, compared with 272 million barrels at year-end 2002.

2002 vs. 2001

Net income from the E&P segment increased 3 percent in 2002, compared with 2001. Although E&P benefited from four months of increased production volumes in 2002 following the merger, this increase was mostly offset by lower natural gas sales prices, higher exploration expenses, and the unfavorable $24 million impact of a tax law change in the United Kingdom. Our average worldwide crude oil sales price was $24.07 per barrel in 2002, a 1 percent increase over $23.74 in 2001. Our average worldwide natural gas price in 2002 was $2.77 per thousand cubic feet, a 14 percent decrease from $3.23 in 2001.

Our proved reserves at year-end 2002 were 7.81 billion barrels of oil equivalent, a 52 percent increase over year-end 2001’s 5.13 billion barrels of oil equivalent. The increase was attributable to the merger.

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U.S. E&P

2003 vs. 2002

Net income from our U.S. E&P operations increased 105 percent in 2003, compared with 2002. Net income from our Alaskan operations increased $575 million in 2003. The improvement in Alaska reflects higher crude oil prices, and a net $143 million benefit from the cumulative effect of adopting SFAS No. 143 and FIN 46, partially offset by slightly lower crude oil production volumes. The West Coast price of our Alaskan crude oil production increased 22 percent in 2003, from $23.75 per barrel in 2002 to $28.87 per barrel in 2003. Normal field declines and some operating interruptions in 2003 were mostly offset by increased production from the Borealis satellite field, the new Kuparuk Palm drill site, and Alpine, which enabled us to experience only a slight decrease in our Alaska crude oil production rate in 2003.

Our E&P Lower 48 net income increased $643 million in 2003, primarily because of increased natural gas production and sales prices, as well as, to a lesser extent, higher crude oil production and prices. U.S. Lower 48 natural gas prices increased 71 percent in 2003. Our increased production volumes in the Lower 48 mainly were the result of the merger, partially offset by the impact of asset dispositions. We continued our Lower 48/Gulf of Mexico asset rationalization program in 2003, which resulted in the sale of properties that did not fit into our long-term growth strategy. As planned, we are exiting the shallow water areas of the Gulf of Mexico. The Lower 48 operations recognized a net $1 million charge from the cumulative effect of adopting SFAS No. 143 and FIN 46 effective January 1, 2003.

2002 vs. 2001

Net income from U.S. E&P operations decreased 14 percent in 2002, compared with 2001. Although net income for 2002 benefited from four months of increased production volumes following the merger, this increase was more than offset by lower natural gas prices, lower production volumes in Alaska, and higher dry hole costs. Our U.S. average natural gas price in 2002 was 23 percent lower than in 2001.

Our U.S. crude oil production decreased slightly in 2002, while natural gas production increased 20 percent. The increase in natural gas production was mainly due to four months of production from fields acquired in the merger. The merger impact on total crude oil production was offset by lower production in Alaska, which experienced normal field declines, along with operating interruptions at the Prudhoe Bay field.

International E&P

2003 vs. 2002

Net income from our international E&P operations increased 225 percent in 2003, compared with 2002. Increased production volumes following the merger accounted for the majority of the earnings improvement. Higher crude oil and natural gas prices contributed to the remaining increase.

International E&P’s production on a barrel-of-oil-equivalent basis averaged 916,000 barrels per day in 2003, compared with 482,000 barrels per day in 2002. In addition, our Syncrude mining operations produced 19,000 barrels per day in 2003, compared with 8,000 barrels per day in 2002. Although the merger was the primary reason for the production increase, other items impacting our production rate in 2003 were:

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Included in international E&P’s net income in 2003 was a net foreign currency transaction loss of $50 million, compared with a net loss of $34 million in 2002.

International E&P’s net income in 2003 also was favorably impacted by the following items:

2002 vs. 2001

Net income from international E&P operations increased 66 percent in 2002. The improvement reflects four months of increased production volumes following the merger. However, 2002 net income included a $24 million deferred tax charge related to tax law changes in the United Kingdom. Net income in 2002 also included a $77 million leasehold impairment of deepwater Block 34, offshore Angola, due to an unsuccessful exploratory well in the block, along with higher dry hole charges.

Our international crude oil production increased 64 percent in 2002, while natural gas production increased 126 percent. The increases were mainly due to the addition of four months of production from fields acquired in the merger.

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Midstream

2003 vs. 2002

The Midstream segment purchases raw natural gas from producers and gathers natural gas through extensive pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel, or blendstock.

Our Midstream segment consists of a 30.3 percent interest in Duke Energy Field Services, LLC (DEFS), as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses, primarily in the United States, Canada and Trinidad.

Net income from the Midstream segment increased 136 percent in 2003, compared with 2002. The increase primarily was attributable to improved results from DEFS and the addition of midstream operations following the merger. DEFS’ results mainly increased because of higher natural gas liquids prices in 2003. In addition, DEFS’ results in 2002 included higher costs for gas imbalance adjustment accruals.

Included in the Midstream segment’s 2003 net income was a basis-difference benefit of $36 million, compared with $35 million in 2002, representing the amortization of the excess amount of our 30.3 percent equity interest in the net assets of DEFS over the book value of our investment in DEFS.

2002 vs. 2001

Net income from the Midstream segment decreased 54 percent in 2002, compared with 2001. The decrease was primarily due to lower results from DEFS, which experienced a decline in natural gas liquids prices, increased costs for gas imbalance accruals and other adjustments, and higher operating expenses.

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These items were partially offset by the benefit of four months’ results from operations acquired in the merger.

Included in the Midstream segment’s net income in 2002 was a benefit of $35 million, representing the amortization of the basis difference between the book value of ConocoPhillips’ contribution to DEFS and our 30.3 percent equity interest in DEFS. The corresponding amount for 2001 was $36 million.

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R&M

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2003 vs. 2002

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

Net income from our R&M segment increased substantially in 2003, compared with 2002. The improved results primarily were due to significantly higher U.S. refining margins. The addition of refining and marketing assets in the merger also contributed to the higher 2003 earnings, as did increased wholesale gasoline margins. Partially offsetting the improvements was a net charge of $125 million for the cumulative effect of the adoption of FIN 46 for variable interest entities involving synthetic leases and certain other financing structures.

Our refineries produced 2.7 million barrels per day of petroleum products in 2003, compared with 2.0 million barrels per day in 2002. The increase reflects the addition of production from refineries acquired in the merger.

2002 vs. 2001

Net income from the R&M segment declined 64 percent in 2002, compared with 2001, reflecting lower refining margins, along with an $84 million after-tax impairment of a tradename and leasehold improvements of certain retail sites. R&M earnings for 2002 included four months’ results from operations acquired in the merger, as well as the impact of a full year’s results from Tosco operations, while the 2001 results included Tosco operations for only the last three and one-half months of 2001.

Worldwide crude oil refining capacity utilization was 90 percent in 2002, compared with 94 percent in 2001. Our refineries produced 2.0 million barrels per day of petroleum products in 2002, compared with 814,000 barrels per day in 2001. The increase reflects a full year of operations for refineries acquired in the Tosco acquisition and four months of operations for the refineries acquired in the merger.

U.S. R&M

2003 vs. 2002

Net income from our U.S. R&M operations increased significantly in 2003, compared with 2002. The improved results mainly were due to significantly higher refining margins, particularly during the third quarter of 2003. Industry U.S. refining margins were strong in the third quarter of 2003 due to increased gasoline demand in August and an unusual number of refined product supply disruptions, including refinery outages in the Midwest caused by a major power blackout in August 2003. See the “Outlook” section for additional discussion of refining margins. We capitalized on the strong refining margins in the third quarter by running our U.S. refineries at a utilization rate of 96 percent during the quarter. However, this rate was negatively impacted by a fire at our Ponca City, Oklahoma, refinery during July that resulted in portions of the facility being shut down. The Ponca City refinery’s throughput was restored in the fourth quarter of 2003 to levels achieved before the fire.

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The addition of refining and marketing assets in the merger also contributed to the higher 2003 earnings, as did increased wholesale gasoline margins. Partially offsetting the margin improvements in 2003 was a net charge of $125 million for the cumulative effect of the adoption of FIN 46 for variable interest entities involving synthetic leases and certain other financing structures, along with higher utility costs.

For the full year of 2003, our U.S. refineries ran at a crude oil capacity utilization rate of 96 percent, compared with 91 percent in 2002. The rate in 2002 was lowered by higher maintenance turnaround activity, the impact of tropical storms on our Gulf Coast refineries, and the loss of Venezuelan crude oil supply in the fourth quarter due to the economic and political instability in that country during the quarter.

2002 vs. 2001

Net income from U.S. R&M operations declined 65 percent in 2002, compared with 2001. The decrease was primarily due to lower refining margins, particularly in the Midcontinent and Gulf Coast regions, along with an $84 million after-tax impairment of a tradename and leasehold improvements of certain retail sites. These items were partially offset by increased production and sales volumes as a result of the Tosco acquisition and the merger. Net income for 2002 included four months of operations acquired in the merger, and a full year of Tosco operations, while the 2001 results included Tosco operations for only three and one-half months. Effective January 1, 2001, we changed our method of accounting for the costs of major maintenance turnarounds from the accrue-in-advance method to the expense-as-incurred method. The cumulative effect of this change in accounting principle increased R&M net income by $26 million. Also included in 2001 was a $27 million write-down of inventories to market value.

International R&M

2003 vs. 2002

Net income from our international R&M operations increased substantially in 2003, compared with 2002. The improvement was due to the larger size and scope of our international refining and marketing operations following the merger, along with higher international refining margins. Prior to the merger, our international R&M operations consisted only of our Whitegate refinery in Ireland with a rated crude oil capacity of 72,000 barrels per day. The merger added one wholly owned and four joint-venture refineries, with a rated crude oil capacity of 370,000 barrels per day. In addition, the merger added an extensive marketing network throughout Europe and Asia. Included in international R&M’s net income in 2003 was a net foreign currency gain of $18 million, compared with a net gain of $9 million in 2002.

Our international crude oil capacity utilization rate was 87 percent in 2003, compared with 78 percent in 2002. The lower utilization rate in 2002 primarily was the result of the Humber refinery in the United Kingdom being shut down for an extended period of time in the fourth quarter due to a power outage and subsequent downtime.

2002 vs. 2001

Net income from international R&M operations increased $3 million in 2002, compared with 2001, reflecting the impact of the merger. The Humber refinery was shut down for an extended period of time during the fourth quarter of 2002, which negatively impacted international R&M’s 2002 results.

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Chemicals

2003 vs. 2002

The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem), which we account for using the equity method of accounting. 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.

As the results in both years indicate, the chemicals industry continues to be challenged to effectively utilize capacity, manage costs and improve margins in a difficult economic environment. The worldwide chemicals industry experienced an economic downturn beginning in the second half of 2000, and the downturn continued through 2003. The downturn has led to excess production capacity in the industry and pressured margins on key products. The chemicals industry has also been impacted by high energy prices, which negatively impacts both utility and feedstock costs.

2002 vs. 2001

The Chemicals segment incurred a net loss of $14 million in 2002, compared with a net loss of $128 million in 2001. Higher margins in 2002 contributed to the improvement in results. Lower operating expenses, feedstock costs and energy prices in 2002 were partially offset by decreased sales prices.

Due to depressed economic conditions in the chemicals industry, asset retirements and impairments totaling $84 million after-tax were recognized by CPChem in 2001. A developmental reactor at the Pasadena Plastics Complex in Pasadena, Texas, was retired; accelerated depreciation was recognized by CPChem on two polyethylene reactors at the Orange chemical plant in Orange, Texas; an ethylene unit was retired at the Sweeny complex in Old Ocean, Texas; an equity affiliate of CPChem recorded a property impairment related to a polypropylene facility; property impairments were taken on the manufacturing facility in Puerto Rico; and the benzene and cyclohexane units at the Puerto Rico facility were retired. In addition, the valuation allowance on the Puerto Rico facility’s deferred tax asset related to its net operating losses was increased in 2001 so that the deferred tax assets were fully offset by valuation allowances. Partially offsetting these impairments and retirements was a business interruption insurance settlement recognized by CPChem, and a favorable deferred tax adjustment recorded by ConocoPhillips related to the Puerto Rico facility, together totaling $57 million after-tax.

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Emerging Businesses

2003 vs. 2002

The Emerging Businesses segment includes the development of new businesses outside our traditional operations. Emerging Businesses incurred a net loss of $99 million in 2003, compared with a net loss of $310 million in 2002. The net loss in 2003 was less than that in 2002 as a result of a $246 million write-off of purchased in-process research and development costs in the third quarter of 2002 related to Conoco’s natural gas-to-liquids and other technologies. In accordance with FASB Interpretation No. 4, “Applicability of FASB Statement No. 2 to Business Combinations Accounted for by the Purchase Method,” value assigned to research and development activities in the purchase price allocation that have no alternative future use are required to be charged to expense at the date of the consummation of the combination. The $246 million charge was the same on both a before-tax and after-tax basis, because there was no tax basis in the assigned value prior to its write-off.

2002 vs. 2001

The Emerging Businesses segment posted a net loss of $310 million in 2002, compared with a net loss of $12 million in 2001. Results for 2002 included a $246 million write-off of acquired in-process research and development costs described above. The increased number of developing businesses after the merger also contributed to the larger losses in 2002.

Corporate and Other

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2003 vs. 2002

Net interest after-tax represents interest expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 53 percent in 2003, compared with 2002. The increase in 2003 mainly was due to our higher debt levels following the merger, the impact of the adoption of FIN 46 for variable interest entities involving synthetic leases and certain other financing structures, and increased premiums on the early retirement of debt. The adoption of FIN 46 at January 1, 2003, increased debt, which resulted in higher interest expense. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for additional information.

After-tax corporate general and administrative expenses were the same in 2003 as in 2002. Expenses in 2003 were impacted by the merger, as well as the expensing of stock options. Beginning in 2003, on a prospective basis, we elected to use the fair-value accounting method provided for under SFAS No. 123, “Accounting for Stock-Based Compensation.” Offsetting these items were increased allocations of certain staff costs to the operating segments in 2003. The increased corporate allocations did not have a material impact on the operating segments’ results.

Income from discontinued operations was $237 million in 2003, compared with a loss of $993 million in 2002. The net loss in 2002 reflects charges totaling $1,008 million after-tax related to the impairment of properties, plants and equipment; goodwill; intangible assets; and provisions for losses associated with various operating lease commitments. For additional information about our discontinued operations, see Note 4—Discontinued Operations, in the Notes to Consolidated Financial Statements.

On an after-tax basis, merger-related costs were $223 million in 2003, compared with $307 million in 2002. Included in these costs were employee relocation expenses, transition labor costs, and other charges directly associated with the merger.

The category “Other” consists primarily of items not directly associated with the operating segments on a stand-alone basis, including certain foreign currency transaction gains and losses, and environmental costs associated with sites no longer in operation. Results from Other were improved in 2003 because of higher foreign currency transaction gains and an after-tax gain of $34 million in the first quarter of 2003, representing beneficial interests we had in certain insurance companies as a result of the conversion of those companies from mutual companies to stock companies, a process known as demutualization. These beneficial interests arose from our prior purchase and ownership of various insurance policies and contracts issued by the mutual companies. Prior to the demutualizations, our mutual ownership interests in these insurance companies were not recognized because the ownership interests in the mutual companies were neither capable of valuation nor marketable. Included in Other in 2003 was a net foreign currency transaction gain of $67 million, after-tax, compared with a net gain of $21 million in 2002.

2002 vs. 2001

Corporate and Other’s net loss was $1,918 million in 2002, compared with $415 million in 2001. The increased net loss in 2002 reflects losses from discontinued operations, primarily due to impairments, and merger-related costs. Net interest expense and corporate general and administrative costs were also higher in 2002 due to the merger.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

To meet our liquidity requirements, including funding our capital program, paying dividends and repaying debt, we look to a variety of funding sources, primarily cash generated from operating activities. During 2003, available cash was used to support the company’s ongoing capital expenditures program, repay debt and pay dividends. In October 2003, our Board of Directors (Board) declared a dividend of $.43 per share, payable December 1, 2003, which represented a 7.5 percent increase from the previous quarter’s dividend rate. Total dividends paid on our common stock in 2003 was $1.1 billion. During 2003, cash and cash equivalents increased $183 million to $490 million.

Significant Sources of Capital

Operating Activities
During 2003, cash of $9,356 million was provided by operating activities, an increase of $4,378 million from 2002. The increase in cash provided by operating activities was primarily due to:

In addition, working capital changes increased cash flow from operating activities $589 million in 2003, compared with an increase of $982 million in 2002. Cash from operating activities provided by discontinued operations amounted to $189 million, compared with $202 million in 2002.

