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, and intentions, 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,” “should,” “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 98.

•                   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, 2005, ConocoPhillips employed approximately 35,600 people.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 26—Segment Disclosures and Related Information in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

EXPLORATION AND PRODUCTION (E&P)

At December 31, 2005, our E&P segment represented 57 percent of ConocoPhillips’ total assets, while contributing 62 percent of net income.

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, 2005, 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 financial results or statistics from our equity investment in the ordinary shares of 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.  However, our share of LUKOIL is included in the supplemental oil and gas operations disclosures on pages 170 through 185.

The information listed below appears in the supplemental oil and gas operations disclosures and is incorporated herein by reference:

In 2005, E&P’s worldwide production, including its share of equity affiliates’ production other than LUKOIL, averaged 1,543,000 barrels-of-oil-equivalent (BOE) per day, about the same as the 1,542,000 BOE per day averaged in 2004.  During 2005, 633,000 BOE per day were produced in the United States, a slight increase from 629,000 BOE per day in 2004.  Production from our international E&P operations averaged 910,000 BOE per day in 2005, a slight decrease from 913,000 BOE per day in 2004.  In addition, our Canadian Syncrude mining operations had net production of 19,000 barrels per day in 2005, compared with 21,000 barrels per day in 2004.  Benefiting 2005 production was the startup of the

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Hamaca upgrader in Venezuela in the fourth quarter of 2004; the Bayu-Undan field in the Timor Sea, which was still ramping up during 2004; and a full year’s production from the Magnolia field in the Gulf of Mexico, which continued to ramp-up during 2005. These benefits were offset by scheduled and unscheduled maintenance and normal field production declines.  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 38 percent in 2005, from $36.06 per barrel to $49.87 per barrel.  E&P’s annual average worldwide natural gas sales price also increased, from $4.61 per thousand cubic feet in 2004 to $6.30 per thousand cubic feet in 2005.

E&P—U.S. OPERATIONS

In 2005, U.S. E&P operations contributed 40 percent of E&P’s worldwide liquids production and 42 percent of natural gas production, the same as in 2004.

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 102,100 barrels per day in 2005, compared with 109,600 barrels per day in 2004, while natural gas liquids production averaged 18,500 barrels per day in 2005, compared with 22,100 barrels per day in 2004.

Prudhoe Bay satellite fields, including Aurora, Borealis, Polaris, Midnight Sun, and Orion, produced 14,500 net barrels per day of crude oil in 2005, compared with 14,600 net barrels per day in 2004.  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 15,200 barrels per day in 2005, compared with 17,800 barrels per day in 2004, while natural gas liquids production averaged 1,000 barrels per day in 2005, the same as 2004.  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 lower production tax rate that was intended to encourage development of these marginal deposits.  Accordingly, beginning in February 2005, the production tax for these satellite fields is the same 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 55.3 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 64,600 barrels per day in 2005, compared with 67,900 barrels per day in 2004.

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Other fields within the Greater Kuparuk Area produced 16,000 net barrels per day of crude oil in 2005, compared with 19,300 net barrels per day in 2004, primarily from the Tarn, Tabasco, and Meltwater satellites.  We have a 55.4 percent interest in Tarn and Tabasco and a 55.5 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 5,300 barrels per day in 2005, compared with 5,500 barrels per day in 2004.  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 Kuparuk drill site, and Drill Site 1J, which is the first stand-alone West Sak drill site.  Drill Site 1E started up in July 2004, and its 13-well drilling program was completed in late 2005.  The 1J drilling program, consisting of 31 wells, began in 2005, with first production in October 2005.  Peak production is expected in 2007.  In evaluation of other areas for possible West Sak development, two successful appraisal wells were completed in 2005.

Western North Slope

The Alpine field, located west of the Kuparuk field, began production in November 2000.  In 2005, the field produced at a net rate of 76,600 barrels of oil per day, compared with 63,500 barrels per day in 2004. The increased production was the result of the capacity expansion projects discussed below.  We are the operator and hold a 78 percent interest in Alpine.

During 2004, the Alpine Capacity Expansion Phase I project 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 handling 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 of produced water.  Phase II was completed in 2005, after which Alpine’s crude oil production capacity was further expanded by approximately 30,000 gross barrels per day with increased seawater injection rates to boost reservoir pressure.

In November 2004, the U.S. Department of Interior Bureau of Land Management (BLM) issued a favorable Environmental Impact Statement (EIS) Record of Decision to develop future Alpine satellites.  Subsequently, 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 National Petroleum Reserve—Alaska (NPR-A).  A final decision to move forward on these additional 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 2005 averaged 105 million cubic feet per day of natural gas, compared with 94 million cubic feet per day in 2004.  Production from the North Cook Inlet field is used to supply our share of gas to the Kenai LNG plant (discussed below).

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Our interest in the Beluga River field is 33 percent.  Net production averaged 57 million cubic feet per day of natural gas in 2005, compared with 63 million cubic feet per day in 2004.  Gas from the Beluga River field is sold to local utilities and industrial consumers, and is 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, utilizing two LNG tankers for transport.  We sold 42.8 net billion cubic feet of LNG to Japan in 2005, compared with 38.6 net billion cubic feet in 2004.

Exploration

During 2005, we drilled five North Slope exploration and appraisal wells.  This activity included two wildcat wells in the NPR-A, one infrastructure-led exploration (ILX) well near the Alpine field, and two appraisal wells in the West Sak field.  The two NPR-A wells and the ILX well were classified as dry holes, but the data gathered is being further evaluated for a future development opportunity.  Additionally, we completed an evaluation of the economic viability of exploration and appraisal wells drilled in prior years, and classified five wells as dry holes.

We were also the successful bidder acquiring 66,262 gross and net acres at the Minerals Management Service oil and gas lease sale in the Beaufort Sea held on March 30, 2005.  Furthermore, we acquired 21,320 gross and net acres directly from another company in July 2005.  As a result of acquiring this additional acreage, we had under lease approximately 1.7 million net undeveloped acres (onshore and offshore) as of December 31, 2005, in Alaska.

Transportation

We transport the petroleum liquids produced 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.  A project to upgrade TAPS’ pump stations began in 2004 and is expected to be completed in 2006.  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.

We continue to evaluate a gas pipeline project to deliver natural gas from Alaska’s North Slope to the Lower 48.  The Alaska Natural Gas Pipeline Act was passed by the U.S. 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 federal tax legislation granting seven-year depreciation for the Alaska portion of the pipeline and confirming the existing 15 percent enhanced oil recovery tax credit would apply to the gas treatment plant.  In October 2005, we announced that we reached an agreement in principle with the state of Alaska on the base fiscal contract terms for an Alaskan natural gas pipeline project.  In early 2006, the state of Alaska announced that they had reached an agreement in principle with all the co-venturers in the project.  Once a final form of agreement is reached among all the parties, it will be subject to final approval by the Alaska State Legislature before it can be executed. Additional agreements for the gas to transit Canada will also be required.

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 through 2004: the Polar Resolution in 2002; the Polar Discovery in 2003; and the Polar Adventure in 2004.  These 140,000-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 in 2006, although contractual and hurricane-related issues may further delay delivery of this last vessel.

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Lower 48 States

Gulf of Mexico

At year-end 2005, our portfolio of producing properties in the Gulf of Mexico included four fields operated by us and five fields operated by our co-venturers.

We operate and hold a 75 percent interest in the Magnolia field in Garden Banks 783 and 784.  The Magnolia field is developed from a tension-leg platform in 4,700 feet of water.  Production from Magnolia began in December 2004.  Well completion activities continued throughout 2005, and will continue into mid-2006.  Net production from Magnolia averaged 18,700 barrels per day of liquids and 43 million cubic feet per day of natural gas in 2005.  Hurricanes shut in Magnolia for approximately 20 days in 2005, but only caused minimal damage.

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 the unitized area in 2005 averaged 13,500 barrels per day of liquids and 16 million cubic feet per day of natural gas, compared with 21,000 barrels per day of liquids and 30 million cubic feet per day of natural gas in 2004.  The lower 2005 average daily production rate was due to Ursa/Princess being shut in, or significantly curtailed, for approximately 85 days in 2005 for hurricanes and repairs to infrastructure following hurricane Katrina.  Ursa/Princess resumed production at a curtailed rate in mid-November 2005, and returned to full production in late-December 2005.

We have a 16.8 percent interest in the K2 field.  K2 is a subsea development located in Green Canyon Block 562.  First production began in May 2005, and our net production averaged 700 BOE per day in 2005.  Hurricanes shut in K2 for approximately 22 days in 2005, but caused no damage to the field.  Drilling and completion activities will continue into early 2006, with peak net production of 6,000 BOE per day expected in 2006.

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 the onshore Upper Texas Gulf Coast, East Texas and North Louisiana areas.  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 traded in early 2005 for additional interests in Texas properties that integrate well with our existing assets.

Activities in 2005 primarily were centered on continued optimization and development of these assets.  Combined production from Lower 48 onshore fields in 2005 averaged a net 1,147 million cubic feet per day of natural gas and 54,900 barrels per day of liquids, compared with 1,184 million cubic feet per day of natural gas and 54,100 barrels per day of liquids in 2004.

E&P—NORTHWEST EUROPE

In 2005, E&P operations in Northwest Europe contributed 27 percent of E&P’s worldwide liquids production, compared with 29 percent in 2004.  Northwest Europe operations contributed 31 percent of natural gas production in 2005, compared with 34 percent in 2004.  Our Northwest European assets are principally located in the Norwegian and U.K. sectors of the North Sea.

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Norway

The Greater Ekofisk Area is located approximately 200 miles offshore Norway in the center of the North Sea.  The Greater Ekofisk Area is comprised of four producing fields: Ekofisk, Eldfisk, Embla, and Tor.  The Ekofisk complex serves as a hub for petroleum operations in the area, with surrounding developments utilizing the Ekofisk infrastructure.  Net production in 2005 from the Greater Ekofisk Area was 124,800 barrels of liquids per day and 122 million cubic feet of natural gas per day, compared with 127,400 barrels of liquids per day and 125 million cubic feet of natural gas per day in 2004.  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 Greater Ekofisk Area.  The project consists of two interrelated components: construction of a new platform, Ekofisk 2/4M, and modification of the existing Ekofisk and Eldfisk complexes to increase processing capacity.  Construction began in 2003, and production from the new 2/4M platform commenced in October 2005.

We also have ownership interests in other producing fields in the Norwegian sector of the 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 81,900 barrels of liquids per day and 150 million cubic feet of natural gas per day in 2005, compared with 87,700 barrels of liquids per day and 176 million cubic feet of natural gas per day in 2004.

We and our co-venturers received approval from Norwegian authorities in 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.

In 2005, approval was received from the Norwegian and U.K. authorities to proceed with a further development of the Statfjord area.  The project, named the “Statfjord Late-Life Project,” is a gas recovery project, with production startup targeted for the late-2007 time frame.  We have a combined Norway/U.K. 15.2 percent interest in this project.

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

Four exploration wells were completed in 2005.  Three near-field exploration wells were drilled in the Oseberg and Troll licences, one of which was successful.  An additional well was drilled in the Voring Basin and tested hydrocarbons.  Although the well was expensed as a dry hole, we plan to conduct further appraisal.  A further near-field well was started in 2005, located within the Troll license, with operations continuing into 2006.

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 315 million cubic feet of natural gas per day and 13,100 barrels of liquids per day in 2005, compared with 347 million cubic feet of natural gas per day and

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15,500 barrels of liquids per day in 2004.  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: Callanish and Brodgar.  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 was completed in the fourth quarter of 2005, 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 123 million cubic feet of natural gas per day in 2005, compared with 14,100 barrels of liquids per day and 118 million cubic feet of natural gas per day in 2004.

We continue to supply gas from J-Block to Enron Capital and Trade Resources Limited (Enron Capital), which was placed in Administration in the United Kingdom in November 2001.  We have 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 15 producing gas fields in the southern North Sea, in the Rotliegendes and Carboniferous areas.  Net production in 2005 averaged 278 million cubic feet per day of natural gas and 1,200 barrels of liquids per day, compared with 306 million cubic feet per day of natural gas and 1,400 barrels per day of liquids in 2004.

In 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 began in September 2005, with net production expected to increase as development drilling continues.  Initially, the development consists of three wells from a six-slot wellhead platform.  We are the operator of the Saturn Unit Area with a 42.9 percent interest.

In 2005, we received U.K. government approval for the Munro development.  First production from Munro was achieved in August 2005, from a single well platform that is tied into the Caister-Murdoch System infrastructure.  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 35,400 barrels of liquids per day and 34 million cubic feet of natural gas per day in 2005, compared with 38,800 barrels of liquids per day and 47 million cubic feet of natural gas per day in 2004.

We have a 24 percent interest in the Clair field development in the Atlantic Margin.  First production from Clair began in early 2005, with plateau production expected in 2007.  The Clair development includes a conventional platform with production and process topsides facilities supported by a fixed-steel jacket.  Oil

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from the field is exported to the Sullom Voe terminal in Shetland via pipeline, while natural gas is carried through a spur line into the Magnus enhanced oil recovery trunk line.

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, and our reverse-flow rights provide an 85 million net cubic feet of natural gas import capability to the United Kingdom.

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 four exploration wells and one appraisal well in 2005.  Drilling operations have been concluded on one well in the southern North Sea and another in the J-Block area, both of which were successful.  Three further wells were started in 2005, one in the Britannia area, one in the J-Block area, and one adjacent to the Clair field in the Atlantic Margin.  Operation on these wells continued into 2006.

Denmark

Exploration

We hold two exploration licenses in Denmark: 5/98 (Hejre) and 4/98 (Svane).  Drilling and testing of an appraisal well, adjacent to a 2001 discovery in the Hejre license, was completed in 2005.  The well was successful.

E&P—CANADA

In 2005, E&P operations in Canada contributed 3 percent of E&P’s worldwide liquids production (excluding Syncrude production), compared with 4 percent in 2004.  Canadian operations contributed 13 percent of natural gas production in 2005, the same as in 2004.

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, including a coalbed methane program in the central region.  The south region has shallow gas and medium-to-heavy oil.  Production from these oil and gas operations in western Canada averaged a net 32,300 barrels per day of liquids and 425 million cubic feet per day of natural gas in 2005, compared with 35,000 barrels per day of liquids and 433 million cubic feet per day of natural gas in 2004.

Surmont

The Surmont lease is located approximately 35 miles south of Fort McMurray, Alberta.  We own a 50 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.  Consistent with our practice and in accordance with U.S. Securities and Exchange Commission guidelines, we use year-end prices for hydrocarbon reserve estimation.  Due to low Canadian

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bitumen values at December 31, 2005, we did not record any proved crude oil reserves for the Surmont project in 2005.  The Surmont project remains an economically viable and important component of our 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 2013.  We anticipate processing our share of the heavy oil produced as a feedstock in our U.S. refineries.

Parsons Lake/Mackenzie Gas Project

We are working with three other energy companies, as members of the Mackenzie Delta Producers’ Group, on the development of the Mackenzie Valley pipeline and gathering system, which is proposed to transport onshore gas production from the Mackenzie Delta in northern Canada to established markets in North America.  Our interest in the pipeline and gathering system varies by component, averaging approximately 18 percent.  We have 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.  Considerable progress on several issues, including socio-economic responsibility, and benefits and access agreements with four of the five aboriginal groups, have resulted in the decision by the project proponents to proceed to the regulatory hearings. The National Energy Board started hearings on January 25, 2006.  First production from Parsons Lake is expected in 2011.

Exploration

We hold exploration acreage in four areas of Canada: offshore eastern Canada, the foothills of western Alberta, the Mackenzie Delta/Beaufort Sea, and the Arctic Islands.  In eastern Canada, we operate eight contiguous exploration licenses in the deepwater Laurentian basin.  Recent exploratory activity in the Laurentian basin included a 2D seismic survey in 2004, and two 3D seismic programs completed in September 2005.  In the Mackenzie Delta, we participated in an appraisal well to follow-up the Umiak discovery from 2004.  Oil and gas flowed during testing of the discovery well and the appraisal well.  Plans to commercialize this discovery will be integrated into the broader Parsons Lake Development project.

In the foothills, we drilled three wildcat exploratory wells in 2005.  One well is being tied-in for production.  The remaining two are being tested.  Throughout the rest of the Western Canadian Sedimentary basin, we participated in the drilling of approximately 70 low-risk wells near our producing assets.

Elsewhere in the frontiers regions, we hold varying equity interests in discoveries along the Labrador Shelf and in the Arctic Islands.  Further exploration in these basins is contemplated as distribution methods for natural gas become more certain.

Other Canadian Operations

Syncrude Canada Ltd.

We own a 9.0 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,

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about 25 miles north of Fort McMurray, Alberta, with an auxiliary mining and extraction facility approximately 20 miles from the Mildred Lake plant.  Syncrude Canada Ltd. holds eight oil sands leases and the associated surface rights, of which our share is approximately 23,000 net acres.  Our net share of production averaged 19,100 barrels per day in 2005, compared with 21,000 barrels per day in 2004.

The development of the Stage III expansion-mining project continued in 2005, which is expected to increase our Syncrude production.  The Aurora North Train II mine was completed and started up in the fourth quarter of 2003 and the SW Quadrant Replacement Mine was also completed and became operational by year-end 2005.  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 2005, E&P operations in South America were focused on our operations in Venezuela.  South American operations contributed 11 percent of E&P’s worldwide liquids production in 2005, compared with 9 percent in 2004.

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 project is an integrated operation that produces heavy crude oil from reserves in 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 operated by PDVSA in Venezuela.  Our net production was 50,200 barrels of heavy crude oil per day in 2005, compared with 59,600 barrels per day in 2004, and is included in equity affiliate production.

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 is operated by Petrolera Ameriven on behalf of the owners.  The other participants in Hamaca are PDVSA and Chevron Corporation, each owning 30 percent. 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 56,100 barrels per day of heavy crude oil in 2005, compared with 32,600 barrels per day in 2004, 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.

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Gulf of Paria

In March 2005, a development plan addendum for Phase I of the Corocoro field in the Gulf of Paria was approved by the Venezuelan government.  This addendum addressed revisions to the original development plan approved in 2003.  The wellhead platform was installed in late 2005, and the drilling program is expected to begin in the second quarter of 2006.  First production from the central processing facility is targeted for 2008, with the possibility of production from an interim processing facility in 2007.  We operate the field with a 32.2 percent interest.

Plataforma Deltana Block 2

We have a 40 percent interest in Plataforma Deltana Block 2.  The block is operated by our co-venturer 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.  PDVSA has the option to enter the project with a 35 percent interest, which would proportionately reduce our interest in the project to 26 percent.

E&P —ASIA PACIFIC

In 2005, E&P operations in the Asia Pacific area contributed 12 percent of E&P’s worldwide liquids production and 11 percent of natural gas production, compared with 10 percent and 9 percent in 2004, respectively.

Indonesia

We operate nine Production Sharing Contracts (PSCs) in Indonesia and have a non-operator interest in two 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 2005 averaged a net 298 million cubic feet per day of natural gas and 15,100 barrels per day of oil, compared with 250 million cubic feet per day of natural gas and 15,400 barrels per day of oil in 2004.

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.  In October 2005, natural gas export sales began from the Belanak field.  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 25 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.  In October 2005, we purchased an additional 3 percent interest in the Pangkah PSC, bringing our ownership to its current 25 percent.

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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 a non-operator interest in the Banyumas PSC in Java.  During 2005, we sold our interests in 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 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 majority-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 2004, we began the development of the Suban Phase II project, which is an expansion of the existing Suban gas plant in the Corridor PSC.

The South Jambi ‘B’ PSC is also located in South Sumatra, and we have a 45 percent interest.  In 2004, we completed the construction of the South Jambi shallow gas project for the 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 three exploration and appraisal wells were drilled during 2005, of which one was successful.  In the Ketapang PSC, an appraisal well of the Bukit Tua field, completed in 2005, provided data for progressing a development plan, which was submitted to the government of Indonesia in December 2005.  In August 2005, the government of Indonesia awarded us a 100 percent interest in the Amborip VI exploration block in Papua Offshore, for which we expect to sign a PSC in early 2006.

China

Our combined net production of crude oil from the Xijiang facilities averaged 10,600 barrels per day in 2005, compared with 10,400 barrels per day in 2004.  The Xijiang development consists of two 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 2005, the field produced 12,600 net barrels of oil per day, compared with 15,000 net barrels per day in 2004.  We have a 49 percent interest, with the remainder held by the China National Offshore Oil Corporation.  The Phase I development utilizes one manned wellhead platform and a leased FPSO facility.

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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 approved by the Chinese government in January 2005.  Detailed design engineering, procurement and construction activities have begun on the second phase of development, which are planned to include five wellhead platforms, central processing facilities and a new FPSO.  The first wellhead platform of Phase II is expected to be put into production in 2007, and production through the new FPSO is expected by early 2009.

Vietnam

Our ownership interest in Vietnam is centered around the Cuu Long Basin in the South China Sea, and consists of two primarily oil producing blocks, two exploration blocks, and one gas pipeline transportation system.

We have a 23.3 percent interest in Block 15-1 in the Cuu Long Basin.  First production began in the fourth quarter of 2003 with the startup of the Su Tu Den development.  Net production in 2005 was 15,100 barrels of oil per day, compared with 20,800 barrels per day in 2004.  The oil is being processed through a one-million-barrel FPSO vessel.

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.  Su Tu Vang is located approximately four miles south of Su Tu Den, and is now being developed.  First oil production is targeted for 2008.  In addition, successful appraisal of the Su Tu Den Northeast and Su Tu Trang fields within Block 15-1 continued in 2005.

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 2005 was 14,500 barrels of liquids per day and 18 million cubic feet per day of natural gas, compared with 11,800 barrels per day and 16 million cubic feet per day in 2004.  Development of the central part of the field was completed in 2005, with first production in June.

Transportation

We own a 16.3 percent interest in the Nam Con Son natural gas pipeline.  This 244-mile transportation system links gas supplies from the Nam Con Son Basin to gas markets in southern Vietnam.

Exploration

During 2005, we and our co-venturers successfully completed an exploration well in the Su Tu Nau field, located in the north corner of Block 15-1.  Su Tu Nau is our fifth field discovery in Block 15-1, following Su Tu Den, Su Tu Vang, Su Tu Den Northeast, and Su Tu Trang.

Two successful appraisal wells were drilled in the Su Tu Trang field in 2005, a gas condensate field discovered in 2003 in the southeast area of the Block 15-1.

We also own interests in offshore Blocks 5-3, 133 and 134.

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 is re-injected into the reservoir.  This phase began production in February 2004, and averaged a net rate of 47,800 barrels of liquids per day in

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2005, compared with 28,100 barrels per day in 2004.  Development drilling concluded at the end of March 2005.  A major maintenance shutdown was performed during 2005.

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 2005, construction of the LNG facility proceeded, as did the laying of the pipeline.  Following commissioning of the pipeline, limited natural gas production from the Bayu-Undan field began flowing into the pipeline in August 2005, to support the commissioning of the LNG plant.  The first LNG cargo was loaded in February 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, increasing to approximately 260 million cubic feet per day by 2009.

Elang/Kakatua/Kakatua North

During 2005, we continued to produce ultra-light crude oil from these fields at a combined average net rate of 1,400 barrels per day, compared with 1,700 barrels per day in 2004.  We are the operator with an interest of 57.4 percent.

Greater Sunrise

We and our co-venturers continued to evaluate commercial development options and LNG markets in the Asia Pacific region and the North American West Coast during 2005.  The focus in 2005 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.  In December 2005, we were notified that agreement had been reached between the governments of Australia and Timor-Leste with respect to Sunrise.  The agreement was signed on January 12, 2006, but needs to be ratified by the respective parliaments.  Commercial progress on the project will require further clarification on fiscal and jurisdictional issues with the respective governments.  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 2005, our net share of production was 34 million cubic feet of natural gas per day.

Exploration

During 2005, we announced a discovery in the Caldita No. 1 exploration well in the NT/P 61 license located offshore Northern Territory Australia.  Technical evaluation to assess the further appraisal and development of the Caldita discovery is under way.  Appraisal work likely will include acquiring and interpreting 3D seismic data, and drilling one or more appraisal wells to define the size and quality of the natural gas accumulation.  In October 2005, we were awarded the NT/P 69 license located adjacent to NT/P 61.  We are operator of the NT/P 61 and the NT/P 69 licenses, with a 60 percent interest in each.

Malaysia

Exploration

We have interests in deepwater Blocks G and J located off the east Malaysian state of Sabah.  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.  The field was successfully appraised during 2004 and 2005, and is moving toward field development.  In 2004, we successfully completed the drilling of the Malikai discovery in Block G.  Appraisal of this discovery is scheduled to continue into 2006.  In 2005, we had two additional Block G discoveries—Ubah and Pisagan.  Appraisal of these discoveries is scheduled to occur in 2006 and 2007.  We have a 35 percent interest in Block G.

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During the first quarter of 2005, we announced that we and our co-venturers had signed a production sharing contract with PETRONAS, the Malaysian national oil company, for the appraisal and development of the Kebabangan oil field in Block J.  The KBB #4 appraisal well was drilled and deemed unsuccessful in expanding the commercial size of this oil field, and a leasehold impairment was recorded during the fourth quarter of 2005.  Development opportunities are being reviewed with co-venturers, and a development proposal is expected to be made to PETRONAS in 2006.  We have a 40 percent interest in the oil rights of Kebabangan field.

E&P —AFRICA AND THE MIDDLE EAST

Nigeria

At year-end 2005, we were producing from four onshore Oil Mining Leases (OMLs), in which we have a 20 percent non-operator interest.  These leases produced a net 28,900 barrels of liquids per day and 84 million cubic feet of natural gas per day in 2005, compared with 30,500 barrels per day and 71 million cubic feet per day in 2004.  In 2005, 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 in Kwale, Nigeria.  The plant came online in March 2005, and supplies electricity to Nigeria’s national electricity supplier.  The plant consumes 68 million gross cubic feet per day of natural gas, sourced from proved natural gas reserves in the OMLs.

In October 2003, ConocoPhillips, the Nigerian National Petroleum Corporation (NNPC), and two other co-venturers 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 formed an incorporated joint venture, Brass LNG Limited, to undertake the project.  The front-end engineering and design work are expected to be completed in 2006, and will be the basis for commercial development of the facility, which could be operational as early as 2010.

Exploration

We also have production sharing contracts on deepwater Nigeria Oil Prospecting Licenses (OPLs), with a contractor interest on OPL 318 of 35 percent, OPL 248 of 72 percent, OPL 220 of 47.5 percent, and on OPL 214 of 20 percent.  We operate all the OPLs except OPL 214.  OPL 250 was relinquished in November 2005.  OPL 220 has been converted into a Producing License, OML 131, subject to final government approval.  The first exploration well on OPL 214 was drilled in 2005 and temporarily abandoned.  On OPL 318, drilling commenced on the third and final exploration well in November 2005.  The well did not encounter any significant accumulation of hydrocarbons, and was written off to dry hole expense in 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 us 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 drilled an appraisal well and a further exploratory well in 2005.  The Londji Marine No. 1 and Coco Marine No. 2 wells were drilled consecutively starting in June 2005, with the Coco Marine No. 2 encountering some hydrocarbon producing zones.  Both wells were plugged and abandoned as dry holes.  We continue to evaluate the block, on which our interest expires in March 2007 unless extended.

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Libya

In late-December 2005, we announced that, in conjunction with our co-venturers, we reached agreement with the Libyan National Oil Corporation on the terms under which we would return to our former oil and natural gas production operations in the Waha concessions in Libya.  ConocoPhillips and Marathon Oil Corporation each hold a 16.33 percent interest, Amerada Hess Corporation holds an 8.16 percent interest, and the Libyan National Oil Corporation holds the remaining 59.16 percent interest.  The concessions currently produce approximately 350,000 barrels of oil per day, and encompass nearly 13 million acres located in the Sirte Basin.  The fiscal terms of the agreement are similar to the terms in effect at the time of the suspension of the co-venturers’ activities in 1986, and include a 25-year extension of the concessions to 2031-2034.

As a result of the transaction, we added 238 million barrels of crude oil to our net proved reserves in 2005. Based on a current gross production estimate of 350,000 barrels of oil per day, we expect our entitlement to be approximately 45,000 net barrels of oil per day in 2006.  In accordance with our policy of accounting for E&P production on the sales rather than the entitlements method, revenue and production from our working interest share of Libyan operations will be based on actual volumes sold by us during a period.  We currently have, and expect to continue to build, a crude oil underlift position in the near term, from selling less than our entitlement.  We expect to begin make-up of our underlift position in 2006.

Qatar

Qatargas 3

Qatargas 3 is an integrated project, jointly owned by Qatar Petroleum (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent).  The project comprises upstream natural gas production facilities to produce approximately 1.4 billion gross cubic feet per day of natural gas from Qatar’s North field over the 25-year life of the project.  The project also includes a 7.8-million-gross-ton-per-year LNG facility.  The LNG will be shipped from Qatar in a fleet of large LNG vessels, and is destined for sale primarily in the United States.  The first LNG cargos are expected to be delivered from Qatargas 3 in 2009.

The onshore Engineering, Procurement and Construction (EPC) contract for Qatargas 3 was awarded in late-December 2005.  The EPC contract covers the engineering, procurement, and construction of onshore facilities for the LNG facility.  The EPC contract marks the final investment decision for the project, with all definitive agreements signed and financing completed.

In order to capture cost savings, Qatargas 3 will execute the development of the onshore and offshore assets as a single integrated project with Qatargas 4, a joint venture between Qatar Petroleum and Royal Dutch Shell plc.  This includes the joint development of offshore facilities situated in a common offshore block in the North field, as well as the construction of two identical LNG process trains, and associated gas treating facilities for both the Qatargas 3 and Qatargas 4 joint ventures.

Gas-to-Liquids

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.  Preliminary engineering and design studies have been completed .  In April 2005, the Qatar Minister of Petroleum stated that there would be a postponement of new GTL projects in order to further study impacts on infrastructure, shipping and contractors, and to ensure that the development of its gas resources occurs at a sustainable rate.  Work continues with the Qatar authorities on the appropriate timing of the project to meet the objectives of Qatar and ConocoPhillips.

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Dubai

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

Iraq

We have the right to cooperate with LUKOIL to obtain the Iraqi government's confirmation of LUKOIL’s rights under its production sharing agreement (PSA) relating to the West Qurna field.  Subject to obtaining such confirmation and the consents of governmental authorities and the parties to the contract, we have the right 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 12,900 barrels of oil per day in 2005, compared with 13,300 barrels per day in 2004, and is included in equity affiliate production.

NMNG

On June 30, 2005, ConocoPhillips and LUKOIL created the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the northern part of Russia’s Timan-Pechora province.  We have a 30 percent ownership interest with a 50 percent governance interest in the joint venture.  We use the equity method of accounting for this joint venture.  We are working with LUKOIL to finalize the development plan for the Yuzhno Khylchuyu (YK) field, award major contracts and start construction, with a target of starting up the field in late 2007.

Production from the NMNG joint-venture fields is transported via pipeline to LUKOIL’s existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets.  LUKOIL intends to complete an expansion of the terminal’s capacity in late 2007 to accommodate production from the YK field, with ConocoPhillips participating in the design and financing of the terminal expansion.

Other

In late 2004, we signed a Memorandum of Understanding with Gazprom to undertake a joint study on the development of the Shtokman natural gas field in the Barents Sea.  In September 2005, we were notified that we were included on the “short list” of candidates to participate in the Shtokman LNG project.  We are currently engaged in a joint feasibility study with Gazprom and the other candidates.  Gazprom has indicated they will make their final partner selection in the March/April 2006 time frame.

Caspian Sea

In the North Caspian Sea, we have a 9.26 percent interest in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement (NCSPSA), which includes the Kashagan field.  In March 2005, agreement was reached with the Republic of Kazakhstan to conclude the sale of BG International’s interest in the NCSPSA to several of the remaining partners and for the subsequent sale of one-half of the acquired interests to KazMunayGas.  This agreement increased our ownership interest from 8.33 percent to 9.26 percent.

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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. The first phase of field development currently being executed includes the construction of three artificial drilling islands for more than 60 wells, barges with processing facilities and living quarters, and pipelines to carry products onshore to oil, gas and sulphur plants.  The initial production phase of the contract is for 20 years, with options to extend the agreement an additional 20 years.

Transportation

We have a 2.5 percent interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline.  This 1,760 kilometer pipeline will transport crude oil from the Caspian region through Azerbaijan, Georgia and Turkey, for tanker loadings at the Mediterranean port of Ceyhan.  The BTC pipeline is expected to be operational by mid-2006.

Exploration

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.  The Aktote prospect and the Kashagan Southwest prospect were announced as discoveries in 2003, and in 2004, the Kairan prospect was announced as a discovery.  With the successful test on Kairan, the Exploration Period under the NCSPSA came to a close.

In 2005, appraisal of these discoveries continued.  An appraisal well was drilled on Kalamkas More, and 3D seismic operations were carried out on the Kairan and Aktote prospects during 2005.

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.  In 2005, we executed an option to secure 0.3 billion cubic feet per day of capacity in a subsequent expansion of the facility, which is subject to certain regulatory approvals and commercial decisions to proceed.

We are pursuing three other proposed U.S. 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 is in various stages of the regulatory permitting process.

During 2005, we signed a Memorandum of Understanding with Essent Energie B.V. to study the feasibility of developing an LNG import terminal in the Netherlands.  The companies identified a potential project site at the Port of Eemshaven, and completed the feasibility study, which resulted in a recommendation to proceed to the next phase of more detailed engineering.  A final investment decision could be made as early as 2007, subject to the economic outlook and the receipt of the necessary permits.  If the outcome of these procedures is positive, the operation of the terminal could start in 2010.

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During 2005, we, along with the other Norsea Pipeline Limited shareholders, made an application to obtain planning permission for an LNG regasification facility and combined heat and power plant at the Norsea Pipeline Limited existing oil terminal site at Teesside, United Kingdom.  The planning permission process is expected to be complete by mid-2007.

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

Natural Gas Pricing

Compared with the more global nature of crude oil commodity pricing, natural gas prices have historically varied more in different regions of the world.  We produce natural gas from regions around the world that have significantly different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices than in the Lower 48 region of the United States.  Moreover, excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the U.S. Lower 48 states and other markets because of a lack of infrastructure and because of the difficulties in transporting 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 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.

Burlington Resources Acquisition

On the evening of December 12, 2005, ConocoPhillips and Burlington Resources Inc. announced they had signed a definitive agreement under which ConocoPhillips would acquire Burlington Resources Inc.  The transaction has a preliminary value of $33.9 billion.  This transaction is expected to close on March 31, 2006, subject to approval by Burlington Resources shareholders at a special meeting set for March 30, 2006.

Under the terms of the agreement, Burlington Resources shareholders will receive $46.50 in cash and 0.7214 shares of ConocoPhillips common stock for each Burlington Resources share they own.  This represents a transaction value of $92 per share, based on the closing of ConocoPhillips shares on Friday, December 9, 2005, the last unaffected day of trading prior to the announcement.

Burlington Resources is an independent exploration and production company, and holds a substantial position in North American natural gas reserves and production.  At year-end 2004, as reported in its Annual Report on Form 10-K, Burlington Resources had proved worldwide natural gas reserves of 8,226 billion cubic feet, including 5,076 billion cubic feet in the United States and 2,330 billion cubic feet in Canada.  Worldwide, Burlington Resources had 630 million barrels of crude oil and natural gas liquids combined, with 483 million barrels in the United States and 72 million barrels in Canada.  During 2004, Burlington Resources’ worldwide net natural gas production averaged 1,914 million cubic feet per day, while its net liquids production averaged 151,000 barrels per day.

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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, 2005.  No difference exists between our estimated total proved reserves for year-end 2004 and year-end 2003, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2005.

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 278 million barrels of crude oil in the future, including 0.9 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, Canada, 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 our natural gas delivery commitment relates to proved undeveloped reserves in Indonesia, a portion of which 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

At December 31, 2005, our Midstream segment represented 2 percent of ConocoPhillips’ total assets, while contributing 5 percent of net income.

Our Midstream business is primarily conducted through our 50 percent equity investment in Duke Energy Field Services, LLC (DEFS).  In July 2005, ConocoPhillips and Duke Energy Corporation (Duke) restructured their respective ownership levels in DEFS, which resulted in DEFS becoming a jointly controlled venture, owned 50 percent by each company.  This restructuring increased our ownership in DEFS to 50 percent, from 30.3 percent, through a series of direct and indirect transfers of certain Canadian Midstream assets from DEFS to Duke, a disproportionate cash distribution from DEFS to Duke from the sale of DEFS’ interest in TEPPCO, and a combined payment by ConocoPhillips to Duke and DEFS of approximately $840 million.  The Empress plant in Canada was not included in the initial transaction as originally anticipated due to weather-related damage.  However, the Empress plant was sold to Duke on August 1, 2005, for approximately $230 million.

The Midstream business purchases raw natural gas from producers and gathers 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 2005, including our share of DEFS’, was 195,000 barrels per day, compared with 194,000 barrels per day in 2004.

DEFS markets a portion of its natural gas liquids to ConocoPhillips and Chevron Phillips Chemical Company LLC (a joint venture between ConocoPhillips and Chevron Corporation) under a supply agreement that continues until December 31, 2014.  This purchase commitment is on an “if-produced, will-

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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, 2005, DEFS owned or operated 54 natural gas liquids extraction plants, 11 natural gas liquids fractionation plants, and its gathering and transmission systems included approximately 56,000 miles of pipeline.  In 2005, DEFS’ raw natural gas throughput averaged 5.9 billion cubic feet per day, and natural gas liquids extraction averaged 353,000 barrels per day, compared with 5.9 billion cubic feet per day and 356,000 barrels per day, respectively, in 2004 (2004 amounts were restated to reflect discontinued operations within DEFS).  DEFS’ assets are primarily located in the Gulf Coast area, West Texas, Oklahoma, the Texas Panhandle, and the Rocky Mountain area.

Outside of DEFS, our U.S. natural gas liquids business included the following assets as of December 31, 2005:

•                   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 in Texas and Louisiana.

•                   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).

We also own a 39 percent equity interest in Phoenix Park Gas Processors Limited (Phoenix Park), a joint venture primarily with the National Gas Company of Trinidad and Tobago Limited.  Phoenix Park processes gas in Trinidad and markets natural gas liquids throughout the Caribbean and into the U.S. Gulf Coast.  Its facilities include a 1.35-billion-cubic-feet-per-day gas processing plant and a natural gas liquids fractionator that was expanded from 46,000 to 70,000 barrels per day in the fourth quarter of 2005.  Our share of natural gas liquids extracted averaged 6,100 barrels per day in 2005, the same as in 2004.

In Syria, operations were transferred to the Syrian Gas Company at the end of the service contract on December 31, 2005.  Final administrative requirements associated with closing out the service contract will be undertaken during the first half of 2006.  We have no plans to make additional investments in operations in Syria.

REFINING AND MARKETING (R&M)

At December 31, 2005, our R&M segment represented 29 percent of ConocoPhillips’ total assets, while contributing 31 percent of net income.

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.

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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).  Accordingly, 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 procures feedstocks for R&M’s refineries, facilitates supplying a portion of the gas and power needs of the R&M facilities, and supplies petroleum products to our marketing operations.  Commercial has buyers, traders and marketers in offices in Houston, London, Singapore and Calgary.

We are planning to spend $4 billion to $5 billion over the period 2006 through 2011 to increase our U.S. refining system’s ability to process heavy-sour crude oil and other lower-quality feedstocks.  These investments are expected to incrementally increase refining capacity and clean products yield at our existing facilities, while providing competitive returns.

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East Coast Region

Bayway Refinery

The Bayway refinery is located on the New York Harbor in Linden, New Jersey.  The refinery has a crude oil processing capacity of 238,000 barrels per day, and processes mainly light low-sulfur crude oil.  Crude oil is supplied to the refinery by tanker, primarily from the North Sea, Canada 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.

Trainer Refinery

The Trainer refinery is located on the Delaware River in Trainer, Pennsylvania.  The refinery has a crude oil processing capacity of 185,000 barrels per day, and processes mainly light low-sulfur crude oil.  The Bayway and Trainer refineries are operated in coordination with each other by sharing crude oil cargoes, moving feedstocks between the facilities, and sharing certain personnel.  Trainer receives crude oil from the North Sea and West Africa.  The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel, along with home heating oil.  Other products include residual fuel oil and liquefied petroleum gas.  Refined products are distributed to customers in Pennsylvania, New York and New Jersey via pipeline, barge, railcar and truck.

Gulf Coast Region

Alliance Refinery

The Alliance refinery is located on the Mississippi River in Belle Chasse, Louisiana.  The refinery has a crude oil processing capacity of 247,000 barrels per day, and processes mainly light low-sulfur crude oil.  Alliance receives domestic crude oil from the Gulf of Mexico via pipeline, and foreign 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.

The Alliance refinery was shutdown in anticipation of Hurricane Katrina in late-August 2005, then remained shut down as a result of flooding and damages sustained during the hurricane.  Removal of water from the site was completed by October, and repair work began.  The refinery began partial operation in late-January 2006, and is expected to return to full operations around the end of the first quarter of 2006.

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, and processes mainly heavy, high-sulfur, low-sulfur and acidic crude oil.  The refinery receives domestic and foreign crude oil, with a majority of its foreign crude oil being heavy Venezuelan and Mexican crude oil 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.  Construction of an S Zorb™ Sulfur Removal Technology unit to produce low-sulfur gasoline was completed and began operation in late 2005.

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The Lake Charles facilities include a specialty coker and calciner that manufacture graphite petroleum coke, which is supplied to the steel industry.  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 and Penreco, joint ventures that are part of our Specialty Businesses function within R&M.

The Lake Charles refinery was shutdown in anticipation of Hurricane Rita in September 2005, resumed operations in mid-October, and returned to full operations in November.

Sweeny Refinery

The Sweeny refinery is located in Old Ocean, Texas.  Effective January 1, 2005, the crude oil processing capacity was increased by 13,000 barrels per day, and effective January 1, 2006, it was further increased by 18,000 barrels per day.  Both increases were a result of incremental debottlenecking.  As a result, the refinery’s current crude oil processing capacity is 247,000 barrels per day.  The refinery 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.

The Sweeny refinery was shutdown in anticipation of Hurricane Rita in September 2005, and resumed operations by October.

Central Region

Wood River Refinery

The Wood River refinery is located on the east side of the Mississippi River in Roxana, Illinois.  It is R&M’s largest refinery, with a crude oil processing capacity of 306,000 barrels per day.  The refinery processes a mix of both light low-sulfur and heavy high-sulfur crude oil.  The refinery receives domestic and foreign crude oil by various pipelines.  The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel.  Other products include petrochemical feedstocks (benzene and propylene) and asphalt.  Through an off-take agreement, a significant portion of its gasoline and diesel is sold to a third party for delivery via pipelines into the upper Midwest, including the Chicago, Illinois, and Milwaukee, Wisconsin, metropolitan areas.  The remaining refined products are distributed to customers in the Midwest by pipeline, truck, barge and railcar.

In November 2005, we announced plans to install our proprietary S Zorb™ Sulfur Removal Technology (SRT) at the refinery.  The new 32,000-barrel-per-day S Zorb SRT unit is targeted for completion in early 2007.

Ponca City Refinery

The Ponca City refinery is located in Ponca City, Oklahoma.  The refinery 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 crude oil are delivered by pipeline from the Gulf of Mexico, Oklahoma, Kansas, Texas and Canada.  The refinery produces high ratios of gasoline and diesel fuel from crude oil.  Finished

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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, and the complex includes a natural gas liquids fractionation facility.  The crude oil processing capacity of the refinery is 146,000 barrels per day, and the natural gas liquids fractionation capacity is 45,000 barrels per day.  The refinery processes mainly light-sour and medium-sour crude oil.  It 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 company-owned 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, Colorado, and the Midcontinent region.

During 2005, construction began on a 25,000-barrel-per-day coker at the Borger refinery, with an estimated completion date in the second quarter of 2007.  This project will allow the refinery to comply with clean fuel regulations for ultra-low-sulfur diesel and low-sulfur gasoline, as well as comply with required reductions of sulfur dioxide emissions.  Additional project benefits include improved operating performance by adding additional upgrading capability, improved utilization, and capability to process heavy Canadian crude oil.

West Coast Region

Billings Refinery

The Billings refinery is located in Billings, Montana.  The refinery has a crude oil processing capacity of 58,000 barrels per day, and processes a mixture of Canadian heavy, high-sulfur crude, plus domestic high-sulfur and low-sulfur crude oil, 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.

Los Angeles Refinery

The Los Angeles refinery is composed of two linked facilities located about five miles apart in Carson and Wilmington, California.  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 crude oil.  The refinery receives domestic crude oil via pipeline from California, and both foreign and domestic crude oil by tanker through a third-party terminal in the Port of Long Beach.  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.

In late 2005, we entered into an agreement to utilize a proposed facility to provide waterborne crude oil receipt capacity in the Los Angeles harbor.  This facility, which is expected to be operational in late 2007 or 2008, will allow the refinery to increase its proportion of waterborne crude oil versus California crude oil and accept crude oil from very large tankers.

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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.  Effective April 1, 2005, the refinery’s crude oil processing capacity was increased by 9,000 barrels per day as a result of a project implementation related to clean fuels, and effective January 1, 2006, it was further increased by 5,000 barrels per day due to incremental debottlenecking.  As a result, the refinery’s current crude oil processing capacity is 120,000 barrels per day.  The refinery processes mainly heavy, high-sulfur crude oil.  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, and both foreign and domestic crude oil by tanker.  Semi-refined liquid products from the Santa Maria facility are sent by pipeline to the Rodeo facility for upgrading into 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 is located on Puget Sound in Ferndale, Washington.  Effective January 1, 2006, the refinery’s crude oil processing capacity was increased by 3,000 barrels per day as a result of incremental debottlenecking.  As a result, the refinery’s current crude oil processing capacity is 96,000 barrels per day. The refinery primarily receives crude oil from the Alaskan North Slope, with secondary sources supplied from 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. 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 11,800 outlets in 49 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 10,800 outlets.  We place a strong emphasis on the wholesale channel of trade because of its lower capital requirements.  Our refineries and transportation systems provide strategic support to these operations.  We also buy and sell petroleum products in the spot market.  Our refined products are marketed on both a branded and unbranded basis.

In addition to automotive gasoline and diesel fuel, we produce and market aviation gasoline, which is used by smaller, piston-engine aircraft.  Aviation gasoline and jet fuel are sold through independent marketers at approximately 570 Phillips 66 branded locations in the United States.

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, Breakplace, or Circle K brand convenience stores.

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At December 31, 2005, CFJ Properties, our 50/50 joint venture with Flying J, owned and operated 100 truck travel plazas that carry the Conoco and/or Flying J brands.

Transportation

Pipelines and Terminals

At December 31, 2005, we had approximately 29,000 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.

In November 2005, we entered into a Memorandum of Understanding which commits us to ship crude oil on the proposed Keystone oil pipeline, and gives us the right to acquire up to a 50 percent ownership interest in the pipeline, subject to certain conditions being met.  The Keystone pipeline is intended to transport approximately 435,000 barrels per day of crude oil from Hardisty, Alberta, to Patoka, Illinois, through a 1,840-mile pipeline system.  In addition to approximately 1,100 miles of new pipeline in the United States, the Canadian portion of the proposed project includes the construction of approximately 220 miles of new pipeline and the conversion of approximately 540 miles of existing pipeline facilities from natural gas to crude oil transmission.  The Keystone pipeline, upon receipt of the necessary shipper support and appropriate regulatory approvals in Canada and the United States, is expected to be in service in 2009.  We expect to utilize the Keystone pipeline to integrate our upstream assets in Canada with our Wood River refinery in Illinois.

Tankers

At December 31, 2005, we had under charter 15 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, 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.  During 2005, we sold our interest in Venco, a coke calcining joint venture in which we had a 50 percent interest.

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 crude oil.  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 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 Europe and the United States.  We also operate a crude oil and products storage complex with a 7.5-million-barrel capacity, facilitated by an offshore mooring buoy, 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.  Effective January 1, 2006, the refinery’s capacity was increased by 14,000 barrels per day, with our share being an increase of 3,000 barrels per day, due to incremental debottlenecking.  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 C eská 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 produces a high yield of transport fuels and petrochemical feedstocks, and 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.  The Kralupy refinery has a high yield of transportation 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.  Effective January 1, 2006, the refinery’s capacity was increased by 4,000 barrels per day, with our share being an increase of 2,000 barrels per day, due to incremental debottlenecking.  Crude oil processed by the refinery is sourced mostly from the Middle East.  The refinery produces a full range of refined petroleum products. The refinery capitalizes on our proprietary coking technology to upgrade low-cost feedstocks to higher- margin products.  Our share of refined products is distributed by truck to “ProJET” retail sites in Malaysia, or transported by sea, primarily to Asian markets.

Refinery Acquisition

In November 2005, we executed a definitive agreement for the cash purchase of the Wilhelmshaven refinery in Wilhelmshaven, Germany.  The purchase includes the 275,000-barrel-per-day refinery, a marine terminal, rail and truck loading facilities and a tank farm, as well as another entity that provides commercial and administrative support to the refinery.  The purchase is expected to be completed during the first quarter of 2006, subject to satisfaction of closing conditions, including obtaining the necessary governmental approvals and regulatory permits.  The acquisition is expected to provide a foundation for strengthening the company’s ability to supply products to key export markets.

Our current plans include a deep conversion project for the refinery, moving it from a low-complexity facility to a high-complexity facility.  This proposed project would allow the refinery to run a more advantaged crude slate, including Russian-export blends, while increasing overall conversion and reducing operating costs.

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The addition of the Wilhelmshaven refinery would increase our overall European refining capacity by approximately 74 percent, from 372,000 barrels per day at year-end 2005 to 647,000 barrels per day.

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, low-price, high-volume 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, a joint venture, in which we have an equity interest, markets products in Switzerland under the “Coop” brand name.  During 2005, we sold our equity interest in a joint venture that marketed products in Turkey.  We also sell a portion of our Ireland refinery output to inland Irish markets.

As of December 31, 2005, R&M had approximately 2,110 marketing outlets in its European operations, of which approximately 1,530 were company-owned, and 580 were dealer-owned.  Through our joint-venture operations in Switzerland, we also have interests in 168 additional sites.  The company’s largest branded site networks are in Germany and the United Kingdom, which account for approximately 60 percent of our total European branded units.

As of December 31, 2005, R&M had 145 marketing outlets in our wholly owned Thailand operations in Asia.  In addition, through a joint venture in Malaysia, 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.  We are currently in the process of transitioning our Malaysian retail business from mostly company-operated sites to dealer-operated sites, and the fuel will still be branded “ProJET.”

LUKOIL INVESTMENT

At December 31, 2005, our LUKOIL Investment segment represented 5 percent of ConocoPhillips’ total assets, while contributing 5 percent of net income.

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.

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, and by year-end 2005, we had increased our ownership to 16.1 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.  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, 2005, was 1,442 million BOE.

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As reported in LUKOIL’s 2004 annual report, the majority of its 2004 upstream oil production was sourced within Russia, with 65 percent from the western Siberia region, 14 percent from the Timan-Pechora region and 12 percent from the Urals region.  Outside of Russia, LUKOIL has oil production in Kazakhstan and Egypt, and has exploratory or other projects under way in Kazakhstan, Colombia, Azerbaijan, Uzbekistan, Iran, Saudi Arabia and Iraq.  Downstream, LUKOIL has eight refineries with a net crude oil throughput capacity of approximately 1.2 million barrels per day.  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

At December 31, 2005, our Chemicals segment represented 2 percent of ConocoPhillips’ total assets, while contributing 2 percent of net income.

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

CPChem’s business is structured around three primary operating segments:  Olefins & Polyolefins, Aromatics & Styrenics, and Specialty Products.  The Olefins & Polyolefins segment   produces and markets ethylene, propylene, and other olefin products, which are primarily consumed within CPChem for the production of polyethylene, normal alpha olefins (NAO),   polypropylene, and polyethylene pipe.  The Aromatics & Styrenics segment manufactures and markets aromatics products, such as benzene, styrene, paraxylene and cyclohexane.  This segment also manufactures and markets polystyrene, as well as styrene-butadiene copolymers.  The Specialty Products segment manufactures and markets a variety of specialty chemical products, including organosulfur chemicals, solvents, catalysts, drilling chemicals, mining chemicals and high-performance polyphenylene sulfide polymers and compounds.

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 production plant and eight plastic pipe production 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 production 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,” was completed in 2003.  CPChem has signed an agreement for the development of a second complex to be built in Mesaieed, called “Q-Chem II.”  The facility will be designed to produce polyethylene and normal alpha olefins, on a site adjacent to the Q-Chem complex.  In connection with this project, CPChem and Qatar Petroleum entered into a separate agreement with Total Petrochemicals and Qatar Petrochemical Company Ltd., establishing a joint venture to develop an ethylene cracker in Ras Laffan Industrial City, Qatar.  The cracker will provide ethylene feedstock via pipeline to the planned polyethylene and normal alpha olefins plants.  Construction began in late 2005, with operational startup of both projects anticipated in late 2008.

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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, which began in the fourth quarter of 2004, is in conjunction with an expansion of SCP’s benzene plant, together called the “JCP Project.”  Operational startup is anticipated in late 2007.

EMERGING BUSINESSES

At December 31, 2005, our Emerging Businesses segment represented 1 percent of ConocoPhillips’ total assets.

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 for two years through early 2005.  Sufficient data was collected to enable further technology and design modifications to be tested on a pilot plant scale in 2005 and 2006.

Technology Solutions

Our Technology Solutions businesses develop 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 ^TM SRT), alkylation technologies (ReVAP ^TM , IMP ^TM , SOFT ^TM ), and delayed coking (ThruPlus®) technologies.  We also offer a gasification technology (E-Gas ^TM ) that uses petroleum coke, coal, and other low-value hydrocarbon as feedstock, resulting in high-value synthesis gas that can be used for a slate of products, including power, hydrogen and chemicals.

Power Generation

The focus of our power business is on developing integrated projects to support the company’s E&P and R&M strategies and business objectives.  The projects that are primarily in place to 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.

Immingham CHP, a 730-megawatt, gas-fired combined heat and power plant in North Lincolnshire, United Kingdom, was placed in commercial operations in October 2004.  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.  Development work on Immingham Phase 2 began with the award of a contract for front-end engineering and securing of additional connection availability to the U.K. grid.  The final decision to proceed with Phase 2 will be made later in 2006.

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.

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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 19, 2005, issue of the Oil & Gas Journal , our E&P segment had, on a BOE basis, the eighth-largest total of worldwide proved 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’ principal 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 19, 2005, issue of the Oil & Gas Journal , our R&M segment had the second-largest U.S. refining capacity of 13 large refiners of petroleum products, after giving consideration to the recent merger of Valero Energy Corporation and Premcor Inc.  Worldwide, it ranked sixth 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 2005 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.

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GENERAL

At the end of 2005, we held a total of 1,804 active patents in 70 countries worldwide, including 732 active U.S. patents.  During 2005, we received 55 patents in the United States and 148 foreign patents.  Our products and processes generated licensing revenues of $42 million in 2005.  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 $125 million, $126 million and $136 million in 2005, 2004 and 2003, respectively.

The environmental information contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 85 through 88 under the caption, “Environmental,” is incorporated herein by reference.  It includes information on expensed and capitalized environmental costs for 2005 and those expected for 2006 and 2007.

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 Web site at http://www.sec.gov.

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Item 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K.  Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.

A substantial or extended decline in crude oil, natural gas and natural gas liquids prices, as well as refining margins, would reduce our operating results and cash flows, and could impact our future rate of growth and the carrying value of our assets.

Prices for crude oil, natural gas and natural gas liquids fluctuate widely.  Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas, natural gas liquids and refined products.  Historically, the markets for crude oil, natural gas, natural gas liquids and refined products have been volatile and may continue to be volatile in the future.  Many of the factors influencing the prices of crude oil, natural gas, natural gas liquids and refined products are beyond our control.  These factors include, among others:

•                   Worldwide and domestic supplies of, and demand for, crude oil, natural gas, natural gas liquids and refined products.

•                   The cost of exploring for, developing, producing, refining and marketing crude oil, natural gas, natural gas liquids and refined products.

The long-term effects of these and other conditions on the prices of crude oil, natural gas, natural gas liquids and refined products are uncertain.  Generally, our policy is to remain exposed to market prices of commodities; however, management may elect to hedge the price risk of our crude oil, natural gas, natural gas liquids and refined products.

Lower crude oil, natural gas, natural gas liquids and refined products prices may reduce the amount of these commodities that we can produce economically, which may reduce our revenues, operating income and cash flows.  Significant reductions in commodity prices could require us to reduce our capital expenditures and impair the carrying value of our assets.

Estimates of crude oil and natural gas reserves depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates.  Any material changes in those conditions or other factors affecting those assumptions could impair the quantity and value of our crude oil and natural gas reserves.

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The proved crude oil and natural gas reserve information relating to us included in this annual report has been derived from engineering estimates prepared by our personnel.  The estimates were calculated using crude oil and natural gas prices in effect as of December 31, 2005, as well as other conditions in existence as of that date.  Any significant future price changes will have a material effect on the quantity and present value of our proved reserves.  Future reserve revisions could also result from changes in, among other things, governmental regulation.

Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of crude oil and natural gas that cannot be directly measured.  Estimates of economically recoverable crude oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including:

•                   Historical production from the area, compared with production from other comparable producing areas.

As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of reserves and future net cash flows based on the same available data.  Because of the subjective nature of crude oil and natural gas reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:

The discounted future net revenues from our reserves should not be considered as the market value of the reserves attributable to our properties.  As required by rules adopted by the SEC, the estimated discounted future net cash flows from our proved reserves, as described in the supplemental oil and gas operations disclosures on pages 183 through 185, are based generally on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower.

In addition, the 10 percent discount factor, which SEC rules require to be used to calculate discounted future net revenues for reporting purposes, is not necessarily the most appropriate discount factor based on our cost of capital and the risks associated with our business and the crude oil and natural gas industry in general.

If we are unsuccessful in acquiring or finding additional reserves, our future crude oil and natural gas production would decline, thereby reducing our cash flows and results of operations, negatively impacting our financial condition.

The rate of production from crude oil and natural gas properties generally declines as reserves are depleted. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities, or, through engineering studies, identify additional or secondary recovery reserves, our proved reserves will decline materially as we produce crude oil and natural gas.  Accordingly, to the extent that we are not successful in replacing the crude oil and natural gas we produce

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with good prospects for future production, our business will decline.  Creating and maintaining an inventory of projects depends on many factors, including:

•                   Obtaining rights to explore, develop and produce crude oil and natural gas in promising areas.

We may not be able to find or acquire additional reserves at acceptable costs.

Crude oil price increases and environmental regulations may reduce our refined product margins.

The profitability of our R&M segment depends largely on the margin between the cost of crude oil and other feedstocks we refine and the selling prices we obtain for refined products.  Our overall profitability could be adversely affected by the availability of supply and rising crude oil and other feedstock prices that we do not recover in the marketplace.  Refined product margins historically have been volatile and vary with the level of economic activity in the various marketing areas, the regulatory climate, logistical capabilities and the available supply of refined products.

In addition, environmental regulations, particularly the 1990 amendments to the Clean Air Act, have imposed, and are expected to continue to impose, increasingly stringent and costly requirements on our refining and marketing operations, which may reduce refined product margins.

We will continue to incur substantial capital expenditures and operating costs as a result of compliance with, and changes in, environmental laws and regulations, and, as a result, our profitability could be materially reduced.

Our businesses are subject to numerous laws and regulations relating to the protection of the environment. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations.  To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected.  The specific impact of these laws and regulations on us and our competitors may vary depending on a number of factors, including the age and location of operating facilities, marketing areas and production processes.  We may also be required to make material expenditures to:

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•                   Curtail operations.

We may become subject to liabilities that we currently do not anticipate in connection with new, amended or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination.  In addition, any failure by us to comply with existing or future laws could result in civil or criminal fines and other enforcement actions against us.

Our, and our predecessors’, operations also could expose us to civil claims by third parties for alleged liability resulting from contamination of the environment or personal injuries caused by releases of hazardous substances.

Environmental laws are subject to frequent change and many of them have become more stringent.  In some cases, they can impose liability for the entire cost of cleanup on any responsible party, without regard to negligence or fault, and impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them.

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Environmental” in Item 7 of this annual report.

Worldwide political and economic developments could damage our operations and materially reduce our profitability and cash flows.

Local political and economic factors in international markets could have a material adverse effect on us. Approximately 65 percent of our crude oil, natural gas and natural gas liquids production in 2005 was derived from production outside the United States, and 66 percent of our proved reserves, as of December 31, 2005, were located outside the United States.

There are many risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, natural gas, natural gas liquids or refined product pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations.  These risks include, among others:

•                   Political and economic instability, war, acts of terrorism and civil disturbances.

•                   The possibility that a foreign government may seize our property, with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements and concessions, or may impose additional taxes or royalties.

•                   Fluctuating currency values, hard currency shortages and currency controls.

Continued hostilities and turmoil in the world and the occurrence or threat of future terrorist attacks could affect the economies of the United States and other developed countries.  A lower level of economic activity could result in a decline in energy consumption, which could cause our revenues and margins to decline and limit our future growth prospects.  More specifically, our energy-related assets may be at greater risk of future terrorist attacks than other possible targets.  A direct attack on our assets, or assets used by us, could have a material adverse effect on our operations, financial condition, results of operations and prospects.  These risks could lead to increased volatility in prices for crude oil, natural gas, natural gas liquids and refined products and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain the insurance coverage that we consider adequate.

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Actions of the U.S. government through tax and other legislation, executive order and commercial restrictions could reduce our operating profitability both in the United States and abroad.  The U.S. government can prevent or restrict us from doing business in foreign countries.  These restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various countries.  Actions by both the United States and host governments have affected operations significantly in the past and will continue to do so in the future.

We also are exposed to fluctuations in foreign currency exchange rates.  We do not comprehensively hedge our exposure to currency rate changes, although we may choose to selectively hedge certain working capital balances, firm commitments, cash returns from affiliates and/or tax payments.  These efforts may not be successful.

Changes in governmental regulations may impose price controls and limitations on production of crude oil and natural gas.

Our operations are subject to extensive governmental regulations.  From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas wells below actual production capacity in order to conserve supplies of crude oil and natural gas.  Because legal requirements are frequently changed and subject to interpretation, we cannot predict the effect of these requirements.

Our operations are subject to business interruptions and casualty losses, and we do not insure against all potential losses, so we could be seriously harmed by unexpected liabilities.

Our exploration and production operations are subject to unplanned occurrences, including blowouts, explosions, fires, loss of well control, formations with abnormal pressures, spills and adverse weather.  In addition, our refining, marketing and transportation operations are subject to business interruptions due to scheduled refinery turnarounds and unplanned events such as explosions, fires, pipeline interruptions, pipeline ruptures, crude oil or refined product spills, inclement weather or labor disputes.  Our operations are also subject to the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks, as well as hazards of marine operations, such as capsizing, collision and damage or loss from severe weather conditions.  All such hazards could result in loss of human life, significant property and equipment damage, environmental pollution, impairment of operations and substantial losses to us.  These hazards have adversely affected us in the past, and litigation arising from a catastrophic occurrence in the future at one of our locations may result in our being named as a defendant in lawsuits asserting potentially large claims or being assessed potentially substantial fines by governmental authorities.  In addition, we are exposed to risks inherent in any business, such as terrorist attacks, equipment failures, accidents, theft, strikes, protests and sabotage, that could disrupt or interrupt operations.

We maintain insurance against many, but not all, potential losses or liabilities arising from these operating hazards in amounts that we believe to be prudent.  Uninsured losses and liabilities arising from operating hazards could reduce the funds available to us for exploration, drilling, production and other capital expenditures and could materially reduce our profitability.

Our investments in joint ventures decrease our ability to manage risk.

We conduct many of our operations through joint ventures in which we may share control with our joint-venture partners.  As with any joint-venture arrangement, differences in views among the joint-venture participants may result in delayed decisions or in failures to agree on major issues.  There is the risk that our joint-venture partners may at any time have economic, business or legal interests or goals that are

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inconsistent with those of the joint venture or us.  There is also risk that our joint-venture partners may be unable to meet their economic or other obligations and that we may be required to fulfill those obligations alone.  Failure by us, or an entity in which we have a joint-venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.

We anticipate entering into additional joint ventures with other entities.  We cannot assure that we will undertake such joint ventures or, if undertaken, that such joint ventures will be successful.

We may not be successful in continuing to grow through acquisitions, and any further acquisitions may require us to obtain additional financing or could result in dilution of earnings per share.

A substantial portion of our growth over the last several years has been attributable to acquisitions.  Risks associated with acquisitions include those relating to:

•                   Diversion of management time and attention from our existing businesses and other priorities.

•                   Difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business into those of our existing operations.

•                   Liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance.

•                   Greater than anticipated expenditures required for compliance with environmental or other regulatory standards, or for investments to improve operating results.

•                   Difficulties in achieving anticipated operational improvements.

We may not be successful in continuing to grow through acquisitions.  In addition, the financing of future acquisitions may require us to incur additional indebtedness, which could limit our financial flexibility, or to issue additional equity, which could result in dilution of the ownership interests of existing stockholders. Any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.

Our results of operations could be adversely affected by goodwill impairments.

As a result of mergers and acquisitions, at year-end 2005 we had approximately $15 billion of goodwill on our balance sheet.  Goodwill is not amortized, but instead must be tested at least annually for impairment by applying a fair-value-based test.  Goodwill is deemed impaired to the extent that its carrying amount exceeds the residual fair value of the reporting unit.  Although our latest tests indicate that no goodwill impairment is currently required, future deterioration in market conditions could lead to goodwill impairments that could have a substantial negative affect on our profitability.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

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