2008

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		01-0562944 (I.R.S. Employer Identification No.)

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

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. þ Yes o No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes þ No

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes þ No

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2008, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $94.39, was $143.4 billion. The registrant, solely for the purpose of this required presentation, had deemed its Board of Directors and grantor trusts to be affiliates, and deducted their stockholdings of 741,761 and 42,397,731 shares, respectively, in determining the aggregate market value.

The registrant had 1,480,240,553 shares of common stock outstanding at January 31, 2009.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 13, 2009 (Part III)

 

 

TABLE OF CONTENTS

Item				Page
PART I
1 and 2.		Business and Properties			1
		Corporate Structure			1
		Segment and Geographic Information			1
		Exploration and Production (E&P)			2
		Midstream			15
		Refining and Marketing (R&M)			16
		LUKOIL Investment			21
		Chemicals			22
		Emerging Businesses			22
		Competition			23
		General			24
1A.		Risk Factors			25
1B.		Unresolved Staff Comments			27
3.		Legal Proceedings			27
4.		Submission of Matters to a Vote of Security Holders			29
		Executive Officers of the Registrant			30
PART II
5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			31
6.		Selected Financial Data			32
7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			33
7A.		Quantitative and Qualitative Disclosures About Market Risk			73
8.		Financial Statements and Supplementary Data			77
9.		Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			174
9A.		Controls and Procedures			174
9B.		Other Information			174
PART III
10.		Directors, Executive Officers and Corporate Governance			175
11.		Executive Compensation			175
12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			175
13.		Certain Relationships and Related Transactions, and Director Independence			175
14.		Principal Accounting Fees and Services			175
PART IV
15.		Exhibits, Financial Statement Schedules			176
Exhibit 10.11
Exhibit 10.12.2
Exhibit 10.21.2
Exhibit 10.22
Exhibit 10.23
Exhibit 10.26
Exhibit 10.27
Exhibit 10.30
Exhibit 12
Exhibit 21
Exhibit 23
Exhibit 31.1
Exhibit 31.2
Exhibit 32

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. Items 1 and 2, Business and Properties, contain forward-looking statements including, without limitation, statements relating to our 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 “forecast,” “intend,” “believe,” “expect,” “plan,” “schedule,” “target,” “should,” “goal,” “may,” “anticipate,” “estimate” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any 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 72.

EXPLORATION AND PRODUCTION (E&P)

At December 31, 2008, our E&P segment represented 67 percent of ConocoPhillips’ total assets. This segment explores for, produces, transports 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 bitumen and upgrade it into a synthetic crude oil. Operations to liquefy natural gas and transport the resulting liquefied natural gas (LNG) are also included in the E&P segment. At December 31, 2008, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Ecuador, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria and Russia.

In October 2008, we closed on a transaction with Origin Energy to further enhance our long-term Australasian natural gas business. The 50/50 joint venture, named Australia Pacific LNG, will focus on coalbed methane production from the Bowen and Surat basins in Queensland, Australia, and LNG processing and export sales.

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 our LUKOIL Investment segment. As a result, references to results, production, prices and other statistics throughout the E&P segment discussion exclude amounts related to our investment in LUKOIL. However, our share of LUKOIL is included in the supplemental oil and gas operations disclosures on pages 147 through 166, as well as in the net proved reserves table shown below.

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

•

Proved worldwide crude oil, natural gas and natural gas liquids reserves.

•

Net production of crude oil, natural gas and natural gas liquids.

•

Average sales prices of crude oil, natural gas and natural gas liquids.

•

Average production costs per barrel of oil equivalent (BOE).

•

Net wells completed, wells in progress and productive wells.

•

Developed and undeveloped acreage.

The following table is a summary of the proved reserves information included in the supplemental oil and gas operations disclosures. Natural gas reserves are converted to BOE based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE.

In 2008, E&P’s worldwide production, including its share of equity affiliates’ production other than LUKOIL, averaged 1,767,000 barrels of oil equivalent per day (BOED), compared with the 1,857,000 averaged in 2007. During 2008, 775,000 BOED were produced in the United States, a decrease from 843,000 in 2007. Production from our international E&P operations averaged 992,000 BOED in 2008, a decrease compared with 1,014,000 in 2007. In addition, our Canadian Syncrude mining operations had net production of 22,000 barrels per day in 2008, compared with 23,000 in 2007. The change in worldwide production was primarily due to field decline and the expropriation of our Venezuelan oil interests, partially offset by production from new developments primarily in the United Kingdom, Indonesia, Russia, Norway and Canada.

E&P’s worldwide annual average crude oil sales price increased 39 percent, from $67.11 per barrel in 2007 to $93.12 in 2008. E&P’s average annual worldwide natural gas sales price increased 32 percent, from $6.26 per thousand cubic feet in 2007 to $8.27 in 2008.

E&P—UNITED STATES

In 2008, U.S. E&P operations contributed 44 percent of E&P’s worldwide liquids production and 43 percent of natural gas production, compared with 46 percent and 45 percent in 2007, respectively.

Alaska

Greater Prudhoe Area

The Greater Prudhoe Area is composed of the Prudhoe Bay field and five satellite fields, as well as the Greater Point McIntyre Area fields. Prudhoe Bay, the largest oil field on Alaska’s North Slope, is the site of a large waterflood and enhanced oil recovery operation, as well as a gas processing plant that processes and re-injects natural gas into the reservoir. Prudhoe Bay’s satellites include Aurora, Borealis, Polaris, Midnight Sun and Orion, while the Point McIntyre, Niakuk, Raven and Lisburne fields are part of the Greater Point McIntyre Area. We have a 36.1 percent nonoperator interest in all fields within the Greater Prudhoe Area. Net oil production from the Greater Prudhoe Area averaged 106,000 barrels per day in 2008, compared with 107,000 in 2007, while natural gas liquids production averaged 17,000 barrels per day in 2008, compared with 19,000 in 2007.

Greater Kuparuk Area

We operate the Greater Kuparuk Area, composed of the Kuparuk field and four satellite fields: Tarn, Tabasco, Meltwater and West Sak. Kuparuk is located about 40 miles west of Prudhoe Bay. Our ownership interest in the area is approximately 55 percent. 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 re-injection. Net oil production from the area averaged 67,000 barrels per day in 2008, compared with 74,000 in 2007.

Western North Slope

The Alpine field and its satellite fields, located west of the Kuparuk field, produced at a net rate of 70,000 barrels of oil per day in 2008, compared with 80,000 in 2007. We operate and hold a 78 percent interest in Alpine and its three satellites, the Nanuq, Fiord and Qannik fields. The Qannik field began production in July 2008.

Cook Inlet Area

Our assets include the North Cook Inlet field, the Beluga River field, and the Kenai LNG facility, all of which we operate. We have a 100 percent interest in the North Cook Inlet field, while we own 33.3 percent of the Beluga River field. Net production in 2008 from the Cook Inlet Area averaged 88 million cubic feet per day of natural gas, compared with 101 million in 2007. Production from the North Cook Inlet field is used primarily to supply our share of gas to the Kenai LNG plant and also as a backup supply to local utilities, while gas from the Beluga River field is primarily sold to local utilities and is used as backup 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. We sold 27 net billion cubic feet in 2008, compared with 31 billion in 2007. In June 2008, the U.S.

Department of Energy announced its approval of a two-year extension of the plant’s export license, extending it through March 2011.

Exploration

We were the successful bidder on 98 blocks totaling $506 million in the February 2008 Chukchi Sea lease sale. During 2008, our primary area of exploratory drilling activity was in the National Petroleum Reserve-Alaska on the Western North Slope. Three wells were drilled in the area, and all three encountered hydrocarbons. One of the wells was expensed as a dry hole, and we are evaluating the potential for future development of the other two discoveries.

Transportation

We transport the petroleum liquids produced on the North Slope to south-central Alaska through an 800-mile pipeline that is part of the Trans-Alaska Pipeline System (TAPS). We have a 28.3 percent ownership interest in TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok pipelines on the North Slope.

Our wholly owned subsidiary Polar Tankers, Inc. manages the marine transportation of our North Slope production, using five company-owned double-hulled tankers in addition to chartering third-party vessels as necessary.

During the second quarter of 2008, ConocoPhillips and BP plc formed a limited liability company to progress the pipeline project named Denali—The Alaska Gas Pipeline. The project, which would move approximately 4 billion cubic feet per day of Alaska natural gas to North American markets, would consist of a gas treatment plant on Alaska’s North Slope and a large-diameter pipeline through Alaska to Alberta, Canada. Should a new pipeline be required to transport gas from Alberta, the project also could include a large-diameter pipeline from Alberta to the U.S. Lower 48.

Denali announced plans to reach the first major project milestone before year-end 2010. This milestone is an open season, a process during which the pipeline company seeks customers to make long-term firm transportation commitments to the project. We expect Denali would seek certification from the Federal Energy Regulatory Commission (FERC) and the Canadian National Energy Board if the open season is successful, and thereafter move forward with project construction. Summer fieldwork related to the project began in late May 2008, primarily in eastern Alaska, and involved route reconnaissance and environmental studies. In late June 2008, the Denali project was approved to use FERC’s prefiling process. There is a pipeline project competing with Denali that is structured under the Alaska Gasline Inducement Act.

U.S. Lower 48

Gulf of Mexico

At year-end 2008, our portfolio of producing properties in the Gulf of Mexico mainly consisted of one operated field and three fields operated by co-venturers, including:

•

75 percent operator interest in the Magnolia field in Garden Banks Blocks 783 and 784.

•

16 percent nonoperator interest in the unitized Ursa field located in the Mississippi Canyon area.

•

16 percent nonoperator interest in the Princess field, a northern, subsalt extension of the Ursa field.

•

12.4 percent nonoperator interest in the unitized K2 field, comprised of seven blocks in the Green Canyon area.

Net production from our Gulf of Mexico properties averaged 18,000 barrels per day of liquids and 24 million cubic feet per day of natural gas in 2008, compared with 25,000 barrels per day and 36 million cubic feet per day in 2007.

Onshore

Our 2008 onshore production principally consisted of natural gas, with the majority of production located in the San Juan Basin, Permian Basin, Lobo Trend, Bossier Trend, and panhandles of Texas and Oklahoma. We also have operations in the Wind River, Anadarko and Fort Worth basins, as well as in East Texas and northern

and southern Louisiana. Other onshore ownership includes properties in the Williston Basin, the Piceance Basin and the Cedar Creek Anticline.

The San Juan Basin, located in northwestern New Mexico and southwestern Colorado, includes the majority of our coalbed methane (CBM) production. Additionally, we continue to pursue development opportunities in three conventional formations in the San Juan Basin. Net production from San Juan averaged 48,000 barrels per day of liquids and 863 million cubic feet per day of natural gas in 2008, compared with 50,000 barrels per day and 971 million cubic feet per day in 2007.

In addition to our CBM production from the San Juan Basin, we also hold CBM acreage positions in the Uinta Basin in Utah, the Black Warrior Basin in Alabama, and the Piceance Basin in Colorado.

Onshore activities in 2008 were mostly centered on continued optimization and development of existing assets. Combined production from all Lower 48 onshore fields in 2008 averaged a net 1,970 million cubic feet per day of natural gas and 147,000 barrels per day of liquids, compared with 2,146 million cubic feet per day and 157,000 barrels per day in 2007.

Transportation

In 2006, we acquired a 24 percent interest in West2East Pipeline LLC, a company holding a 100 percent interest in Rockies Express Pipeline LLC. Rockies Express is completing construction of a 1,679-mile natural gas pipeline from Colorado to Ohio that is expected to have an approximate capacity of 1.8 billion cubic feet per day. A section of the pipeline extending from Colorado to Missouri was placed in service in May 2008, and construction continues on the remaining portion of the pipeline project. Full pipeline service extending to Lebanon, Ohio, is expected by June 2009, while service to the final destination of Clarington, Ohio, is scheduled to begin by year-end 2009.

Exploration

During 2008, we completed 122 gross onshore exploration wells. Most of the wells were located in the Bakken play in the Williston Basin, the Bossier Trend, and the Fort Worth Basin Barnett play, all of which are company focus areas. Other areas with active exploration drilling programs included the Anadarko Basin, Wyoming, Colorado and South Texas.

Gulf of Mexico deepwater leasehold acreage was expanded by successful bidding at federal offshore lease sales in March and August 2008, with high bids totaling $334 million, adding 22 new blocks. At year end we had interests in 267 lease blocks totaling 1.1 million net acres. During 2008, we completed two successful appraisal wells and participated in four deepwater exploration wells. Three of the exploration wells were expensed as dry holes, and operations on one well continued into 2009.

E&P—EUROPE

In 2008, E&P operations in Europe contributed 24 percent of E&P’s worldwide liquids production, compared with 22 percent in 2007. European operations contributed 20 percent of natural gas production in 2008, compared with 19 percent in 2007. Our European assets are principally located in the Norwegian and U.K. sectors of the North Sea.

Norway

We operate and hold a 35.1 percent interest in the Greater Ekofisk Area, located approximately 200 miles offshore Norway in the center of the North Sea. The Greater Ekofisk Area is composed of four producing fields: Ekofisk, Eldfisk, Embla and Tor. Net production in 2008 from the Greater Ekofisk Area was 99,000 barrels of liquids per day and 100 million cubic feet of natural gas per day, compared with 103,000 barrels per day and 103 million cubic feet per day in 2007.

We also have varying ownership interests in other producing fields in the Norwegian sector of the North Sea and in the Norwegian Sea, including:

•

24.3 percent interest in the Heidrun field.

•

20 percent interest in the Alvheim field.

•

10.3 percent interest in the Statfjord field.

•

23.3 percent interest in the Huldra field.

•

1.6 percent interest in the Troll field.

•

9.1 percent interest in the Visund field.

•

6.4 percent interest in the Grane field.

•

2.4 percent interest in the Oseberg area.

Net production from these and other fields in the Norwegian sector of the North Sea and the Norwegian Sea averaged 68,000 barrels of liquids per day and 139 million cubic feet of natural gas per day in 2008, compared with 67,000 barrels per day and 133 million cubic feet per day in 2007.

The Alvheim North Sea development achieved first production in June 2008 through a floating production, storage and offloading (FPSO) vessel and subsea installations. At year-end 2008, Alvheim was producing at a net rate of 16,000 barrels per day of liquids and 7 million cubic feet per day of natural gas. Net peak production of 18,000 barrels per day of liquids and 9 million cubic feet per day of natural gas is expected in the second quarter of 2009.

Transportation

We have interests in the transportation and processing infrastructure in the Norwegian sector of the North Sea, including interests in the Norpipe Oil Pipeline System and in Gassled, which owns most of the Norwegian gas transportation system.

Exploration

We participated in seven exploration wells during 2008, with five of the wells encountering hydrocarbons. Two gas discoveries were made in the PL218 license, and two others were made in the Oseberg area. A discovery was also made on the East Flank of the Visund field, and operations in this well continued into 2009. In late 2008, we were awarded two Norway exploration licenses, both in the central North Sea.

United Kingdom

In addition to our 58.7 percent interest in the Britannia natural gas and condensate field, we own 50 percent of Britannia Operator Limited, the operator of the field. Net production from Britannia and its satellite fields averaged 277 million cubic feet of natural gas per day and 24,000 barrels of liquids per day in 2008, compared with 252 million cubic feet per day and 10,000 barrels per day in 2007. We achieved first production from two Britannia satellites, Callanish and Brodgar, in June and July 2008, respectively. We have a respective 83.5 percent interest and a 75 percent interest in these satellite fields.

We operate and hold a 36.5 percent interest in the Judy/Joanne fields, which together make up J-Block. Additionally, our operated Jade field, in which we hold a 32.5 percent interest, produces from a wellhead platform and pipeline tied to J-Block facilities. Together, these fields produced a net 13,000 barrels of liquids per day and 88 million cubic feet of natural gas per day in 2008, compared with 14,000 barrels per day and 94 million cubic feet per day in 2007.

Our various ownership interests in 18 producing gas fields in the Rotliegendes and Carboniferous areas of the southern North Sea yielded average net production in 2008 of 241 million cubic feet per day of natural gas, compared with 276 million in 2007.

We also have ownership interests in several other producing fields in the U.K. sector of the North Sea, including:

•

23.4 percent interest in the Alba field.

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40 percent interest in the MacCulloch field.

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4.8 percent interest in the Statfjord field.

Production from these and other remaining fields in the U.K. sector of the North Sea averaged a net 17,000 barrels of liquids per day and 14 million cubic feet of natural gas per day in 2008, compared with 20,000 barrels per day and 15 million cubic feet per day in 2007.

In the Atlantic Margin, we have a 24 percent interest in the Clair field. Net production in 2008 averaged 11,000 barrels of liquids per day, compared with 7,000 in 2007.

The Millom, Dalton and Calder fields in the East Irish Sea, in which we have a 100 percent ownership interest, are operated on our behalf by a third party. Net production in 2008 averaged 43 million cubic feet of natural gas per day, compared with 36 million in 2007.

Transportation

The Interconnector pipeline, linking the United Kingdom and Belgium, facilitates marketing natural gas produced in the United Kingdom throughout Europe. Our 10 percent equity share allows us to ship approximately 200 million cubic feet of natural gas per day to markets in continental Europe, and our reverse-flow rights provide an 85 million cubic feet per day import capability into the United Kingdom.

We operate the Teesside oil and Theddlethorpe gas terminals, in which we have 29.3 percent and 50 percent ownerships, respectively. We also have a 100 percent ownership interest in the Rivers Gas Terminal, operated by a third party, in the United Kingdom.

Exploration

During 2008 we were awarded interests in three exploration licenses: two in the central North Sea and one in the West of Shetland region. We also participated in three appraisal wells and three exploration wells in the Southern Gas Basin, central North Sea and the West of Shetland region, with four of the wells encountering hydrocarbons. Three of these six wells were drilled in the proximity of the Jasmine discovery and confirmed the viability of that project.

Netherlands

Our varying nonoperator production interests in the Dutch sector of the North Sea, as well as interests in offshore pipelines and an onshore gas plant and terminal at Den Helder, were sold in December 2008. Net production in 2008 averaged 50 million cubic feet of natural gas per day, compared with 52 million in 2007.

E&P—CANADA

In 2008, E&P operations in Canada contributed 8 percent of E&P’s worldwide liquids production (excluding Syncrude production), compared with 7 percent in 2007. Canadian operations contributed 22 percent of E&P’s worldwide natural gas production in 2008 and 2007.

Oil and Gas Operations

Western Canada

Operations in western Canada encompass properties throughout Alberta, northeastern British Columbia, and southern Saskatchewan. Net production from these oil and gas operations in western Canada averaged 44,000 barrels per day of liquids and 1,054 million cubic feet per day of natural gas in 2008, compared with 46,000 barrels per day and 1,106 million cubic feet per day in 2007.

Surmont

We operate and have a 50 percent interest in the Surmont oil sands lease, located approximately 35 miles south of Fort McMurray, Alberta. The Surmont project uses an enhanced thermal oil recovery method called steam-assisted gravity drainage (SAGD). Steam injection began in the second quarter of 2007, and first production was achieved in the fourth quarter of 2007. Average net production of bitumen from Surmont during 2008 was 6,000 barrels per day, and the 2008 average sales price was $46.85 per barrel. Net peak production of 13,000 barrels per day is expected in 2013.

FCCL

On January 3, 2007, we closed on a business venture with EnCana Corporation to create an integrated North American heavy oil business. The venture consists of two 50/50 business ventures: a Canadian upstream general partnership, the FCCL Oil Sands Partnership, and a U.S. downstream limited liability company, WRB Refining LLC. FCCL’s operating assets consist of the Foster Creek and Christina Lake SAGD bitumen projects, both located in the eastern flank of the Athabasca oil sands in northeastern Alberta. EnCana is the operator and managing partner of FCCL. With Christina Lake phase 1B becoming operational in mid-2008 and the continuing ramp-up of Foster Creek phase C, our share of FCCL’s production increased to 30,000 barrels per day in 2008, compared with 27,000 in 2007. Foster Creek phases D and E are expected to add additional production of more than 20,000 net barrels per day combined and are expected to become operational in early 2009. The average sales price realized on FCCL’s 2008 production was $58.54 per barrel. See the Refining and Marketing (R&M) section for information on WRB.

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. We have a 75 percent interest in the Parsons Lake gas field, one of the primary fields in the Mackenzie Delta that would anchor the pipeline development. The Joint Review Panel (JRP), an independent body appointed by the Minister of Environment to evaluate the potential impacts of the project on the environment and lives of the people in the project area, completed public hearings in November 2007. The JRP issued a press release in December 2008, indicating a report assessing the environmental and socio-economic impact of the proposed project would be released in December 2009. The pipeline project awaits the JRP report and will continue to progress toward regulatory authorizations, but it has deferred detailed engineering work pending resolution with the federal government on the fiscal and commercial framework.

Exploration

We hold exploration acreage in four areas of Canada: western Canada, offshore eastern Canada, the Mackenzie Delta/Beaufort Sea region, and the Arctic Islands. In 2008, the company added 62,000 acres in the Horn River play in western Canada and acquired two additional Beaufort licenses. Within western Canada, we participated in 43 exploratory wells.

Syncrude Canada Ltd.

We own a 9 percent interest in the Syncrude Canada Ltd. (SCL) joint venture, created for the purpose of mining shallow deposits of oil sands, extracting the bitumen, and upgrading it into a light sweet crude oil called Syncrude. The primary plant and facilities are located at Mildred Lake, about 25 miles north of Fort McMurray, Alberta. SCL, as operator of the joint venture, holds eight oil sands leases and the associated surface rights, of which our share is approximately 22,400 net acres. Net production averaged 22,000 barrels per day in 2008, compared with 23,000 in 2007.

U.S. Securities and Exchange Commission regulations currently in effect define the Syncrude 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 2008, E&P operations in South America contributed 1 percent of E&P’s worldwide liquids production, compared with 5 percent in 2007.

Venezuela

Petrozuata, Hamaca and Corocoro

On June 26, 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. In response, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates directly assumed the activities associated with and control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project.

Plataforma Deltana Block 2

We have a 40 percent nonoperated interest in Plataforma Deltana Block 2 which holds a gas discovery made by PDVSA. Several critical components required to progress an investment decision have not yet been defined by the govenment.

Peru

At year-end 2008, we held ownership interests in five exploration blocks in Peru. Two 2D seismic programs were carried out during the year in Blocks 39 and 104, and the sale of Block 57 was completed in the second quarter of the year. In the fourth quarter of 2008, we completed an appraisal well in Block 39, but the well did not confirm a stand-alone commercial hydrocarbon accumulation. The appraisal well and suspended discovery well were expensed as dry holes.

Ecuador

In Ecuador, we own a 42.5 percent interest in Block 7 and a 46.3 percent interest in Block 21. Net production in 2008 averaged 9,000 barrels of crude oil per day, compared with 10,000 in 2007.

Argentina

We sold our assets in Argentina in September 2008.

E&P—ASIA PACIFIC

In 2008, E&P operations in the Asia Pacific region contributed 11 percent of E&P’s worldwide liquids production and 13 percent of natural gas production, compared with 10 percent and 11 percent in 2007, respectively.

Australia and Timor Sea

Australia Pacific LNG

In October 2008, we closed on a transaction with Origin Energy, an integrated Australian energy company, to further enhance our long-term Australasian natural gas business. The 50/50 joint venture, named Australia Pacific LNG, will focus on coalbed methane (CBM) production from the Bowen and Surat basins in Queensland, Australia, and LNG processing and export sales. With this transaction, we gained access to CBM resources in Australia and will enhance our LNG position with the expected creation of an additional LNG hub targeting Asia Pacific markets. Four LNG trains are anticipated, each currently expected to process an estimated 3.5 million gross tons of LNG per year. An estimated 20,500 gross wells are ultimately envisioned to supply both the domestic gas market and the LNG development. Drilling and production operations will be supported by gas gathering systems and centralized gas processing and compression stations, as well as by dewatering and water treatment facilities.

Our share of the joint venture’s year-end production rate was 68 million cubic feet per day. Current production is sold into the Australian domestic market. CBM field development work is ongoing in parallel with front-end engineering associated with the planned LNG processing facilities.

Bayu-Undan

We operate and hold a 57.2 percent ownership interest in the Bayu-Undan field located in the Timor Sea. The field averaged a net production rate of 36,000 barrels of liquids per day in 2008, compared with 34,000 in 2007. Our share of natural gas production was 210 million cubic feet per day in 2008, compared with 189 million in 2007. Produced natural gas is used to supply the Darwin LNG plant, of which we own a 57.2 percent interest. In 2008, we sold 159 billion gross cubic feet of LNG to utility customers in Japan, compared with 140 billion in 2007.

Greater Sunrise

We have a 30 percent interest in the Greater Sunrise gas and condensate field located in the Timor Sea. Although agreement has been reached between the governments of Australia and Timor-Leste concerning sharing of revenues from the anticipated development of Greater Sunrise, key challenges to be resolved before significant funding commitments can be made include ensuring the reservoir is adequately appraised, gaining co-venturer and government alignment on the development concept, and establishing fiscal stability arrangements. Immediate activity is focused on reprocessing seismic data and integrating the results of an appraisal well to define the remaining appraisal program, as well as advancing the development concept screening phase.

Western Australia

In 2008, our share of production from the Athena/Perseus (WA-17-L) gas field, located offshore Western Australia, was 35 million cubic feet of natural gas per day, compared with 34 million in 2007.

Exploration

In November 2008, we acquired 50 percent interests in two permits in the Arafura Basin, offshore Northern Territory. In the Bonaparte Basin, we drilled one successful appraisal well at the Sunrise field. Additionally, seismic processing from the NT/P69 and the NT/P61 permits was completed, and interpretation of this data is currently under way to further evaluate the Caldita and Barossa discoveries.

The company also operates the WA-314-P, WA-315-P and WA-398-P permits in the Browse Basin. During 2008, acquisition and processing of seismic data in WA-398-P was completed. An exploration drilling campaign will be conducted in these permits during 2009.

Indonesia

We operate seven production sharing contracts (PSCs) in Indonesia. Production from Indonesia in 2008 averaged a net 343 million cubic feet per day of natural gas and 15,000 barrels per day of oil, compared with 330 million cubic feet per day and 12,000 barrels per day in 2007. Our assets are concentrated in two core areas: the West Natuna Sea and onshore South Sumatra.

We operate four offshore PSCs: South Natuna Sea Block B, Amborip VI, Kuma and Arafura Sea. The South Natuna Sea Block B PSC, in which we have a 40 percent interest, has two producing oil fields and 16 gas fields in various stages of development.

We operate three onshore PSCs. Corridor and South Jambi B are in South Sumatra, and Warim is in Papua. As part of the Corridor PSC, in which 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, Batam and West Java. We have a 45 percent interest in the South Jambi B PSC, a shallow gas project that supplies natural gas to Singapore.

Transportation

We are a 35 percent owner of a consortium company that has a 40 percent ownership in PT Transportasi Gas Indonesia, which owns and operates the Grissik to Duri and Grissik to Singapore natural gas pipelines.

Exploration

In November 2008, we acquired the Arafura Sea Block, and a 2D seismic survey was completed on the block by year end. One appraisal well was drilled at the South Belut field, and one appraisal well and one exploration well were drilled at the North Belut field.

China

Production related to our 49 percent share of the Peng Lai 19-3 field in Bohai Bay Block 11-05 averaged 14,000 barrels of oil per day in 2008, compared with 10,000 in 2007. We also hold a 49 percent interest in the nearby Peng Lai 25-6 field. An FPSO vessel to accommodate production from both fields is expected to be installed in early 2009. Concurrent development of both fields continues.

The Xijiang development consists of two fields located approximately 80 miles south of Hong Kong in the South China Sea. Our ownership in these fields ranges from 12.3 percent to 24.5 percent. Facilities include two manned platforms and an FPSO vessel. Combined net production of oil from the Xijiang fields averaged 7,000 barrels per day in 2008, compared with 8,000 in 2007.

We have a 24.5 percent interest in the offshore Panyu field, also located in the South China Sea, which produced 12,000 net barrels of oil per day in 2008 and 13,000 in 2007. In July 2008, we sold our 100 percent interest in the onshore Ba Jiao Chang natural gas field.

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, four exploration blocks, and one gas pipeline transportation system.

We have a 23.3 percent interest in Block 15-1 in the Cuu Long Basin. Net production in 2008 was 13,000 barrels of oil per day, compared with 14,000 in 2007. The oil is processed through a 1-million-barrel FPSO vessel and through the Su Tu Vang central processing platform and new floating storage and offloading (FSO) vessel. First oil production from the Su Tu Vang satellite field was achieved in October 2008.

Also in the Cuu Long Basin, we have a 36 percent interest in the Rang Dong field in Block 15-2. All wellhead platforms produce into an FSO vessel. Net production in 2008 was 9,000 barrels per day of liquids and 16 million cubic feet per day of natural gas, compared with 8,000 barrels per day and 15 million cubic feet per day in 2007.

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

In 2008, we drilled one exploration well in Block 15-1 that was expensed as a dry hole.

Malaysia

We have interests in three deepwater PSCs located off the eastern Malaysian state of Sabah: Block G, Block J, and the Kebabangan Cluster. Development of the Gumusut discovery in Block J continues.

Exploration

In 2008, we completed two successful appraisal wells in Block G to evaluate the prior Ubah and Petai discoveries. Kebabangan and Malikai, a Block G discovery, are moving toward field development.

E&P—MIDDLE EAST AND AFRICA

During 2008, E&P operations in the Middle East and Africa contributed 8 percent of E&P’s worldwide liquids production and 2 percent of natural gas production, the same as in 2007.

Qatar

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. The project also includes a 7.8-million-gross-ton-per-year LNG facility, from which LNG will be shipped in

new LNG carriers destined for sale in the United States and other markets. The first LNG cargoes are expected to be loaded in the fourth quarter of 2010.

In order to capture cost savings, Qatargas 3 is executing 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. Upon completion of the Qatargas 3 and Qatargas 4 projects, production from the LNG plant and associated facilities will be combined and shared.

We have a 12.4 percent ownership interest in the Golden Pass LNG regasification facility and associated pipeline. The facilities are currently being constructed on the Sabine-Neches Industrial Ship Channel northwest of Sabine Pass, Texas. Subject to the negotiation of definitive agreements, ConocoPhillips will also secure capacity rights in the regasification terminal and pipeline to manage the LNG we will purchase from Qatargas 3. In addition to the United States, other market alternatives for Qatargas 3 LNG production are being pursued. Despite sustaining some damage during Hurricane Ike, the Golden Pass LNG terminal is expected to be operational in time to receive the first cargoes of Qatargas 3 production.

Libya

ConocoPhillips holds a 16.3 percent interest in the Waha concessions in Libya, which encompass nearly 13 million gross acres. Net oil production averaged 47,000 barrels per day in 2008 and 2007.

Nigeria

During 2008, we produced from four onshore Oil Mining Leases (OMLs), in which we have a 20 percent nonoperator interest. Net production from these leases was 21,000 barrels of liquids per day and 105 million cubic feet of natural gas per day in 2008, compared with 19,000 barrels per day and 117 million cubic feet per day in 2007.

We have a 20 percent interest in a 480-megawatt gas-fired power plant in Kwale, Nigeria, which supplies electricity to Nigeria’s national electricity supplier. In 2008, the plant consumed 11 million net cubic feet per day of natural gas sourced from our proved reserves in the OMLs.

We have a 17 percent equity interest in Brass LNG Limited, which plans to construct an LNG facility in the Niger Delta.

Exploration

We drilled an exploration well in block OPL214 that did not confirm commercial quantities of hydrocarbons and was expensed as a dry hole. Development planning activities for the prior Uge discovery in the same block continue. In the fourth quarter of 2007, we assigned our interest in OPL248 to a co-venturer. This assignment was formally acknowledged by the Nigerian government in the third quarter of 2008.

Abu Dhabi

In July 2008, we signed an Interim Agreement with the Abu Dhabi National Oil Company (ADNOC) to develop the Shah gas field in Abu Dhabi. This large-scale project involves the development of natural gas condensate reservoirs within the onshore Shah gas field, the construction of a new 1-billion-cubic-feet-per-day natural gas processing plant at Shah, new natural gas and liquid pipelines, and sulfur-exporting facilities at Ruwais. ADNOC would have a 60 percent interest and we would have a 40 percent interest in the project. We are currently working on final project agreements with ADNOC.

Algeria

We have interests in three fields in Block 405a: the Menzel Lejmat North field, the Ourhoud field, and the development stage El Merk (EMK) oil field unit. Net production from these fields averaged 13,000 barrels of oil per day in 2008, compared with 11,000 in 2007.

E&P—RUSSIA AND CASPIAN

Russia

Polar Lights

We have a 50 percent equity interest in Polar Lights Company, an entity created to develop fields in the Timan-Pechora Basin in northern Russia. Net production averaged 11,000 barrels of oil per day in 2008, compared with 12,000 in 2007.

NMNG

We have a 30 percent ownership interest with a 50 percent governance interest in OOO Naryanmarneftegaz (NMNG), a joint venture with LUKOIL. NMNG is working to develop resources in the northern part of Russia’s Timan-Pechora province, including the Yuzhno Khylchuyu (YK) field. Initial production from YK was achieved in June 2008, with the field producing at a net rate of 24,000 barrels of oil per day at year end. Net peak production of 45,000 barrels per day is expected to be reached in the second quarter of 2009. Production from the NMNG joint venture fields is transported via pipeline to LUKOIL’s terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. Late in the second quarter of 2008, LUKOIL completed an expansion of the terminal’s gross oil-throughput capacity from 30,000 barrels per day to 240,000 barrels per day to accommodate production from the YK field.

Caspian

In the Caspian Sea, we have an interest in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement (NCSPSA), which includes the Kashagan field. The first phase of field development currently being executed includes construction of artificial drilling islands with processing facilities and living quarters, and pipelines to carry production onshore. First production is expected in the latter part of 2012. The initial production phase of the contract is for 20 years, with options to extend the agreement an additional 20 years.

In 2004, the Republic of Kazakhstan approved the submitted development plan and budget relating to the Kashagan oil field development and, in 2007, triggered dispute proceedings under the NCSPSA following submission of a revised development plan and budget reflecting Kashagan cost increases and schedule delays. Definitive agreements were signed October 31, 2008, resolving the Kashagan field development dispute and allowing Kazakhstan’s state-owned energy company, JSC National Company KazMunayGas, to increase its ownership interest from 8.33 percent to 16.81 percent. As a result, our interest in the NCSPSA was reduced from 9.26 percent to 8.40 percent, effective January 1, 2008. We will receive our share of the purchase price plus accrued interest in three annual installments beginning from the date of first commercial production. In addition, a new joint operating company, with significant involvement from the owners, was established and will operate future phases of Kashagan. We will have seconded employees in the joint operating company.

Transportation

We have a 2.5 percent interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline, which transports crude oil from the Caspian region through Azerbaijan, Georgia and Turkey for tanker loadings at the port of Ceyhan.

Exploration

In October 2008, we signed a Memorandum of Understanding to negotiate terms for the exploration and development of the N Block, located offshore Kazakhstan, under a new subsoil use contract. Subsequently, in December 2008, we signed a Heads of Agreement that would give us a 24.5 percent interest in the exploration and development of the N Block. In addition, development studies continue for the next phase of Kashagan and the satellite fields of Kalamkas, Kairan and Aktote.

E&P—OTHER

LNG

We have a long-term agreement with Freeport LNG Development, L.P. to use 0.9 billion cubic feet per day of regasification capacity at Freeport’s 1.5-billion-cubic-feet-per-day LNG receiving terminal in Quintana, Texas. The terminal became operational late in the second quarter of 2008. In order to deliver natural gas from the Freeport terminal to market, we constructed a 32-mile, 42-inch pipeline from the Freeport terminal to a point near Iowa Colony, Texas. Construction was completed in the second quarter of 2008 to coincide with the

Freeport terminal startup. Due to present market conditions, which favor the flow of LNG to European and Asian markets, our near-to-mid-term utilization of the Freeport terminal is expected to be limited. We are responsible for monthly process-or-pay payments to Freeport irrespective of whether we utilize the terminal for regasification. The financial impact of this capacity underutilization is not expected to be material to our future earnings or cash flows.

We received planning permission in 2008 for an LNG regasification facility and combined heat and power plant at the existing Norsea Pipeline Limited oil terminal site at Teesside, United Kingdom.

Commercial

Our Commercial organization optimizes the commodity flows of our E&P segment. This group markets our crude oil and natural gas production, using commodity buyers, traders and marketers in offices in the United States, the United Kingdom, Singapore, Canada and Dubai.

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, 2008. No difference exists between our estimated total proved reserves for year-end 2007 and year-end 2006, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2008.

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 6 trillion cubic feet of natural gas and 119 million barrels of crude oil in the future, including approximately 800 billion cubic feet related to the minority interests of consolidated subsidiaries. These contracts have various expiration dates through the year 2025. We expect to fulfill the majority of these delivery commitments with proved developed reserves. In addition, we anticipate using proved undeveloped reserves and spot market purchases to fulfill these commitments. See the disclosure on “Proved Undeveloped Reserves” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for information on the development of proved undeveloped reserves.

MIDSTREAM

At December 31, 2008, our Midstream segment represented 1 percent of ConocoPhillips’ total assets. Our Midstream business is primarily conducted through our 50 percent equity investment in DCP Midstream, LLC, a joint venture with Spectra Energy.

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 2008, including our share of DCP Midstream, were 188,000 barrels per day, compared with 211,000 in 2007.

DCP Midstream markets a portion of its natural gas liquids to ConocoPhillips and Chevron Phillips Chemical Company LLC under a supply agreement that continues until December 31, 2014. This purchase commitment is on an “if-produced, will-purchase” basis and so 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 the agreement, natural gas liquids are purchased at various published market index prices, less transportation and fractionation fees.

DCP Midstream is headquartered in Denver, Colorado. At December 31, 2008, DCP Midstream owned or operated 53 natural gas liquids extraction and 10 natural gas liquids fractionation plants, and its gathering and transmission systems included approximately 60,000 miles of pipeline. In 2008, DCP Midstream’s raw natural gas throughput averaged 6.2 billion cubic feet per day, and natural gas liquids extraction averaged 360,000 barrels per day, compared with 5.9 billion cubic feet per day and 363,000 barrels per day in 2007. DCP Midstream’s assets are primarily located in the following producing regions of the United States: Rocky Mountains, Midcontinent, Permian, East Texas/North Louisiana, South Texas, Central Texas, and Gulf Coast.

Outside of DCP Midstream, our U.S. natural gas liquids business included the following as of year-end 2008:

•

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).

•

A 12.5 percent equity interest in a fractionation plant in Mont Belvieu, Texas (with our net share of capacity at 26,000 barrels per day).

We also own a 39 percent equity interest in Phoenix Park Gas Processors Limited, a joint venture principally with the National Gas Company of Trinidad and Tobago Limited. Phoenix Park processes natural gas in Trinidad and markets natural gas liquids in the Caribbean, Central America and the U.S. Gulf Coast. Its facilities include a 1.35-billion-cubic-feet-per-day gas processing plant and a 70,000-barrel-per-day natural gas liquids fractionator. A third gas processing train is currently under construction and, when complete in 2009, will bring Phoenix Park’s total processing capacity to 2 billion cubic feet per day. Our share of natural gas liquids extracted averaged 8,000 barrels per day in 2008 and 2007. Our share of fractionated liquids averaged 14,000 barrels per day in 2008, compared with 13,000 in 2007.

REFINING AND MARKETING (R&M)

At December 31, 2008, our R&M segment represented 24 percent of ConocoPhillips’ total assets. R&M operations encompass refining crude oil and other feedstocks into petroleum products (such as gasolines, 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 the Asia Pacific region. The R&M segment does not include the results or statistics from our equity investment in LUKOIL, which are reported in our LUKOIL Investment segment.

Our 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, supplies petroleum products to our marketing operations, and markets petroleum products directly to third parties. Commercial has buyers, traders and marketers in offices in the United States, the United Kingdom, Singapore, Canada and Dubai.

Primary crude oil characteristics and sources of crude oil for our U.S. refineries are as follows:

Capacities for and yields of clean products, as well as other products produced, relating to our U.S. refineries are as follows:

		Clean Product Capacity (MBD)												Other Refined Product Output
										Clean				Fuel Oil &				Natural								Petro-
										Product Yield				Other Heavy				Gas				Petroleum				chemical
		Gasolines				Distillates				Capability				Intermediates				Liquids				Coke				Feedstock				Asphalt
Bayway			145				110				90	%			•				•								•
Trainer			105				65				85	%			•				•
Alliance			125				120				88	%			•				•				•				•
Lake Charles			90				110				69	%			•				•				•	**
Sweeny			130				120				86	%			•				•				•				•
Wood River*			83				45				80	%			•				•				•				•				•
Borger*			55				28				89	%							•				•				•
Ponca City			105				75				90	%			•				•				•
Billings			35				25				89	%							•				•
Ferndale			50				30				73	%			•
Los Angeles			85				61				86	%											•
San Francisco			50				45				72	%			•				•				•

MSLP

ConocoPhillips has a 50 percent interest in Merey Sweeny, L.P. (MSLP), a limited partnership that owns a 70,000-barrel-per-day delayed coker and related facilities at the Sweeny refinery that produce fuel-grade petroleum coke. Petróleos de Venezuela S.A. (PDVSA), which owns the other 50 percent interest, supplies the refinery with heavy, high-sulfur crude oil. We are the operator and managing partner. Late in 2008, PDVSA notified us that January 2009 nominated crude oil supplies for MSLP would not be delivered due to Venezuelan government-ordered production reductions. Similar notifications have been received for nominated supplies for February and March. We processed alternative crude oils at MSLP during January. Late in January, MSLP entered into a planned turnaround, which will continue into March 2009.

WRB

On January 3, 2007, we closed on a business venture with EnCana Corporation to create an integrated North American heavy oil business. The venture consists of two 50/50 business ventures: a Canadian upstream general partnership, the FCCL Oil Sands Partnership, and a U.S. downstream limited liability company, WRB Refining LLC. WRB consists of the Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas, respectively. We are the operator and managing partner of WRB. For the Wood River refinery, operating results are shared 50/50. For the Borger refinery, we were entitled to 65 percent of the operating results in 2008, with our share decreasing to 50 percent in all years thereafter. See the Exploration and Production (E&P) section for additional information on FCCL.

Since formation, the joint venture has expanded the processing capability of heavy Canadian crude to 95,000 barrels per day from 60,000 barrels per day with the startup of a coker at Borger in 2007. In addition, during 2008, the final permit was received and plans were progressed to expand the Wood River refinery, including the installation of a coker. With the completion of this project, anticipated in 2011, total processing capability of heavy Canadian or similar crudes at Wood River will increase to 225,000 barrels per day, and existing asphalt production at the refinery will be replaced with production of upgraded products.

Capital Projects

In 2008, capital was directed toward projects to meet environmental and air emission standards and to further improve the operating reliability, safety and energy efficiency of processing units. In addition, capital was spent for small projects that are expected to yield an incremental return through providing improvements in overall transportation fuel yields and product mix.

Significant projects during 2008 included progressing an expansion of a hydrocracker at the Rodeo facility of our San Francisco refinery. When complete in 2009, this project is expected to increase clean product yield at the refinery. We also installed wet gas scrubbers at our Los Angeles and Ponca City refineries in order to improve air emissions from those plants. Another project completed during the year was a coker upgrade at our Los Angeles refinery, which improved the yield of transportation fuels.

Marketing

In the United States as of December 31, 2008, R&M marketed gasoline, diesel and aviation fuel through approximately 8,340 outlets in 49 states. The majority of these sites utilize the Phillips 66 , Conoco or 76 brands.

Wholesale

At December 31, 2008, our wholesale operations utilized a network of marketers operating approximately 7,270 outlets that provided refined product offtake from our refineries, including Borger and Wood River. A strong emphasis is placed on the wholesale channel of trade because of its lower capital requirements. 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, we produce and market aviation gasoline, which is used by smaller, piston engine aircraft. At December 31, 2008, aviation gasoline and jet fuel were sold through independent marketers at approximately 630 Phillips 66 -branded locations in the United States.

Retail

At December 31, 2008, our retail operations consisted of approximately 330 owned and operated sites under the Conoco , Phillips 66 and 76 brands. Company-operated retail operations were focused in 10 states, mainly in the Midcontinent, Rocky Mountain and West Coast regions. Most of these outlets marketed merchandise through the Kicks or Circle K brand convenience stores.

At December 31, 2008, CFJ Properties, our 50/50 joint venture with Flying J, owned and operated approximately 110 truck travel plazas that carry the Conoco , Flying J or both brands. Flying J filed for Chapter 11 bankruptcy protection in December 2008. Flying J continues to operate the CFJ properties jointly owned with ConocoPhillips.

In December 2006, we announced our U.S. company-owned and company-operated retail outlets and our U.S. company-owned and dealer-operated retail outlets would be divested to new or existing wholesale marketers. Approximately 830 sites were included in the held for sale plans. About 620 sites have been sold, including approximately 390 outlets sold in January 2009. The remaining sites included in the original disposition plan are also expected to be sold in 2009.

Transportation

We distribute refined products to our customers via company-owned and common-carrier pipeline, barge, railcar and truck.

Pipelines and Terminals

At December 31, 2008, R&M had approximately 28,000 miles of common-carrier crude oil, raw natural gas liquids, and petroleum products pipeline systems in the United States, including those partially owned or operated by affiliates. We also owned or operated 48 finished product terminals, seven liquefied petroleum gas terminals, five crude oil terminals and one coke exporting facility.

In December 2007, we acquired a 50 percent equity interest in four Keystone pipeline entities (Keystone), to create a joint venture with TransCanada Corporation. In October 2008, we elected to exercise an option to reduce our equity interest from 50 percent to 20.01 percent. The change in equity will occur through a dilution mechanism, which is expected to gradually lower our ownership interest until it reaches 20.01 percent by the third quarter of 2009. At December 31, 2008, our ownership interest was 38.7 percent. Keystone’s first phase, a 2,148-mile, 590,000-barrel-per-day crude oil pipeline from Alberta to delivery points in Illinois and Oklahoma, is expected to be mechanically complete in late 2009. A second phase is expected to carry up to 700,000 barrels per day to refineries on the Gulf Coast. We anticipate utilizing the Keystone pipeline to transport our Canadian crude oil production to market, including as a source of supply to our U.S. refineries.

Tankers

During 2008, we disposed of our international marine operations consisting of leasehold interests in six double-hulled crude oil tankers and replaced the disposed operations with long-term charter agreements. At December 31, 2008, we had 17 double-hulled crude oil tankers, with capacities ranging in size from 700,000 to 2,100,000 barrels, which are under charter primarily to transport feedstocks to certain of our U.S. refineries. In addition, we had under charter five double-hulled product tankers utilized to transport our heavy and clean products. The tankers discussed here exclude the operations of the company’s subsidiary, Polar Tankers, Inc., which are discussed in the E&P segment, 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. Our lubes are marketed under the Phillips 66 , Conoco , 76 and Kendall brands. We also manufacture and market high-quality graphite and anode-grade petroleum cokes in the United States and Europe for use in the global steel and aluminum industries.

The company’s 50-percent-owned Excel Paralubes joint venture owns a hydrocracked lubricant base oil manufacturing plant located adjacent to the Lake Charles refinery. The facility produces approximately 20,000 barrels per day of high-quality, clear hydrocracked base oils.

In January 2008, we sold our 50 percent interest in Penreco, which manufactured and marketed highly refined specialty petroleum products.

Primary crude oil characteristics and sources of crude oil for our international refineries are as follows:

Capacities for and yields of clean products, as well as other products produced, relating to our international refineries are as follows:

Clean Product Capacity (MBD)

Other Refined Product Output

Clean

Fuel Oil &

Product Yield

Other Heavy

Natural Gas

Petroleum

Gasolines

Distillates

Capability

Intermediates

Liquids

Coke

Asphalt

Humber

84

119

84

%

•

•

•

*

Whitegate

18

30

65

%

•

Wilhelmshaven

36

102

53

%

•

MiRO

25

26

85

%

•

•

•

•

Melaka

14

36

85

%

•

•

•

•

We operate a crude oil and products storage complex consisting of 7.5 million barrels of storage capacity and an offshore mooring buoy, located about 80 miles southwest of the Whitegate refinery in Bantry Bay, Ireland.

During 2008, we continued to progress our plans to upgrade the Wilhelmshaven refinery in Germany. Our future capital budget incorporates funds to economically improve the operation of the refinery, enabling it to process heavier, higher-sulfur crude oil and produce predominantly low-sulfur diesel.

In late 2007, we and our co-venturers sanctioned a project for the expansion of the Melaka refinery to be completed during 2010. This project is intended to increase crude oil, conversion and treating unit capacities.

In May 2006, we signed a Memorandum of Understanding with Saudi Aramco to conduct a detailed evaluation of the proposed development of a 400,000-barrel-per-day, full-conversion refinery in Yanbu, Saudi Arabia. The refinery would be designed to process Arabian heavy crude oil and produce high-quality, ultra-low-sulfur refined products. In November 2008, we agreed to delay the bidding process associated with the refinery’s construction due to uncertainties in the contracting and financial markets. The originally scheduled bidding process requested bids be submitted in December 2008. Instead, project bidding is now scheduled to begin in 2009.

Marketing

At December 31, 2008, R&M had marketing operations in five European countries. R&M’s European marketing strategy is to sell primarily through owned, leased or joint venture retail sites using a low-cost, high-volume strategy. We use the JET brand name to market retail and wholesale products in Austria, Germany 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. 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 in the aforementioned countries and Ireland.

As of December 31, 2008, R&M had approximately 1,260 marketing outlets in its European operations, of which approximately 860 were company-owned and 400 were dealer-owned. Through our joint venture operations in Switzerland, we also have interests in 200 additional sites. In October 2008, we sold our 274 fueling stations in Norway, Sweden and Denmark to Statoil.

LUKOIL INVESTMENT

At December 31, 2008, our LUKOIL Investment segment represented 4 percent of ConocoPhillips’ total assets. In 2004, we became a strategic equity investor in OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. Under the Shareholder Agreement between the two companies, we have representation on the LUKOIL Board of Directors, and LUKOIL’s corporate charter requires unanimous Board consent for certain key decisions. At year-end 2008, we had a 20 percent ownership interest in LUKOIL based on authorized and issued shares. Based on estimated shares outstanding at year end, our ownership was 20.06 percent. We use the equity method of accounting for our investment in LUKOIL. See Note 7—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for additional information.

As reported in LUKOIL’s publicly available 2007 annual report, the majority of its 2007 upstream oil production was sourced within Russia, with 62 percent from the western Siberia region, 15 percent from the Timan-Pechora province and 12 percent from the Urals region. Outside of Russia, LUKOIL had 2007 oil production in Kazakhstan, Egypt and Azerbaijan, and gas production in Uzbekistan. Eighty-eight percent of LUKOIL’s natural gas production was sourced within Russia. In addition, LUKOIL has an active exploration program focused in Russia but also encompassing several international countries. Downstream, LUKOIL has seven refineries with a net crude oil throughput capacity of approximately 1.2 million barrels per day. LUKOIL also has a marketing network extending to 24 countries, with the majority of wholesale and retail sales in Russia, the United States and Europe.

CHEMICALS

At December 31, 2008, our Chemicals segment represented 2 percent of ConocoPhillips’ total assets. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem), a joint venture with Chevron Corporation, headquartered in The Woodlands, Texas.

CPChem’s business is structured around two primary operating segments: Olefins & Polyolefins and Specialties, Aromatics & Styrenics. 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, polypropylene, and polyethylene pipe. The Specialties, 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. Furthermore, this segment manufactures and markets a variety of specialty chemical products including organosulfur chemicals, solvents, catalysts, drilling chemicals, mining chemicals and high-performance engineering plastics and compounds.

CPChem’s domestic facilities are located in California, Connecticut, Illinois, Louisiana, Mississippi, Ohio and Texas. International facilities are located in Belgium, Brazil, China, Columbia, Qatar, Saudi Arabia, Singapore and South Korea.

CPChem owns a 49 percent interest in Qatar Chemical Company Ltd. (Q-Chem), a joint venture that owns a major olefins and polyolefins complex in Mesaieed, Qatar. CPChem also owns a 49 percent interest in Qatar Chemical Company II Ltd. (Q-Chem II), a joint venture that began construction of a second complex in Mesaieed in 2005. This Q-Chem II facility is designed to produce polyethylene and normal alpha olefins on a site adjacent to the Q-Chem complex. In connection with this project, CPChem entered into a separate agreement establishing a joint venture to develop an ethylene cracker in Ras Laffan Industrial City, Qatar. Operational startup of the Q-Chem II project is anticipated in late 2009.

In 2003, CPChem formed a 50-percent-owned joint venture company to develop an integrated styrene facility in Al Jubail, Saudi Arabia. The facility is being built adjacent to the existing aromatics complex owned by Saudi Chevron Phillips Company (SCP), another 50-percent-owned CPChem joint venture. Construction of the facility, which began in the fourth quarter of 2004, is in conjunction with an expansion of SCP’s existing benzene plant, together called the “JCP Project.” Operational startup occurred in the third quarter of 2008, while project completion is anticipated during the first quarter of 2009.

In 2007, CPChem formed a 50-percent-owned joint venture, Saudi Polymers Company (SPC), to construct and operate an integrated petrochemicals complex at Al Jubail, Saudi Arabia. Construction began in January 2008, and commercial production is scheduled to begin in late 2011. Prior to project completion, based on a planned initial public offering of shares in CPChem’s joint venture partner’s company and a corresponding increase in the partner’s ownership interest in SPC, CPChem’s ownership is expected to decline to 35 percent.

In 2007, CPChem and the Dow Chemical Company signed a nonbinding Memorandum of Understanding relating to the formation of a joint venture involving assets from their polystyrene and styrene monomer businesses. Joint venture operations commenced in May 2008, with CPChem contributing two domestic plants and Dow contributing four domestic and two international plants.

EMERGING BUSINESSES

At December 31, 2008, our Emerging Businesses segment represented 1 percent of ConocoPhillips’ total assets. The segment encompasses the development of new technologies and businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels and the environment.

The focus of our power business is on developing projects to support our E&P and R&M strategies. While projects primarily in place to enable these strategies are included within their respective segments, projects with a significant merchant component are included in the Emerging Businesses segment.

The Immingham combined heat and power plant (CHP), a wholly owned 730-megawatt facility in the United Kingdom, provides steam and electricity to the Humber refinery and steam to a neighboring refinery, as well as merchant power into the U.K. market. In October 2006, we announced we would expand capacity at Immingham to 1,180 megawatts. 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. Commercial operation of the expansion is expected to start in mid-2009.

We also own a gas-fired cogeneration plant in Orange, Texas, as well as a 50 percent operating interest in Sweeny Cogeneration LP, a joint venture near the Sweeny refinery complex.

Our Technology group focuses on developing new business opportunities designed to provide future growth prospects for ConocoPhillips. Areas of interest include advanced hydrocarbon processes, energy conversion technologies, new petroleum-based products, renewable fuels and carbon capture technology. We have commercialized production of renewable diesel, a new type of renewable fuel that utilizes existing infrastructure. In 2007, we formed a research relationship with Iowa State University to develop new methods for producing second-generation biofuels. In addition, we have formed alliances with Tyson Foods and Archer Daniels Midland to produce and market the next generation of renewable transportation fuels. We have also formed an internal group that is evaluating wind, solar and geothermal investment opportunities.

We are working with General Electric Company to develop a technology center in Qatar to research water sustainability solutions for petroleum, petrochemical, municipal and agricultural applications. The Qatar center will examine ways of treating and using by-product water from oil production and refining operations, as well as other projects relating to industrial and municipal water sustainability. In conjunction with the Interim Agreement to develop the Shah field with the Abu Dhabi National Oil Company, we are planning to develop a technology center in Abu Dhabi that will conduct research and provide technical service in areas including reservoir management and development of sour gas fields; safe and efficient processing of gas with high hydrogen sulfide and carbon dioxide concentrations; and sour gas sequestration. Both centers are expected to open in 2009.

We offer a gasification technology (E-Gas) that uses petroleum coke, coal, and other low-value hydrocarbons as feedstock, resulting in high-value synthesis gas used for a slate of products, including power, hydrogen and chemicals. In 2008, we completed a feasibility study and submitted applications for all required environmental permits related to a proposed coal-to-substitute natural gas (SNG) facility, which would have a capacity of 60 billion to 70 billion cubic feet per year and be located in Muhlenberg County, Kentucky. We also became a founding member of the Western Kentucky Carbon Storage Foundation, which is funding evaluation of carbon storage in deep underground formations through a test well project directed by the Kentucky Geologic Survey.

A conceptual engineering study was completed in 2008 for a project at our Sweeny refinery in Texas that would utilize E-Gas technology to convert petroleum coke to low-carbon power or SNG and hydrogen. To minimize carbon dioxide (CO2) emissions from the facility, the proposed design allows CO2 to be captured, transported and safely stored in nearby geological formations. This project would increase clean energy supply while establishing critical carbon capture and storage infrastructure in the Texas Gulf Coast region. A more detailed feasibility study is expected in 2009.

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 our segments 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 publicly available year-end 2007 reserves statistics, we had the sixth-largest total of worldwide proved reserves of nongovernment-controlled companies. We deliver our oil and natural gas production into the worldwide oil and natural gas commodity markets. Principal methods of competing include geological, geophysical and engineering research and technology; experience and expertise; economic analysis in connection with property acquisitions; and operating efficient oil and gas producing properties.

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

Downstream, our R&M segment competes primarily in the United States, Europe and the Asia Pacific region. Based on the statistics published in the December 22, 2008, issue of the Oil & Gas Journal , our R&M segment had the second-largest U.S. refining capacity of 18 large refiners of petroleum products. Worldwide, our refining capacity ranked fourth among nongovernment-controlled companies. In the Chemicals segment, CPChem generally ranked within the top 10 producers of many of its major product lines, based on average 2008 production capacity, as published by industry sources. Petroleum products, petrochemicals and plastics are delivered into the worldwide commodity markets. Elements of competition for both our R&M and Chemicals segments include product improvement, new product development, low-cost structures, and improved manufacturing and distribution systems. In the marketing portion of the business, competitive factors include product properties and processibility, reliability of supply, customer service, price and credit terms, advertising and sales promotion, and development of customer loyalty to ConocoPhillips’ or CPChem’s branded products.

GENERAL

At the end of 2008, we held a total of 1,464 active patents in 81 countries worldwide, including 556 active U.S. patents. During 2008, we received 39 patents in the United States and 58 foreign patents. Our products and processes generated licensing revenues of $38 million in 2008. 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 $209 million, $160 million, and $117 million in 2008, 2007, and 2006, respectively.

The environmental information contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 63 through 65 under the caption “Environmental” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2008 and those expected for 2009 and 2010.

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 U.S. Securities and Exchange Commission (SEC). Alternatively, you may access these reports at the SEC’s Web site at http://www.sec.gov .

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.

Our operating results, our future rate of growth and the carrying value of our assets are exposed to the effects of changing commodity prices and refining margins.

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. The factors influencing the prices of crude oil, natural gas, natural gas liquids and refined products are beyond our control. Lower crude oil, natural gas, natural gas liquids and refined products prices may reduce the amount of these commodities we can produce economically, which may have a material adverse effect on our revenues, operating income and cash flows.

Unless we successfully add to our existing proved reserves, our future crude oil and natural gas production will decline, resulting in harm to our business.

The rate of production from crude oil and natural gas properties generally declines as reserves are depleted. Except to the extent that we 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 we are unsuccessful in replacing the crude oil and natural gas we produce with good prospects for future production, our business will suffer reduced cash flows and results of operations.

Any material change in the factors and assumptions underlying our estimates of crude oil and natural gas reserves could impair the quantity and value of those reserves.

Our proved crude oil and natural gas reserve information included in this annual report has been derived from engineering estimates prepared or reviewed by our personnel. 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. 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. Any changes in the factors and assumptions underlying our estimates of these items could result in a material negative impact to the volume of reserves reported.

We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Likewise, future environmental laws and regulations may impact or limit our current business plans and reduce demand for our products.

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:

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The discharge of pollutants into the environment.

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Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions, or potential future control of greenhouse gas emissions).

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The handling, use, storage, transportation, disposal and clean up of hazardous materials and hazardous and nonhazardous wastes.

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The dismantlement, abandonment and restoration of our properties and facilities at the end of their useful lives.

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 business, financial condition, results of operations and cash flows in future periods could be materially adversely affected.

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

Actions of the U.S., state and local governments 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, such as the expropriation of our oil assets by the Venezuelan government, and will continue to do so in the future.

Local political and economic factors in international markets could have a material adverse effect on us. Approximately 56 percent of our crude oil, natural gas and natural gas liquids production in 2008 was derived from production outside the United States, and 62 percent of our proved reserves, as of December 31, 2008, were located outside the United States. We are subject to 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.

The current financial crisis could have a material adverse affect on our financial strength and that of our business co-venturers.

Recent disruptions in the credit markets and concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices, both of which have contributed to a decline in our stock price and corresponding market capitalization. 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. Decreased returns on pension fund assets may also materially increase our pension funding requirements. Likewise, the capital and credit markets have become increasingly volatile as a result of adverse conditions. If the capital and credit markets continue to experience volatility and the availability of funds remains limited, we, and third parties with whom we do business, may incur increased costs associated with issuing commercial paper and/or other debt instruments and this, in turn, could adversely affect our ability to advance our strategic plans as currently contemplated. In this context, changes in our debt rating could have a material adverse effect on our interest costs and financing sources.

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 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 participants. There is a risk that our joint venture participants may at any time have economic, business or legal interests or goals that are inconsistent with those of the joint venture or us, or that our joint venture participants may be unable to meet their economic or other obligations and 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.

Our operations are inherently dangerous and require significant and continuous oversight.

The scope and nature of our operations present a variety of operational hazards and risks that must be managed through continual oversight and control. These risks are present throughout the process of extraction, transportation, refinement and storage of the hydrocarbons we produce. Failure to manage these risks could result in injury or loss of life, environmental damage, loss of revenues and damage to our reputation.

On December 15, 2008, the Trainer refinery received Citations and a Notification of Penalty (Citation) from the Occupational Safety and Health Administration (OSHA) for 26 alleged violations noted during the OSHA National Emphasis Program review of the refinery. The Citation seeks $115,500 in penalties for a variety of alleged Process Safety Management violations. We are working with OSHA to resolve this matter.

Matters Previously Reported

The South Coast Air Quality Management District (SCAQMD) conducted an audit of the Los Angeles refinery in 2007 to assess compliance with applicable local, state, and federal regulations related to fugitive emissions. As a result of the audit, SCAQMD issued three Notices of Violations (NOVs) alleging multiple counts of noncompliance. We resolved two of the three NOVs for a total payment of $42,500 in the third quarter of 2008 and reached an agreement with SCAQMD to resolve the third NOV for $12,500 in the fourth quarter of 2008.

SCAQMD conducted an audit of the Los Angeles refinery in August 2008 to assess compliance with applicable local, state and federal regulations related to fugitive emissions. As a result of the audit, on August 28, 2008, SCAQMD issued five NOVs alleging noncompliance. SCAQMD has not yet specified a penalty for these alleged violations. We are working with SCAQMD to resolve these NOVs.

On July 16, 2008, ConocoPhillips received a demand from the Bay Area Air Quality Management District (BAAQMD) to settle 24 NOVs issued in late 2006 and 2007 for alleged violations of air pollution-control regulations at the San Francisco refinery. The amount of the settlement demand is $304,500. On December 29, 2008, BAAQMD added an additional seven NOVs issued in 2008 and a corresponding additional $340,500 to its settlement demand. We are working with BAAQMD to resolve these NOVs.

On June 2, 2008, the Billings refinery received a Violation Letter from the Montana Department of Environmental Quality (MDEQ) for opacity and nickel emissions, which occurred during startup of the catalytic cracker in April 2007. The letter also alleged certain monitoring quality assurance/quality control violations. The letter requests a penalty of $604,000. We intend to work with the MDEQ to resolve this matter.

On March 27, 2008, the Trainer refinery received a proposed Consent Assessment of Civil Penalty from the Pennsylvania Department of Environmental Protection (PADEP) for alleged air quality violations that occurred from 2002 to 2007. The assessment covers several categories of alleged air quality violations including emission events, air emissions inventory reporting, and violation of permit conditions. We paid $129,424 in the fourth quarter of 2008 to resolve this matter.

On March 27, 2008, the Sweeny refinery received a Notice of Enforcement (NOE) from the Texas Commission on Environmental Quality (TCEQ) for an emissions event related to flaring that occurred on January 28, 2008. A penalty of $32,000 was submitted to the TCEQ in September 2008. This matter is subject to formal approval by the TCEQ Commissioners. We expect consideration of approval to occur in the first quarter of 2009.

On February 11, 2008, ConocoPhillips Alaska, Inc. (CPAI) received an NOV from the North Slope Borough (NSB) in relation to its Alpine facility on the North Slope of Alaska. The NOV alleges that three fuel tanks at the Alpine facility lacked adequate containment and/or setbacks from water bodies. There was no environmental impact due to these alleged violations. The NOV proposed penalties of $207,000, which was later reduced to $128,000. CPAI paid the reduced penalty under protest in accordance with the payment demands in the NOV. On March 11, 2008, CPAI filed an appeal with the NSB Planning Commission challenging the alleged violations and penalties in the NOV. We will continue to work with the NSB to resolve this matter.

In October 2003, the District Attorney’s Office in Sacramento, California, filed a complaint in Superior Court for alleged methyl tertiary-butyl ether (MTBE) contamination in groundwater. On April 4, 2008, the District Attorney’s Office filed an amended complaint that included alleged violations of state regulations relating to operation or maintenance of underground storage tanks. There are numerous defendants named in the suit in addition to ConocoPhillips. We intend to continue to contest this lawsuit.

In October 2007, we received a Complaint from the U.S. EPA alleging violations of the Clean Water Act related to a 2006 oil spill at our Bayway refinery and proposing a penalty of $156,000. We are working with the EPA and the U.S. Coast Guard to resolve this matter.

On December 16, 2005, the Bayway refinery experienced a hydrocarbon spill to the Rahway River and Arthur Kill. On August 26, 2006, we signed an Order on Consent with the state of New York pursuant to which we paid a penalty of $50,000 and conducted a beach cleanup. Also in December 2008, we paid a total of $106,578 for natural resource damages and other costs to the New Jersey Department of Environmental Protection, the U.S. Department of the Interior and the U.S. Department of Commerce. This matter is resolved.

In March 2005, ConocoPhillips Pipe Line Company (CPPL) received a Notice of Probable Violation and Proposed Civil Penalty from the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (DOT) alleging violation of DOT operation and safety regulations at certain facilities in Kansas, Missouri, Illinois, Indiana, Wyoming and Nebraska. DOT is proposing penalties in the amount of $184,500. An information hearing was held on September 24, 2007. CPPL has provided additional information in support of its position. We are currently awaiting a ruling from DOT.

The U.S. Coast Guard and Washington State Department of Ecology investigated the possible sources of an oil spill in Puget Sound. In November 2004, the U.S. Attorney and the U.S. Coast Guard offices in Seattle, Washington, issued subpoenas to Polar Tankers, Inc., a subsidiary of ConocoPhillips Company, for records related to the vessel Polar Texas. On December 23, 2004, the governor of the state of Washington and the U.S. Coast Guard publicly announced they believed the Polar Texas was the source of the spill. The company fully cooperated with the investigations. The U.S. Attorney’s Office in Seattle declined prosecution of the company. As previously reported, Polar Tankers, ConocoPhillips and the state of Washington settled the matter, with payment of civil penalties and response costs. The settlement did not include any admission of liability. The company and the authorities remain in settlement negotiations regarding the natural resource damage assessment.

In April 2004, in response to several historical spills at the Albuquerque Products Terminal, we received an Administrative Compliance Order from the New Mexico Environment Department. The order does not propose a penalty assessment, but rather attempts to impose specific design, construction and operational changes. We have been in negotiations with the agency and in June 2007 proposed a settlement offer of $100,000. We will continue to work with the agency to resolve this matter.

There is no family relationship among the officers named above. Each officer of the company is elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as appropriate. Each officer of the company holds office from date of election until the first meeting of the directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the next annual meeting is May 13, 2009. Set forth below is information about the executive officers.

Rand C. Berney was appointed Vice President and Controller upon completion of the merger in 2002.

John A. Carrig was appointed President and Chief Operating Officer in October 2008, having previously served as Executive Vice President, Finance, and Chief Financial Officer since the merger in 2002.

W. C. W. Chiang was appointed Senior Vice President, Refining, Marketing and Transportation in October 2008. He previously served as Senior Vice President, Commercial since 2007. Prior to that, he served as President, Americas Supply & Trading, Commercial, from 2005 through 2007 and as President, Downstream Strategy, Integration and Specialty Businesses from 2003 through 2005.

Sigmund L. Cornelius was appointed Senior Vice President, Finance, and Chief Financial Officer in October 2008. Prior to that, he served as Senior Vice President, Planning, Strategy and Corporate Affairs since September 2007, having previously served as President, Exploration and Production—Lower 48 since 2006. He served as President, Global Gas since 2004, and prior to that served as President, Lower 48, Latin America and Midstream since 2003.

James L. Gallogly was appointed Executive Vice President, Exploration and Production in October 2008, and prior to that served as Executive Vice President, Refining, Marketing and Transportation from April 2006. He previously served as President and Chief Executive Officer of Chevron Phillips Chemical Company LLC since 2000.

Janet L. Kelly was appointed Senior Vice President, Legal, General Counsel and Corporate Secretary effective September 1, 2007, having previously served as Deputy General Counsel since 2006. Prior to joining ConocoPhillips in 2006, she was a partner at Zelle, Hoffman, Voelbel, Mason and Gette during 2005 and 2006. She previously served as Senior Vice President, Chief Administrative Officer and Chief Compliance Officer of Kmart Corporation during 2003 and 2004.

James J. Mulva has served as Chairman of the Board of Directors and Chief Executive Officer since October 2008, having previously served as Chairman of the Board of Directors, President and Chief Executive Officer since October 2004. Prior to that, he served as President and Chief Executive Officer since completion of the merger in 2002.

Jeff W. Sheets was appointed Senior Vice President, Planning and Strategy in October 2008, having previously served as Vice President and Treasurer since the merger in 2002.

PART II

Item 6. SELECTED FINANCIAL DATA

See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance an understanding of this data.

The financial data for 2008 includes the impact of impairments relating to goodwill and to our LUKOIL investment that together amount to $32,853 million before- and after-tax. For additional information, see the “Goodwill Impairment” section of Note 9—Goodwill and Intangibles and the “LUKOIL” section of Note 7—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements.

The financial data for 2007 includes the impact of a $4,588 million before-tax ($4,512 million after-tax) impairment related to the expropriation of our oil interests in Venezuela. For additional information, see the “Expropriated Assets” section of Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Additionally, the acquisition of Burlington Resources in 2006 affects the comparability of the amounts included in the table above. See Note 3—Acquisition of Burlington Resources Inc., in the Notes to Consolidated Financial Statements, for additional information. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for information on changes in accounting principles affecting the comparability of amounts included in the table above.

February 25, 2009

Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions, that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “intends,” “believes,” “expects,” “plans,” “scheduled,” “should,” “anticipates,” “estimates” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 72.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is an international, integrated energy company. We are the third-largest integrated energy company in the United States, based on market capitalization. We have approximately 33,800 employees worldwide, and at year-end 2008 had assets of $143 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

Our business is organized into six operating segments:

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Exploration and Production (E&P) —This segment primarily explores for, produces, transports and markets crude oil, natural gas and natural gas liquids on a worldwide basis.

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Midstream —This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, predominantly in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream, LLC.

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Refining and Marketing (R&M) —This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.

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LUKOIL Investment —This segment consists of our equity investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. At December 31, 2008, our ownership interest was 20 percent based on issued shares and 20.06 percent based on estimated shares outstanding.

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Chemicals —This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem).

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Emerging Businesses —This segment represents our investment in new technologies or businesses outside our normal scope of operations.

In 2008, the energy industry was characterized by extreme volatility. Forecasts of worldwide economic growth and increasingly scarce supply, a weakening U.S. dollar, and other factors helped drive crude oil prices to record highs. This was followed by an abrupt shift into a severe global financial recession, which reduced current and forecasted demand for petroleum products. Because of this, crude oil prices fell rapidly and refining margins also significantly weakened.

As a result of the significant drop in global equity markets during the fourth quarter of 2008, we recorded two individually significant impairments in 2008 that were primarily linked to market capitalizations—a $25.4 billion write-down of our E&P segment’s recorded goodwill, and a $7.4 billion reduction in the carrying value of our LUKOIL investment. These impairments contributed to a net loss in 2008 of $17.0 billion, compared with net income in 2007 of $11.9 billion, which includes the impact of a $4.5 billion impairment due to expropriation of our Venezuelan assets. Since these 2008 and 2007 impairment charges were noncash, they did not impact our cash provided by operating activities, which was $22.7 billion in 2008, compared with $24.6 billion in 2007.

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

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Operating our producing properties and refining and marketing operations safely, consistently and in an environmentally sound manner. Safety is our first priority, and we are committed to protecting the health and safety of everyone who has a role in our operations and the communities in which we operate. Maintaining high utilization rates at our refineries and minimizing downtime in producing fields enable us to capture the value available in the market in terms of prices and margins. During 2008, our worldwide refining capacity utilization rate was 90 percent, compared with 94 percent in 2007. The lower rate primarily reflects reduced throughput at our Wilhelmshaven, Germany, refinery due to economic conditions, as well as higher unplanned downtime including impacts from hurricanes in the U.S. Gulf Coast region. Concerning the environment, we strive to conduct our operations in a manner consistent with our environmental stewardship principles.

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

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Successful exploration and development of new fields.

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Acquisition of existing fields.

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Applying new technologies and processes to improve recovery from existing fields.

Through a combination of all three methods listed above, we have been successful in the past in maintaining or adding to our production and proved reserve base. Although it cannot be assured, we anticipate being able to do so in the future. In the three years ending December 31, 2008, our reserve replacement was 124 percent, including the impacts of the Burlington Resources acquisition, additional equity investments in LUKOIL, the FCCL Oil Sands Partnership with EnCana, the Australia Pacific LNG joint venture with Origin Energy, and the expropriation of our Venezuelan oil assets.

Access to additional resources has become increasingly difficult as direct investment is prohibited in some nations, while fiscal and other terms in other countries can make projects uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.

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Controlling costs and expenses. Since we cannot control the prices of the commodity products we sell, controlling operating and overhead costs, within the context of our commitment to safety and environmental stewardship, are high priorities. We monitor these costs using various methodologies that are reported to senior management monthly, on both an absolute-dollar basis and a per-unit basis. Because managing operating and overhead costs is critical to maintaining competitive positions in our

industries, cost control is a component of our variable compensation programs. In response to the current depressed market environment, we expect to reduce our work force in 2009, reduce the headcount of contractors, and continue to emphasize cost discipline throughout our operations.

With the rise in commodity prices over the last several years and through the first half of 2008, and the subsequent increase in industry-wide spending on capital and major maintenance programs, we and other energy companies experienced inflation for the costs of certain goods and services in excess of general worldwide inflationary trends. Such costs included rates for drilling rigs, steel and other raw materials, as well as costs for skilled labor. With the weakening of the economy and the decline in commodity prices, our industry began to see some relief from this upward cost pressure in late 2008 and into early 2009.

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Selecting the appropriate projects in which to invest our capital dollars. We participate in capital-intensive industries. As a result, we must often invest significant capital dollars to explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, or continue to maintain and improve our refinery complexes. We invest in those projects that are expected to provide an adequate financial return on invested dollars. However, there are often long lead times from the time we make an investment to the time that investment is operational and begins generating financial returns.

In October 2008, we formed Australia Pacific LNG, a 50/50 joint venture with Origin Energy for the development of coalbed natural gas in Australia, and the subsequent liquefaction and transport of the liquefied natural gas targeting Asia Pacific markets. In January 2007, we entered into two 50/50 business ventures with EnCana to create an integrated North American heavy oil business, consisting of the upstream FCCL Oil Sands Partnership in Canada and the downstream WRB Refining LLC in the United States.

Our capital expenditures and investments in 2008 totaled $19.1 billion, and we anticipate capital expenditures and investments to be approximately $11.7 billion in 2009. The reduced capital budget in 2009 reflects the impact of the Origin transaction on the 2008 totals, and a planned reduction in response to current market conditions. In addition to our capital program, we paid dividends on our common stock of $2.9 billion in 2008, and repurchased $8.2 billion of our common stock.

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Managing our asset portfolio. We continue to evaluate opportunities to acquire assets that will contribute to future growth at competitive prices. The 2006 Burlington Resources acquisition, the 2007 EnCana business ventures, and the 2008 Origin Energy joint venture are examples of such activity. We also continually assess our assets to determine if any no longer fit our strategic plans and should be sold or otherwise disposed. This management of our asset portfolio is important to ensuring our long-term growth and maintaining adequate financial returns. In 2008, we completed the disposition of our retail marketing assets in Norway, Sweden and Denmark, and we also sold all of our E&P properties in Argentina and the Netherlands. We closed on the sale of a large part of our U.S. retail marketing assets in January 2009.

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Developing and retaining a talented work force. We strive to attract, train, develop and retain individuals with the knowledge and skills to implement our business strategy and who support our values and ethics. Throughout the company, we focus on the continued learning, development and technical training of our employees. Professional new hires participate in structured development programs designed to accelerate their technical and functional skills.

Our key performance indicators are shown in the statistical tables provided at the beginning of the operating segment sections that follow. These include crude oil, natural gas and natural gas liquids prices and production, refining capacity utilization, and refinery output.

Other significant factors that can affect our profitability include:

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Impairments. As mentioned above, we participate in capital-intensive industries. At times, our investments become impaired when our reserve estimates are revised downward, when crude oil or natural gas prices, or refinery margins decline significantly for long periods of time, or when a decision to dispose of an asset leads to a write-down to its fair market value. We may also invest large amounts of money in exploration blocks which, if exploratory drilling proves unsuccessful, could lead to a material impairment of leasehold values. Before-tax impairments in 2008, excluding the goodwill impairment discussed below and a $7.4 billion impairment related to our LUKOIL investment, totaled $1.7 billion. This amount compares with $0.4 billion of impairments, excluding the impairment of expropriated assets (discussed below), in 2007.

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Goodwill. At year-end 2008, we had $3.8 billion of goodwill on our balance sheet, compared with $29.3 billion at year-end 2007. In 2008, we recorded a $25.4 billion complete impairment of our E&P segment goodwill, primarily as a function of decreased year-end commodity prices and the decline in our market capitalization. For additional information, see Note 9—Goodwill and Intangibles, in the Notes to Consolidated Financial Statements. Deterioration of market conditions in the future could lead to other goodwill impairments that may have a substantial negative, though noncash, effect on our profitability.

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Effective tax rate. Our operations are located in countries with different tax rates and fiscal structures. Accordingly, even in a stable commodity price and fiscal/regulatory environment, our overall effective tax rate can vary significantly between periods based on the “mix” of pretax earnings within our global operations.

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Fiscal and regulatory environment. As commodity prices and refining margins fluctuated upward over the last several years, certain governments have responded with changes to their fiscal take. These changes have generally negatively impacted our results of operations, and further changes to government fiscal take could have a negative impact on future operations. In June 2007, our Venezuelan oil projects were expropriated, and we recorded a $4.5 billion after-tax impairment (see the “Expropriated Assets” section of Note 10—Impairments, in the Notes to Consolidated Financial Statements). The company was also negatively impacted by increased production taxes enacted by the state of Alaska in the fourth quarter of 2007. In October 2007, the government of Ecuador increased the tax rate of the Windfall Profits Tax Law implemented in 2006, increasing the amount of government royalty entitlement on crude oil production to 99 percent of any increase in the price of crude oil above a contractual reference price. In Canada, the Alberta provincial government changed the royalty structure for Crown lands, effective January 1, 2009, so that a component of the new royalty rate is tied to prevailing prices. In October 2008, we and our co-venturers signed definitive agreements for the proportional dilution of our equity interests in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement, which includes the Kashagan field, to allow the state-owned energy company to increase its ownership percentage effective January 1, 2008. Partially offsetting the above fiscal take increases were lower corporate income tax rates enacted by Canada and Germany during 2007. These tax rate reductions applied to all corporations and were not exclusive to the oil and gas industry.

Segment Analysis

The E&P segment’s results are most closely linked to crude oil and natural gas prices. These are commodity products, the prices of which are subject to factors external to our company and over which we have no control. Industry crude oil prices for West Texas Intermediate (WTI) were higher in 2008, compared with 2007, averaging $99.56 per barrel in 2008, an increase of 38 percent. The increase was driven by concerns during the first half of 2008 of adequate supplies given the strong oil demand growth in developing Asia and the Middle East. The average annual price for WTI moderated due to the economic crisis in the second half of 2008 that impacted demand from all regions of the world. Industry natural gas prices for Henry Hub increased 32 percent during 2008 to an average price of $9.04 per million British thermal units (MMBTU), primarily due to increased demand from the industrial and electric power sector during the first half of 2008 and higher oil prices. These factors were moderated by higher domestic production and lower demand, which led to higher storage in the second half of 2008.

The Midstream segment’s results are most closely linked to natural gas liquids prices. The most important factor on the profitability of this segment is the results from our 50 percent equity investment in DCP Midstream. DCP Midstream’s natural gas liquids prices increased 11 percent in 2008.

Refining margins, refinery utilization, cost control and marketing margins primarily drive the R&M segment’s results. Refining margins are subject to movements in the cost of crude oil and other feedstocks, and the sales prices for refined products, both of which are subject to market factors over which we have no control. Industry refining margins in the United States were lower overall in comparison with 2007. The primary factor contributing to the reduced refining margins in 2008 was a decrease in gasoline demand.

The LUKOIL Investment segment consists of our investment in the ordinary shares of LUKOIL. At December 31, 2008, our ownership interest in LUKOIL was 20 percent based on issued shares and 20.06 percent based on estimated shares outstanding. LUKOIL’s results are subject to factors similar to those of our E&P and R&M segments. LUKOIL’s upstream results are closely linked to Russian (Urals) crude oil prices and are heavily impacted by extraction tax rates. Refining margins are significant factors on LUKOIL’s downstream results. Export tariff rates for crude oil and refined products also have a significant impact on both upstream and downstream results.

The Chemicals segment consists of our 50 percent interest in CPChem. The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on market factors over which CPChem has little or no control. CPChem is investing in feedstock-advantaged areas in the Middle East with access to large, growing markets, such as Asia.

The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels and the environment. Some of these technologies have the potential to become important drivers of profitability in future years.

RESULTS OF OPERATIONS

2008 vs. 2007

The lower results in 2008 were primarily the result of:

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A $25,443 million before- and after-tax goodwill impairment of all E&P segment goodwill. This impairment was recorded during the fourth quarter.

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A $7,410 million before- and after-tax impairment of our LUKOIL investment taken during the fourth quarter.

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Lower U.S. refining margins in our R&M segment.

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An increase in other asset impairments, predominantly in our E&P and R&M segments.

These items were partially offset by:

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Higher crude oil, natural gas and natural gas liquids prices, benefiting our E&P, Midstream and LUKOIL Investment segments. Commodity price benefits were somewhat counteracted by increased production taxes.

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A 2007 complete impairment ($4,588 million before-tax, $4,512 million after-tax) of our oil interests in Venezuela, resulting from their expropriation on June 26, 2007.

2007 vs. 2006

The lower results in 2007 were primarily the result of:

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The complete impairment of our oil interests in Venezuela.

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Lower crude oil production in the E&P segment.

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Higher production and operating expenses, higher production taxes, and higher depreciation, depletion and amortization expense in the E&P segment.

These items were partially offset by:

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The net benefit of asset rationalization efforts in the E&P and R&M segments.

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Higher realized crude oil, natural gas, and natural gas liquids prices in the E&P segment.

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Higher realized worldwide refining margins, including the benefit of planned inventory reductions, in the R&M segment.

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Increased equity earnings from our investment in LUKOIL due to higher estimated commodity prices and volumes, and an increase in our average equity ownership percentage.

Statement of Operations Analysis

2008 vs. 2007

Sales and other operating revenues increased 28 percent in 2008, while purchased crude oil, natural gas and products increased 37 percent. These increases were mainly the result of higher petroleum product prices and higher prices for crude oil, natural gas and natural gas liquids.

Equity in earnings of affiliates decreased 16 percent in 2008, reflecting:

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Lower results from WRB Refining LLC, due to lower margins and a decline in equity ownership in accordance with the designed formation of the venture.

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Lower results from CPChem, due to higher operating costs, lower specialties, aromatics and styrenics margins, and lower olefins and polyolefins volumes.

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The absence of earnings from our heavy oil joint ventures expropriated by Venezuela in 2007.

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Increased losses related to our Naryanmarneftegaz (NMNG) joint venture as a result of higher production taxes and increased depreciation, depletion and amortization (DD&A) costs during the startup and early production phase of the Yuzhno Khylchuyu (YK) field.

These negative results were somewhat offset by improved results from the FCCL Oil Sands Partnership, DCP Midstream, LUKOIL (excluding the investment impairment), and CFJ Properties.

Other income decreased 45 percent during 2008, mainly due to a lower net benefit from asset rationalization efforts, the release in 2007 of escrowed funds associated with our Hamaca joint venture in Venezuela, and the settlement of retroactive adjustments for crude oil quality differentials on Trans-Alaska Pipeline System shipments (Quality Bank) in 2007.

Exploration expenses increased 33 percent during 2008, reflecting increased dry hole costs and higher expenses for post-discovery feasibility and development planning studies.

Impairments increased from $5,030 million in 2007 to $34,539 million in 2008. This increase reflects a $25,443 million goodwill impairment recorded during 2008 in our E&P segment. Also contributing to the increase was a $7,410 million impairment of our LUKOIL investment taken during 2008. These 2008 impairments were partially offset by a 2007 impairment of $4,588 million related to the expropriation of our oil interests in Venezuela.

Other impairments increased $1,244 million during 2008 primarily due to property impairments taken in response to a significantly diminished outlook for crude oil and natural gas prices, refining margins and power spreads, as well as in response to revised capital spending plans. For additional information, see Note 7—Investments, Loans, and Long-Term Receivables, Note 9—Goodwill and Intangibles, and Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Interest and debt expense decreased 25 percent in 2008, primarily due to lower average interest rates, as well as the absence of 2007 interest expense related to the Alaska Quality Bank settlements.

Foreign currency transaction losses incurred during 2008 totaled $117 million, compared with foreign currency transaction gains of $201 million in 2007. This change occurred as the Canadian dollar, Russian rouble, British pound, and euro all weakened against the U.S. dollar during 2008, compared with the strengthening of these currencies against the U.S. dollar in 2007.

See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our income tax expense and effective tax rate.

2007 vs. 2006

Equity in earnings of affiliates increased 21 percent in 2007. The increase reflects earnings from WRB and FCCL, our downstream and upstream business ventures with EnCana, formed in January 2007. Also, we had improved results from LUKOIL, reflecting higher estimated commodity prices and volumes, and an increase in our average equity ownership percentage. These increases were partially offset by lower earnings from Hamaca and Petrozuata, our heavy oil joint ventures expropriated by Venezuela in the second quarter of 2007. Additionally, CPChem reported lower earnings, primarily due to lower olefins and polyolefins margins.

Other income increased 188 percent during 2007, primarily due to:

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Higher net gains on asset dispositions associated with asset rationalization efforts.

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The release in 2007 of escrowed funds related to the extinguishment of Hamaca project financing.

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The Alaska Quality Bank settlements in 2007.

These increases were partially offset by the recognition in 2006 of recoveries on business interruption insurance claims attributable to losses sustained from hurricanes in 2005.

Exploration expenses increased 21 percent during 2007, primarily reflecting the amortization of unproved North American leaseholds obtained in the Burlington Resources acquisition and the impairment of an international exploration license. The increase also reflects higher geological and geophysical expenses and higher dry hole costs.

Depreciation, depletion and amortization increased 14 percent during 2007, primarily resulting from the addition of Burlington Resources’ assets in the E&P segment’s depreciable asset base for a full year in 2007 versus only nine months in 2006.

Impairments reflects an impairment of $4,588 million related to the expropriation of our oil interests in Venezuela recorded in the second quarter of 2007. Impairments unrelated to the expropriation decreased 35 percent during 2007, primarily due to impairments recorded in 2006 of certain assets held for sale in the R&M segment, comprised of properties, plants and equipment, trademark intangibles and goodwill.

Interest and debt expense increased 15 percent during 2007, primarily due to the interest expense component of the Alaska Quality Bank settlements, as well as higher expense associated with the funding requirements for the business venture with EnCana.

Foreign currency transaction gains during 2007 primarily reflect the strengthening of the Canadian dollar against the U.S. dollar.

Segment Results

E&P