Asset Sales
Following the merger, we initiated an asset disposition program to sell approximately $3 billion to $4 billion of assets by the end of 2004. Through year-end 2003, we had sold approximately $3.4 billion of assets and raised our target to $4.5 billion by year-end 2004. In February 2004, we sold our 46.7 percent interest in Petrovera Resources Limited, which primarily produced conventional heavy oil in Western Canada. Additional assets expected to be sold in 2004 are primarily related to our marketing

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business. In addition, we are proceeding with plans to dispose of some of our non-DEFS Midstream assets. During 2003, $2.7 billion was received from the sale of various assets, including the remaining assets required to be sold by the Federal Trade Commission as a result of the merger, a substantial portion of our U.S. retail marketing sites, and non-strategic E&P properties. Proceeds from these asset sales have been, and will be, used primarily to pay off debt.

Commercial Paper and Credit Facilities
While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our operating cash flows remain exposed to the volatility of commodity crude oil and natural gas prices and refining and marketing margins, as well as periodic cash needs to finance tax payments and crude oil, natural gas and petroleum product purchases. Our primary funding source for short-term working capital needs is a $4 billion commercial paper program, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). Commercial paper maturities are generally limited to 90 days. At December 31, 2003, we had $709 million of commercial paper outstanding, compared with $1,517 million of commercial paper outstanding at December 31, 2002, of which $206 million was denominated in foreign currencies.

Effective October 14, 2003, we entered into two new revolving credit facilities to replace our previously existing $2 billion 364-day facility that expired on that same date. The new revolving credit facilities consist of a $1.5 billion 364-day facility and a $500 million five-year facility. We also have two revolving credit facilities totaling $2 billion expiring in October 2006. There were no outstanding borrowings under these facilities at December 31, 2003. These credit facilities support the company’s $4 billion commercial paper program. In addition, one of our Norwegian subsidiaries has two $300 million revolving credit facilities that expire in June 2004, under which no borrowings were outstanding at December 31, 2003.

Moody’s Investor Service has maintained a rating of A3 on our senior long-term debt; and Standard and Poors’ Rating Service and Fitch have maintained ratings of A-. We do not have any ratings triggers on any of our corporate debt that would cause an automatic event of default in the event of a downgrade of our credit rating and thereby impact our access to liquidity. In the event that our credit rating deteriorated to a level that would prohibit us from accessing the commercial paper market, we would still be able to access funds under our $4.6 billion revolving credit facilities. Based on our year-end commercial paper balance of $709 million, we had access to $3.9 billion in borrowing capacity as of December 31, 2003, which provides ample liquidity to cover daily operations.

Shelf Registration
In late 2002, we filed a universal shelf registration statement with the U.S. Securities and Exchange Commission for various types of debt and equity securities. As a result, we have available to issue and sell a total of $5 billion of various types of securities under the universal shelf registration statement.

Minority Interests
At December 31, 2003, we had outstanding $842 million of equity held by minority interest owners, including a net minority interest of $496 million in Ashford Energy Capital S.A. and a $141 million net minority interest in Conoco Corporate Holdings L.P.

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Receivables Factoring
At December 31, 2003 and 2002, we also had sold $226 million and $264 million, respectively, of receivables under factoring arrangements. We retained servicing responsibility for these sold receivables, which gives us certain benefits, the fair value of which approximates the fair value of the liability incurred for continuing to service the receivables. See Note 15—Sales of Receivables, in the Notes to Consolidated Financial Statements, for additional information.

Off-Balance Sheet Arrangements

Receivables Monetization
At December 31, 2002, certain credit card and trade receivables had been sold to two Qualifying Special Purpose Entities (QSPEs) in revolving-period securitization arrangements. These arrangements provided for us to sell, and the QSPEs to purchase, certain receivables and for the QSPEs to then issue beneficial interests of up to $1.5 billion to five bank-sponsored entities. All five bank-sponsored entities are multi-seller conduits with access to the commercial paper market and purchase interests in similar receivables from numerous other companies unrelated to us. We have no ownership interests, nor any variable interests, in any of the bank-sponsored entities. As a result, we do not consolidate any of these entities. Furthermore, we do not consolidate the QSPEs because they meet the requirements of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” to be excluded from the consolidated financial statements of ConocoPhillips.

During 2003, we purchased from the bank-sponsored entities the senior interests of one of our two existing QSPEs and discontinued selling receivables to it. We have consolidated this QSPE since acquiring the senior interests. Also during 2003, the third-party beneficial interest holders approved amendments to the other QSPE to increase the amount of third-party beneficial interests that can be issued to $1.2 billion. These changes resulted in a net reduction of the maximum level of senior beneficial interests that can be issued to third-party beneficial interest holders from $1.5 billion to $1.2 billion. At December 31, 2003

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and 2002, we had sold accounts receivable of $1.2 billion and $1.3 billion, respectively. The receivables transferred to the QSPE meets the isolation requirements and other requirements of SFAS No. 140 to be accounted for as sales. Accordingly, receivables transferred to the QSPEs were accounted for as sales.

We retain beneficial interests in this QSPE that are subordinate to the beneficial interests issued to the bank-sponsored entities. These retained interests, which are reported on the balance sheet in accounts and notes receivable—related parties, were $1.3 billion at both December 31, 2003 and 2002. We also retain servicing responsibility related to the sold receivables, which gives us certain benefits, the fair value of which approximates the fair value of the liability incurred for continuing to service the receivables. The carrying value of the subordinated beneficial interests approximates fair market value due to the short term of the underlying assets, which makes stress testing unnecessary.

Preferred Stock
During 1996 and 1997, we formed two statutory business trusts, Phillips 66 Capital I (Trust I) and Phillips 66 Capital II (Trust II), with ConocoPhillips owning all of the common securities of the trusts. The sole purpose of the trusts was to issue preferred securities to outside investors, investing the proceeds thereof in an equivalent amount of subordinated debt securities of ConocoPhillips. The two trusts were established to raise funds for general corporate purposes. On May 31, 2002, we redeemed all of the outstanding subordinated debt securities held by Trust I, which triggered the redemption of the $300 million of trust preferred securities of Trust I at par value, $25 per share. The redemption was funded by the issuance of commercial paper.

At December 31, 2003, Trust II had $350 million of mandatorily redeemable preferred securities outstanding, whose sole asset was $361 million of ConocoPhillips’ subordinated debt securities, which bear interest at 8 percent. Distributions on the trust preferred securities are paid by the trust with funds from interest payments made by ConocoPhillips on the subordinated debt securities. We made interest payments in 2003 totaling $29 million. In addition, we have guaranteed the payment obligations of the trust on the trust preferred securities to the extent we have made interest payments on the subordinated debt securities. Prior to January 1, 2003, we consolidated Trust II and the mandatorily redeemable preferred securities were presented in the mezzanine section of the balance sheet. The subordinated debt securities and related income statement effects were eliminated in our consolidated financial statements. However, with the adoption of the provisions of FIN 46, effective January 1, 2003, we were required to deconsolidate Trust II, which had the effect of increasing debt by $361 million since the subordinated debt securities were no longer eliminated in consolidation, and removing the mandatorily redeemable preferred securities from our balance sheet. When we redeem the subordinated debt securities, Trust II is required to apply all the redemption proceeds to the immediate redemption of the preferred securities. See Note 2—Changes in Accounting Principles and Note 19—Preferred Stock and Other Minority Interests, in the Notes to Consolidated Financial Statements, for additional information.

Affiliated Companies
As part of our normal ongoing business operations and consistent with normal industry practice, we invest in, and enter into, numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. At December 31, 2003, we were liable for certain contingent obligations under various contractual arrangements as described below.

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Capital Requirements

For information about our capital expenditures and investments, see “Capital Spending” below.

Our balance sheet debt at December 31, 2003, was $17.8 billion. This reflects debt reductions of approximately $4.8 billion during 2003, including accounting changes that increased balance sheet debt approximately $2.8 billion as a result of the adoption of FIN 46. See Note 2—Changes in Accounting Principles and Note 14—Debt, in the Notes to Consolidated Financial Statements, for additional information.

During 2003, we reduced our commercial paper balance outstanding from $1.5 billion at December 31, 2002, to $709 million at December 31, 2003. In 2003, we paid off the following notes and debt facilities as they were called or matured and funded the payments with cash from operating activities and proceeds from asset dispositions:

In October and November 2003, we executed certain interest rate swaps that had the effect of converting $1.5 billion of debt from fixed to floating rate. These swaps qualify for hedge accounting under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities.”

Also during 2003, we issued $79.5 million of tax-exempt bonds and assumed an additional amount of $20 million.

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Contractual Obligations

The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2003:

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Capital Spending

Capital Expenditures and Investments

Our capital spending for continuing operations for the three-year period ending December 31, 2003, totaled $13.6 billion. Spending was primarily focused on the growth of our E&P business, with 76 percent of total spending for continuing operations in this segment. The capital programs of DEFS, our gas gathering, processing and marketing joint-venture company, and CPChem, our chemicals joint-venture company, are intended to be self-funding, and are not reflected in the amounts above.

Including about $500 million in capitalized interest and $400 million that will be funded by minority interests in the Bayu-Undan gas export project, our Board has approved $6.9 billion for capital projects and investments for continuing operations in 2004, a 12 percent increase over our 2003 capital spending of $6.2 billion. We plan to direct 78 percent of our 2004 capital budget to E&P and 19 percent to R&M. The remaining budget will be allocated toward emerging businesses, mainly power generation; and general corporate purposes, with a majority related to global integration of systems. Thirty-eight percent of the budget is targeted for projects in the United States.

E&P

Capital spending for continuing operations for E&P during the three-year period ending December 31, 2003, totaled $10.3 billion. The expenditures over the three-year period supported several key exploration and development projects including:

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Capital expenditures for construction of our Endeavour Class tankers and an additional interest in the Trans-Alaska Pipeline System were also included in the E&P segment.

We have contracted to build, for approximately $200 million each, five double-hulled Endeavour Class tankers for use in transporting Alaskan crude oil to the U.S. West Coast. During 2001, the Polar Endeavour, the first Endeavour Class tanker, entered service. The second tanker, the Polar Resolution, entered service in May 2002 and the third tanker, the Polar Discovery, was delivered for service in September 2003. We expect to add a new Endeavour Class tanker to our fleet in both 2004 and 2005, allowing us to retire older ships and cancel non-operated charters.

In Alaska, we continued development drilling in the Kuparuk, Tabasco and West Sak fields in the Greater Kuparuk Area, Prudhoe Bay satellite fields and the Alpine field. In 2003, we, along with our co-venturers, drilled or participated in 71 new development wells at Greater Prudhoe Bay, 17 new development wells at Greater Kuparuk and five development wells at Alpine. Also in 2003, funds were expended on the Alpine capacity expansion project that is expected to start up in the second half of 2004.

In the Lower 48, we continued to explore and develop our acreage positions in the deepwater Gulf of Mexico, South Texas, the San Juan Basin, the Permian Basin, and the Texas Panhandle. In the Gulf of Mexico, development drilling has been completed in the Magnolia and Princess Phase 1 fields. Sanction for the K2 project development is expected in the first quarter of 2004. Preliminary engineering for Princess Phase 2 and Ursa waterflood is expected to begin in the first quarter of 2004. Magnolia’s tension-leg platform construction is ongoing and first production is expected prior to the end of 2004. In February 2003, we began drilling the Lorien exploration well on Block 199, which was declared a discovery in July. The well has been temporarily suspended pending evaluation of development alternatives. The Voss deepwater exploratory well drilled in Keathley Canyon Block 511 was declared dry in early 2003 and as required was charged against 2002 earnings. The Yorick deepwater exploratory well in Green Canyon Block 435 was declared a dry hole in late 2003.

Onshore capital was focused on natural gas developments in the San Juan Basin of New Mexico and the Lobo Trend of South Texas. In addition, Lower 48 is pursuing select opportunities in its other producing basins.

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In Canada, we continued with development of the Stage III expansion-mining project in the Canadian province of Alberta, which is expected to increase our Canadian Syncrude production. The Aurora Train 2 project (the new mine) started up in late-October 2003. The upgrader expansion project is expected to start up in the second half of 2005. In the fourth quarter of 2003, approval was obtained for our project in Surmont. Our ownership share is 43.5 percent. The Surmont lease covers over 200 square miles. This initial development project is designed to use “steam assisted gravity drainage” technology, with first oil production expected in 2006. In addition to these projects, we also are involved in conventional oil and gas properties in Canada.

During the fourth quarter of 2001, we began production of heavy crude oil from the Hamaca project in Venezuela’s Orinoco Oil Belt. Construction of an upgrader to convert heavy crude oil into a medium-grade crude oil continues. Completion of the upgrader is expected by the end of 2004. We own a 40 percent equity interest in the Hamaca project. Our other heavy-oil project in Venezuela, Petrozuata, incurred capital expenditures in 2003 associated with solids handling and restoration capacity projects, as well as ongoing drilling.

In addition to the Hamaca and Petrozuata developments, we have an interest in the Corocoro oil discovery in Venezuela’s Gulf of Paria West. In April 2003, Venezuelan authorities and co-venturers approved Phase I of the development plan for the Corocoro field. We are the operator of the block. In September 2003, we acquired a 37.5 percent interest in the Gulf of Paria East Block. A portion of the Corocoro discovery extends onto this block. Our interest in the development is 32.2 percent.

In February 2003, Venezuelan authorities granted a 35-year license to ChevronTexaco to appraise and develop Plataforma Deltana Block 2. ChevronTexaco selected us as their minority partner in accordance with the terms of the license, which was approved by the Venezuelan government in late 2003. We now have a 40 percent interest in the project. Plataforma Deltana Block 2 is located to the east of our Corocoro discovery. Block 2 already has a gas discovery on it, and additional drilling is planned for 2004.

In Brazil, we added joint-venture partners for our two deepwater blocks, BM-ES-11 and BM-PAMA-3, and purchased additional seismic data in 2002. In 2003, 3-D seismic results indicated the prospect for BM-ES-11 was below expectations, leading to a write-off of our leasehold investment and the initiation of plans to exit the block. Further evaluation of BM-PAMA-3 is planned for 2004.

In 2003, we continued with several development projects in the U.K. and Norwegian sectors of the North Sea, including the Clair field in the U.K. sector. We expect first production from Clair in late 2004. Late in the third quarter of 2003, we and our co-venturers began oil production from the Grane field in the Norwegian North Sea. Net peak production from proved reserves of approximately 14,000 barrels per day is anticipated in 2005.

We continued the development of the CMS3 area, a single unitized project, comprising five natural gas reservoirs in the southern sector of the U.K. North Sea. Collectively, the fields are known as CMS3 due to their utilization of the production and transportation facilities of our operated Caister Murdoch System (CMS). In September 2002, production commenced from the Hawksley field, followed in the fourth quarter by production at the Murdoch K field. During 2003, McAdam came onstream in the second quarter and Watt began in the fourth quarter. Drilling operations on the final reservoir, Boulton H, are ongoing in 2004. We are the operator of CMS3 and hold a 59.5 percent interest.

In December 2003, our Board approved the development of the Britannia field satellites in the North Sea. A development plan has been submitted for government approval. These satellites are comprised of the Callanish and Brodgar fields. The Callanish field is an oil reservoir, and the Brodgar field is a gas

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condensate reservoir with properties similar to those of Britannia. The fields are planned to be developed jointly via a bridge-linked platform to Britannia, with production startup scheduled for 2007. We are the operator of both fields with an interest of 75 percent in Brodgar and 83.5 percent in Callanish.

Elsewhere in the Norwegian sector of the North Sea, in 2003, we, along with our co-venturers, approved a plan to further develop the Ekofisk Area to increase the recovery of oil and gas from the area by improving the area’s processing capacity and reliability. The Ekofisk growth project consists of two interrelated components: the construction and installation of a new steel wellhead and process platform and an increase in capacity from existing facilities. We expect to complete and install the steel jacket in 2004 and the topsides early in the summer of 2005. Additional production from this development is anticipated to begin in the fall of 2005. We are modifying the existing Ekofisk Complex and four additional platforms to increase processing capacity.

In 2002, we and our co-venturers, in conjunction with the government of the Republic of Kazakhstan, declared the Kashagan field on the Kazakhstan shelf in the north Caspian Sea to be commercial. A development plan for the field was approved by the Republic of Kazakhstan in February 2004. Four of five planned appraisal wells on Kashagan had been successfully completed by the end of 2003. The fifth well is currently being tested. In May 2002, we along with the other remaining co-venturers, completed the acquisition of proportionate interests of two co-venturers' rights, which increased our ownership interest from 7.14 percent to 8.33 percent. In October 2002, we and our co-venturers announced a new hydrocarbon discovery in the Kazakhstan sector of the Caspian Sea. In 2003, a 3-D survey was carried out over the Kalamkas field and an initial appraisal well is planned for 2005.

During 2003, we exercised our pre-emptive rights related to B.G. International’s sale of their share in the North Caspian License that includes the Kashagan field. The transaction is expected to close in 2004, at which time our interest in the license will increase from 8.33 percent to 10.19 percent. In November 2003, we and our co-venturers announced the successful completion of the first offshore exploration wells on the Aktote and Kashagan Southwest prospects. These two wells are located in the Kazakhstan sector of the Caspian Sea in an area adjacent to the Kashagan field. Another exploration well, on the Kairan prospect, completed drilling in 2003 and will be tested in 2004.

In late-December 2002, we began production from Phase I of our Peng Lai 19-3 development located on Block 11/05 in China’s Bohai Bay. During 2003, we continued with planning and design for Phase II of the Peng Lai 19-3 development, which includes multiple wellhead platforms, central processing facilities, and a floating storage and offloading facility. We are developing, in conjunction with Phase II, the Peng Lai 25-6 oil field, located three miles east of Peng Lai 19-3. We also drilled exploration wells on the Peng Lai 19-9 prospect and the Peng Lai 13-1 prospect, which resulted in two discoveries. The Peng Lai 19-9-1 well is located two miles east of the Peng Lai 19-3 oil field, and along with adjacent structures will be a part of the Phase II development.

In the Timor Sea, we continued with development activities associated with the Bayu-Undan gas recycle and gas development projects. We continued to drill future production wells and have installed all major facilities, including two production, processing and living quarters platforms and an unmanned production platform. A multi-product floating, storage and offloading vessel was connected to the production facilities during the fourth quarter of 2003. First liquids production began in February 2004, and full capacity of 62,000 net barrels per day of condensate and natural gas liquids is anticipated to be reached in the third quarter of 2004. An average rate of 23,000 net barrels per day of combined condensate and natural gas liquids is expected for 2004.

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We also have received approval of the gas development plan for the Bayu-Undan project from the Timor Sea Designated Authority, concluded fiscal and legal provisions with the government of Timor Lesté, and executed new production sharing contract (PSC) arrangements with the Designated Authority. The gas development project includes a liquefied natural gas (LNG) plant, including a pipeline to Darwin, Australia. The first LNG cargo from the 3.52 million-ton-per-year facility is scheduled for delivery in early 2006. During the third quarter of 2003, construction of the LNG facility and the pipeline began. In June 2003, we sold what currently equates to a 10.08 percent interest in the unitized Bayu-Undan field; purchased other interests that currently equate to a 2.65 percent interest in the field; sold a 43.3 percent interest in the Bayu-Undan pipeline under construction; and sold a 43.3 percent interest in Darwin LNG Pty Ltd (owner of the LNG plant to be constructed). The net result is that we retain a 56.72 percent controlling interest in the integrated project.

In Vietnam’s Block 15-1, the Su Tu Den Phase I (southwest area) development project was approved in December 2001 and production from this area began in late-October 2003. We also are evaluating the commerciality of the Su Tu Vang fields and the northeast portion of the Su Tu Den field. In November 2003, we announced the completion of a successful exploratory well in the Su Tu Trang field in Block 15-1. Technical evaluation is in progress to assess the reservoir potential of the Su Tu Trang field.

In the third quarter of 2002, we began production from two new wellhead platforms in the Block 15-2 Rang Dong field in Vietnam. 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 is now possible on all three wellhead platforms and gas lift is possible on the N-1 and E-1 wellhead platforms. These facilities became operational in the fourth quarter of 2003.

We continued with the appraisal and development of key gas fields in Indonesia. In 2003, we announced 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. We also 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. In addition, we continue to develop the offshore Belanak and other fields in the Block B PSC in the Natuna Sea, for which a floating production storage and offloading vessel is under construction. The vessel is expected to be completed in the first half of 2005.

In May 2002, initial results showed that the first exploratory well drilled in Block 34, offshore Angola, was a dry hole. In view of this information, we reassessed the fair value of the remainder of the block and determined that our investment in the block was impaired by $77 million, both before- and after-tax. In December 2003, the second exploration well was drilled in Block 34, offshore Angola. The well encountered non-commercial gas and was plugged and abandoned. In view of this information, we fully impaired our remaining investment in the block.

In 2003, we obtained a 40 percent interest in Block 248 and a 20 percent interest in Block 214, both offshore Nigeria. First exploration drilling is planned for Block 248 in the second quarter of 2004.

Other capital spending for E&P during the three-year period ended December 31, 2003, supported:

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2004 Capital Budget

E&P’s 2004 capital budget for continuing operations is $5.4 billion, 19 percent higher than actual expenditures in 2003. Twenty-six percent of E&P’s 2004 capital budget is planned for the United States, with 46 percent of that slated for Alaska.

We have budgeted $628 million for worldwide exploration capital activities in 2004, with 17 percent of that amount, $106 million, allocated to the United States. Outside the United States, significant exploration expenditures are planned in Kazakhstan, Venezuela, the United Kingdom and Norway.

We plan to spend $656 million in 2004 for our Alaskan operations. A majority of the capital spending will fund Prudhoe Bay, Greater Kuparuk and Western North Slope operations—including additional work on the Alpine capacity expansion project, Orion and West Sak field developments—construction of Endeavour Class tankers, and the exploratory activity discussed above.

In the Lower 48, offshore capital expenditures will be focused on the continued development of the Magnolia, Ursa and Princess fields in the deepwater Gulf of Mexico. Onshore capital will focus primarily on developing natural gas reserves within core areas, such as the San Juan Basin of New Mexico and the Lobo Trend of South Texas.

E&P is directing $3.9 billion of its 2004 capital budget to international projects. The majority of these funds will be directed to developing major long-term projects, including the Bayu-Undan liquids and gas development projects in the Timor Sea; the Hamaca heavy-oil project in Venezuela; additional development of oil and gas reserves in offshore Block B and onshore South Sumatra blocks in Indonesia; the second phase of Bohai Bay in China; projects in the Caspian region, including Baku-Tbilisi-Ceyhan pipeline; projects in Canada, including Syncrude, Surmont heavy-oil and the Mackenzie Delta gas development; and the Qatargas 3 LNG facility in Qatar. In addition, funds will be used to expand the company’s positions in the U.K. and Norwegian sectors of the North Sea.

Costs incurred for the years ended December 31, 2003, 2002, and 2001, relating to the development of proved undeveloped oil and gas reserves were $2,002 million, $1,631 million, and $1,423 million, respectively. As of December 31, 2003, estimated future development costs relating to the development of proved undeveloped oil and gas reserves for the years 2004 through 2006 were projected to be $1,767 million, $1,111 million, and $659 million, respectively.

R&M

Capital spending for continuing operations for R&M during the three-year period ending December 31, 2003, was primarily for refinery-upgrade projects to improve product yields, to meet new environmental standards, to improve the operating integrity of key processing units, and to install advanced process control technology, as well as for safety projects. Total capital spending for continuing operations for R&M for the three-year period was $2.4 billion, representing 18 percent of our total capital spending for continuing operations.

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Key projects during the three-year period included:

In early 2003, we completed three major projects: a polypropylene plant at the Bayway refinery in Linden, New Jersey, and both a fluid catalytic cracking unit and a S Zorb unit at the Ferndale, Washington, refinery. The Bayway polypropylene plant utilizes propylene feedstock from the Bayway refinery to make up to 775 million pounds per year of polypropylene. The plant became operational in March 2003. At Ferndale, the fluid catalytic cracking unit significantly improves gasoline production per barrel of crude input and the new S Zorb unit reduces sulfur in gasoline. Both became fully operational in 2003.

Also in 2003, we made investments related to clean fuels, safety and environmental projects throughout our refining system. We completed projects at our refineries in Ponca City, Oklahoma and Roxana, Illinois, to produce the low-sulfur gasoline required by the Environmental Protection Agency (EPA). We also began construction of a new diesel hydrotreater at the Rodeo facility of our San Francisco area refinery that is expected to produce reformulated California highway diesel an estimated one year ahead of the June 2006 deadline.

In July 2003, we completed the acquisition of certain refining assets in Hartford, Illinois, from Premcor. The operations of these assets are being integrated into the operations of our nearby Wood River refinery. The overall production of the refinery will only increase slightly, but integration of the new assets will enable the refinery to process heavier, lower cost crude oil. Startup of the integrated facilities is expected in the second quarter of 2004.

Internationally, we continue to invest in our ongoing refining and marketing operations, including a replacement reformer at our Humber refinery in the United Kingdom and marketing growth in select countries in Europe and Asia.

2004 Capital Budget

R&M’s 2004 capital budget for continuing operations is $1.3 billion, a 9 percent increase over spending of $1.2 billion in 2003. Domestic spending is expected to consume 81 percent of the R&M budget.

We plan to direct about $900 million of the R&M capital budget to domestic refining, primarily to fund clean fuels projects in order to comply with new EPA standards for refined products. Worldwide, clean fuels spending for our R&M business is expected to be about $600 million, or 55 percent of the total refining budget. Our U.S. marketing and transportation businesses are expected to spend about $125 million, while the remaining budget will fund projects in our international refining and marketing businesses in Europe and the Asia Pacific region.

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Emerging Businesses

Capital spending for Emerging Businesses during 2003 was primarily for construction of the Immingham combined heat and power cogeneration plant near the company’s Humber refinery in the United Kingdom. We expect the plant to be operational in mid-2004.

Emerging Businesses’ 2004 capital budget of $62 million is primarily dedicated to the completion of the Immingham plant.

Contingencies

Legal and Tax Matters

We accrue for contingencies when a loss is probable and the amounts can be reasonably estimated. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on the company’s financial statements.

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

Environmental

We are subject to the same numerous international, federal, state, and local environmental laws and regulations, as are other companies in the petroleum exploration and production industry; and refining, marketing and transportation of crude oil and refined products businesses. The most significant of these environmental laws and regulations include, among others, the:

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These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.

Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States. Under the Clean Air Act, the EPA has promulgated a number of stringent limits on air emissions and established a federally mandated operating permit program. Violations of the Clean Air Act and most other environmental laws and regulations in the United States are enforceable with civil and criminal sanctions.

The EPA also has promulgated specific rules governing the sulfur content of gasoline, known generically as the “Tier II Sulfur Rules,” the first phase requirements of which became applicable to our gasoline as of January 2004. To meet the requirements, we are implementing a compliance strategy that relies on the use of a combination of technologies, including our proprietary S Zorb technology.

The EPA also has promulgated rules regarding the sulfur content in highway diesel fuel, which become applicable in 2006. In April 2003, the EPA proposed a rule regarding emissions from non-road diesel engines and limiting non-road diesel fuel sulfur content. If promulgated, this rule would significantly reduce non-road diesel fuel sulfur content limits as early as 2007. We are currently evaluating S Zorb systems for removing sulfur from diesel fuel in special applications. The refining industry is actively considering several advanced and conventional technologies for complying with these rules. Because the non-road rule is not final, we are still evaluating and developing capital strategies for future compliance. Additional areas of potential air-related impact are the proposed revisions to the National Ambient Air Quality Standards (NAAQS) and the Kyoto Protocol. In July 1997, the EPA promulgated more stringent revisions to the NAAQS for ozone and particulate matter. Since that time, final adoption of these revisions has been the subject of litigation (American Trucking Association, Inc. et al. v. United States Environmental Protection Agency) that eventually reached the U.S. Supreme Court during the fall of 2000. In February 2001, the U.S. Supreme Court remanded this matter, in part, to the EPA to address the implementation provisions relating to the revised ozone NAAQS. If adopted, the revised NAAQS could result in substantial future environmental expenditures for us.

In 1997, an international conference on global warming concluded an agreement, known as the Kyoto Protocol, which called for reductions of certain emissions that contribute to increases in atmospheric greenhouse gas concentrations. The United States has not ratified the treaty codifying the Kyoto Protocol

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but may in the future. In addition, other countries where we have interests, or may have interests in the future, have made commitments to the Kyoto Protocol and are in various stages of formulating applicable regulations. Currently, it is not possible to accurately estimate the costs that we could incur to comply with such regulations, but such expenditures could be substantial.

We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require that contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states have adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater. MTBE standards continue to evolve, and future environmental expenditures associated with the remediation of MTBE-contaminated underground storage tank sites could be substantial.

At RCRA permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer term, expenditures are subject to considerable uncertainty and may fluctuate significantly.

We, from time to time, receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2002, we reported we had been notified of potential liability under CERCLA and comparable state laws at 58 sites around the United States. In the 2002 report, sites from Phillips and Conoco were listed separately resulting in eight duplicate listings. These duplicate listings are consolidated in this 2003 report. At December 31, 2003, we had combined the eight duplicate listings, reclassified one existing site, and resolved six sites. Additionally, we had received 16 new notices of potential liability, leaving 61 sites where we have been notified of potential liability.

For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.

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Expensed environmental costs were $593 million in 2003 and are expected to be about $596 million in 2004 and $574 million in 2005. Capitalized environmental costs were $522 million in 2003 and are expected to be about $742 million and $967 million in 2004 and 2005, respectively.

Remediation Accruals

We accrue for remediation activities when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. These accrued liabilities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).

Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we have identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of December 31, 2003.

Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.

At December 31, 2003, our balance sheet included a total environmental accrual related to continuing operations of $1,119 million, compared with $743 million at December 31, 2002. The increase in accruals from year-end 2002, primarily resulted from evaluation of Conoco environmental liabilities during the purchase price allocation period. We expect to incur the majority of these expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse affect upon our results of operations or financial position as a result of compliance with environmental laws and regulations.

Other

We have deferred tax assets related to certain accrued liabilities, alternative minimum tax credits, and loss carryforwards. Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will, more likely than not, be realized. Uncertainties that may affect the realization of these assets include tax law changes and the future level of product prices and costs. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable income. The alternative minimum tax credit can be carried forward indefinitely to reduce our regular tax liability.

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NEW ACCOUNTING DEVELOPMENTS

In December 2003, the FASB revised and reissued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106,” which revises and requires additional disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by previous Financial Accounting Board Standards. We adopted the provisions of this Standard effective December 2003. Certain provisions of this Standard regarding disclosure of information about foreign plans and disclosure of estimated future benefit payments are not required until 2004. The adoption of the provisions applicable to 2003 did not have an impact on our results of operations or financial position, nor will the adoption of the additional provisions in 2004 have an impact on our results of operations or financial position.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” to address the balance sheet classification of certain financial instruments that have characteristics of both liabilities and equity. This statement was immediately effective for all contracts created or modified after May 31, 2003, and became effective July 1, 2003, for all previously existing contracts. On November 7, 2003, the FASB issued FASB Staff Position No. FAS 150-3, which deferred certain provisions of SFAS No. 150. As a result of adopting this new accounting standard in the third quarter of 2003, and the subsequent November 7, 2003, deferral of certain provisions, there was no impact on our 2003 financial statements. We continue to monitor the deferral status of SFAS No. 150.

In June 2001, the FASB issued SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” which became effective on July 1, 2001, and January 1, 2002, respectively. The Securities and Exchange Commission (SEC) has requested the Emerging Issues Task Force (EITF) to consider the issue of whether SFAS Nos. 141 and 142 require interests held under oil, gas and mineral leases to be separately classified as intangible assets on the balance sheets of companies in the extractive industries. Historically, in accordance with SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” we have capitalized the cost of oil and gas leasehold interests and, consistent with industry practice, reported these assets as part of tangible E&P properties, plants and equipment.

If such interests were deemed to be intangible assets by the EITF, mineral rights to extract oil and gas for both proved and unproved properties would be classified separately from E&P properties, plants and equipment as intangible assets on our balance sheet. This interpretation by the EITF would only affect the classification of oil and gas mineral rights on our balance sheet and would not affect total assets, net worth, results of operations or cash flows.

E&P properties, plants and equipment at December 31, 2003 and 2002, included approximately $10.5 billion and $10.8 billion, respectively, of mineral rights to extract oil and gas, net of accumulated depletion, that would be reclassified on the balance sheet as intangible assets, if the interpretation that the SEC requested the EITF to consider was applied. We plan to continue to classify oil and gas mineral rights as E&P properties, plants and equipment until further guidance is provided by the EITF.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1—Accounting Policies

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in the Notes to Consolidated Financial Statements for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting policies are discussed with the Audit and Compliance Committee on an annual basis and are presented below.

Oil and Gas Accounting
Accounting for oil and gas exploratory activity is subject to special accounting rules that are unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet, pending determination of whether proved oil and gas reserves have been discovered on the prospect.

Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense. This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. By the end of the contractual period of the leasehold, the impairment probability percentage will have been adjusted to 100 percent if the leasehold is expected to be abandoned, or will have been adjusted to zero percent if there is an oil or gas discovery that is under development. See the supplemental Oil and Gas Operations disclosures about Costs Incurred and Capitalized Costs for more information about the amounts and geographic locations of costs incurred in acquisition activity, and the amounts on the balance sheet related to unproved properties.

Exploratory Costs
For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a judgmental determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. This judgment usually is made within two months of the completion of the drilling effort, but can take longer, depending on the complexity of the geologic structure. Accounting rules require that this judgment be made at least within one year of well completion. If a judgment is made that the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and are reported in exploration expense. Exploratory wells that are judged to have discovered potentially economic quantities of oil and gas and that are in areas where a major capital expenditure (e.g., a pipeline or offshore platform) would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized on the balance sheet as long as additional exploratory appraisal work is under way or firmly planned. For complicated offshore exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal work on the potential oil and gas field. Unlike leasehold acquisition costs, there is no periodic impairment assessment of suspended exploratory well costs. Management continuously monitors the results of the additional appraisal drilling and seismic work and expenses the suspended well costs as dry holes when it judges that the potential field does not warrant further exploratory efforts in the near term.

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See the supplemental Oil and Gas Operations disclosures about Costs Incurred and Capitalized Costs for more information about the amounts and geographic locations of costs incurred in exploration activity and the amounts on the balance sheet related to unproved properties, as well as the Wells In Progress disclosure for the number and geographic location of wells not yet declared productive or dry.

Proved Oil and Gas Reserves
Engineering estimates of the quantities of recoverable oil and gas reserves in oil and gas fields are inherently imprecise and represent only approximate amounts because of the subjective judgments involved in developing such information. Despite the inherent imprecision in these engineering estimates, accounting rules require supplemental disclosure of “proved” oil and gas reserve estimates due to the importance of these estimates to better understanding the perceived value and future cash flows of a company’s oil and gas operations. The judgmental estimation of proved oil and gas reserves also is important to the income statement because the proved oil and gas reserve estimate for a field serves as the denominator in the unit-of-production calculation of depreciation, depletion and amortization of the capitalized costs for that field. There are several authoritative guidelines regarding the engineering criteria that have to be met before estimated oil and gas reserves can be designated as “proved.” Our reservoir engineering department has policies and procedures in place that are consistent with these authoritative guidelines. We have qualified and experienced internal engineering personnel who make these estimates. Proved reserve estimates are updated annually and take into account recent production and seismic information about each field. Also, as required by authoritative guidelines, the estimated future date when a field will be permanently shut-in for economic reasons is based on an extrapolation of oil and gas prices and operating costs prevalent at the balance sheet date. This estimated date when production will end affects the amount of estimated recoverable reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes.

Canadian Syncrude Reserves
Canadian Syncrude proven reserves cannot be measured precisely. Reserve estimates of Canadian Syncrude are based on subjective judgments involving geological and engineering assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting the bitumen and upgrading it into a light sweet crude oil. Despite the inherent imprecision in these engineering estimates, these estimates are used in determining depreciation expense.

Impairment of Assets
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets, at an entire complex level for downstream assets, or at a site level for retail stores. Because there usually is a lack of quoted market prices for long-lived assets, the fair value usually is based on the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The expected future cash flows used for impairment reviews and related fair-value calculations are based on judgmental assessments of future production volumes, prices and costs, considering all available information at the date of review. See Note 12—Property Impairments, in the Notes to Consolidated Financial Statements, for additional information.

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Asset Retirement Obligations and Environmental Costs
Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at production sites. The largest asset removal obligations facing us involve removal and disposal of offshore oil and gas platforms around the world, and oil and gas production facilities and pipelines in Alaska. The estimated discounted costs of dismantling and removing these facilities are accrued at the installation of the asset. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria will have to be met when the removal event actually occurs. Asset removal technologies and costs are constantly changing, as well as political, environmental, safety and public relations considerations. See Note 1—Accounting Policies and Note 13—Asset Retirement Obligations and Accrued Environmental Costs, in the Notes to Consolidated Financial Statements, for additional information.

Business Acquisitions

Purchase Price Allocation
Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business. For most assets and liabilities, purchase price allocation is accomplished by recording the asset or liability at its estimated fair value. The most difficult estimations of individual fair values are those involving properties, plants and equipment and identifiable intangible assets. We use all available information to make these fair value determinations and, for major business acquisitions, typically engage an outside appraisal firm to assist in the fair value determination of the acquired long-lived assets. We have, if necessary, up to one year after the acquisition closing date to finish these fair value determinations and finalize the purchase price allocation.

Intangible Assets and Goodwill
In connection with the acquisition of Tosco Corporation on September 14, 2001, and the merger on August 30, 2002, we recorded material intangible assets for tradenames, air emission permit credits, and permits to operate refineries. These intangible assets were determined to have indefinite useful lives and so are not amortized. This judgmental assessment of an indefinite useful life has to be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines that these intangible assets then have definite useful lives, amortization will have to commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to periodic lower-of-cost-or-market tests, which requires management’s judgment of the estimated fair value of these intangible assets. See Note 6—Acquisition of Tosco Corporation, Note 3—Merger of Conoco and Phillips, and Note 12—Property Impairments, in the Notes to Consolidated Financial Statements, for additional information.

Also in connection with the acquisition of Tosco and the merger, we recorded a material amount of goodwill. Under the accounting rules for goodwill, this intangible asset is not amortized. Instead, goodwill is subject to annual reviews for impairment based on a two-step accounting test. The first step is to compare the estimated fair value of any reporting units within the company that have recorded goodwill with the recorded net book value (including the goodwill) of the reporting unit. If the estimated fair value of the reporting unit is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required that year. If, however, the estimated fair value of the reporting unit is below the recorded net book value, then a second step must be performed to determine the amount of the goodwill impairment to record, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical new acquisition of the reporting unit. The various purchase business combination rules are followed to determine a hypothetical purchase price allocation for the reporting

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unit’s assets and liabilities. The residual amount of goodwill that results from this hypothetical purchase price allocation is compared with the recorded amount of goodwill for the reporting unit, and the recorded amount is written down to the hypothetical amount if lower. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment. A component is a reporting unit if the component constitutes a business for which discrete financial information is available and segment management regularly reviews the operating results of that component. However, two or more components of an operating segment shall be aggregated and deemed a single reporting unit if the components have similar economic characteristics. We have determined that we have three reporting units for purposes of assigning goodwill and testing for impairment. These are Worldwide Exploration and Production, Worldwide Refining and Worldwide Marketing. Our Midstream, Chemicals and Emerging Businesses operating segments were not assigned any goodwill from the merger because the two predecessor companies’ operations did not overlap in these operating segments so we were unable to capture significant synergies and strategic advantages from the merger in these areas.

In our Exploration and Production operating segment, management reporting is primarily organized based on geographic areas. All of these geographic areas have similar business processes, distribution networks and customers, and are supported by a worldwide exploration team and shared services organizations. Therefore, all components have been aggregated into one reporting unit, Worldwide Exploration and Production, which is the same as the operating segment. In contrast, in our Refining and Marketing operating segment, management reporting is primarily organized based on functional areas. Because the two broad functional areas of Refining and Marketing have dissimilar business processes and customers, we concluded that it would not be appropriate to aggregate these components into only one reporting unit at the Refining and Marketing operating segment level. Instead, we have identified two reporting units within the operating segment: Worldwide Refining and Worldwide Marketing. Components in those two reporting units have similar business processes, distribution networks and customers. If we later reorganize our businesses or management structure so that the components within these three reporting units are no longer economically similar, the reporting units would be revised and goodwill would be re-assigned using a relative fair value approach in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” Goodwill impairment testing at a lower reporting unit level could result in the recognition of impairment that would not otherwise be recognized at the current higher level of aggregation. In addition, the sale or disposition of a portion of these three reporting units will be allocated a portion of the reporting unit’s goodwill, based on relative fair values, which will adjust the amount of gain or loss on the sale or disposition.

Because quoted market prices for our reporting units are not available, management has to apply judgment in determining the estimated fair value of these reporting units for purposes of performing the first step of the periodic goodwill impairment test. Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and observed market multiples of operating cash flows and net income, and may engage an outside appraisal firm for assistance. In addition, if the first test step is not met, further judgment has to be applied in determining the fair values of individual assets and liabilities for purposes of the hypothetical purchase price allocation. Again, management has to use all available information to make these fair value determinations and may engage an outside appraisal firm for assistance. At year-end 2003, the estimated fair values of our Worldwide Exploration and Production, Worldwide Refining, and Worldwide Marketing reporting units, excluding those included in discontinued operations, ranged from between 15 percent to 35 percent higher than recorded net book values (including goodwill) of the reporting units. However, a lower fair value estimate in the future for any of these reporting units could result in impairment of the $15.1 billion of goodwill.

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Inventory Valuation
Prior to the acquisition of Tosco in September 2001 and the merger in August 2002, our inventories on the last-in, first-out (LIFO) cost basis were predominantly reflected on the balance sheet at historical cost layers established many years ago, when price levels were much lower. Therefore, prior to 2001, our LIFO inventories were relatively insensitive to current price level changes. However, the acquisition of Tosco and the ConocoPhillips merger added LIFO cost layers that were recorded at replacement cost levels prevalent in late September 2001 and August 2002, respectively. As a result, our LIFO cost inventories are now much more sensitive to lower-of-cost-or-market impairment write-downs, whenever price levels fall. We recorded a LIFO inventory lower-of-cost-or-market impairment in the fourth quarter of 2001 due to a crude oil price deterioration. While crude oil is not the only product in the company’s LIFO pools, its market value is a major factor in lower-of-cost-or-market calculations. We estimate that additional impairments could occur if a 60 percent/40 percent blended average of West Texas Intermediate/Brent crude oil prices falls below $21.25 per barrel at a reporting date. The determination of replacement cost values for the lower-of-cost-or-market test uses objective evidence, but does involve judgment in determining the most appropriate objective evidence to use in the calculations.

Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. This also impacts the required company contributions into the plans. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations. For Employee Retirement Income Security Act-qualified pension plans, the actuary exercises fiduciary care on behalf of plan participants in the determination of the judgmental assumptions used in determining required company contributions into plan assets. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A 1 percent decrease in the discount rate would increase annual benefit expense by $85 million, while a 1 percent decrease in the return on plan assets assumption would increase annual benefit expense by $25 million.

OUTLOOK

After adjusting for asset dispositions, E&P’s worldwide production for 2004 is expected to be about the same level as it was in 2003. The dispositions contributed approximately 37,000 barrels of oil equivalent per day to 2003 production. For 2004, production increases in Asia Pacific and Latin America are expected to offset net declines in the United States, Canada and the North Sea.

In R&M, the optimization of spending related to clean fuels project initiatives will be an important focus area during 2004. In addition, we expect our average refinery crude oil utilization rate for 2004 to average about the same as in 2003.

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Crude oil and natural gas prices are subject to external factors over which we have no control, such as global economic conditions, political events, demand growth, inventory levels, weather, competing fuels prices, and availability of supply. Crude oil prices rose significantly in 2003 due to supply disruptions during the year in several producing countries and the delays in the return of Iraqi crude production to the market in the face of rising global oil demand. As a result of these factors, global oil inventories remained at exceptionally low levels throughout 2003. Low oil inventories, coupled with economic recovery and the prospects for higher oil demand growth are expected to keep prices elevated through the first half of 2004. U.S. natural gas prices weakened moderately during the second half of 2003 from the very strong levels experienced during the second quarter, but the annual average was significantly higher in 2003 versus 2002. Prices weakened in the second half due to a strong buildup of natural gas inventories during the summer and early fall, as mild weather, weak industrial demand and fuel switching reduced natural gas demand. At the same time, high prices and the startup of a mothballed regasification terminal increased LNG imports to the United States. However, natural gas prices rose moderately in December, reflecting continuing concerns about the adequacy of gas supplies in the United States. Supply adequacy concerns are expected to keep prices above historical levels in 2004.

Refining margins are subject to movements in the price of crude oil and other feedstocks, and the prices of petroleum products, which are subject to market factors over which we have no control, such as the U.S. and global economies; government regulations; military, political and social conditions in oil producing countries; seasonal factors that affect demand, such as the summer driving months; and the levels of refining output and product inventories. U.S. and international refining and marketing margins rose in 2003 versus 2002, due to improved refined product demand and a series of supply disruptions. U.S. refining margins were above the five-year historical average in 2003 as a result of refinery outages in several regions of the United States, a product pipeline rupture in Arizona, and labor strikes in Venezuela, which removed both crude and refined products from the market. Combined with strong product demand, product inventories were drawn down to extremely low levels in the first half of the year, which elevated refining margins. Stronger demand in the face of tight supplies also improved marketing margins in 2003 versus 2002. The sustainability of current refining and marketing margins depends on the continued recovery of the global economy and refined product demand growth.

In February 2003, the Venezuelan government implemented a currency exchange control regime. The government has published legal instruments supporting the controls, one of which establishes official exchange rates for the U.S. dollar. The devaluation of the Venezuelan currency by approximately 17 percent in February 2004 did not have a significant impact on our Venezuelan operations; however, future changes in the exchange rate could have a significant impact on our Venezuelan operations. In addition, our Venezuelan operations remain subject to civil unrest in the country. Our Venezuelan operations contributed approximately $150 million to our 2003 net income.

In June 2003, we and our co-venturers in the Mackenzie gas project in Canada announced that funding and participation agreements have been reached and a preliminary information package was submitted to relevant regulatory authorities. The Mackenzie gas project involves natural gas production facilities, compression and gathering pipelines in the Mackenzie Delta area, and a pipeline system in the Mackenzie River Valley. The filing of the information package is a key step in the process leading to the submission of applications for the development of the natural gas fields and pipeline facilities. Regulatory applications are expected to be filed in 2004. First gas production is currently targeted to commence in late 2009.

In July 2003, we signed a Heads of Agreement with Qatar Petroleum for the development of Qatargas 3, a large-scale LNG project located in Qatar and servicing the U.S. natural gas market. This provides the framework for the necessary agreements and the completion of key feasibility studies. Qatargas 3 would be an integrated project, jointly owned by us and Qatar Petroleum, consisting of facilities to produce and liquefy gas from Qatar’s North field. The LNG would be shipped from Qatar, and we would be

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responsible for regasification and marketing within the United States. Average daily gas sales volumes are projected to be approximately 1 billion cubic feet per day with startup anticipated in the 2009 timeframe.

In late October 2003, we signed a Heads of Agreement with the Nigerian National Petroleum Corporation, ENI and ChevronTexaco to conduct front-end engineering and design work for an LNG facility to be constructed in Nigeria’s central Niger Delta. The participants have agreed to form an incorporated joint venture, Brass LNG Limited, to undertake the project. The engineering and design studies are expected to be completed in 2005, and the facility is targeted to be operational in 2009.

In December 2003, we signed a Statement of Intent with Qatar Petroleum regarding the construction of a gas-to-liquids plant in Ras Laffan, Qatar. The Statement of Intent initiates detailed technical and commercial pre-front-end engineering and design studies and establishes principles for negotiating a Heads of Agreement for an integrated reservoir-to-market plant. More definite agreements are expected in 2004.

Also in December 2003, we announced the signing of an agreement with Freeport LNG Development, L.P. to participate in its proposed LNG receiving terminal in Quintana, Texas. We would acquire 1 billion cubic feet per day of regasification capacity in the terminal for our use and obtain 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.

In addition, we and our co-venturer are pursuing a proposed LNG receiving terminal in Harpswell, Maine. The proposal calls for construction of the terminal at a site previously used as a U.S. Navy fuel depot. LNG would be converted back to natural gas at the terminal for delivery through a new pipeline that would connect the terminal to the existing pipeline grid. Depending on receipt of the necessary regulatory approvals, construction could begin in 2006, with the facility operational by 2009.

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This annual report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements can be identified by the words “expects,” “anticipates,” “intends,” “plans,” “projects,” “believes,” “estimates” and similar expressions.

We have based the forward-looking statements relating to our operations on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you that these statements are not guarantees of future performance and involve risks, uncertainties and assumptions that we cannot predict. In addition, we have based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcome and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:

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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Financial Instrument Market Risk

We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose cash flows or earnings to changes in commodity prices, foreign exchange rates or interest rates. We may use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of electric power, natural gas, crude oil and related products, fluctuations in interest rates and foreign currency exchange rates, or to exploit market opportunities.

Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient liquidity for comparable valuations without approval from the Chief Executive Officer. The Authority

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Limitations document also authorizes the Chief Executive Officer to establish the maximum Value at Risk (VaR) limits for the company and compliance with these limits is monitored daily. The Chief Financial Officer monitors risks resulting from foreign currency exchange rates and interest rates, while the Executive Vice President of Commercial monitors commodity price risk. Both report to the Chief Executive Officer. The Commercial group manages our commercial marketing, optimizes our commodity flows and positions, monitors related risks of our upstream and downstream businesses, and selectively takes price risk to add value.

Commodity Price Risk

We operate in the worldwide crude oil, refined products, natural gas, natural gas liquids, and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing, and financing activities. Generally, our policy is to remain exposed to market prices of commodities; however, executive management may elect to use derivative instruments to hedge the price risk of our crude oil and natural gas production, as well as refinery margins.

Our Commercial group uses futures, forwards, swaps, and options in various markets to optimize the value of our supply chain, which may move our risk profile away from market average prices to accomplish the following objectives:

We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative commodity instruments held or issued, including commodity purchase and sales contracts recorded on the balance sheet at December 31, 2003, as derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period, the VaR for those instruments issued or held for trading purposes at December 31, 2003 and 2002, was immaterial to our net income and cash flows. The VaR for instruments held for purposes other than trading at December 31, 2003 and 2002, was also immaterial to our net income and cash flows.

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Interest Rate Risk

The following tables provide information about our financial instruments that are sensitive to changes in interest rates. The debt tables present principal cash flows and related weighted-average interest rates by expected maturity dates; the derivative table shows the notional quantities on which the cash flows will be calculated by swap termination date. Weighted-average variable rates are based on implied forward rates in the yield curve at the reporting date. The carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices.