UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Form 10-K

Commission file number 001-32395

ConocoPhillips

600 North Dairy Ashford
Houston, TX 77079

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

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. [   ]

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, 2004, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $76.29, was $52.5 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 397,605 and 24,701,314 shares, respectively, in determining the aggregate market value.

The registrant had 695,810,445 shares of common stock outstanding at January 31, 2005.

Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 5, 2005 (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 92.

Items 1 and 2.   BUSINESS AND PROPERTIES

CORPORATE STRUCTURE

ConocoPhillips is an international, integrated energy company. ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger between Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips). The merger between Conoco and Phillips (the merger) was consummated on August 30, 2002, at which time Conoco and Phillips combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips. As a result of the merger, Conoco and Phillips each became wholly owned subsidiaries of ConocoPhillips. For accounting purposes, Phillips was designated as the acquirer of Conoco and ConocoPhillips was treated as the successor of Phillips. Accordingly, Phillips’ operations and results are presented in this Form 10-K for all periods prior to the close of the merger. From the merger date forward, the operations and results of ConocoPhillips reflect the combined operations of the two companies. Subsequent to the merger, Conoco was renamed ConocoPhillips Holding Company, and Phillips was renamed ConocoPhillips Company, but for ease of reference, those companies will be referred to respectively in this document as Conoco and Phillips. Effective January 1, 2005, ConocoPhillips Holding Company was merged into ConocoPhillips Company.

Our business is organized into six operating segments:

	•	Exploration and Production (E&P)—This segment primarily explores for, produces and markets crude oil, natural gas, and natural gas liquids on a worldwide basis.
	•	Midstream—This segment gathers and processes natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States, Canada and Trinidad. The Midstream segment includes our 30.3 percent equity investment in Duke Energy Field Services, LLC, a joint venture with Duke Energy.
	•	Refining and Marketing (R&M)—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.
	•	LUKOIL Investment—This segment consists of our equity investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia. Our investment was 10 percent at December 31, 2004.

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	•	Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC, a joint venture with ChevronTexaco Corporation.
	•	Emerging Businesses—This segment encompasses the development of new businesses beyond our traditional operations, including new technologies related to natural gas conversion into clean fuels and related products (e.g., gas-to-liquids), technology solutions, power generation, and emerging technologies.

At December 31, 2004, ConocoPhillips employed approximately 35,800 people.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 27—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, produces and markets crude oil, natural gas, and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the bitumen and upgrade it into a synthetic crude oil. Operations to liquefy and transport natural gas are also included in the E&P segment. At December 31, 2004, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Venezuela, Indonesia, offshore Timor Leste in the Timor Sea, Australia, Vietnam, China, Nigeria, the United Arab Emirates, and Russia.

The E&P segment does not include the results or statistics from our equity investment in LUKOIL, which are reported in a separate segment (LUKOIL Investment). As a result, references to results, production, prices and other statistics throughout the E&P segment exclude those related to our equity investment in LUKOIL.

The information listed below appears in the supplemental oil and gas operations disclosures on pages 168 through 186 and is incorporated herein by reference:

	•	Proved worldwide crude oil, natural gas and natural gas liquids reserves.
	•	Net production of crude oil, natural gas and natural gas liquids.
	•	Average sales prices of crude oil, natural gas and natural gas liquids.
	•	Average production costs per barrel-of-oil-equivalent.
	•	Net wells completed, wells in progress, and productive wells.
	•	Developed and undeveloped acreage.

In 2004, E&P’s worldwide production, including its share of equity affiliates’ production other than LUKOIL, averaged 1,542,000 barrels-of-oil-equivalent (BOE) per day, a 3 percent decrease from 1,590,000 BOE per day in 2003. During 2004, 629,000 BOE per day were produced in the United States, a 7 percent decrease from 674,000 BOE per day in 2003. Production from our international E&P operations averaged 913,000 BOE per day in 2004, down slightly from 916,000 BOE per day in 2003. In addition, our Canadian Syncrude mining operations had net production of 21,000 barrels per day in 2004, compared with 19,000 barrels per day in 2003. The decreased production mainly reflects the impact of

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asset dispositions during 2003 and 2004, as well as normal field production declines. The impact of these items was partially offset by the ramp-up of oil production from the Su Tu Den field in Vietnam since startup in late 2003, the ramp-up of liquids production from the Bayu-Undan field in the Timor Sea since startup in February 2004, and the startup of the Hamaca upgrader in Venezuela in the fourth quarter of 2004. We convert our natural gas production to BOE based on a 6:1 ratio: six thousand cubic feet of natural gas equals one barrel-of-oil-equivalent.

E&P’s worldwide annual average crude oil sales price increased 31 percent in 2004, from $27.52 per barrel to $36.06 per barrel. E&P’s annual average worldwide natural gas sales price also increased, going from $4.08 per thousand cubic feet in 2003 to $4.61 per thousand cubic feet in 2004.

At December 31, 2004, E&P held, including its share of equity affiliates other than LUKOIL, a combined 43.2 million net developed and undeveloped acres, compared with 52.6 million net acres at year-end 2003. The decrease in acreage primarily reflects the assignment of our interests in Barbados and Brazil, in addition to the sale of Petrovera. At year-end 2004, E&P held acreage in 22 countries, including acreage held by equity affiliates.

Our finding-and-development-cost-per-BOE metric reported in prior years was calculated by dividing the net reserve change for each reporting period (excluding production and sales) into the costs incurred for the period, as reported in the “Costs Incurred” disclosure required by Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities.” Due to the timing of proved reserve additions and the timing of the related costs incurred to find and develop such proved reserves, this metric often includes quantities of proved reserves for which a majority of the costs of development have not yet been incurred. Conversely, the metric also often includes costs to develop proved reserves that had been added in earlier years. Because this metric may not necessarily represent total finding and development costs for projects under way or may not be indicative of expected future finding and development costs, we discontinued reporting it in our filings with the U.S. Securities and Exchange Commission.

E&P—U.S. OPERATIONS

In 2004, U.S. E&P operations contributed 40 percent of E&P’s worldwide liquids production, compared with 43 percent in 2003. U.S. E&P contributed 42 percent of natural gas production in both years.

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

The Prudhoe Bay field is the largest oil field on Alaska’s North Slope. It is the site of a large waterflood and enhanced oil recovery operation, as well as a gas processing plant that processes and reinjects natural gas back into the reservoir. Our net crude oil production from the Prudhoe Bay field averaged 109,600 barrels per day in 2004, compared with 121,500 barrels per day in 2003, while natural gas liquids production averaged 23,100 barrels per day in 2004, compared with 23,000 barrels per day in 2003. Normal field production declines and facility maintenance were the main causes of the lower production rates in 2004.

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Prudhoe Bay satellite fields, including Aurora, Borealis, Polaris, Midnight Sun, and Orion, produced 14,600 net barrels per day of crude oil in 2004, compared with 16,200 net barrels per day in 2003. Borealis contributed the biggest share in 2004, producing 8,000 net barrels per day. All Prudhoe Bay satellite fields produce through the Prudhoe Bay production facilities.

The Greater Point McIntyre Area (GPMA) primarily is made up of the Point McIntyre, Niakuk, and Lisburne fields. The fields within the GPMA generally produce through the Lisburne Production Center. Net crude oil production for GPMA averaged 17,800 barrels per day in 2004, compared with 18,200 barrels per day in 2003. The bulk of this production came from the Point McIntyre field, which is approximately seven miles north of the Prudhoe Bay field and extends into the Beaufort Sea.

In January 2005, the Governor of Alaska announced that effective February 1, 2005, most satellite fields surrounding the Prudhoe Bay field would no longer qualify for a state production tax incentive that was intended to encourage development of these marginal deposits. Beginning in February, these satellite fields bear the same production tax rate as Prudhoe Bay.

Greater Kuparuk Area
We operate the Greater Kuparuk Area, which is comprised of the Kuparuk field and four satellite fields: Tarn, Tabasco, Meltwater, and West Sak. Our ownership interest is 55.2 percent in the Kuparuk field, which is located about 40 miles west of Prudhoe Bay. Field installations include three central production facilities that separate oil, natural gas and water. The natural gas is either used for fuel or compressed for reinjection. Our net crude oil production from the Kuparuk field averaged 67,900 barrels per day in 2004, compared with 78,600 barrels per day in 2003.

Other fields within the Greater Kuparuk Area produced 19,300 net barrels per day of crude oil in 2004, compared with 21,800 net barrels per day in 2003, primarily from the Tarn, Tabasco, and Meltwater satellites. We have a 55.3 percent interest in Tarn and Tabasco and a 55.4 percent interest in Meltwater.

The Greater Kuparuk Area also includes the West Sak heavy-oil field. Our net crude oil production from West Sak averaged 5,500 barrels per day in 2004, compared with 3,800 barrels per day in 2003. We have a 52.2 percent interest in this field.

During 2004, we and our co-venturers announced plans for the expansion of the West Sak development. The development program includes two drill sites: Drill Site 1E, which is an existing drill site, and Drill Site 1J, which will be the first stand-alone West Sak drill site. Plans call for the drilling of 13 wells at Drill Site 1E and 31 wells at Drill Site 1J. The development projects also include expansion of facilities at Drill Site 1E, and the construction of new facilities, pipelines and power lines for Drill Site 1J. Drill Site 1E, which started up in July 2004, is expected to average 4,100 net barrels of oil per day in 2005. First production from Drill Site 1J, expected in late 2005, is expected to add approximately 800 net barrels per day. Peak production from Drill Site 1J is expected to occur in 2007.

Western North Slope
The Alpine field, located west of the Kuparuk field, began production in November 2000. In 2004, the field produced at a net rate of 63,500 barrels of oil per day, compared with 64,500 barrels per day in 2003. We are the operator and hold a 78 percent interest in Alpine.

During 2004, the Alpine Capacity Expansion Phase I was completed. As a result, Alpine’s gross crude oil production capacity increased approximately 5,000 barrels per day, along with an increase in the site’s produced-water capacity. Originally designed to process about 10,000 barrels per day of produced water, the site can now process about 100,000 barrels per day. The completion of Phase II is scheduled for 2005,

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after which Alpine’s crude oil production capacity is expected to be further expanded by approximately 30,000 gross barrels per day with increased seawater injection rates to boost reservoir pressure.

In January 2003, ConocoPhillips and the U.S. Department of Interior Bureau of Land Management (BLM) signed a Memorandum of Understanding that provides for completion of an Environmental Impact Statement (EIS) for Alpine satellites, as well as future potential developments in the northeast corner of the National Petroleum Reserve-Alaska (NPR-A) and near the Alpine oil field. The BLM issued a favorable EIS Record of Decision in November 2004. In December 2004, we and our co-venturers announced that the companies approved the development of two Alpine satellite oil fields—Fiord and Nanuq. The project will include two satellite drill sites—CD 3 on the Fiord oil field, and CD 4 on the Nanuq oil field—located within an 8-mile radius of the Alpine oil field. Plans call for the drilling of approximately 40 wells, with first production scheduled for late 2006 and peak production in 2008. The oil will be processed through the existing Alpine facilities. The companies intend to seek state, local and federal permits for additional Alpine satellite developments in the NPR-A. A final decision to move forward on these satellite oil fields is not expected to be made until the outcomes of remaining permits are known.

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

We have a 100 percent interest in the North Cook Inlet field. Net production in 2004 averaged 94 million cubic feet per day, compared with 112 million cubic feet per day in 2003. Production from the North Cook Inlet field is used to supply our share of gas to the Kenai LNG plant (discussed below).

Our interest in the Beluga River field is 33 percent. Net production averaged 63 million cubic feet per day in 2004, the same as in 2003. Gas from the Beluga River field is sold to local utilities and industrial consumers, and used as back-up supply to the Kenai LNG plant.

We have a 70 percent interest in the Kenai LNG plant, which supplies LNG to two utility companies in Japan. Using two tankers, the company transports the LNG to Japan, where it is reconverted to dry gas at the receiving terminal. We sold 38.6 net billion cubic feet of LNG to Japan in 2004, compared with 44.0 billion cubic feet in 2003.

Exploration
During the 2004 winter drilling season, we drilled six North Slope exploration and appraisal wells. This activity resulted in two successful appraisal wells in the NPR-A and one successful appraisal well in the West Sak field. We expensed the other three wells as dry holes. In addition, successful exploratory production tests were run in two wells, one each in the Alpine and Prudhoe Bay fields. During 2004, we completed evaluation of six wells drilled in prior drilling seasons, with five of those determined to be successful and one expensed as a dry hole. We were also the successful bidder on 71 tracts covering over 808,000 gross acres (approximately 484,000 net acres) at the June 2004 Bureau of Land Management oil and gas lease sale for the Northwest Planning Area of the NPR-A. As a result of this additional acreage, we now have under lease approximately 1.3 million net exploration acres in the NPR-A.

Transportation
We transport the petroleum liquids that we produce on the North Slope to market through the Trans-Alaska Pipeline System (TAPS), an 800-mile pipeline, marine terminal, spill response and escort vessel system that ties the North Slope of Alaska to the port of Valdez in south-central Alaska. We have a 28.3 percent ownership interest in TAPS. We also have ownership interests in the Alpine, Kuparuk and Oliktok pipelines on the North Slope.

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The owners of TAPS approved plans to upgrade the pipeline’s pump stations. The project is expected to be substantially completed in 2005. The project is expected to reduce operating costs and extend the economic life of the pipeline through increased efficiencies, while maintaining safety and environmental performance standards.

We continue to evaluate a gas pipeline project to deliver natural gas from 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. The Alaska Natural Gas Pipeline Act was passed by Congress and signed by the President in October 2004. This legislation was designed to help facilitate and streamline the federal regulatory process and provides up to $18 billion in federal loan guarantees. Also approved was tax legislation granting seven-year depreciation to the Alaska portion of the pipeline and confirming the existing 15 percent enhanced oil recovery tax credit would apply to the gas treating plant. This federal legislation, along with gaining a fiscal contract with the state of Alaska, is an integral part of moving the project forward. Also in 2004, ConocoPhillips, along with BP and ExxonMobil, entered into negotiations with the state of Alaska under the Stranded Gas Development Act and submitted a detailed proposal to the state in December. These negotiations are ongoing.

Our wholly owned subsidiary, Polar Tankers Inc., manages the marine transportation of our Alaska North Slope production. Polar Tankers operates six ships in the Alaskan trade, chartering additional third-party-operated vessels, as necessary. Beginning with the Polar Endeavour in 2001, Polar Tankers has brought into service a new Endeavour Class tanker each year since: the Polar Resolution in 2002; the Polar Discovery in 2003; and the Polar Adventure in 2004. These 125,000-deadweight-ton, double-hulled crude oil tankers are the first four of five Endeavour Class tankers that we are adding to our Alaska-trade fleet. The fifth and final tanker is scheduled to be in Alaska North Slope service by 2006.

Lower 48 States
Gulf of Mexico
At year-end 2004, our portfolio of producing properties in the Gulf of Mexico included four fields operated by us and four fields operated by our co-venturers. At December 31, 2004, we had 28 leases in production or under development in the deepwater Gulf of Mexico.

We hold a 16 percent interest in the Ursa field located in the Mississippi Canyon area. Ursa utilizes a tension-leg platform in approximately 3,900 feet of water. We also own a 16 percent interest in the Princess field, a northern, subsalt extension of the Ursa field. Our total net production from both fields in 2004 averaged 21,000 barrels per day of liquids and 30 million cubic feet per day of natural gas, compared with 15,900 barrels per day of liquids and 20 million cubic feet per day of natural gas in 2003.

We operate and hold a 75 percent interest in the Garden Banks 783 and 784 leases, which contain the Magnolia field discovered in 1999. Installation of a tension-leg platform, located in approximately 4,700 feet of water, was completed during 2004. First oil production began in December 2004, with the remaining well completions scheduled through the first half of 2005. Peak production of 48,000 net BOE per day is expected during 2005.

We have a 16.8 percent interest in the K2 discovery. K2, located in Green Canyon Block 562, was company-sanctioned for development in the first quarter of 2004. The development will utilize a subsea tieback to a nearby third-party platform. First production is expected in the second half of 2005, with peak net production of 7,000 BOE per day expected during 2007.

During 2004, we sold our interest in the Lorien discovery located in Green Canyon Block 199.

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Onshore
Our onshore Lower 48 production primarily consists of natural gas, with the majority of the production located in the Lobo Trend in South Texas, the San Juan Basin of New Mexico, and the Guymon-Hugoton Trend in the Panhandles of Texas and Oklahoma. We also have oil and natural gas production from the Permian Basin in West Texas and southeast New Mexico. Other positions and production are maintained in other parts of Texas and Oklahoma, the Arkansas/Louisiana/Texas area, and onshore Gulf Coast area. In addition to our coalbed methane production from the San Juan Basin, we also hold coalbed methane acreage positions in the Uinta Basin in Utah and the Black Warrior Basin in Alabama. Our interest in the coalbed methane acreage position in the Powder River Basin in Wyoming was sold in early 2005.

Activities in 2004 primarily were centered on continued optimization and development of these assets. Combined production from Lower 48 onshore fields in 2004 averaged a net 1,184 million cubic feet per day of natural gas and 54,100 barrels per day of liquids, compared with 1,237 million cubic feet per day of natural gas and 57,000 barrels per day of liquids in 2003.

E&P—NORTHWEST EUROPE

In 2004, E&P operations in Northwest Europe contributed 29 percent of E&P’s worldwide liquids production, compared with 30 percent in 2003. Our Northwest European assets are principally located in the Norwegian and U.K. sectors of the North Sea. Northwest Europe operations contributed 34 percent of natural gas production in both years.

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 2004 from the Ekofisk Area was 127,400 barrels of liquids per day and 125 million cubic feet of natural gas per day, compared with 126,500 barrels of liquids per day and 127 million cubic feet of natural gas per day in 2003. We are operator and hold a 35.1 percent interest in Ekofisk.

In 2003, we and our co-venturers approved a plan for further development of the Ekofisk Area. The project consists of two interrelated components: construction of a new platform, Ekofisk 2/4M, and modification of the existing Ekofisk Complex to increase processing capacity. Construction began in 2003, and during 2004 the 2/4M platform progressed on schedule. Production from the new platform is projected to begin in the fall of 2005.

We also have ownership interests in other producing fields in the Norwegian North Sea, and Norwegian Sea, including a 24.3 percent interest in the Heidrun field, a 10.3 percent interest in the Statfjord field, a 23.3 percent interest in the Huldra field, a 1.6 percent interest in the Troll field, a 9.1 percent interest in the Visund field, a 6.4 percent interest in the Grane field, and a 2.4 percent interest in the Oseberg area. Production from these and other fields in the Norwegian sector of the North Sea and the Norwegian Sea averaged a net 87,700 barrels of liquids per day and 176 million cubic feet of natural gas per day in 2004, compared with 93,300 barrels of liquids per day and 149 million cubic feet of natural gas per day in 2003.

We and our co-venturers received approval from Norwegian authorities in October 2004 for the Alvheim North Sea development. The development plans include a floating production storage and offloading vessel and subsea installations. Production from the field is expected to commence in 2007. We have a 20 percent interest in the project.

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

Exploration
Three partner-operated exploration wells were drilled in 2004. All three were near-field exploration wells in the Heidrun and Visund licenses. The drilling near Heidrun resulted in one discovery and one dry hole. The well in the Visund area was a hydrocarbon discovery. In 2005, seven to eight wells are planned to be drilled in Norway and Denmark.

United Kingdom
We are a joint operator of the Britannia natural gas/condensate field, in which we have a 58.7 percent interest. Our net production from Britannia averaged 347 million cubic feet of natural gas per day and 15,500 barrels of liquids per day in 2004, compared with 391 million cubic feet of natural gas per day and 14,500 barrels of liquids per day in 2003. Oil and gas production from Britannia is delivered by pipeline to Scotland. Development drilling in the Britannia field is expected to continue into the year 2007.

In December 2003, we approved a plan for the development of two new Britannia satellite fields: the Callanish and Brodgar fields. The U.K. government approved the development plan in early 2004. The development plan involves producing the fields via subsea manifolds and two new pipelines to Britannia. A new platform, bridge-linked to Britannia, will also be installed to separate production prior to processing on the Britannia platform. Drilling began in the second half of 2004, with the pipelines, manifolds and installation of the bridge-linked platform anticipated for 2006. First production is targeted for 2007. We have a 75 percent interest in the Brodgar field and an 83.5 percent interest in the Callanish field.

We operate and hold a 36.5 percent interest in the Judy/Joanne fields, which together comprise J-Block. Additionally, the Jade field produces from a wellhead platform and pipeline tied to the J-Block facilities. We are the operator of, and hold a 32.5 percent interest in, Jade. Together, these fields produced a net 14,100 barrels of liquids per day and 118 million cubic feet of natural gas per day in 2004, compared with 18,100 barrels of liquids per day and 118 million cubic feet of natural gas per day in 2003.

ConocoPhillips continues to supply gas from J-Block to Enron Capital and Trade Resources Limited (Enron Capital), which was placed in Administration in the United Kingdom on November 29, 2001. ConocoPhillips has been paid all amounts currently due and payable by Enron Capital in respect of the J-Block gas sales agreement. We believe that Enron Capital will continue to pay the amounts due for gas supplied by us in accordance with the terms of the gas sales agreement. We do not currently expect that we will have to curtail sales of gas under the gas sales agreement or shut in production as a result of the Administration of Enron Capital. However, in the event that the arrangements for the processing of Enron 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. Net production in 2004 averaged 306 million cubic feet per day of natural gas and 1,400 barrels of liquids per day, compared with 371 million cubic feet per day of natural gas and 2,000 barrels per day of liquids in 2003.

The Valkyrie development was brought into production in 2004. This is a single well development drilled from a nearby platform. We are the operator with a 50 percent interest.

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During 2004, we received approval from the U.K. government for development of the Saturn Unit Area in the southern North Sea. First gas production from the Saturn Unit Area is expected in the fourth quarter of 2005, with net production expected to increase to a maximum rate of approximately 73 million cubic feet per day within a year following startup. Initially, the development will consist of three wells from a six-slot wellhead platform. We are the operator of the Saturn Unit Area and have an interest of 42.9 percent.

During 2004, we concluded the development of the CMS3 area in the southern sector of the U.K. North Sea with the completion of the Boulton H-1 well. This development consists of five natural gas reservoirs developed as a single, unitized project. Collectively, these fields are known as CMS3 due to their utilization of the production and transportation facilities of the ConocoPhillips-operated Caister Murdoch System (CMS). We are the operator of CMS3 and hold a 59.5 percent interest.

Also during 2004, we received internal and co-venturer approvals for the Munro development, and are working toward U.K. governmental approval in the first quarter of 2005. Munro is a single well development which would tie into the Hawksley subsea manifold (part of CMS3). We are the operator of Munro with a 46 percent interest.

We also have ownership interests in several other producing fields in the U.K. North Sea, including a 23.4 percent interest in the Alba field, a 40 percent interest in the MacCulloch field, a 30 percent interest in the Miller field, an 11.5 percent interest in the Armada field, and a 4.8 percent interest in the Statfjord field. Production from these and the other remaining fields in the U.K. sector of the North Sea averaged a net 38,800 barrels of liquids per day and 47 million cubic feet of natural gas per day in 2004, compared with 44,500 barrels of liquids per day and 61 million cubic feet of natural gas per day in 2003.

We have a 24 percent interest in the Clair field development in the Atlantic Margin. First production from Clair is expected in early 2005, with plateau production expected in 2006 at a net rate of 14,400 BOE per day.

Transportation
The Interconnector pipeline, which connects the United Kingdom and Belgium, facilitates marketing natural gas produced in the United Kingdom throughout Europe. Our 10 percent equity share of the Interconnector pipeline allows us to ship approximately 200 million net cubic feet of natural gas per day to markets in continental Europe.

We operate two terminals in the United Kingdom: the Teesside oil terminal (in which we have a 29.3 percent interest) and the Theddlethorpe gas terminal (in which we have a 50 percent interest).

Exploration
In the U.K. sector of the North Sea, we participated in two wells in the southern North Sea and one well on a structure adjacent to the Callanish field in the central North Sea during 2004. All three of these wells were successful in locating commercial quantities of hydrocarbons. The planned drilling program for 2005 includes seven to eight exploration and appraisal wells.

E&P—CANADA

In 2004, E&P operations in Canada contributed 4 percent of E&P’s worldwide liquids production (excluding Syncrude production), compared with 5 percent in 2003. Canadian operations contributed 13 percent of natural gas production in both years.

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Oil and Gas Operations
Western Canada
Operations in western Canada encompass properties in Alberta, northeastern British Columbia and southwestern Saskatchewan. We separate our holdings in western Canada into four geographic regions. The north region contains a mix of oil and natural gas, and primarily is accessible only in the winter. The central and west regions mainly produce natural gas. The south region has shallow gas and medium-to-heavy oil. Production from these oil and gas operations in western Canada averaged a net 35,000 barrels per day of liquids and 433 million cubic feet per day of natural gas in 2004, compared with 30,300 barrels per day of liquids and 435 million cubic feet per day of natural gas in 2003.

In February 2004, we sold our 46.7 percent interest in Petrovera, a joint venture that produced heavy oil.

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. In May 2003, we received regulatory approval to develop the Surmont project from the Alberta Energy and Utilities Board and in late 2003, our Board of Directors approved the project. In 2003, we classified 223 million barrels as proved crude oil reserves from our Canadian operations, the majority of which related to the Surmont heavy-oil project. Consistent with our practice and in accordance with U.S. Securities and Exchange Commission guidelines that require the use of year-end prices for reserve estimation, due to low December 31, 2004, Canadian bitumen values, we removed all of the crude oil reserves for the Surmont project from the proved category at year-end 2004. Despite this revision, the Surmont project remains an economically viable and important component of our E&P project portfolio.

The Surmont project uses an enhanced thermal oil recovery method called steam assisted gravity drainage. This process involves heating the oil by the injection of steam deep into the oil sands through a horizontal well bore, effectively lowering the viscosity and enhancing the flow of the oil, which is then recovered via gravity drainage into a lower horizontal well bore and pumped to the surface. Over the life of this 30+ year project, we anticipate that approximately 500 production and steam-injection well pairs will be drilled. Construction of the facilities and development drilling began in 2004. Commercial production is expected to begin in late 2006, with peak production expected in 2012. We anticipate using our share of the heavy oil produced as a feedstock in our U.S. refineries.

Transportation
We are working with three other energy companies, as members of the Mackenzie Delta Producers’ Group, on the development of the Mackenzie Valley pipeline, which is proposed to transport onshore gas production from the Mackenzie Delta in northern Canada to established markets in North America. Initial design capacity for the Mackenzie Valley pipeline is proposed to be 1.2 billion cubic feet per day, but capacity would be expandable with additional compression. We would hold a 16 percent interest in the pipeline and a 75 percent interest in the development of the Parsons Lake gas field. The Parsons Lake gas field would be one of the primary fields in the Mackenzie Delta that would anchor the pipeline development. Regulatory applications for the project were submitted in 2004, and first gas production is currently targeted for the 2009 timeframe.

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. As part of our evaluation, we are waiting on the results from drilling on adjacent blocks. In deepwater Newfoundland, we converted our large Laurentian permit into specific exploration licenses. Exploration of these licenses began in 2004 with a 2D seismic survey, and a larger

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3D seismic program is planned for 2005. In the foothills, we drilled four wildcat exploratory wells in 2004. One was successful, and the other three are being tested. In the Mackenzie Delta/Beaufort Sea, we participated in the Umiak well. This well will be tested during the first quarter of 2005 and an appraisal well is also planned.

Other Canadian Operations
Syncrude Canada Ltd.
We own a 9.03 percent interest in Syncrude Canada Ltd., a joint venture created by a number of energy companies for the purpose of mining shallow deposits of oil sands, extracting the bitumen, and upgrading it into a light sweet crude oil called Syncrude. The primary plant and facilities are located at Mildred Lake, about 25 miles north of Fort McMurray, Alberta, together with an auxiliary mining and extraction facility approximately 20 miles from the Mildred Lake plant. Syncrude Canada Ltd. holds eight oil sands leases and the associated surface rights, of which our share is approximately 23,000 net acres. Our net share of production averaged 21,000 barrels per day in 2004, compared with 19,000 barrels per day in 2003.

The development of the Stage III expansion-mining project continued in 2004, which is expected to increase our Syncrude production. The new mine was completed and started up in the fourth quarter of 2003. The upgrader expansion project is expected to be fully operational by mid-2006.

The U.S. Securities and Exchange 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 our supplemental oil and gas information.

E&P—SOUTH AMERICA

In 2004, E&P operations in South America were comprised of interests in Venezuela and Brazil. South American operations contributed 9 percent of E&P’s worldwide liquids production in 2004, compared with 8 percent in 2003.

Venezuela
Petrozuata and Hamaca
Petrozuata is a Venezuelan Corporation formed under an Association Agreement between a wholly owned subsidiary of ConocoPhillips that has a 50.1 percent non-controlling equity interest and a subsidiary of Petroleos de Venezuela S.A. (PDVSA), the national oil company of Venezuela. The Association Agreement has a term of 35 years, that began in 2001.

The project is an integrated operation that produces heavy crude oil from reserves in the Zuata region of the Orinoco Oil Belt, transports it to the Jose industrial complex on the north coast of Venezuela, and upgrades it into heavy, processed crude oil and light, processed crude oil. Associated products produced are liquefied petroleum gas, sulfur, petroleum coke and heavy gas oil. The processed crude oil produced by Petrozuata is used as a feedstock for our Lake Charles, Louisiana, refinery, as well as the Cardon refinery in Venezuela operated by PDVSA. Our net production was 59,600 barrels of heavy crude oil per day in 2004, compared with 51,600 barrels per day in 2003, and is included in equity affiliate production.

In 1997, we entered into an agreement to purchase up to 104,000 barrels per day of the Petrozuata-upgraded crude oil for a market-based formula price over the term of the joint venture in the event that Petrozuata is unable to sell the production for higher prices. All upgraded crude oil sales are denominated in U.S. dollars.

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The Hamaca project also involves the development of heavy-oil reserves from the Orinoco Oil Belt. We own a 40 percent interest in the Hamaca project, which has a 35-year term, beginning in 2004, and is operated by Petrolera Ameriven on behalf of the owners. The other participants in Hamaca are PDVSA and ChevronTexaco Corporation. Our interest is held through a joint limited liability company, Hamaca Holding LLC, for which we use the equity method of accounting. Net production averaged 32,600 barrels per day of heavy crude oil in 2004, compared with 22,100 barrels per day in 2003, and is included in equity affiliate production.

Construction of the heavy-oil upgrader, pipelines and associated production facilities for the Hamaca project at the Jose industrial complex began in 2000. In the fourth quarter of 2004, we began producing on-specification medium-grade crude oil for export at the planned ramp-up capacity of the plant. Our net oil production from the Hamaca field is expected to be approximately 56,100 barrels per day in 2005.

In October 2004, the President of Venezuela made a public statement that the reduction in the royalty rate to 1 percent from 16.67 percent for a period of nine years, or until revenues exceed three times the initial investment, would no longer apply to extra-heavy crude oil producing and processing projects. This statement was later confirmed in writing by the Ministry of Energy and Mines (MEM) to the Petrozuata and Hamaca project representatives. Consequently, Petrozuata and Hamaca began paying royalties at the higher rate effective October 2004. As a result, 2005 production estimates were reduced by approximately 20,000 net barrels per day and our proved reserves at year-end 2004 were reduced 46 million barrels.

Gulf of Paria
In 2003, the Venezuelan authorities approved the original development plan for Phase I of the Corocoro field. Venezuelan authorities did not approve a development plan addendum submitted in 2004. However, in early 2005 verbal agreement of requirements to progress the project was achieved. We will be working with the Venezuelan government and co-venturers to finalize the terms agreed and move the project forward to development. We operate the field with a 32.2 percent interest.

Plataforma Deltana Block 2
We acquired a 40 percent interest in Plataforma Deltana Block 2 in 2003. The block is co-venturer operated and holds a gas discovery made by PDVSA in 1983. Two appraisal wells were completed in 2004, and a third was completed in January 2005. All appraisal wells indicated that the target zones were natural gas bearing. In addition, a new natural gas/condensate discovery was made in a deeper zone. Development of the field may include a well platform, a 170-mile pipeline to shore, and an LNG plant. The LNG would be shipped to the U.S. market.

Exploration
Wildcat exploratory activity in both the Gulf of Paria East and West Blocks was commercially unsuccessful in 2004, which resulted in a full impairment of our leasehold investment in these blocks. However, we are still pursuing evaluation plans to assess future potential.

Brazil
Exploration
We had concession agreements on two deepwater exploration blocks (BM-ES-11 and BM-PAMA-3) offshore Brazil. During 2003 and 2004, further evaluation led to the write-off of our leasehold investments in both blocks. By the end of 2004, we had ceased all operations in Brazil and exited the country.

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E&P—ASIA PACIFIC

In 2004, E&P operations in the Asia Pacific area contributed 10 percent of E&P’s worldwide liquids production, compared with 6 percent in 2003. Asia Pacific operations contributed 9 percent of natural gas production in both years.

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 onshore South Sumatra. A potentially emerging area is offshore East Java. We are a party to five long-term, U.S.-dollar-denominated natural gas contracts that are based on oil price benchmarks. In addition, in 2004 we began supplying natural gas to markets on the Indonesian island of Batam and new contracts were signed to supply natural gas to domestic markets in West Java and East Java. These are U.S.-dollar-denominated, fixed-price contracts. Production from Indonesia in 2004 averaged a net 250 million cubic feet per day of natural gas and 15,400 barrels per day of oil, compared with 255 million cubic feet per day of natural gas and 16,000 barrels per day of oil in 2003.

Offshore Assets
We operate three offshore PSCs: South Natuna Sea Block B, Nila, and Ketapang. We also hold a non-operator interest in the Pangkah PSC offshore East Java.

The South Natuna Sea Block B PSC, in which we have a 40 percent interest, has two currently producing oil fields and 16 gas fields in various stages of development (seven of which have recoverable oil or condensate volumes). In late 2004, oil production began from the Belanak oil and gas field through a new floating production, storage and offloading (FPSO) vessel and related facilities. Also in Block B, we began development of the Kerisi and Hiu fields, with construction contract awards under way, and we began the preliminary engineering phase of the North Belut field development.

In the Pangkah PSC, in which we have a 22 percent interest, the development of the Ujung Pangkah field was approved by the Indonesian government in late 2004 following the signing of contracts for the supply of natural gas to markets in East Java.

Onshore Assets
We operate six onshore PSCs. Four are in South Sumatra: Corridor PSC, Corridor TAC, South Jambi ‘B’, and Sakakemang JOB. We also operate Block A PSC in Aceh, and Warim in Papua. We hold non-operator interests in the Banyumas PSC in Java and the Bentu and Korinci-Baru PSCs in Sumatra.

The Corridor PSC is located onshore South Sumatra and we have a 54 percent interest. We operate six oil fields and six natural gas fields, and supply natural gas from the Grissik and Suban gas processing plants to the Duri steamflood in central Sumatra operated by Caltex and to markets in Singapore and Batam.

In August 2004, we announced the signing of a gas sales agreement with PT Perusahaan Gas Negara (Persero) Tbk. (PGN), the Indonesian state-owned gas transportation company, to supply natural gas for delivery to the industrial markets in West Java and Jakarta. The agreement calls for us to supply approximately 850 billion net cubic feet of gas over a 17-year period commencing in the first quarter of 2007. At the contracted rates, initial gas deliveries are about 65 million net cubic feet per day, ramping up to approximately 140 million net cubic feet per day in 2012, and continuing at that level until the contract terminates in 2023.

Following the execution of the West Java gas sales agreement with PGN in August, we began the development of the Suban Phase II project, which is an expansion of the existing Suban gas plant in the Corridor PSC.

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The South Jambi ‘B’ PSC is also located in South Sumatra, and we have a 45 percent interest. In 2004, we completed the construction of the South Jambi shallow gas project for supply of natural gas to Singapore from the South Jambi B Block, with first production occurring in June 2004.

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

Exploration
In Indonesia, a total of 11 exploration and appraisal wells were drilled during 2004, of which five were successful. In the Pangkah PSC, two appraisal wells confirmed a western extension of the Ujung Pangkah field. In the Ketapang PSC, an appraisal well of the Bukit Tua field provided data for progressing a development plan in 2005. In Sumatra, two appraisal wells were successful in finding additional gas volumes in both the Korinci-Baru and the Bentu PSCs.

China
Our combined net production of crude oil from the Xijiang facilities averaged 10,400 barrels per day in 2004, compared with 10,900 barrels per day in 2003. The Xijiang development consists of three fields located approximately 80 miles from Hong Kong in the South China Sea. The facilities include two manned platforms and a FPSO facility.

Production from Phase I development of the Peng Lai 19-3 field in Bohai Bay Block 11-05 began in late 2002. In 2004, the field produced 15,000 net barrels of oil per day, compared with 14,800 barrels per day in 2003. We have a 49 percent interest, with the remainder held by the China National Offshore Oil Corporation. The Phase I development utilizes one wellhead platform and a FPSO facility.

In December 2004, our Board of Directors approved the second phase of development of the Peng Lai 19-3 field, as well as concurrent development through the same facilities of the nearby Peng Lai 25-6 field. The “Overall Development Program” for both fields was submitted to the Chinese government in November 2004, and was approved in January 2005. Construction activities have since begun. The second phase will include multiple wellhead platforms and a larger FPSO facility.

Vietnam
We have a 23.25 percent interest in Block 15-1 in the Cuu Long Basin in the South China Sea. First production from Block 15-1 began in the fourth quarter of 2003 with the startup of the Su Tu Den development. Net production in 2004 was 20,800 barrels of oil per day. The oil is being processed through a 1 million barrel FPSO vessel.

We have a 36 percent interest in the Rang Dong field in Block 15-2 in the Cuu Long Basin. All wellhead platforms produce into a FPSO vessel. Net production in 2004 was 11,800 barrels of liquids per day and 16 million cubic feet per day of natural gas. Development of the central part of the field is under way, with two additional platforms and additional production and injection wells expected to be completed in the third quarter of 2005.

Transportation
We own a 16.33 percent interest in the Nam Con Son gas pipeline. This 242-mile transportation system links gas supplies from the Nam Con Son Basin to gas markets in southern Vietnam.

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Exploration
An oil discovery was made on the Su Tu Vang prospect in Block 15-1 in the third quarter of 2001, with successful appraisal drilling conducted in 2004. Development scenarios are currently under evaluation, with preliminary engineering commencing in early 2005. The commerciality of the northeast portion of Su Tu Den is also being evaluated, with additional appraisal drilling planned for 2005. In addition to these areas, a successful exploration well was drilled in the Su Tu Trang southeast area of the block in the fourth quarter of 2003. A 3D seismic study was conducted on this area in 2004 and is currently under interpretation. Additional appraisal drilling is scheduled for 2005 to further define this gas condensate discovery. We also own interests in offshore Blocks 5-3, 133 and 134. Our interest in Block 16-2 was relinquished in April 2004 after unsuccessful exploratory activity.

Timor Sea and Australia
Bayu-Undan
We are the operator and hold a 56.7 percent interest in the unitized Bayu-Undan field, located in the Timor Sea, which is being developed in two phases. Phase I is a gas-recycle project, where condensate and natural gas liquids are separated and removed and the dry gas reinjected back into the reservoir. This phase began production in February 2004, and averaged a net rate of 28,100 barrels of liquids per day in 2004.

Phase II involves the installation of a natural gas pipeline from the field to Darwin, and construction of an LNG facility located at Wickham Point, Darwin, to meet gross contracted sales of up to 3 million tons of LNG per year for a period of 17 years to customers in Japan. During 2004, construction of the LNG facility proceeded, as did the laying of the pipeline. The first LNG cargo is scheduled for delivery in early 2006. We have a 56.7 percent controlling interest in the pipeline and LNG facility. Our net share of natural gas production from the Bayu-Undan field is expected to be approximately 100 million cubic feet per day initially, then ramping up to approximately 260 net million cubic feet per day by 2009.

Greater Sunrise
We and our co-venturers evaluated commercial development options and LNG markets in the Asia Pacific region and the North American West Coast during 2004. The focus in 2004 was on an onshore LNG facility located at Darwin, although other alternatives, such as a floating LNG facility and an onshore plant in Timor-Leste, were also considered. Further progress on the project will require resolution of the maritime border dispute between Australia and Timor-Leste and ratification of the International Unitization Agreement by Timor-Leste. We have a 30 percent, non-operator interest in Greater Sunrise.

Athena/Perseus
A cooperative field development agreement for the Athena/Perseus (WA-17-L) gas field, located offshore western Australia, was executed in early 2001. In 2004, our net share of production was 35 million cubic feet of natural gas per day.

Malaysia
Exploration
In 2000, we acquired interests in deepwater Blocks G and J located off the east Malaysian state of Sabah. We participated in four exploration wells in the blocks. The Gumusut 1 well, in which we have a 40 percent interest, was drilled in Block J in 2003 and resulted in an oil discovery. Further exploratory drilling is planned. In September 2004, we successfully completed the drilling of the Malikai discovery, in which we have a 35 percent interest, in Block G. Appraisal of the Malikai discovery is anticipated in 2005. In addition, we plan to acquire a 40 percent interest in the Kebabangan discovery in early 2005. Appraisal work is planned for 2005.

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E&P—AFRICA AND THE MIDDLE EAST

Nigeria
At year-end 2004, we were producing from four onshore Oil Mining Leases (OMLs), in which we have a 20 percent non-operator interest. Our interest in a shallow-water offshore OML was sold in the second quarter of 2004. Together, in 2004 these leases produced a net 30,100 barrels of oil per day and 71 million cubic feet of natural gas per day, compared with 36,900 barrels per day and 63 million cubic feet per day in 2003. In 2004, we continued development of projects in the onshore OMLs to supply feedstock natural gas under a gas sales contract with Nigeria LNG Limited, which owns an LNG facility on Bonny Island.

We have a 20 percent interest in a 480-megawatt gas-fired power plant being constructed in Kwale, Nigeria, to supply electricity to Nigeria’s national electricity supplier under a 20-year agreement. When operational, the plant is expected to consume 68 million gross cubic feet per day of natural gas, sourced from proved natural gas reserves in the OMLs. The plant is targeted to become fully operational in 2005.

In October 2003, ConocoPhillips, the Nigerian National Petroleum Corporation (NNPC), Eni and ChevronTexaco signed a Heads of Agreement to conduct front-end engineering and design work for a new LNG facility that would be constructed in Nigeria’s central Niger Delta. The co-venturers agreed to form an incorporated joint venture, Brass LNG Limited, to undertake the project. These front-end studies are expected to be completed in 2006, and the LNG facility is targeted to become operational in 2010.

Exploration
We also have production sharing contracts on deepwater Nigeria Oil Prospecting Licenses (OPLs), including OPL 318 with a 50 percent interest, OPL 248 with a 28.8 percent interest, OPL 220 with a 47.5 percent interest, OPL 214 with a 20 percent interest, and OPL 250 with a 6.375 percent interest. We drilled the first exploration wells on both OPL 248 and OPL 250 in 2004. Neither of these wells encountered significant hydrocarbons and were classified as dry holes. The first exploration wells on both OPL 214 and OPL 318 are planned for 2005.

Cameroon
Exploration
In December 2002, we announced a successful test of an exploratory well offshore Cameroon. The Coco Marine No. 1 well was located in exploration permit PH 77, offshore in the Douala Basin. Contractor interests in the permit are held 50 percent by ConocoPhillips and 50 percent by a subsidiary of Petronas Carigali. We serve as the operator of the consortium. Seismic data was analyzed during 2004, and we plan an appraisal well and further exploratory drilling in 2005.

Libya
We are participating in discussions with our co-venturers and Libyan authorities regarding terms in connection with our anticipated re-entry into the country.

Qatar
In July 2003, we signed a Heads of Agreement with Qatar Petroleum for the development of Qatargas 3, a large-scale LNG project located in Qatar and servicing the U.S. natural gas markets. The agreement provided the framework for the necessary project agreements and the completion of feasibility studies, both of which were advanced in 2004. Qatargas 3 is planned as an integrated project, jointly owned by ConocoPhillips (30 percent) and Qatar Petroleum. It would consist of the facilities to produce gas from Qatar’s offshore North field, yielding approximately 7.8 million gross tons per year of LNG from a new facility located in Ras Laffan Industrial City. The LNG would be shipped from Qatar to the United States

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in a fleet of new LNG carriers. We would purchase the LNG and be responsible for regasification and marketing within the United States. The project could result in sales of natural gas of up to 1 billion cubic feet per day. Startup of the Qatargas 3 project is estimated to be in the 2009 timeframe.

In December 2003, we signed a Statement of Intent with Qatar Petroleum regarding the construction of a gas-to-liquids (GTL) plant in Ras Laffan, Qatar. The agreement initiates the detailed technical and commercial pre-front-end engineering and design studies and established principles for negotiating a Heads of Agreement for an integrated reservoir-to-market GTL project. Negotiations on more definitive agreements and progress on the studies continued in 2004.

Dubai
In Dubai, United Arab Emirates, we operate Dubai’s four large, offshore oil fields. We are using advanced horizontal drilling techniques and advanced reservoir drainage technology to enhance the recovery rates and efficiencies in these late-life fields.

Iraq
We, along with LUKOIL, will cooperate with the Iraqi government to confirm LUKOIL’s rights under its production sharing agreement (PSA) relating to the West Qurna field in Iraq. Subject to confirmation and the consents of governmental authorities and the parties to the contract, we expect to enter into further agreements regarding the assignment of a 17.5 percent interest in the PSA to us by LUKOIL.

E&P—RUSSIA AND CASPIAN SEA REGION

Russia
Polar Lights
We have a 50 percent ownership interest in Polar Lights Company, a Russian limited liability company established in January 1992 to develop fields in the Timan-Pechora basin in Northern Russia. Our net production from Polar Lights averaged 13,300 barrels of oil per day in 2004, compared with 13,600 barrels per day in 2003, and is included in equity affiliate production.

LUKOIL Joint Venture
We have entered into an arrangement with LUKOIL under which it is anticipated that we will acquire a 30 percent economic interest and a 50 percent voting interest in a joint venture to develop oil and gas resources in the northern part of Russia’s Timan-Pechora province. We anticipate that our acquisition of a 30 percent interest will be completed in the first half of 2005. While this joint venture will be included in our E&P segment, our equity investment in LUKOIL is reflected in the LUKOIL Investment segment.

Other
In late 2004 we signed a Memorandum of Understanding with Gazprom to undertake a joint study on the development of the Shtokman gas field in the Barents Sea. The cooperative study will include the evaluation of LNG feasibility and transportation to the United States and European markets.

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 exercised our pre-emptive rights to acquire a proportionate share of BG International’s 16.67 percent interest in the project. Discussions continue with the Republic of Kazakhstan government to conclude the sale.

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Detailed design, procurement and construction activities continued on the Kashagan oil field development following approval by the Republic of Kazakhstan for the development plan and budget in February 2004. First commercial production is targeted for 2008. The initial production phase of the contract is for 20 years, with options to extend the agreement an additional 20 years.

Exploration
The contracting companies plan to continue to explore other structures within the North Caspian Sea license. The exploration area consists of 10.5 blocks, totaling nearly 2,000 square miles. In 2002, we and our co-venturers announced a new hydrocarbon discovery on the Kalamkas More prospect located approximately 40 miles southwest of the Kashagan field. Exploratory drilling continued in 2003 with three additional wells drilled. The Aktote #1 and the Kashagan Southwest #1 were announced as discoveries in November 2003.

During 2004, the successful completion of the first offshore exploration well on the Kairan prospect was announced. Data analysis and additional studies are being conducted to evaluate the discovery. The testing of the Kairan-1 exploration well brings the Exploration Period under the NCPSA to a close. During 2004, appraisal of the Aktote discovery began with the successful drilling of the Aktote-2 appraisal well.

In the South Caspian Sea offshore Azerbaijan, we have a 20 percent interest in the Zafar Mashal prospect. The first exploratory well was completed in the third quarter of 2004 and the prospect declared non-commercial.

E&P—OTHER

In late 2003, we signed an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in its proposed LNG receiving terminal in Quintana, Texas. This agreement gives us 1 billion cubic feet per day of regasification capacity in the terminal and a 50 percent interest in the general partnership managing the venture. The terminal will be designed with a storage capacity of 6.9 billion cubic feet and a send-out capacity of 1.5 billion cubic feet per day. Freeport LNG received conditional approval in June 2004 from the Federal Energy Regulatory Commission (FERC) to construct and operate the facility. Final approval from FERC was received in January 2005. Construction began in early 2005, and commercial startup is expected in 2008.

We are pursuing three other proposed LNG regasification terminals. The Beacon Port Terminal would be located in federal waters in the Gulf of Mexico, 56 miles south of the Louisiana mainland. Also in the Gulf of Mexico is the proposed Compass Port Terminal, to be located approximately 11 miles offshore Alabama. The third proposed facility would be a joint venture located in the Port of Long Beach, California. Each of these projects are in the initial regulatory permitting process.

The Commercial organization optimizes the commodity flows of our E&P segment. This group markets our crude oil and natural gas production, with commodity buyers, traders and marketers in offices in Houston, London, Singapore and Calgary.

Natural Gas Pricing
Compared with the more global nature of crude oil commodity pricing, natural gas prices have historically varied more in different regions of the world. We produce natural gas from regions around the world that have significantly different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices than in the Lower 48 region of the United States. Moreover,

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excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the U.S. Lower 48 states and other markets because of a lack of infrastructure and because of the difficulties in transporting the natural gas. We, along with other companies in the oil and gas industry, are planning long-term projects in regions of excess supply to install the infrastructure required to produce and liquefy natural gas for transportation by tanker and subsequent regasification in regions where market demand is strong, such as to the U.S. Lower 48 states or certain parts of Asia, but where supplies are not as plentiful. Due to the significance of the overall investment in these long-term projects, the natural gas sales prices (to a third-party LNG facility) or transfer prices (to a company-owned LNG facility) in the areas of excess supply are expected to remain well below sales prices for natural gas that is produced closer to areas of high demand and which can be transferred to existing natural gas pipeline networks, such as in the U.S. Lower 48.

E&P—RESERVES

We have not filed any information with any other federal authority or agency with respect to our estimated total proved reserves at December 31, 2004. No difference exists between our estimated total proved reserves for year-end 2003 and year-end 2002, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2004.

DELIVERY COMMITMENTS

We sell crude oil and natural gas from our E&P producing operations under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Our Commercial organization also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the spot market, or a combination of our reserves and the spot market. Worldwide, we are contractually committed to deliver approximately 5.4 trillion cubic feet of natural gas and 167 million barrels of crude oil in the future, including 1.0 trillion cubic feet related to the minority interests of consolidated subsidiaries. These contracts have various expiration dates through the year 2025. Although these delivery commitments could be fulfilled utilizing proved reserves in the United States, the Timor Sea, Nigeria, Indonesia, and the United Kingdom, we anticipate that some of them will be fulfilled with purchases in the spot market. A portion of the natural gas delivery commitment relates to proved undeveloped reserves in the Timor Sea and Indonesia. The Timor Sea reserves are expected to convert from proved undeveloped to proved developed in 2006 upon completion of the liquefied natural gas infrastructure in the region. A portion of the Indonesian reserves are expected to convert to proved developed in 2007, when additional wells are drilled and the expansion of the Suban gas plant is completed.

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. 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. Total natural gas liquids extracted in 2004, including our share of DEFS’, was 194,000 barrels per day, compared with 215,000 barrels per day in 2003.

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

DEFS is headquartered in Denver, Colorado. At December 31, 2004, DEFS owned and operated 55 natural gas liquids extraction plants, owned an equity interest in another nine, and had two classified in discontinued operations. Also at year end, DEFS’ gathering and transmission systems included approximately 59,000 miles of pipeline. In 2004, DEFS’ raw natural gas throughput averaged 6.4 billion cubic feet per day, and natural gas liquids extraction averaged 363,000 barrels per day, compared with 6.6 billion cubic feet per day and 353,000 barrels per day, respectively, in 2003. DEFS’ assets are primarily located in the Gulf Coast area, West Texas, Oklahoma, the Texas Panhandle, the Rocky Mountain area, and western Canada.

Outside of DEFS, our U.S. natural gas liquids business included the following assets as of December 31, 2004:

	•	A 50 percent interest in a natural gas liquids extraction plant in San Juan County, New Mexico, with a gross plant inlet capacity of 500 million cubic feet per day. We also have minor interests in two other natural gas liquids extraction plants.
	•	A 25,000-barrel-per-day capacity natural gas liquids fractionation plant in Gallup, New Mexico.
	•	A 22.5 percent equity interest in Gulf Coast Fractionators, which owns a natural gas liquids fractionation plant in Mont Belvieu, Texas (with our net share of capacity at 25,000 barrels per day).
	•	A 40 percent interest in a fractionation plant in Conway, Kansas (with our net share of capacity at 42,000 barrels per day).

During 2004, we sold certain Midstream assets located primarily in Texas, Louisiana and New Mexico. This reflected our strategy to divest properties that did not support our natural gas production, while focusing on DEFS as the most effective vehicle for generating income from the processing of third-party natural gas. Included in the dispositions was a 700-mile intrastate natural gas and liquids pipeline system in Louisiana.

Our Canadian natural gas liquids business includes the following assets:

	•	A 92 percent operating interest in the 2.4-billion-cubic-feet-per-day Empress natural gas processing and fractionation facilities near Medicine Hat, Alberta, with natural gas liquids production capacity of 50,000 barrels per day.
	•	A 100 percent interest in a 580-mile Petroleum Transmission Company pipeline from Empress to Winnipeg and five related pipeline terminals.
	•	Two underground natural gas liquids storage facilities, comprised of the Richardson caverns with an approximate one-million-barrel capacity and the Dewdney caverns with an approximate three-million-barrel capacity, along with 800 million cubic feet of natural gas storage capacity.

A 10 percent interest in the 1,902-mile Cochin liquefied petroleum gas pipeline, originating in Edmonton, Alberta, and ending in Sarnia, Ontario, and a terminal storage system that transports propane, ethane and ethylene was sold in the fourth quarter of 2004.

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Canadian natural gas liquids extracted averaged 45,000 barrels per day in 2004, the same as 2003.

We also own a 39 percent equity interest in Phoenix Park Gas Processors Limited, a joint venture primarily with the National Gas Company of Trinidad and Tobago Limited, which processes gas in Trinidad and markets natural gas liquids throughout the Caribbean and into the U.S. Gulf Coast. Phoenix Park’s facilities include a 1.35-billion-cubic-feet-per-day gas processing plant and a 46,000-barrel-per-day natural gas liquids fractionator. Our share of natural gas liquids extracted averaged 6,000 barrels per day in 2004.

In Syria, we have a service contract with the Syrian Petroleum Company that expires on December 31, 2005. Our current plan is to honor that contract to its termination date. We expect our presence in Syria to end in 2006, once the formalities of closing out the service contract are accomplished. We have no plans to seek additional business in Syria.

REFINING AND MARKETING (R&M)

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

The R&M segment does not include the results or statistics from our equity investment in LUKOIL, which are reported in a separate segment (LUKOIL Investment). As a result, references to results, refinery crude oil throughput capacities and other statistics throughout the R&M segment exclude those related to our equity investment in LUKOIL.

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

In December 2002, we committed to and initiated a plan to sell approximately 3,200 marketing sites that did not fit into our long-range plans. In the third quarter of 2003, we concluded the sale of all of the Exxon-branded marketing assets in New York and New England, including contracts with independent dealers and marketers. Approximately 230 of the 3,200 sites were included in this package. In the fourth quarter of 2003, we concluded the sale of our Circle K subsidiary, representing approximately 1,660 sites, as well as the assignment of the franchise relationship with more than 350 franchised and licensed stores. Other, smaller dispositions also occurred during 2003. During the second quarter of 2004, we sold our Mobil-branded marketing assets on the East Coast in two separate transactions. Assets in the packages included approximately 100 company-owned-and-operated sites, and 350 dealer sites. The majority of the remaining sites are under contracts expected to close in 2005.

During the second quarter of 2004, we performed a review of the crude oil refining capacities for our worldwide refining operations. We utilize a “barrels-per-calendar-day” methodology, which includes allowances for maintenance turnarounds, regulatory constraints, crude oil quality and reliability. As a result of this review, effective July 1, 2004, R&M’s total U.S. crude oil capacity was revised downward slightly, from 2,168,000 barrels per day to 2,160,000 barrels per day, while R&M’s international refining capacity decreased from 447,000 barrels per day to 428,000 barrels per day.

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UNITED STATES

Refining

At December 31, 2004, we owned and operated 12 crude oil refineries in the United States, having an aggregate crude oil refining capacity of 2,160,000 barrels per day.

East Coast Region
Bayway Refinery
Located on the New York Harbor in Linden, New Jersey, Bayway has a crude oil processing capacity of 238,000 barrels per day and processes mainly light low-sulfur crudes. Crude oil is supplied to the refinery by tanker, primarily from the North Sea and West Africa. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel, and jet fuel along with home heating oil. Other products include petrochemical feedstocks (propylene) and residual fuel oil. The facility distributes its refined products to East Coast customers through pipelines, barges, railcars and trucks. The mix of products produced changes to meet seasonal demand. Gasoline is in higher demand during the summer, while in winter, the refinery optimizes operations to increase heating oil production. The complex also includes a 775-million-pound-per-year polypropylene plant that became operational in March 2003.

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 185,000 barrels per day and processes mainly light low-sulfur crudes. The Bayway and Trainer refineries are operated in coordination with each other by sharing crude oil cargoes, moving feedstocks between the facilities, and sharing certain personnel. Trainer receives crude oil from the North Sea and West Africa. The refinery

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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 247,000 barrels per day and processes mainly light low-sulfur crudes. Alliance receives domestic crude oil from the Gulf of Mexico via pipeline, and crude oil from the North Sea and West Africa via pipeline connected to the Louisiana Offshore Oil Port. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel along with home heating oil. Other products include petrochemical feedstocks (benzene) and anode petroleum coke. The majority of the refined products are distributed to customers through major common-carrier pipeline systems.

Lake Charles Refinery
The Lake Charles refinery is located in Westlake, Louisiana. The refinery has a crude oil processing capacity of 239,000 barrels per day. The refinery receives domestic and international crude oil and processes heavy, high-sulfur, low-sulfur and acidic crude oil. While the sources of its international crude oil can vary, the majority is Venezuelan and Mexican heavy crudes delivered via tanker. The refinery produces a high percentage of transportation fuels such as gasoline, off-road diesel, and jet fuel along with heating oil. The majority of its refined products are distributed to customers by truck, railcar or major common-carrier pipelines. In addition, refined products can be sold into export markets through the refinery’s marine terminal.

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

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

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 216,000 barrels per day, and processes mainly heavy, high-sulfur crude oil, but also processes light, low-sulfur crude oil. The refinery primarily receives crude oil through 100-percent-owned and jointly owned terminals on the Gulf Coast, including a deepwater terminal at Freeport, Texas. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel, and jet fuel, along with home heating oil. Other products include petrochemical feedstocks (benzene) and petroleum (fuel) coke. Refined products are distributed throughout the Midwest and southeastern United States by pipeline, barge and railcar.

ConocoPhillips has a 50 percent interest in Merey Sweeny, L.P., a limited partnership that owns a 65,000-barrel-per-day delayed coker and related facilities at the Sweeny refinery. PDVSA, which owns the other 50 percent interest, supplies the refinery with Venezuelan Merey, or equivalent Venezuelan, crude oil. We are the operating partner.

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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 R&M’s largest refinery, with a crude oil processing capacity of 306,000 barrels per day. The refinery can process a mix of both light low-sulfur and heavy high-sulfur crudes, which it receives from domestic and foreign sources by pipeline. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel, and jet fuel, along with home heating oil. Other products include petrochemical feedstocks (benzene) and asphalt. Through an off-take agreement, a significant portion of its gasoline, diesel and jet fuel is sold to a third party at the refinery for delivery via pipelines into the upper Midwest, including the Chicago, Illinois, and Milwaukee, Wisconsin, metropolitan areas. Remaining refined products are distributed to customers in the Midwest by pipeline, truck, barge and railcar.

During 2003, we purchased certain assets at Premcor’s Hartford, Illinois, refinery. The purchase included the coker, crude unit, catalytic cracker, alkylation unit, isomerization unit, a portion of the site utilities and a portion of the storage tanks at the Premcor facility. The integration of these units into the refinery was completed during the second quarter of 2004, enabling the refinery to process heavier, lower-cost crude oil.

Ponca City Refinery
The Ponca City refinery is located in Ponca City, Oklahoma. It has a crude oil processing capacity of 187,000 barrels per day, and processes light and medium weight, low-sulfur crude oil. Both foreign and domestic crudes are delivered by pipeline from the Gulf of Mexico, Oklahoma, Kansas, Texas and Canada. The 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.

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 146,000 barrels per day, and the natural gas liquids fractionation capacity is 45,000 barrels per day. The natural gas liquids capacity was reduced during 2004 as part of a reconfiguration project. The refinery processes mainly heavy, high-sulfur crudes. The refinery receives crude oil and natural gas liquids feedstocks through our pipelines from West Texas, the Texas Panhandle and Wyoming. The Borger refinery can also receive foreign crude oil via our pipeline systems. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel, and jet fuel, along with a variety of natural gas liquids and solvents. Pipelines move refined products from the refinery to West Texas, New Mexico, Arizona, Colorado, and the Midcontinent region.

West Coast Region
Billings Refinery
The Billings refinery is located in Billings, Montana, and has a crude oil processing capacity of 58,000 barrels per day, processing a mixture of Canadian heavy, high-sulfur crude, plus domestic high-sulfur and low-sulfur crudes, all delivered by pipeline. A delayed coker converts heavy, high-sulfur residue into higher value light oils. The refinery produces a high percentage of transportation fuels, such as gasoline, jet fuel, and diesel, as well as fuel grade petroleum coke. Finished petroleum products from the refinery are delivered via company-owned pipelines, railcars, and trucks. Pipelines transport most of the refined products to markets in Montana, Wyoming, Utah, and Washington.

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Los Angeles Refinery
The Los Angeles refinery is composed of two linked facilities located about five miles apart in Carson and Wilmington, California, about 15 miles southeast of the Los Angeles International airport. Carson serves as the front-end of the refinery by processing crude oil, and Wilmington serves as the back-end by upgrading products. The refinery has a crude oil processing capacity of 139,000 barrels per day and processes mainly heavy, high-sulfur crudes. The refinery receives domestic crude oil via pipeline from California, and foreign and domestic crude oil by tanker through company-owned and third-party terminals in the Port of Los Angeles. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel, and jet fuel. Other products include fuel-grade petroleum coke. The refinery produces California Air Resources Board (CARB) gasoline using ethanol to meet federally mandated oxygenate requirements. Refined products are distributed to customers in Southern California, Nevada and Arizona by pipeline and truck.

San Francisco Refinery
The San Francisco refinery is composed of two linked facilities located about 200 miles apart. The Santa Maria facility is located in Arroyo Grande, California, about 200 miles south of San Francisco, while the Rodeo facility is in the San Francisco Bay area. The refinery’s crude oil processing capacity is 106,000 barrels per day of mainly heavy, high-sulfur crudes. Both the Santa Maria and Rodeo facilities have calciners to upgrade the value of the coke that is produced. The refinery receives crude oil from central California, including the Elk Hills oil field, and foreign crude oil by tanker. Semi-refined liquid products from the Santa Maria facility are sent by pipeline to the Rodeo facility for upgrading to finished petroleum products. The refinery produces transportation fuels, such as gasoline, diesel, and jet fuel. Other products include calcined and fuel-grade petroleum coke. The refinery produces CARB gasoline using ethanol to meet federally mandated oxygenate requirements. Refined products are distributed by pipeline, railcar, truck and barge.

Ferndale Refinery
The Ferndale refinery in Ferndale, Washington, is about 20 miles south of the United States-Canada border on Puget Sound. The refinery has a crude oil processing capacity of 93,000 barrels per day. The refinery primarily receives crude oil from the Alaskan North Slope, with secondary sources supplied by Canada or the Far East. Ferndale operates a deepwater dock that is capable of taking in full tankers bringing North Slope crude oil from Valdez, Alaska. The refinery is also connected to the Terasen crude oil pipeline that originates in Canada. The refinery produces transportation fuels, such as gasoline, diesel, and jet fuel. Other products include residual fuel oil supplying the northwest marine transportation market.

Construction of a new fluidized catalytic cracking unit to increase the yield of transportation fuel, and a new S Zorb unit that reduces the sulfur in gasoline, both became fully operational in 2003. Most refined products are distributed by pipeline and barge to major markets in the northwest United States.

Marketing

In the United States, R&M markets gasoline, diesel fuel, and aviation fuel through approximately 13,300 outlets in 46 states. The majority of these sites utilize the Conoco, Phillips 66 or 76 brands.

Wholesale
In our wholesale operations, we utilize a network of marketers and dealers operating approximately 12,300 outlets. We place a strong emphasis on the wholesale channel of trade because of its lower capital requirements and higher return on capital. Our refineries and transportation systems provide strategic support to these operations. We also buy and sell petroleum products in the spot market. Our refined products are marketed on both a branded and unbranded basis.

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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 Mountain, and West Coast regions. Most of these outlets market merchandise through the Kicks 66, Breakplace, or Circle K brand convenience stores.

At December 31, 2004, CFJ Properties, our 50/50 joint venture with Flying J, owned and operated 98 truck travel plazas that carry the Conoco and/or Flying J brands. The merger of Conoco and Phillips triggered change of control provisions in the joint venture agreement, giving Flying J the option to purchase our interest in CFJ Properties at fair value. Flying J elected not to exercise their purchase option. As a result, we plan to continue as a co-venturer in CFJ Properties.

Transportation

Pipelines and Terminals
At December 31, 2004, we had approximately 32,500 miles of common-carrier crude oil, raw natural gas liquids and products pipeline systems in the United States, including those partially owned and/or operated by affiliates. We also owned and/or operated 66 finished product terminals, 10 liquefied petroleum gas terminals, seven crude oil terminals and one coke exporting facility.

Tankers
At December 31, 2004, we had under charter 16 double-hulled crude oil tankers, with capacities ranging in size from 650,000 to 1,100,000 barrels. These tankers are utilized to transport feedstocks to certain of our U.S. refineries. We also have a domestic fleet of both owned and chartered boats and barges providing inland and ocean-going waterway transportation. The information above excludes the operations of the 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 specialty products including petroleum cokes, lubes (such as automotive and industrial lubricants), solvents, and pipeline flow improvers to commercial, industrial and wholesale accounts worldwide.

Lubricants are marketed under the Conoco, Phillips 66, 76 Lubricants and Kendall Motor Oil brands. The distribution network consists of over 5,000 outlets, including mass merchandise stores, fast lubes, tire stores, automotive dealers, and convenience stores. Lubricants are also sold to industrial customers in many markets.

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

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We have a 50 percent interest in Penreco, a specialties company, which manufactures and markets highly refined specialty petroleum products, including solvents, waxes, petrolatums and white oils, for global markets.

We manufacture high-quality graphite and anode-grade cokes in the United States and Europe for use in the global steel and aluminum industries. Venco is a coke calcining joint venture in which we have a 50 percent interest. Base green petroleum coke volumes are supplied to Venco’s Lake Charles calcining facility from our Alliance, Lake Charles, and Ponca City refineries.

INTERNATIONAL

Refining

At December 31, 2004, R&M owned or had an interest in six refineries outside the United States with an aggregate crude oil capacity of 428,000 net barrels per day.

Humber Refinery
Our wholly owned Humber refinery is located in North Lincolnshire, United Kingdom. The refinery’s crude oil processing capacity is 221,000 barrels per day. Crude oil processed at the refinery is supplied primarily from the North Sea and includes lower-cost, acidic crudes. The refinery also processes other intermediate feedstocks, mostly vacuum gas oils and residual fuel oil. The 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 fuel oil. The refinery also has two coking units with associated calcining plants, which upgrade the heavy “bottoms” and imported feedstocks into light-oil products and high-value graphite and anode petroleum cokes. Approximately 70 percent of the light oils produced in the refinery are marketed in the United Kingdom, while the other products are exported to the rest of Europe and the United States.

Whitegate Refinery
The Whitegate refinery is located in Cork, Ireland, and has a crude oil processing capacity of 71,000 barrels per day. Crude oil processed by the refinery is light sweet crude sourced mostly from the North Sea. The refinery primarily produces transportation fuels and fuel oil, which are distributed to the inland market via truck and sea, as well as being exported to the European market. We also operate a deepwater crude oil and products storage complex with a 7.5-million-barrel capacity in Bantry Bay, Cork, Ireland.

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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 45 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 a delayed coker. The refinery produces both fuel grade and specialty calcined cokes. The refinery processes crude and other feedstocks supplied by each of the partners in proportion to their respective ownership interests.

Czech Republic Refineries
Through our participation in Èeská rafinérská, a.s. (CRC), we have a 16.33 percent ownership in two refineries in the Czech Republic, giving us a net capacity share of 27,000 barrels per day. The refinery at Litvinov has a crude oil processing capacity of 103,000 barrels per day and processes Russian export blend crude oil delivered by pipeline. Litvinov includes both hydrocracking and visbreaking, producing a high yield of transport fuels and petrochemical feedstocks and only a small amount of fuel oil. The Kralupy refinery has a crude oil processing capacity of 63,000 barrels per day and processes low-sulfur crude, mostly from the Mediterranean. Kralupy has a new fluidized catalytic cracking unit, which gives the refinery a high yield of transport fuels. The two refineries complement each other and are run on an overall optimized basis, with certain intermediate streams moving between the two plants. CRC processes crude and other feedstocks supplied by ConocoPhillips and the other partners, with each partner receiving their proportionate share of the resulting products. We market our share of these finished products in both the Czech Republic and in neighboring markets.

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. The refinery has a rated crude oil processing capacity of 119,000 barrels per day, of which our share is 56,000 barrels per day. Crude oil processed by the refinery is sourced mostly from the Middle East. The refinery produces a full range of refined petroleum products. The refinery capitalizes on our proprietary coking technology to upgrade low-cost feedstocks to higher-margin products. Our share of refined products is distributed by truck to the company’s “ProJET” retail sites in Malaysia, or transported by sea, primarily to Asian markets.

Marketing

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

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

As of December 31, 2004, R&M had approximately 2,100 marketing outlets in its European operations, of which about 1,480 were company-owned, and 620 were dealer-owned. Through our joint venture operations in Turkey and Switzerland, we also have interests in approximately 810 additional sites.

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The company’s largest branded site networks are in Germany and the United Kingdom, which account for approximately 63 percent of our total European branded units.

As of December 31, 2004, R&M had 143 marketing outlets in our wholly owned Thailand operations in Asia. In addition, through a joint venture in Malaysia with Sime Darby Bhd., a company that has a major presence in the Malaysian business sector, we also have an interest in another 43 retail sites. In Thailand and Malaysia, retail products are marketed under the “JET” and “ProJET” brands, respectively.

LUKOIL INVESTMENT

In September 2004, we made a joint announcement with LUKOIL, an international integrated oil and gas company headquartered in Russia, of an agreement to form a broad-based strategic alliance, whereby we would become a strategic equity investor in LUKOIL. Together, we also announced our intention to form a joint venture between the two companies to develop resources in the northern part of Russia’s Timan-Pechora oil and gas province and the intention of the two companies to jointly seek the right to develop the West Qurna oil field in Iraq.

In the announcement, we disclosed that we were the successful bidder in an auction of 7.6 percent of LUKOIL’s authorized and issued ordinary shares held by the Russian government. The transaction closed on October 7, 2004. By year-end 2004, we had increased our ownership in LUKOIL to 10 percent. Under the Shareholder Agreement between the two companies, we had the right to nominate a representative to the LUKOIL Board of Directors (Board). In January 2005, our nominee was elected to the LUKOIL Board, and certain amendments to LUKOIL’s corporate charter that require unanimous Board consent for certain key decisions were approved. In addition, the Shareholder Agreement allows us to increase our ownership interest in LUKOIL to 20 percent and limits our ability to sell our LUKOIL shares for a period of four years, except in certain circumstances. Once we reach 12.5 percent ownership, we have the right to nominate a second representative to the LUKOIL Board. We use the equity method of accounting for our investment in LUKOIL. We estimate that our net share of LUKOIL’s proved reserves at December 31, 2004, was 880 million barrels of oil equivalent.

As reported in LUKOIL’s 2003 annual report, the majority of its upstream production is sourced within Russia, with 68 percent from the western Siberia region, 14 percent from the Timan-Pechora region and 13 percent from the Urals region. Outside of Russia, LUKOIL has projects in Azerbaijan, Kazakhstan, Egypt and Iraq. Downstream, LUKOIL has seven refineries with a net crude oil throughput capacity of approximately 1.2 million barrels daily. In addition, LUKOIL has an interest in approximately 4,600 retail sites in Russia and Europe, and another approximately 2,000 in the northeast United States.

CHEMICALS

Chevron Phillips Chemical Company LLC (CPChem) is a 50/50 joint venture with ChevronTexaco Corporation. We use the equity method of accounting for our investment in CPChem.

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

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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 one pipe fittings plant and nine plastic pipe plants in eight states.

Major international production facilities, including CPChem’s joint-venture facilities, are located in Belgium, China, Saudi Arabia, Singapore, South Korea and Qatar. In addition, there is one plastic pipe plant in Mexico.

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

Construction of a major olefins and polyolefins complex in Mesaieed, Qatar, called “Q-Chem I,” was completed in 2003. The facility completed performance testing and became fully operational in 2004. It has an annual capacity of approximately 1.1 billion pounds of ethylene, 1 billion pounds of polyethylene and 100 million pounds of 1-hexene. CPChem has a 49 percent interest, with a Qatar state firm owning the remaining 51 percent interest.

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

In 2003, CPChem formed a 50 percent-owned joint venture company to develop an integrated styrene facility in Al Jubail, Saudi Arabia. The facility, to be built on a site adjacent to the existing aromatics complex owned by Saudi Chevron Phillips Company (SCP), another 50 percent-owned CPChem joint venture, will include feed fractionation, an olefins cracker, and ethylbenzene and styrene monomer processing units. Construction of the facility will be in conjunction with an expansion of SCP’s benzene plant. Construction began in the fourth quarter of 2004 and operational startup is anticipated in late 2007.

EMERGING BUSINESSES

Emerging Businesses encompass the development of new businesses beyond our traditional operations.

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, operated during 2004 as planned. The plant will be operated in 2005 as necessary to obtain technical data for commercial applications.

Technology Solutions
Our Technology Solutions businesses provide both upstream and downstream technologies and services that can be used in our operations or licensed to third parties. Downstream, major product lines include sulfur removal technologies (S Zorb SRT), alkylation technologies (ReVAP), and delayed coking (ThruPlus) technologies. We also offer a gasification technology (E-Gas) that uses petroleum coke, coal,

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and other low-value hydrocarbon as feedstock, resulting in high-value synthesis gas that can be used for a slate of products, including power, hydrogen and chemicals.

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 their respective E&P and R&M segments. The projects and assets that have a significant merchant component are included in the Emerging Businesses segment.

The power business completed development of a 730-megawatt, gas-fired combined heat and power plant in North Lincolnshire, United Kingdom. The facility provides steam and electricity to the Humber refinery and steam to a neighboring refinery, as well as merchant power into the U.K. market. Construction began in 2002, and the project was placed in commercial operations in October 2004.

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

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

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.

Upstream, our E&P segment competes with numerous other companies in the industry to locate and obtain new sources of supply, and to produce oil and natural gas in an efficient, cost-effective manner. Based on reserves statistics published in the September 13, 2004, issue of the Oil and Gas Journal, our E&P segment had, on a BOE basis, the eighth-largest total of worldwide reserves of non-government-controlled companies. We deliver our oil and natural gas production into the worldwide oil and natural gas commodity markets. The principal methods of competing include geological, geophysical and engineering research and technology; experience and expertise; and economic analysis in connection with property acquisitions.

The Midstream segment, through our equity investment in DEFS and our consolidated operations, competes with numerous other integrated petroleum companies, as well as natural gas transmission and distribution companies, to deliver the components of natural gas to end users in the commodity natural gas markets. DEFS is a large producer of natural gas liquids in the United States. DEFS’ principle methods of competing include economically securing the right to purchase raw natural gas into its gathering systems, managing the pressure of those systems, operating efficient natural gas liquids processing plants, and securing markets for the products produced.

Downstream, our R&M segment competes primarily in the United States, Europe and the Asia Pacific region. Based on the statistics published in the December 20, 2004, issue of the Oil and Gas Journal, our R&M segment had the largest U.S. refining capacity of 14 large refiners of petroleum products.

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Worldwide, it ranked fifth among non-government-controlled companies. In the Chemicals segment, through our equity investment, CPChem generally ranks within the top 10 producers of many of its major product lines, based on average 2004 production capacity, as published by industry sources. Petroleum products, petrochemicals and plastics are delivered into the worldwide commodity markets. Elements of downstream competition include product improvement, new product development, low-cost structures, and manufacturing and distribution systems. In the marketing portion of the business, competitive factors include product properties and processibility, reliability of supply, customer service, price and credit terms, advertising and sales promotion, and development of customer loyalty to ConocoPhillips’ or CPChem’s branded products.

GENERAL

At the end of 2004, we held a total of 1,692 active patents in 70 countries worldwide, including 697 active U.S. patents. During 2004, we received 51 patents in the United States and 121 foreign patents. Our products and processes generated licensing revenues of $28 million in 2004. The overall profitability of any business segment is not dependent on any single patent, trademark, license, franchise or concession. Company-sponsored research and development activities charged against earnings were $126 million, $136 million and $355 million in 2004, 2003 and 2002, respectively.

The environmental information contained in Management’s Discussion and Analysis on pages 77 through 80 under the caption, “Environmental” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2004 and those expected for 2005 and 2006.

International and domestic political developments and government regulation at all levels are prime factors that may materially affect our operations. Such political developments and regulation may affect prices; production levels; asset ownership; allocation and distribution of raw materials and products, including their import, export and ownership; the amount of tax and timing of payment; and the cost and compliance for environmental protection. The occurrences and effects of such events are not predictable.

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Web Site Access to SEC Reports

Our Internet Web site address is http://www.conocophillips.com. Information contained on our Internet Web site is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our Web site, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s Internet Web site at http://www.sec.gov.

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Item 3. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the fourth quarter of 2004 and those matters previously reported in ConocoPhillips’ 2003 Form 10-K and our first-, second- and third-quarter 2004 Forms 10-Q that have not been resolved. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceeding was decided adversely to ConocoPhillips, there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission’s regulations.

In December 2004, the Puget Sound Clean Air Agency (PSCAA) notified us of their intent to seek civil penalties in the amount of $203,000 for alleged violations of various PSCAA regulations at our Tacoma Terminal in the state of Washington. We are currently assessing these allegations and expect to work with the PSCAA towards a resolution of this matter.

In December 2004, the San Luis Obispo Air Pollution Control District (SLOAPCD) notified us of their intent to seek civil penalties in the amount of $2,700,000 for alleged violations of various SLOAPCD regulations at the Santa Maria facility of our San Francisco refinery. We are currently assessing these allegations and expect to work with the SLOAPCD towards a resolution of this matter.

We participated in negotiations throughout 2004 with the U.S. Environmental Protection Agency (EPA), U.S. Department of Justice (DOJ), the states of Louisiana, Illinois, Pennsylvania, New Jersey, and the Northwest Clean Air Agency (the state of Washington) to settle allegations arising out of the EPA’s national enforcement initiative, as well as other related Clean Air Act regulation issues. In January 2005, we entered into a consent decree with the United States and the local agency and states named above. In the consent decree, we agreed to reduce air emissions from refineries in Washington, California, Texas, Louisiana, Illinois, Pennsylvania, and New Jersey by approximately 47,000 tons per year over the next eight years. We plan to spend an estimated $525 million over that time period to install control technology and equipment to reduce emissions from stacks, vents, valves, heaters, boilers, and flares. The consent decree requires us to pay a civil penalty of $4.5 million in addition to at least $10 million to be spent on supplemental environmental projects in Illinois, Pennsylvania, Louisiana, Washington, and New Jersey.

The U.S. Coast Guard and Washington State Department of Ecology are investigating the possible sources of an alleged oil spill in Puget Sound. In November 2004, the U.S. Attorney and the U.S. Coast Guard offices in Seattle, Washington, issued subpoenas to Polar Tankers, Inc., a subsidiary of ConocoPhillips Company, for records related to the vessel Polar Texas. On December 23, 2004, the Governor of the state of Washington and the U.S. Coast Guard publicly announced that they believed the Polar Texas was the source of the alleged spill. Based on everything presently known by the company, we do not believe that we are the source of the alleged spill. The company is fully cooperating with the governmental authorities.

On August 24, 2003, the Contra Costa County District 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 (BAAQMD) regulations at the Rodeo facility of our San Francisco refinery. On October 12, 2004, we entered into a settlement with the BAAQMD to resolve the alleged violations. We paid a civil penalty of $350,000 to the BAAQMD.

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In August 2004 Polar Tankers, Inc., a subsidiary of ConocoPhillips Company, self-reported to the U.S. Coast Guard that a company employee had disclosed to management potential environmental violations onboard the vessel Polar Alaska. The potential violations related to allegations that certain actions may have resulted in one or more wastewater streams being discharged potentially having concentrations of oil exceeding an applicable regulatory limit of 15 parts per million. On September 1, 2004, the United States Attorney’s office in Anchorage issued a subpoena to ConocoPhillips Company and Polar Tankers, Inc. for records relating to the company’s report of potential violations. The company is fully cooperating with the governmental authorities.

On March 2, 2004, the BAAQMD notified us of their intent to seek civil penalties in the amount of $750,000 for 17 alleged violations of various BAAQMD regulations at our Rodeo facility and carbon plant located in the San Francisco area. We are currently assessing these allegations and expect to work with the BAAQMD towards a negotiated resolution of this matter.

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

In November 2003, the EPA issued us a notice of violation for alleged violations of the gasoline Reid Vapor Pressure rules in 1999, 2000 and 2001 at our Wood River and Billings refineries. The alleged violations have been resolved as part of the January 2005 consent decree we entered into with the United States and other parties named above.

In August of 2003, EPA Region 6 issued a Show Cause Order alleging violations of the Clean Water Act at the Borger refinery. The alleged violations relate primarily to discharges of selenium and reported exceedances of permit limits for whole effluent toxicity. We met with the EPA staff on several occasions to discuss the allegations. We believe the EPA staff is evaluating the information presented at the meetings. The EPA has not yet proposed a penalty amount.

On December 31, 2002, we received a Revised Proposed Agreed Order, which amended the June 24, 2002, Proposed Agreed Order, from the Texas Commission on Environmental Quality (TCEQ), proposing a penalty of $458,163 in connection with alleged air emission violations at our Borger refinery as a result of an inspection conducted by the TCEQ in October 2000. On March 19, 2003, the TCEQ issued a recalculation of the proposed penalty in the amount of $467,834. We agreed to resolve this matter for $410,000.

On December 17, 2002, the DOJ notified ConocoPhillips of various alleged violations of the National Pollution Discharge Elimination System permit for the Sweeny refinery. DOJ asserts that these alleged violations occurred at various times during the period beginning January 1997 through July 2002. A consent decree was lodged with the U.S. District Court for the Southern District of Texas, Houston Division on October 4, 2004, proposing a civil penalty of $610,000 and a Supplemental Environmental Project (SEP) valued at approximately $90,000. Under the SEP, ConocoPhillips will donate approximately 128 acres of land it owns near the Sweeny refinery to the U.S. Fish and Wildlife Service for inclusion in the San Bernard National Wildlife Refuge. We await the court’s approval and entry of the consent decree.

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On July 15, 2002, the United States filed a Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) cost recovery action against Conoco Inc. and seven other defendants alleging that the United States had incurred unreimbursed response costs at the Lowry Superfund Site located in Arapahoe County, Colorado. The United States seeks recovery of approximately $12.3 million in past response costs and a declaratory judgment for future CERCLA response cost liability. The defendants filed counterclaims seeking declaratory relief that certain response actions taken by the government were inconsistent with the National Contingency Plan. The defendants’ counterclaims, if successful, will reduce the total amount of response costs that are reimbursable to the government.

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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, 2005. Set forth below is information about 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 effective January 1, 2003, having previously served as President of ConocoPhillips’ Asia Pacific operations since completion of the merger. Prior to the merger, he was Phillips’ Senior Vice President E&P Eurasia-Middle East operations since 2001; and Phillips’ Vice President E&P Eurasia operations since 1998.

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

Philip L. Frederickson was appointed Executive Vice President, Commercial of ConocoPhillips upon completion of the merger. Prior to the merger, he was 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 p.l.c. (now BP p.l.c.) where he was executive vice president and group chief of staff after serving as vice president and general counsel of Amoco.

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

J. J. Mulva was appointed Chairman of the Board of Directors, President and Chief Executive Officer of ConocoPhillips effective October 1, 2004, having previously served as ConocoPhillips’ President and Chief Executive Officer since completion of the merger. Prior to the merger, he was Phillips’ Chairman of the Board of Directors and Chief Executive Officer since 1999.

J. W. Nokes was appointed Executive Vice President, Refining, Marketing, Supply and Transportation of ConocoPhillips upon completion of the merger. Prior to the merger, he was 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, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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.”

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Issuer Purchases of Equity Securities

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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:

	•	The merger of Conoco and Phillips in 2002.
	•	The classification of a substantial portion of our retail marketing operations as discontinued operations in late 2002.
	•	The acquisition of Tosco Corporation in 2001.
	•	The acquisition of Atlantic Richfield Company’s Alaskan operations in 2000.
	•	The contribution of a significant portion of the company’s midstream and chemicals businesses into joint ventures accounted for using equity-method accounting in 2000.

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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Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

February 25, 2005

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 92.

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 Overview

ConocoPhillips is an international, integrated energy company. We are the third largest integrated energy company in the United States, based on market capitalization. We have approximately 35,800 employees worldwide, and at year-end 2004 had assets of $93 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.” Our business is organized into six operating segments:

	•	Exploration and Production (E&P) —This segment primarily explores for, produces and markets crude oil, natural gas, and natural gas liquids on a worldwide basis.
	•	Midstream—This segment gathers and processes natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States, Canada and Trinidad. The Midstream segment includes our 30.3 percent equity investment in Duke Energy Field Services, LLC (DEFS), a joint venture with Duke Energy Corporation.
	•	Refining and Marketing (R&M) —This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.
	•	LUKOIL Investment—This segment consists of our equity investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia. Our investment was 10 percent at December 31, 2004.

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	•	Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem), a joint venture with ChevronTexaco Corporation.
	•	Emerging Businesses—This segment encompasses the development of new businesses beyond our traditional operations, including new technologies related to natural gas conversion into clean fuels and related products (e.g., gas-to-liquids), technology solutions, power generation, and emerging technologies.

Crude oil and natural gas prices, along with refining margins, play the most significant roles in our profitability. Accordingly, our overall earnings depend primarily upon the profitability of our E&P and R&M segments. Crude oil and natural gas prices, along with refining 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:

•

Adding to our proved reserve base. We add to our proved reserve base in three primary ways:

	o	Successful exploration and development of new fields.
	o	Acquisition of existing fields.
	o	Applying new technologies and processes to boost recovery from existing fields.

		Through a combination of all three methods listed above, we have been successful in the past in maintaining or adding to our production and proved reserve base, and we anticipate being able to do so in the future. In the three years ending December 31, 2004, our reserve replacement exceeded 200 percent, excluding the impact of our equity investment in LUKOIL. The replacement rate was primarily attributable to the merger of Conoco and Phillips, and extensions and discoveries. Improved recovery also positively contributed to our reserve replacement success. Although it cannot be assured, going forward, we expect to more than replace our production over the next three years, excluding the impact of our equity investment in LUKOIL. This expectation is based on our current slate of exploratory and improved recovery projects.
	•	Operating our producing properties and refining and marketing operations safely, consistently and in an environmentally sound manner. Safety is our first priority and we are committed to protecting the health and safety of everyone who has a role in our operations. Maintaining high utilization rates at our refineries, minimizing downtime in producing fields, and maximizing the development of our reserves all enable us to capture the value the market gives us in terms of prices and margins. During 2004, our worldwide refinery utilization rate was 94 percent, compared with 95 percent in 2003. Finally, our operations are conducted in a manner that emphasizes our environmental stewardship.
	•	Controlling costs and expenses. Since we cannot control the prices of the commodity products we sell, keeping our operating and overhead costs low, within the context of our commitment to safety and environmental stewardship, is a high priority. We monitor these costs using various methodologies that are reported to senior management monthly, on both an absolute-dollar basis and a per-unit basis. Because low operating and overhead costs are critical to maintaining competitive positions in our industries, cost control is a component of our variable compensation programs.
	•	Selecting the appropriate projects in which to invest our capital dollars. We participate in capital-intensive industries. As a result, we must often invest significant capital dollars to explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, or continue to maintain and improve our refinery complexes. We invest in those projects that are expected to provide an adequate financial return on invested dollars. However, there are often long lead times

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		from the time we make an investment to the time that investment is operational and begins generating financial returns. Our capital expenditures and investments in 2004 totaled $9.5 billion, and we anticipate capital expenditures and investments to be approximately $7.9 billion in 2005. The 2005 amount excludes any discretionary expenditures that may be made to further increase our equity investment in LUKOIL. Excluding investments in LUKOIL, we project that 2005 capital expenditures will be higher than 2004 due to ongoing development projects, cost increases and new opportunities.
	•	Managing our asset portfolio. We continue to evaluate opportunities to acquire assets that will contribute to future growth at competitive prices. We also continually assess our assets to determine if any no longer fit our growth strategy and should be sold or otherwise disposed. This management of our asset portfolio is important to ensuring our long-term growth and maintaining adequate financial returns. During 2004 we substantially completed the asset disposition program that we announced at the time of the merger. Also during 2004, we acquired a 10 percent interest in LUKOIL, a major Russian integrated energy company.
	•	Hiring, developing and retaining a talented workforce. We want to attract, train, develop and retain individuals with the knowledge and skills to implement our business strategy and who support our values and ethics.

Our key performance indicators are shown in the statistical tables provided at the beginning of the 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.

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

	•	Property and leasehold impairments. As mentioned above, we participate in capital-intensive industries. At times, these investments become impaired when our reserve estimates are revised downward, when crude oil or natural gas prices decline significantly for long periods of time, or when a decision to dispose of an asset leads to a write-down to fair market value. Property impairments in 2004 totaled $164 million, compared with $252 million in 2003. We may also invest large amounts of money in exploration blocks which, if exploratory drilling proves unsuccessful, could lead to material impairment of leasehold values.
	•	Goodwill. As a result of mergers and acquisitions, at year-end 2004 we had $15 billion of goodwill on our balance sheet. Although our latest tests indicate that no goodwill impairment is currently required, future deterioration in market conditions could lead to goodwill impairments that would have a substantial negative affect on our profitability.
	•	Tax jurisdictions. As a global company, our operations are located in countries with different tax rates and fiscal structures. Accordingly, our overall effective tax rate can vary significantly between periods based on the “mix” of earnings within our global operations.

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 2004, which contributed significantly to what we view as strong results from this segment in 2004. Industry crude oil prices were approximately $10 per barrel higher in 2004, versus 2003, averaging $41.42 per barrel for West Texas Intermediate. The increase primarily was due to strong global consumption associated with the robust global economic recovery and particularly strong demand growth in China, as well as oil supply disruptions in Iraq and in the U.S. Gulf of Mexico due to hurricane activity, with little excess OPEC production capacity available to replace lost supplies. Industry U.S. natural gas prices were moderately higher in 2004, versus 2003,

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averaging approximately $6.13 per thousand cubic feet for Henry Hub. Natural gas prices rose in 2004 due primarily to higher oil prices, continued concerns regarding the adequacy of U.S. natural gas supplies, and hurricane activity disrupting production in the U.S. Gulf of Mexico. At year-end 2004, we estimated that a $1 per barrel change in crude oil prices would have an estimated $180 million annual impact on net income. For natural gas, the corresponding impact is approximately $50 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 DEFS. Higher natural gas liquids prices improved results from this segment in 2004. During 2004, we sold 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 2004 were improved over 2003, resulting in improved R&M profitability. Industry U.S. refining margins were sharply higher in 2004 versus 2003 due to robust U.S. refined product demand and concerns regarding the adequacy of refined product supplies in the U.S. market in light of tightening gasoline specifications and the ban on methyl tertiary-butyl ether (MTBE) in New York and Connecticut. Industry U.S. marketing margins declined in 2004 versus 2003, as wholesale and retail prices did not keep pace with rising gasoline and diesel spot market prices, which rose in part as a consequence of the increase in crude oil prices. At year-end 2004, we estimated that a 25 cent per barrel change in worldwide refining margins would have an estimated $125 million annual impact on net income. For U.S. marketing margins, the corresponding impact is approximately $100 million for a 1 cent per gallon margin change. Our refineries operated at 94 percent of capacity in 2004, and our goal in 2005 is to operate at an even higher level.

The LUKOIL Investment segment consists of our investment in the ordinary shares of LUKOIL. In October 2004, we closed on a transaction to acquire 7.6 percent of LUKOIL’s shares held by the Russian government for approximately $2 billion. During the remainder of the year, we acquired additional shares in the open market for an additional $641 million, bringing our equity ownership interest in LUKOIL to 10 percent by year-end 2004.

The Chemicals segment consists of our 50 percent interest in 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 had been in a cyclical downturn that began in late 2000. In this difficult market environment, CPChem 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. During 2004, margins improved in the chemicals and plastics industries, leading to improved results from this segment.

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.

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At December 31, 2004, we had a debt-to-capital ratio of 26 percent, compared with 34 percent at the end of 2003. The decrease was due to a $2.8 billion reduction in debt during 2004, along with increased equity reflecting strong earnings. If market conditions permit, we are targeting to lower our debt-to-capital ratio over the next several years to the low-20-percent range. This should improve our cost of capital and further position us for growth opportunities in the future.

Consolidated Results

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

2004 vs. 2003

Net income was $8,129 million in 2004, compared with $4,735 million in 2003. The improved results in 2004 primarily were due to:

	•	Improved refining margins in our R&M segment.
	•	Higher crude oil, natural gas and natural gas liquids prices in our E&P and Midstream segments.
	•	Improved margins in the Chemicals segment.
	•	Initial equity earnings from our investment in LUKOIL.

See the “Segment Results” section for additional information on our segment results.

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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:

	•	Increased E&P and R&M production volumes as a result of the merger.
	•	Higher crude oil, natural gas, and natural gas liquids prices in our E&P segment.
	•	Improved refining and marketing margins in our R&M segment.
	•	Lower impairments and lease loss accruals related to discontinued operations.
	•	Lower merger-related expenses in 2003, compared with 2002.

Income Statement Analysis

2004 vs. 2003

Sales and other operating revenues increased 30 percent in 2004, while purchased crude oil, natural gas and products increased 34 percent. These increases mainly were due to:

	•	Higher petroleum products prices.
	•	Higher prices for crude oil, natural gas and natural gas liquids.
	•	Increased volumes of natural gas bought and sold by our commercial organization in its role of optimizing the commodity flows of our E&P segment.
	•	Higher excise, value added and other similar taxes.

Equity in earnings of affiliates increased 183 percent in 2004. The increase reflects initial equity earnings from our investment in LUKOIL, as well as improved results from:

	•	Our heavy-oil joint ventures in Venezuela (Hamaca and Petrozuata), due to higher crude oil prices and higher production volumes.
	•	Our chemicals joint venture, Chevron Phillips Chemical Company LLC, due to higher volumes and margins.
	•	Our midstream joint venture, Duke Energy Field Services, LLC, reflecting higher natural gas liquids prices.
	•	Our joint-venture refinery in Melaka, Malaysia, due to improved refining margins in the Asia Pacific region.
	•	Our joint-venture delayed coker facilities at the Sweeny, Texas, refinery, Merey Sweeny LLP, due to wider heavy-light crude oil differentials.

Depreciation, depletion and amortization (DD&A) increased 9 percent in 2004, primarily due to new fields onstream for a full year for the first time in 2004, including the Bayu-Undan field in the Timor Sea; the Su Tu Den field, offshore Vietnam; and the Grane field in the Norwegian North Sea. In addition, foreign currency rates and the Norway Removal Grant Act increased DD&A in 2004. In 2005, we expect DD&A to increase by approximately 15 percent over 2004 levels, reflecting new projects in the E&P segment, including a full year’s production from the Magnolia field in the Gulf of Mexico and the Belanak field, offshore Indonesia, as well as new production from the Clair field in the Atlantic Margin and continued ramp-up at the Bayu-Undan field.

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Interest and debt expense declined 35 percent in 2004. The decrease primarily was due to lower average debt levels during 2004 and an increased amount of interest being capitalized on major capital projects.

Our effective tax rate for 2004 was 44 percent, compared with 45 percent for 2003. The decrease in the effective tax rate in 2004, compared with 2003, mainly was due to the impact of a higher proportion of income in lower tax rate jurisdictions, partially offset by reduced benefits from tax rate reductions.

We adopted Financial Accounting Standards Board (FASB) Statement No. 143, “Accounting for Asset Retirement Obligations,” (SFAS No. 143) effective January 1, 2003. As a result, we recognized a benefit of $145 million for the cumulative effect of this accounting change. Also effective January 1, 2003, we adopted Financial Accounting Standards Board Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities,” (FIN 46(R)) 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. We recognized a net $95 million charge in 2003 for the cumulative effect of these two accounting changes.

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, when comparing 2003 with 2002, the merger significantly increased:

	•	Sales revenues and purchase costs due to higher volumes of products being bought and sold.
	•	Equity earnings due to an increased number of equity affiliates.
	•	Production and operating expenses and selling, general and administrative expenses due to the increased size and scope of operations following the merger, partially offset by lower merger-related costs in 2003.
	•	Depreciation, depletion and amortization due to the increased depreciable asset base.
	•	Taxes other than income taxes due to higher gasoline sales, production volumes and property and payroll taxes.
	•	Interest and debt expense due to higher debt levels following the merger.

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.

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.

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.

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 SFAS No. 143. See Note 2—Changes in Accounting Principles, in the Notes to Financial Statements, for additional information.

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In addition to the merger impact, interest and debt expense also increased in 2003 because of the adoption of FIN 46(R). The adoption of FIN 46(R) 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, 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 6—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.

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. The restructuring program was essentially completed during 2004. The information in Note 5—Restructuring, in the Notes to Consolidated Financial Statements, is incorporated herein by reference.

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Segment Results

E&P

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The E&P segment explores for, produces and markets crude oil, natural gas, and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the bitumen and upgrade it into a synthetic crude oil. At December 31, 2004, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Nigeria, Venezuela, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, the United Arab Emirates, Vietnam, and Russia.

2004 vs. 2003

Net income from the E&P segment increased 33 percent in 2004. The increase primarily was due to higher crude oil prices and, to a lesser extent, higher natural gas and natural gas liquids prices. Increased sales prices were partially offset by lower crude oil and natural gas production, as well as higher exploration expenses and lower net gains on asset dispositions. The 2003 period included a net benefit of $142 million for the cumulative effect of accounting changes (SFAS No. 143 and FIN 46(R)), as well as benefits of $233 million from changes in certain international income tax and site restoration laws and equity realignment of certain Australian operations. Included in 2004 is a $72 million benefit related to the remeasurement of deferred tax liabilities from the 2003 Canadian graduated tax rate reduction and a 2004 Alberta provincial tax rate change.

If crude oil and natural gas prices in 2005 do not remain at the historically strong levels experienced in 2004, E&P’s earnings would be negatively impacted in 2005. See the “Business Environment and Executive Overview” section for additional discussion of crude oil and natural gas prices, including estimates of our E&P segment’s sensitivities to crude oil and natural gas prices.

Proved reserves at year-end 2004 were 7.61 billion barrels of oil equivalent (BOE), compared with 7.85 billion BOE at year-end 2003. This excludes the estimated 880 million BOE reported in the LUKOIL Investment segment. Our Canadian Syncrude mining operations had an additional 258 million barrels of proved oil sands reserves at the end of 2004, compared with 265 million barrels at year-end 2003.

2003 vs. 2002

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(R) for variable interest entities involving synthetic leases and certain other financing structures increased E&P’s net income by $142 million in 2003.

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.

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U.S. E&P

2004 vs. 2003

Net income from our U.S. E&P operations increased 24 percent in 2004. The increase was mainly the result of higher crude oil prices and, to a lesser extent, higher natural gas and natural gas liquids prices, partially offset by lower crude oil and natural gas production volumes and lower net gains on asset dispositions. In addition, the 2003 period included a net benefit of $142 million for the cumulative effect of accounting changes (SFAS No. 143 and FIN 46(R)).

U.S. E&P production on a BOE basis averaged 629,000 barrels per day in 2004, down 7 percent from 674,000 BOE per day in 2003. The decreased production primarily was the result of the impact of 2003 asset dispositions, normal field production declines, and planned maintenance activities during 2004.

2003 vs. 2002

Net income from our U.S. E&P operations increased 105 percent in 2003, compared with 2002. The improvement reflects higher crude oil and natural gas prices, higher production volumes, and a net $143 million benefit from the cumulative effect of adopting SFAS No. 143 and FIN 46(R).

U.S. E&P production averaged 674,000 BOE per day in 2003, an increase of 15 percent from 587,000 BOE per day in 2002. The increased production primarily was the result of the merger, as well as increased production from the Borealis satellite field at Kuparuk and from the Alpine field, partially offset by normal field production declines and the impact of asset dispositions.

International E&P

2004 vs. 2003

Net income from our international E&P operations increased 43 percent in 2004. The increase primarily was due to higher crude oil prices and, to a lesser extent, higher natural gas and natural gas liquids prices and higher natural gas liquids volumes. Higher prices were partially offset by increased exploration expenses.

International E&P production averaged 913,000 BOE per day in 2004, down slightly from 916,000 BOE per day in 2003. This excludes the estimated 38,000 barrels per day reported in the LUKOIL Investment segment. Production was favorably impacted in 2004 by the startup of production from the Su Tu Den field in Vietnam in late 2003, the ramp-up of liquids production from the Bayu-Undan field in the Timor Sea since startup in February 2004, and the startup of the Hamaca upgrader in Venezuela in the fourth quarter of 2004. These items were more than offset by the impact of asset dispositions, normal field production declines, and planned maintenance. In addition, our Syncrude mining operations produced 21,000 barrels per day in 2004, compared with 19,000 barrels per day in 2003.

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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 averaged 916,000 BOE per day in 2003, compared with 482,000 BOE 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. The merger was the primary reason for the production increase.

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

	•	In Norway, the Norway Removal Grant Act (1986) was repealed in the second quarter of 2003. Prior to its repeal, this Act required the Norwegian government to contribute to the cost of removing offshore oil and gas production facilities. Now, the co-venturers in the facilities must fund all removal costs, but can deduct the removal costs, as incurred, under the Petroleum Tax Act, at the marginal tax rate in effect at the time of removal. These changes required us: to recognize an additional liability for the government’s share, prior to repeal of the Act, of the future removal costs, with a corresponding increase in properties, plants and equipment (PP&E); and to establish a net deferred tax asset for the temporary differences between the financial basis and tax basis of all of our Norwegian removal assets and liabilities. Some of the increases in PP&E were on shut-in fields, which led to immediate impairments of those properties. The overall impact on 2003 results was a net after-tax benefit of $87 million.
	•	In the Timor Sea region, ConocoPhillips and its co-venturers received final approvals from authorities to proceed with the natural gas development phase of the Bayu-Undan project in the second quarter of 2003. This approval allowed a broad ownership interest re-alignment among the co-venturers to proceed, which included our sale of a 10 percent interest in the project and the issuance of equity by previously wholly owned subsidiaries. In addition, the ratification of the Australia/Timor Leste treaty lowered the company’s deferred tax liability position. The net result of these events was an after-tax benefit of $51 million in 2003. See Note 6—Subsidiary Equity Transactions, in the Notes to Consolidated Financial Statements, for additional information.
	•	In November 2003, the Canadian Parliament enacted federal tax rate reductions for oil and gas producers. As a result, we recognized a $95 million benefit upon revaluation of our deferred tax liability in the fourth quarter.

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Midstream

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of 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. The Midstream segment consists of our 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.

2004 vs. 2003

Net income from the Midstream segment increased 81 percent in 2004. The improvement was primarily attributable to improved results from DEFS, which had:

	•	Higher gross margins, primarily reflecting higher natural gas liquids prices.
	•	A $23 million (gross) charge in 2003 for the cumulative effect of accounting changes, mainly related to the adoption of SFAS No. 143; partially offset by investment impairments and write-downs of assets held for sale during 2004.

Our Midstream operations outside of DEFS had higher earnings in 2004 as well, reflecting the impact of higher natural gas liquids prices that more than offset the effect of asset dispositions in 2004.

Included in the Midstream segment’s net income was a benefit of $36 million in 2004, the same as 2003, 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.

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2003 vs. 2002

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.

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R&M

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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 petroleum products, and transporting, distributing and marketing petroleum products. R&M has operations in the United States, Europe and Asia Pacific.

2004 vs. 2003

Net income from the R&M segment increased 116 percent in 2004, primarily due to higher refining margins. This was partially offset by lower U.S. marketing margins, and higher maintenance turnaround and utility costs. The 2003 period included a $125 million net charge for the cumulative effect of accounting changes (FIN 46(R)).

2003 vs. 2002

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(R) for variable interest entities involving synthetic leases and certain other financing structures.

U.S. R&M

2004 vs. 2003

Net income from our U.S. R&M operations increased 115 percent in 2004, primarily due to higher refining margins, partially offset by lower marketing margins, and higher maintenance turnaround and utility costs. The 2003 period included a $125 million net charge for the cumulative effect of accounting change (FIN 46(R)).

Our U.S. refining capacity utilization rate was 95 percent in 2004, compared with 96 percent in 2003. The lower capacity utilization was due to increased maintenance downtime.

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. 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(R) for variable interest entities involving synthetic leases and certain other financing structures, along with higher utility costs.

Our U.S. refineries ran at a crude oil capacity utilization rate of 96 percent in 2003, 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.

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International R&M

2004 vs. 2003

Net income from the international R&M operations increased 119 percent in 2004, with the improvement primarily attributable to higher refining margins, partially offset by negative foreign currency impacts on operating costs.

Our international crude oil refining capacity utilization rate was 91 percent in 2004, compared with 94 percent in 2003. Beginning in the third quarter of 2004, we changed our crude oil capacity utilization statistic at the Humber refinery to make it consistent with our other refineries. This change has been applied to the operating statistics for 2003 and 2002.

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. 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 94 percent in 2003, compared with 83 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.

LUKOIL Investment

This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. In October 2004, we closed on a transaction to acquire 7.6 percent of LUKOIL’s shares held by the Russian government. During the remainder of 2004, we increased our ownership interest to 10 percent.

In addition to our estimate of our fourth-quarter weighted-average 8.6 percent equity share of LUKOIL’s earnings, this segment also reflects the amortization of the basis difference between our equity interest in the net assets of LUKOIL and the historical cost of our investment in LUKOIL. In addition, this segment will include the costs associated with the employees seconded to LUKOIL.

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Because LUKOIL’s accounting cycle close and preparation of U.S. GAAP financial statements occurs subsequent to our accounting cycle close, our equity earnings and statistics for 2004 from our LUKOIL investment are an estimate, based on market indicators, historical production trends of LUKOIL, and other factors. Any difference between the estimate and actual results will be recorded in a subsequent period. This estimate-to-actual adjustment will then be a recurring component of future period results.

Chemicals

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.

2004 vs. 2003

Net income from the Chemicals segment increased $242 million in 2004, compared with 2003. The improvement reflects that CPChem had improved equity earnings from Qatar Chemical Company Ltd. (Q-Chem), an olefins and polyolefins complex in Qatar, and Saudi Chevron Phillips Company, an aromatics complex in Saudi Arabia. Results from CPChem’s consolidated operations also improved from higher ethylene and benzene margins, as well as increased ethylene, polyethylene and normal alpha olefins sales volumes.

2003 vs. 2002

The worldwide chemicals industry experienced an economic downturn beginning in the second half of 2000, and the downturn continued through 2003. The downturn 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.

Emerging Businesses

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The Emerging Businesses segment includes the development of new businesses outside our traditional operations. These activities include gas-to-liquids (GTL) operations, power generation, technology solutions such as sulfur removal technologies, and emerging technologies, such as renewable fuels and emission management technologies.

2004 vs. 2003

Emerging Businesses incurred a net loss of $102 million in 2004, compared with a net loss of $99 million in 2003. Contributing to the higher losses in 2004 were lower domestic power margins and higher maintenance costs, as well as increased costs associated with the Immingham power plant project in the United Kingdom, which entered the initial commissioning phase of the project during 2004. Prior to the initial commissioning phase, most costs associated with this project were capitalized as construction costs. This project completed the initial commissioning phase and began commercial operations in October 2004. Partially offsetting these items were lower research and development costs, compared with 2003, which included the costs of a demonstration GTL plant then under construction. Construction of the GTL plant was substantially completed during the second quarter of 2003.

2003 vs. 2002

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 GTL 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.

Corporate and Other

2004 vs. 2003

After-tax net interest consists of interest and debt expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt and costs associated with the receivables

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monetization program. Net interest decreased 19 percent in 2004, primarily due to lower average debt levels, an increased amount of interest being capitalized in 2004, lower charges for premiums paid on the early retirement of debt, and lower costs associated with the receivables monetization program.

After-tax corporate general and administrative expenses increased 23 percent in 2004. The increase reflects higher compensation costs, which includes increased stock-based compensation due to an increase in both the number of units issued and higher stock prices in the 2004 period.

Discontinued operations net income declined 91 percent in 2004, reflecting asset dispositions completed during 2003 and 2004.

Beginning with the second quarter of 2004, we no longer separately identify merger-related costs because these activities have been substantially completed.

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 lower in 2004, mainly due to the inclusion in the 2003 period of gains related to insurance demutualization benefits, negative foreign currency transaction impacts, higher environmental costs and increased minority interest expense.

2003 vs. 2002

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(R) 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(R) at January 1, 2003, increased debt, which resulted in higher interest expense.

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.

Results from Other were improved in 2003, compared with 2002, 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.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, primarily cash generated from operating activities. In addition, during 2004 we raised approximately $1.6 billion in funds from the sale of assets. During 2004, available cash was used to support the company’s ongoing capital expenditures and investments program, repay debt and pay dividends. In September 2004, our Board of Directors (Board) declared a quarterly dividend of $.50 per share, which represented a 16 percent increase from the previous quarter’s dividend rate. Total dividends paid on our common stock in 2004 were $1.2 billion. During 2004, cash and cash equivalents increased $897 million to $1,387 million. In early 2005, a portion of this cash was used to repay $544 million of commercial paper that had been outstanding at December 31, 2004.

In addition to cash flows from operating activities and proceeds from asset sales, we also rely on our commercial paper and credit facility programs, as well as our $5 billion universal shelf registration statement, to support our short- and long-term liquidity requirements. We anticipate that these sources of liquidity will be adequate to meet our funding requirements through 2006, including our capital spending program and required debt payments.

Our cash flows from operating activities increased in each of the annual periods from 2002 through 2004. In addition to favorable market conditions, major acquisitions and mergers played a significant role in the upward trend of our cash flows from operating activities. The most significant event during this period was the merger of Conoco and Phillips on August 30, 2002. Phillips was designated as the acquirer for accounting purposes, so 2002 operating cash flows included eight months (January through August) of Phillips’ activity only and four months of ConocoPhillips’ activity (September through December), while 2003 included the first full year of ConocoPhillips’ activity. Absent any other significant acquisitions or mergers during 2005, we expect that market conditions will be the most important factor affecting our 2005 cash flows, when compared with 2004.

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Significant Sources of Capital

Operating Activities
During 2004 cash of $11,959 million was provided by operating activities, an increase of $2,603 million from 2003. This increase in cash provided by operating activities was primarily due to an increase in income from continuing operations, partially offset by an increase in working capital. The working capital increase primarily was driven by higher accounts receivable and a higher retained interest in receivables sold to a Qualifying Special Purpose Entity (QSPE), partly offset by higher accounts payable. Contributing to the increase in accounts receivable and accounts payable were higher sales and purchase prices, respectively. For additional information on income from continuing operations, see the Results of Operations section. For additional information on receivables sold to a QSPE, see Receivables Monetization in the Off-Balance Sheet Arrangements section.

Our cash flows from operating activities for both the short- and long-term are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During 2003 and particularly in 2004, we benefited from high crude oil and natural gas prices, as well as strong refining margins. The sustainability of these prices and margins are driven by market conditions over which we have no control. In addition, the level of our production volumes of crude oil, natural gas and natural gas liquids also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, the addition of proved reserves through exploratory success, and the timely and cost-effective development of those proved reserves.

We will need to continue to add to our proved reserve base through exploration and development of new fields, or by acquisition, and to apply new technologies and processes to boost recovery from existing fields in order to maintain or increase production and proved reserves. We have been successful in the past in maintaining or adding to our production and proved reserve base and, although it cannot be assured, anticipate being able to do so in the future. Our barrel-of-oil-equivalent (BOE) production, after adjusting our 2003 production for approximately 60,000 BOE per day for assets sold in 2003 and early 2004, has increased in each of the past three years (2002, 2003 and 2004). Excluding the impact of our equity investment in LUKOIL on our production, we expect our 2005 production level to be approximately 4 percent higher than our 2004 level of 1.54 million BOE per day. In 2006, we expect our production level to increase an additional 4 percent over our projected 2005 BOE production level. Beyond 2006, we estimate our BOE production to grow at an average annual rate of approximately 3 percent for the period 2007 through 2010. These projections are tied to projects currently scheduled to begin production or ramp-up in those years and exclude our Canadian Syncrude mining operations.

Excluding the impact of our equity investment in LUKOIL on our proved oil and gas reserves, our reserve replacement over the three-year period ending December 31, 2004, exceeded 200 percent. Contributing to our success during this three-year period were proved reserves added by the merger of Conoco and Phillips, volumes added through extensions and discoveries, and improved recovery. Although it cannot be assured, going forward, we expect to more than replace our production over the next three years. This expectation is based on our current slate of exploratory and improved recovery projects. As discussed in Critical Accounting Policies, engineering estimates of proved reserves are imprecise and therefore each year reserves may be revised upward or downward due to the impact of changes in oil and gas prices or as more technical data becomes available on the reservoirs. In 2004 and 2002, revisions decreased our reserves, while in 2003, revisions increased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future. The net addition of proved undeveloped reserves accounted for 64 percent, 76 percent and 34 percent of our total net additions in 2004, 2003 and 2002, respectively.

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During these years, we converted, on average, approximately 13 percent per year of our proved undeveloped reserves to proved developed reserves. Of the proved undeveloped reserves we had at December 31, 2004, we estimate that the average annual conversion rate for these reserves for the following three years will be in the 25 percent range. For additional information related to the development of proved undeveloped reserves, see the discussion under the E&P section of Capital Spending. The projections and actual results noted above exclude the impact of our equity investment in LUKOIL, and the anticipated production and reserve replacement results are subject to risks, including reservoir performance; operational downtime; finding and development execution; obtaining management, Board and third-party approval of development projects in a timely manner; regulatory changes; geographical location; market prices; and environmental issues; and therefore, cannot be assured.

Asset Sales
Following the merger, we initiated an asset disposition program. Our ultimate target was to raise approximately $4.5 billion by the end of 2004. During 2004, proceeds from asset sales were $1.6 billion, bringing total proceeds to approximately $5.0 billion since the program began. While we will continue to have modest asset disposition activity, this asset disposition program was essentially completed at the end of the second quarter of 2004. Proceeds from these asset sales were 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 $5 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, 2004, we had $544 million of commercial paper outstanding, compared with $709 million of commercial paper outstanding at December 31, 2003.

Effective October 12, 2004, we entered into two new revolving credit facilities totaling $5 billion to replace our previously existing $1.5 billion 364-day facility that was set to expire on October 13, 2004; two revolving credit facilities totaling $2 billion expiring in October 2006; and a $500 million facility expiring in October 2008. The two new facilities include a $2.5 billion four-year facility expiring in October 2008 and a $2.5 billion five-year facility expiring in October 2009. Both facilities are available for use as direct bank borrowings or as support for our $5 billion commercial paper program. In addition, the five-year facility may be used to support issuances of letters of credit totaling up to $750 million. The facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The credit agreements do contain a cross-default provision relating to our, or any of our consolidated subsidiaries’, failure to pay principal or interest on other debt obligations of $200 million or more. There were no outstanding borrowings under these facilities at December 31, 2004.

One of our Norwegian subsidiaries had two $300 million revolving credit facilities that expired in June 2004, which were not renewed.

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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 $5 billion revolving credit facilities. Based on our commercial paper balance of $544 million and having issued $173 million of letters of credit at year-end, we had access to $4.3 billion in borrowing capacity as of December 31, 2004, which provides liquidity to cover daily operations. In addition, at year-end 2004 our $1.4 billion cash balance and $720 million of remaining capacity related to our receivables monetization program also supported our liquidity position.

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, 2004, we had outstanding $1,105 million of equity held by minority interest owners, including a minority interest of $504 million in Ashford Energy Capital S.A. The remaining minority interest amounts related to controlled-operating joint ventures with minority interest owners. The largest of these, $542 million, was related to the Bayu-Undan liquefied natural gas project in the Timor Sea. During the third quarter of 2004, a $141 million net minority interest in Conoco Corporate Holdings L.P. was retired.

In December 2001, in order to raise funds for general corporate purposes, Conoco and Cold Spring Finance S.a.r.l. formed Ashford Energy Capital S.A. through the contribution of a $1 billion Conoco subsidiary promissory note and $500 million cash by Cold Spring. Through its initial $500 million investment, Cold Spring is entitled to a cumulative annual preferred return based on three-month LIBOR rates, plus 1.32 percent. The preferred return at December 31, 2004, was 3.34 percent. In 2008, and at each 10-year anniversary thereafter, Cold Spring may elect to remarket their investment in Ashford, and if unsuccessful, could require ConocoPhillips to provide a letter of credit in support of Cold Spring’s investment, or in the event that such letter of credit is not provided, then cause the redemption of their investment in Ashford. Should ConocoPhillips’ credit rating fall below investment grade, Ashford would require a letter of credit to support $475 million of the term loans, as of December 31, 2004, made by Ashford to other ConocoPhillips subsidiaries. If the letter of credit is not obtained within 60 days, Cold Spring could cause Ashford to sell the ConocoPhillips subsidiary notes. At December 31, 2004, Ashford held $1.7 billion of ConocoPhillips subsidiary notes and $25 million in investments unrelated to ConocoPhillips. We report Cold Spring’s investment as a minority interest because it is not mandatorily redeemable and the entity does not have a specified liquidation date. Other than the obligation to make payment on the subsidiary notes described above, Cold Spring does not have recourse to our general credit.

Receivables Factoring
At December 31, 2003, we had sold $226 million 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. At December 31, 2004, we had no receivables outstanding under similar arrangements. See Note 14—Sales of Receivables, in the Notes to Consolidated Financial Statements, for additional information.

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Off-Balance Sheet Arrangements

Receivables Monetization
At December 31, 2004 and 2003, certain credit card and trade receivables had been sold to a QSPE in a revolving-period securitization arrangement. This arrangement provides for us to sell, and the QSPE to purchase, certain receivables, and for the QSPE to then issue beneficial interests of up to $1.2 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 QSPE because it meets 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.

At December 31, 2004 and 2003, the QSPE had issued beneficial interests to the bank-sponsored entities of $480 million and $1.2 billion, respectively. The receivables transferred to the QSPE met the isolation and other requirements of SFAS No. 140 to be accounted for as sales and were accounted for accordingly.

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 $3.2 billion at December 31, 2004, and $1.3 billion at December 31, 2003. We also retain servicing responsibility related to the sold receivables, which gives us certain rights and abilities, 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 in the QSPE approximates fair market value due to the very short term of the underlying assets. See Note 14—Sales of Receivables, in the Notes to Consolidated Financial Statements, for additional information.

Preferred Securities
In 1997, we formed a statutory business trust, Phillips 66 Capital II (Trust II), with ConocoPhillips owning all of the common securities of the trust. The sole purpose of the trust was to issue preferred securities to outside investors, investing the proceeds thereof in an equivalent amount of subordinated debt securities of ConocoPhillips. The trust was established to raise funds for general corporate purposes.

At December 31, 2004 and 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 of $29 million in both 2004 and 2003. In addition, we guaranteed the payment obligations of the trust on the trust preferred securities to the extent we made interest payments on the subordinated debt securities. 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 18—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, 2004, we were liable for certain contingent obligations under various contractual arrangements as described below.

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	•	Hamaca: The Hamaca project involves the development of heavy-oil reserves from the Orinoco Oil Belt. We own 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 Petroleos de Venezuela S.A. (PDVSA) and ChevronTexaco Corporation. Our interest is held through a jointly owned limited liability company, Hamaca Holding LLC, for which we use the equity method of accounting. Hamaca Holding LLC revenues for 2004 were approximately $625 million, expenses were approximately $413 million and cash provided by operating activities was approximately $324 million. We have a 57.1 percent non-controlling ownership interest in Hamaca Holding LLC. In the second quarter of 2001, we, along with our co-venturers in the Hamaca project, secured approximately $1.1 billion in a joint debt financing. The Export-Import Bank of the United States provided a guarantee supporting a 17-year-term $628 million bank facility. The joint venture also arranged a $470 million 14-year-term commercial bank facility for the project. Total debt of $957 million was outstanding under these credit facilities at December 31, 2004. Of this amount, $383 million is recourse to ConocoPhillips. The proceeds of these joint financings were used to primarily fund a heavy-oil upgrader. The remaining necessary funding was provided by capital contributions from the co-venturers on a pro rata basis to the extent necessary to successfully complete construction. Once completion certification is achieved (required by October 1, 2005), the joint project financings will become non-recourse with respect to the co-venturers and the lenders under those facilities can then look only to the Hamaca project’s cash flows for payment.
	•	Merey Sweeny L.P. (MSLP): MSLP is a limited partnership in which we and PDVSA each own an indirect 50 percent interest. During 1999, MSLP issued $350 million of 8.85 percent bonds due 2019 that we, along with PDVSA, were jointly-and-severally liable for under a construction completion guarantee. In May 2004, MSLP achieved completion certification. As a result, the construction completion guarantee related to the debt and bond financing arrangements secured by MSLP expired and the debt became non-recourse to ConocoPhillips and the bondholders can look only to MSLP cash flows for payment.
	•	Other: At December 31, 2004, we had guarantees of approximately $250 million outstanding for our portion of other joint-venture debt obligations, which have terms of up to 20 years. Payment would be required if a joint venture defaults on its debt obligations. Included in these outstanding guarantees was $95 million associated with the Polar Lights Company joint venture in Russia.
	For additional information about guarantees see Note 15—Guarantees, in the Notes to Consolidated Financial Statements.

Capital Requirements

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

Our balance sheet debt at December 31, 2004, was $15.0 billion. This reflects debt reductions of approximately $2.8 billion during 2004. The debt reduction primarily resulted from repayment in April of the $1,350 million aggregate principal amount of our 5.90% Notes due 2004 at maturity, the redemption in August 2004 of the $1,150 million aggregate principal amount of our 8.5% Notes due 2005, and a reduction of $165 million in our outstanding commercial paper balance to $544 million at December 31, 2004. The 8.5% Notes were redeemed at a premium of $58 million plus accrued interest. In addition, we have given notice to redeem in March 2005 our $400 milion 3.625% Notes due 2007. Going forward, we have no significant mandatory debt retirements until payment of the $1,250 million aggregate principal amount of our 5.45% Notes due in 2006, at maturity.

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On February 4, 2005, we announced a stock repurchase program that provides for the repurchase of up to $1 billion of the company’s common stock over a period of up to two years. The program will serve as a means of offsetting dilution to shareholders from the company’s stock-based compensation programs. Acquisitions for the share repurchase program will be made at management’s discretion at prevailing prices, subject to market conditions and other factors. Purchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan will be held as treasury shares.

Contractual Obligations

The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2004: