2009

 

 

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

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

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) (Zip Code)

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

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

Title of each class		Name of each exchange on which registered
Common Stock, $.01 Par Value		New York Stock Exchange
Preferred Share Purchase Rights Expiring June 30, 2012		New York Stock Exchange
6.65% Debentures due July 15, 2018		New York Stock Exchange
7% Debentures due 2029		New York Stock Exchange
9.375% Notes due 2011		New York Stock Exchange

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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. o

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.

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, 2009, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $42.06, was $62.3 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 811,943 and 39,808,419 shares, respectively, in determining the aggregate market value.

The registrant had 1,486,838,088 shares of common stock outstanding at January 31, 2010.

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 12, 2010 (Part III)

 

 

TABLE OF CONTENTS

Item		Page
PART I
1 and 2. Business and Properties			1
Corporate Structure			1
Segment and Geographic Information			2
Exploration and Production (E&P)			2
Midstream			14
Refining and Marketing (R&M)			15
LUKOIL Investment			20
Chemicals			21
Emerging Businesses			21
Competition			22
General			23
1A. Risk Factors			24
1B. Unresolved Staff Comments			26
3. Legal Proceedings			26
4. Submission of Matters to a Vote of Security Holders			27
Executive Officers of the Registrant			28
PART II
5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			30
6. Selected Financial Data			31
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			32
7A. Quantitative and Qualitative Disclosures About Market Risk			67
8. Financial Statements and Supplementary Data			70
9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			171
9A. Controls and Procedures			171
9B. Other Information			171
PART III
10. Directors, Executive Officers and Corporate Governance			172
11. Executive Compensation			172
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			172
13. Certain Relationships and Related Transactions, and Director Independence			172
14. Principal Accounting Fees and Services			172
PART IV
15. Exhibits, Financial Statement Schedules			173
Signatures			178
EX-12
EX-21
EX-23
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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 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 66.

Items 1 and 2. BUSINESS AND PROPERTIES

CORPORATE STRUCTURE

ConocoPhillips is an international, integrated energy company. ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger between Conoco Inc. and Phillips Petroleum Company. The merger between Conoco and Phillips was consummated on August 30, 2002.

Our business is organized into six operating segments:

	•		Exploration and Production (E&P)—This segment primarily explores for, produces, transports and markets crude oil, natural gas, natural gas liquids and bitumen on a worldwide basis.
	•		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.
	•		Refining and Marketing (R&M)—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.
	•		LUKOIL Investment—This segment consists of our equity investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. At December 31, 2009, our ownership interest was 20 percent based on issued shares and 20.09 percent based on estimated shares outstanding.
	•		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.
	•		Emerging Businesses—This segment represents our investment in new technologies or businesses outside our normal scope of operations.

At December 31, 2009, ConocoPhillips employed approximately 30,000 people.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 25—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

EXPLORATION AND PRODUCTION (E&P)

At December 31, 2009, our E&P segment represented 66 percent of ConocoPhillips’ total assets. This segment primarily explores for, produces, transports and markets crude oil, natural gas, natural gas liquids and bitumen on a worldwide basis. Operations to liquefy natural gas and transport the resulting liquefied natural gas (LNG) are also included in the E&P segment. At December 31, 2009, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria and Russia.

The E&P segment does not include the financial results or statistics from our equity investment in the ordinary shares of LUKOIL, which are reported in 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 “Oil and Gas Operations” disclosures, as well as in the net proved reserves table shown below.

The information listed below appears in the “Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements and is incorporated herein by reference:

	•		Proved worldwide crude oil and natural gas liquids, natural gas, bitumen and synthetic oil reserves.
	•		Net production of crude oil and natural gas liquids, natural gas, bitumen and synthetic oil.
	•		Average sales prices of crude oil and natural gas liquids, natural gas, bitumen and synthetic oil.
	•		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 “Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements. Approximately 65 percent of our proved reserves are located in politically stable countries that belong to the “Organization for Economic Cooperation and Development.” Natural gas reserves are converted to BOE based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE.

		Millions of Barrels of Oil Equivalent
Net Proved Reserves at December 31		2009				2008				2007
Crude oil and natural gas liquids
Consolidated operations			3,194				3,340				3,778
Equity affiliates			1,710				1,677				1,834
Total Crude Oil and Natural Gas Liquids			4,904				5,017				5,612
Natural gas
Consolidated operations			3,161				3,360				3,750
Equity affiliates			880				798				490
Total Natural Gas			4,041				4,158				4,240
Bitumen
Consolidated operations			417				100				85
Equity affiliates			716				700				623
Total Bitumen			1,133				800				708
Synthetic oil
Consolidated operations			248				—				—
Equity affiliates			—				—				—
Total Synthetic Oil			248				—				—
Total consolidated operations			7,020				6,800				7,613
Total equity affiliates			3,306				3,175				2,947
Total company			10,326				9,975				10,560
Includes amounts related to LUKOIL investment:			1,967				1,893				1,838
Excludes Syncrude mining-related reserves (synthetic oil):			n/a				249				221

In 2009, E&P’s worldwide production, including its share of equity affiliates’ production other than LUKOIL, averaged 1,854,000 barrels of oil equivalent per day (BOED), compared with 1,789,000 in 2008. During 2009, 755,000 BOED were produced in the United States, a decrease from 775,000 in 2008. Production from our international E&P operations averaged 1,099,000 BOED in 2009, an increase compared with 1,014,000 in 2008. Worldwide production increased primarily due to new developments in the United Kingdom, Russia, China, Canada, Vietnam and Norway, in addition to less unplanned downtime. These increases were partially offset by field decline.

E&P’s worldwide annual average crude oil and natural gas liquids sales price decreased 37 percent, from $88.91 per barrel in 2008 to $55.63 in 2009. E&P’s average annual worldwide natural gas sales price decreased 48 percent, from $8.27 per thousand cubic feet in 2008 to $4.26 in 2009.

E&P—UNITED STATES

In 2009, U.S. E&P operations contributed 40 percent of E&P’s worldwide liquids production and 41 percent of natural gas production, compared with 43 percent for each in 2008.

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 are 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 and natural gas liquids production from the Greater Prudhoe Area averaged 119,000 barrels per day in 2009, compared with 123,000 in 2008.

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 65,000 barrels per day in 2009, compared with 67,000 in 2008.

Western North Slope

On the Western North Slope we operate the Colville River Unit, composed of the Alpine Field and three satellite fields: Nanuq, Fiord and Qannik. Alpine is located about 30 miles west of Kuparuk. Our ownership interest in the area is approximately 78 percent. Net production in 2009 was 68,000 barrels of oil per day, compared with 70,000 in 2008. Further development of potential satellite fields west of Alpine and into the National Petroleum Reserve—Alaska (NPRA) is contingent upon the receipt of permit approvals and additional exploration appraisal work. Planned development of one of these satellites, the Alpine West CD5 Project, has been postponed due to the denial of a key permit from the U.S. Army Corps of Engineers in February 2010. We expect to appeal their decision.

Cook Inlet Area

We operate the North Cook Inlet Unit, the Beluga River Unit, and the Kenai LNG Plant in the Cook Inlet Area. We have a 100 percent interest in the North Cook Inlet Unit, while we own 33.3 percent of the Beluga River Unit. Net production in 2009 from the Cook Inlet Area averaged 85 million cubic feet per day of natural gas, compared with 88 million in 2008. Production from the North Cook Inlet Unit 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 Unit 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 21 net billion cubic feet of LNG in 2009, compared with 27 billion in 2008.

Exploration

In a February 2008 lease sale conducted by the U.S. Department of Interior (DOI) under the Outer Continental Shelf (OCS) Lands Act, we successfully bid, and were awarded 10-year primary term leases, on 98 blocks in the Chukchi Sea, for total bid payments of $506 million. Various special interest groups have brought two separate lawsuits challenging (1) the DOI’s entire OCS leasing program, and (2) the Chukchi Sea lease sale conducted by the DOI under that program. In the first suit, the Court ordered the DOI to reconsider one aspect of its OCS leasing program. The results of the DOI’s reconsideration are expected during the first quarter of 2010. In the second suit, briefs have been filed on behalf of the defendants, including the DOI, in support of the Chukchi Sea lease sale, and a decision is expected later in 2010. We continue to progress plans for drilling an exploration well on our Chukchi Sea leases no earlier than 2012. In January 2010, we exchanged a 25 percent working interest in 50 of these leases for cash consideration and additional working interests in the Lower Tertiary play of the deepwater Gulf of Mexico.

Two exploration wells were drilled in the Greater Mooses Tooth Unit, located in the NPRA. One of the wells was expensed as a dry hole, while the second well encountered hydrocarbons. We are evaluating the potential for future development of this latest discovery.

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.

In 2008, ConocoPhillips and BP plc formed a limited liability company to progress the pipeline project named Denali—The Alaska Gas Pipeline. The project would move Alaska natural gas to North American markets. Denali has continued to progress the project in preparation for its open season in 2010, during which the pipeline company will seek customers to make long-term firm transportation commitments to the project. 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 2009, 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 21,000 barrels per day of liquids and 28 million cubic feet per day of natural gas in 2009, compared with 18,000 barrels per day and 24 million cubic feet per day in 2008.

Onshore

Our 2009 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.

Onshore activities in 2009 were mostly centered on continued optimization and development of existing assets. Combined net production from all Lower 48 onshore fields in 2009 averaged 1,899 million cubic feet per day of natural gas and 145,000 barrels per day of liquids, compared with 1,970 million cubic feet per day and 147,000 barrels per day in 2008.

The San Juan Basin, located in northwestern New Mexico and southwestern Colorado, includes the majority of our U.S. 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 903 million cubic feet per day of natural gas and 49,000 barrels per day of liquids in 2009, compared with 863 million cubic feet per day and 48,000 barrels per day in 2008.

Transportation

In 2006, we acquired a 24 percent interest in West2East Pipeline LLC, which merged into Rockies Express Pipeline LLC in December 2009. In November 2009, Rockies Express completed construction of a 1,679-mile natural gas pipeline from Colorado to Ohio, which has the capacity to deliver 1.8 billion cubic feet of natural gas per day to eastern markets. We increased our ownership interest to 25 percent upon project completion.

Exploration

During 2009, we participated in two significant discoveries in the deepwater Gulf of Mexico. We hold an 18 percent interest in the Tiber discovery and a 40 percent interest in the Shenandoah discovery. Both discoveries require future appraisal drilling. In addition, we were the successful bidder on 27 blocks in the March and August 2009 federal offshore lease sales. At year end, we had interests in 287 lease blocks totaling

1.1 million net acres in the Gulf of Mexico. In January 2010, we exchanged a 25 percent working interest in 50 of our leases in the Chukchi Sea for cash consideration and additional working interests in the Lower Tertiary play of the deepwater Gulf of Mexico.

We drilled and completed 52 gross onshore exploration wells. The majority of the wells were located in the Bakken play in the Williston Basin and the Fort Worth Basin Barnett play. We have seen encouraging results from initial wells in our Eagle Ford play in South Texas where we have accumulated over 240,000 acres. Other areas with active exploration drilling programs included Wyoming, Colorado and East Texas.

E&P—EUROPE

In 2009, E&P operations in Europe contributed 23 percent of E&P’s worldwide liquids production, compared with 24 percent in 2008. European operations contributed 18 percent of natural gas production in 2009, compared with 20 percent in 2008. 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 North Sea. The Greater Ekofisk Area is composed of four producing fields: Ekofisk, Eldfisk, Embla and Tor. Net production in 2009 from the Greater Ekofisk Area was 92,000 barrels of liquids per day and 89 million cubic feet of natural gas per day, compared with 99,000 barrels per day and 100 million cubic feet per day in 2008.

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.
	•		6.2 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 128 million cubic feet of natural gas per day in 2009, compared with 68,000 barrels per day and 139 million cubic feet per day in 2008.

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 eight wells in 2009, with six of the wells encountering hydrocarbons. Two discoveries were made on the Visund East flank, two discoveries were made in the Oseberg Area and two discoveries were made in the Alvheim Area. We were also awarded an additional 128,000 acres in 2009.

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. We also have an 83.5 percent interest and a 75 percent interest in the Callanish and Brodgar Britannia satellite fields, respectively. Net production from Britannia and its satellite fields averaged 304 million cubic feet of natural gas per day and 40,000 barrels of liquids per day in 2009, compared with 277 million cubic feet per day and 24,000 barrels per day in 2008.

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 the J-Block facilities. Together, these fields produced a net 12,000 barrels of liquids per day and 96 million cubic feet of natural gas per day in 2009, compared with 13,000 barrels per day and 88 million cubic feet per day in 2008.

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 2009 of 185 million cubic feet per day of natural gas, compared with 241 million in 2008.

We also have ownership interests in several other producing fields in the U.K. sector of the North Sea. Net production from these fields averaged 16,000 barrels of liquids per day and 12 million cubic feet of natural gas per day in 2009, compared with 17,000 barrels per day and 14 million cubic feet per day in 2008.

In the Atlantic Margin, we have a 24 percent interest in the Clair Field. Net production in 2009 averaged 12,000 barrels of liquids per day, compared with 11,000 in 2008.

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 2009 averaged 60 million cubic feet of natural gas per day, compared with 43 million in 2008.

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 ownership interests, respectively. We also have a 100 percent ownership interest in the Rivers Gas Terminal, operated by a third party, in the United Kingdom.

Exploration

We participated in three exploration wells in 2009. One well was a discovery, one was expensed as a dry hole and the third was drilling at year end. The discovery was made in the Southern Gas Basin and began production in 2009.

Poland

Exploration

In 2009, we entered into a shale gas venture in Poland that provides us with the opportunity to evaluate and earn a 70 percent interest in six exploration licenses in the Baltic Basin. We acquired seismic data in 2009 and intend to drill our first well in 2010.

E&P—CANADA

In 2009, E&P operations in Canada contributed 11 percent of E&P’s worldwide liquids production, compared with 10 percent in 2008. Canadian operations contributed 22 percent of E&P’s worldwide natural gas production in 2009, the same as in 2008.

Western Canada

Operations in western Canada encompass oil and gas properties throughout Alberta, northeastern British Columbia, and southern Saskatchewan. Net production from western Canada averaged 1,062 million cubic feet per day of natural gas and 40,000 barrels per day of liquids in 2009, compared with 1,054 million cubic feet per day and 44,000 barrels per day in 2008.

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). The average net production of bitumen from Surmont during 2009 was 7,000 barrels per day, compared with 6,000 barrels per day in 2008, with net peak production of 12,000 barrels per day expected in 2013. Surmont Phase II was sanctioned in 2009 and is expected to begin producing in 2015, increasing Surmont’s net production to 50,000 barrels per day in 2017.

FCCL

In 2007, we formed two 50/50 business ventures with EnCana Corporation (now Cenovus Energy Inc.) to create an integrated North American heavy oil business: FCCL Partnership, a Canadian upstream general partnership, and WRB Refining LLC, a U.S. downstream limited liability company. FCCL’s assets, operated by Cenovus, 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. Our share of FCCL’s production increased to 43,000 barrels per day in 2009, compared with 30,000 barrels per day in 2008, primarily due to Foster Creek Phases 1D and 1E commencing operations late in the first quarter of 2009 and continuing to ramp-up throughout the year. Construction of Christina Lake Phase 1C continued through the year, and in the fourth quarter of 2009, we sanctioned Christina Lake Phase 1D. See the Refining and Marketing (R&M) section for information on WRB.

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 synthetic 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 23,000 barrels per day in 2009, compared with 22,000 in 2008.

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, which would anchor the pipeline development. The Joint Review Panel, 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, conditionally recommended approval of the project in December 2009. We anticipate the Mackenzie Delta Producers’ Group will continue to pursue needed regulatory authorizations, but detailed engineering work has been deferred pending resolution with the federal government on the fiscal and commercial framework.

Exploration

We hold exploration acreage in four areas of Canada: offshore eastern Canada, onshore western Canada, the Mackenzie Delta/Beaufort Sea Region, and the Arctic Islands. During 2009, we began drilling an exploration well in the Laurentian Basin, located offshore eastern Canada that continued into 2010. We also acquired an additional 900,000 acres in the Laurentian Basin in 2009. In western Canada, we participated in 27 wells resulting in 23 discoveries. We also acquired an additional 71,000 acres, including over 22,000 acres in the Horn River shale gas play, increasing our position to nearly 100,000 acres. In the Beaufort Sea Region, we acquired additional interest in the Amauligak Strategic Discovery License.

E&P—SOUTH AMERICA

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. For additional information, see the “Expropriated Assets” section of Note 10—Impairments, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Plataforma Deltana Block 2

We sold our 40 percent nonoperating interest in Plataforma Deltana Block 2 to PDVSA during 2009.

Peru

Exploration

At year-end 2009, we held ownership interests in four exploration blocks in Peru. Final preparations are under way for a 2D seismic program scheduled for 2010 in Block 39. We operate Blocks 123, 124 and 129, and are continuing preparations for a 2D seismic program scheduled to commence in the first quarter of 2010. We relinquished Block 104 during 2009.

Ecuador

In April 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before the World Bank’s International Centre for Settlement of Investment Disputes (ICSID) against The Republic of Ecuador and PetroEcuador as a result of the newly-enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by the ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally seized crude oil. As a result, our assets in Ecuador were effectively expropriated. In the third quarter of 2009, Ecuador took over operations in Block 7 and 21, formalizing the complete expropriation of our assets. A jurisdictional hearing before the ICSID was held in January 2010, with the outcome still pending. For additional information, see the “Expropriated Assets” section of Note 10—Impairments, in the Notes to Consolidated Financial Statements.

E&P—ASIA PACIFIC/MIDDLE EAST

In 2009, E&P operations in the Asia Pacific/Middle East Region contributed 13 percent of E&P’s worldwide liquids production and 16 percent of natural gas production, compared with 11 percent and 13 percent in 2008, 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 (APLNG), is focused on 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. Multiple LNG trains are anticipated. Over 20,000 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 water treatment facilities.

Our share of the joint venture’s production in 2009 was 84 million cubic feet per day of natural gas. 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. During 2009, Laird Point was selected as the future site for LNG facilities. Final investment decision on the initial LNG trains is planned for the fourth quarter of 2010.

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 35,000 barrels of liquids per day in 2009, compared with 36,000 in 2008. Our share of natural gas production was 216 million cubic feet per day in 2009, compared with

210 million in 2008. Produced natural gas is used to supply the Darwin LNG Plant, in which we own a 57.2 percent interest. In 2009, we sold 156 billion gross cubic feet of LNG to utility customers in Japan, compared with 159 billion in 2008.

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 gaining co-venturer and government alignment on the development concept, and establishing fiscal stability arrangements.

In 2009, 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, the same as in 2008.

Exploration

During 2009, we drilled two exploration wells and started a third in the offshore Browse Basin. The first well, Poseidon-1, was a significant discovery. Poseidon-2, the initial appraisal well for the discovery, encountered hydrocarbons in some of the same sands as were seen in the discovery well and is currently being evaluated. A seismic survey has recently been acquired over the discovery. Additionally, Kontiki-1 was drilled on a prospect independent from Poseidon and was expensed as a dry hole. We intend to drill at least one additional well in the Browse Basin in 2010.

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, leased LNG carriers destined for sale in the United States and other markets. The first LNG cargoes are expected to be loaded in the second half 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 Terminal and affiliated Golden Pass Pipeline. The terminal is currently under construction adjacent to the Sabine-Neches Industrial Ship Channel northwest of Sabine Pass, Texas. Subject to the negotiation of definitive agreements, ConocoPhillips will hold terminal and pipeline capacity for the receipt, storage and regasification of the LNG purchased from Qatargas 3 and the transportation of regasified LNG to interconnect with major interstate natural gas pipelines.

Indonesia

We operate seven production sharing contracts (PSCs) in Indonesia. Three of these PSCs are in various stages of development from which net production grew to an average of 447 million cubic feet per day of natural gas and 19,000 barrels per day of liquids in 2009, compared with 343 million cubic feet per day and 17,000 barrels per day in 2008. Our producing assets are primarily concentrated in two core areas: the South Natuna Sea and onshore South Sumatra.

South Natuna Sea Block B

The offshore South Natuna Sea Block B PSC, in which we have a 40 percent interest and are the operator, has two producing oil fields and 16 natural gas fields in various stages of development. Natural gas production is sold under international sales agreements to Malaysia and Singapore. The North Belut Field in Block B achieved first gas production in November 2009.

South Sumatra

These onshore blocks are comprised of the Corridor and South Jambi B PSCs. The Corridor PSC, in which we have a 54 percent interest, has six oil fields and six natural gas fields in various stages of development. Natural gas is supplied 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, which supplies natural gas to Singapore.

Exploration

We operate three offshore exploration PSCs: Amborip VI, Kuma and Arafura Sea, where exploration drilling is scheduled to take place in the fourth quarter of 2010 and the first quarter of 2011. We also operate the Warim onshore exploration PSC in Papua.

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.

China

We are the operator and have a 49 percent share of the Peng Lai 19-3 Field in Bohai Bay Block 11-05, as well as the nearby Peng Lai 19-9 and Peng Lai 25-6 Fields. As part of our Bohai Bay Phase II Project, a floating production, storage and offloading (FPSO) vessel to accommodate production from these fields was installed in May 2009. Development of Peng Lai 19-3 continues. Net production averaged 33,000 barrels of oil per day in 2009, compared with 14,000 in 2008. Production should continue to ramp-up over the next two years, with annual average net production of 69,000 barrels of oil per day anticipated in 2011.

The Xijiang development consists of two fields located approximately 80 miles south of Hong Kong in the South China Sea. Combined net production of oil from the Xijiang Fields averaged 5,000 barrels per day in 2009, compared with 7,000 in 2008. Under the terms of the contract, our ownership rights in the 24-3/1 Field ended in January 2010, and our rights in the 30-2 Field will end in November 2010. Our ownership in these fields was 24.5 percent and 12.3 percent, respectively, at December 31, 2009.

We have a 24.5 percent interest in the offshore Panyu Field, also located in the South China Sea, which produced 11,000 net barrels of oil per day in 2009 and 12,000 in 2008.

Exploration

We entered a pilot evaluation program in a coalbed methane play in the onshore Qinshui Basin in 2009. The pilot program is expected to last between 12-18 months and will involve drilling and monitoring the production performance of a series of horizontal wells. At the end of the program, we will have the option to elect an assignment of a 30 percent interest in three PSCs covering the play. We drilled two exploration wells on our existing offshore Bohai Block BZ 11/05, both of which were expensed as dry holes.

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 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 2009 was 22,000 barrels of oil per day, compared with 13,000 in 2008. The oil is processed through a 1 million barrel FPSO vessel and through the Su Tu Vang central processing platform and floating storage and offloading (FSO) vessel.

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 2009 was 7,000 barrels per day of liquids and 15 million cubic feet per day of natural gas, compared with 9,000 barrels per day and 16 million cubic feet per day in 2008.

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.

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 deepwater oil discovery in Block J is currently under way and includes the installation of a semi-submersible oil production platform.

Exploration

We participated in two exploration wells during 2009, a successful appraisal of the Petai discovery on Block G, and the Sigapon 1 Well in Block J, which was expensed as a dry hole.

Bangladesh

Exploration

We were formally awarded two deepwater blocks in offshore Bangladesh in 2009. PSC negotiations continue into 2010.

Abu Dhabi

In July 2009, we signed the Shah Gas Field Joint Venture and Field Entry agreements with the Abu Dhabi National Oil Company to progress the Shah Gas Field Project. 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 gas liquids pipelines, and sulfur-exporting facilities at Ruwais. A final investment decision is expected in 2010, and we hold a 40 percent interest in the proposed project.

E&P—AFRICA

During 2009, E&P operations in Africa contributed 7 percent of E&P’s worldwide liquids production and 2 percent of natural gas production, compared with 8 percent and 2 percent, respectively, in 2008.

Nigeria

During 2009, we produced from four onshore Oil Mining Leases (OMLs), in which we have a 20 percent nonoperator interest. Net production from these leases was 19,000 barrels of liquids per day and 111 million cubic feet of natural gas per day in 2009, compared with 21,000 barrels per day and 105 million cubic feet per day in 2008.

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 2009, the plant consumed 12 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

Development studies continue for the Uge discovery in offshore deepwater Block OPL 214. Onshore, we participated in the start of the Obiafu SW Deep B exploration well, but the well was abandoned and expensed due to pad location problems. We plan to redrill the well in 2010.

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 45,000 barrels per day in 2009, versus 47,000 in 2008.

Algeria

We have interests in three fields in Block 405a: the Menzel Lejmat North Field, the Ourhoud Field, and the development stage El Merk oil field unit. The El Merk Project was sanctioned in 2009 and is expected to begin producing in 2012. Net production from these fields averaged 14,000 barrels of oil per day in 2009, compared with 13,000 in 2008.

E&P—RUSSIA

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. Net production from the joint venture averaged 46,000 barrels per day in 2009, compared with 13,000 in 2008. 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.

Polar Lights

We have a 50 percent equity interest in Polar Lights Company, an entity that owns producing fields in the Timan-Pechora Basin in northern Russia. Net production averaged 9,000 barrels of oil per day in 2009, compared with 11,000 in 2008.

E&P—CASPIAN

In the Caspian Sea, we have an 8.4 percent interest in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement, 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. The initial production phase of the contract is for 20 years, with options to extend the agreement an additional 20 years. A joint operating company oversees the Kashagan development, and expects first production in late 2012.

Transportation

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

Exploration

In 2009, we acquired a 24.5 percent interest in the N Block, located offshore Kazakhstan. In addition, appraisal drilling and 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. 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.

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, 2009. No difference exists between our estimated total proved reserves for year-end 2008 and year-end 2007, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2009.

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 60 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 the “Oil and Gas Operations” section following the Notes to Consolidated Financial Statements, for information on the development of proved undeveloped reserves.

MIDSTREAM

At December 31, 2009, 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 2009, including our share of DCP Midstream, were 187,000 barrels per day, compared with 188,000 in 2008.

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. Beginning in 2015, the volume commitment is reduced by 20 percent each year until the volume commitment is zero. This purchase commitment is on an “if-produced, will-purchase” basis and is expected to have a relatively stable purchase pattern over the remaining term of the contract. 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, 2009, 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 2009, DCP Midstream’s raw natural gas throughput averaged 6.1 billion cubic feet per day, and natural gas liquids extraction averaged 358,000 barrels per day, compared with 6.2 billion cubic feet per day and 360,000 barrels per day in 2008. 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 2009:

	•		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 24,300 barrels per day).
	•		A 40 percent interest in a fractionation plant in Conway, Kansas (with our net share of capacity at 43,200 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).
	•		A commercial trading organization based in Houston, Texas, that optimizes the flow of natural gas liquids and markets propane on a wholesale basis.

We also own a 39 percent equity interest in Phoenix Park Gas Processors Limited, which 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 2 billion-cubic-feet-per-day gas processing plant and a 70,000 barrel-per-day natural gas liquids fractionator. A third gas processing train was completed in July 2009, which increased total processing capacity to 2 billion cubic feet per day. Our share of natural gas liquids extracted averaged 8,000 barrels per day in 2009 and 2008. Our share of fractionated liquids averaged 17,000 barrels per day in 2009, compared with 14,000 in 2008.

REFINING AND MARKETING (R&M)

At December 31, 2009, 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.

R&M—UNITED STATES

Refining

At December 31, 2009, we owned or had an interest in 12 operated refineries in the United States.

								Net Crude Throughput
Refinery		Location		Ownership				Capacity (MBD)
East Coast Region
Bayway		Linden, New Jersey			100.00	%			238
Trainer		Trainer, Pennsylvania			100.00				185
									423
Gulf Coast Region
Alliance		Belle Chasse, Louisiana			100.00				247
Lake Charles		Westlake, Louisiana			100.00				239
Sweeny		Old Ocean, Texas			100.00				247
									733
Central Region
Wood River		Roxana, Illinois			50.00				153
Borger		Borger, Texas			50.00				73
Ponca City		Ponca City, Oklahoma			100.00				187
									413
West Coast Region
Billings		Billings, Montana			100.00				58
Ferndale		Ferndale, Washington			100.00				100
Los Angeles		Carson/Wilmington, California			100.00				139
San Francisco		Arroyo Grande/San Francisco, California		100.00					120
									417
									1,986

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

Characteristics

Sources

Europe

Middle East

Sweet

Medium Sour

Heavy Sour

High TAN*

United States

Canada

South America

& FSU**

& Africa

Bayway

•

•

•

•

Trainer

•

•

•

Alliance

•

•

•

Lake Charles

•

•

•

•

•

•

Sweeny

•

•

•

•

•

Wood River

•

•

•

•

•

•

•

Borger

•

•

•

•

Ponca City

•

•

•

•

•

•

Billings

•

•

•

•

Ferndale

•

•

•

•

Los Angeles

•

•

•

•

•

•

•

San Francisco

•

•

•

•

•

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 &

Product Yield

Other Heavy

Natural Gas

Petro-

Gasolines

Distillates

Capability

Intermediates

Liquids

Petroleum Coke

chemical 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

55

30

75

•

Los Angeles

85

61

86

•

San Francisco

52

52

87

•

•

•

MSLP

Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a 70,000 barrel-per-day delayed coker and related facilities at the Sweeny Refinery used to produce fuel-grade petroleum coke. Prior to August 28, 2009, MSLP was owned 50/50 by us and PDVSA. Under the agreements that govern the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery gave us the right to acquire PDVSA’s 50 percent ownership interest in MSLP. On August 28, 2009, we exercised that right. In public statements, PDVSA has challenged our actions. We continue to use the equity method of accounting for our investment in MSLP.

WRB

In 2007, we closed on a business venture with EnCana Corporation (now Cenovus) to create an integrated North American heavy oil business. This venture consists of two 50/50 business ventures: a Canadian upstream general partnership, FCCL 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. 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 the majority of the existing asphalt production at the refinery will be replaced with production of upgraded products.

Capital Projects

In 2009, 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. During 2009, we expanded a hydrocracker at the Rodeo facility of our San Francisco Refinery. The hydrocracker was commissioned in September 2009, resulting in a 12 percent increase in clean product yield.

Marketing

In the United States as of December 31, 2009, we marketed gasoline, diesel and aviation fuel through approximately 8,500 outlets in 49 states. The majority of these sites utilize the Phillips 66, Conoco or 76 brands.

Wholesale

At December 31, 2009, our wholesale operations utilized a network of marketers operating approximately 7,680 outlets that provided refined product offtake from our refineries. 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, 2009, aviation gasoline and jet fuel were sold through independent marketers at approximately 710 Phillips 66-branded locations in the United States.

Retail

At December 31, 2009, CFJ Properties, our 50/50 joint venture with Flying J, owned and operated approximately 110 Flying J-branded truck travel plazas. Flying J filed for Chapter 11 bankruptcy protection in December 2008. In July 2009, Flying J and Pilot Travel Centers LLC (Pilot) announced a planned merger of their retail businesses, which was approved by the bankruptcy court in January 2010, and is currently under governmental antitrust review. Subject to the closing of the Flying J/Pilot merger and other customary conditions, we have agreed to sell our interest in CFJ to Pilot.

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. Of the approximately 830 sites included in the held for sale plans, approximately 100 dealer-operated sites remain to be sold in 2010.

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, 2009, R&M managed approximately 30,000 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 44 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, to create a joint venture with TransCanada Corporation. In 2008 we exercised an option to reduce our equity interest through a dilution mechanism, which gradually lowered our ownership interest to 20.01 percent by the third quarter of 2009. In the third quarter of 2009, we sold our remaining ownership interest in Keystone.

Tankers

At December 31, 2009, we had 21 double-hulled crude oil tankers under charter, with capacities ranging in size from 713,000 to 2,100,000 barrels. These tankers are used primarily to transport feedstocks to certain of our U.S. refineries. In addition, we utilitized five double-hulled product tankers 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, polypropylene 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.

R&M—INTERNATIONAL

Refining
At December 31, 2009, R&M owned or had an interest in five refineries outside the United States.

								Net Crude Throughput
		Location		Ownership				Capacity (MBD)
Humber		N. Lincolnshire, United Kingdom			100.00	%			221
Whitegate		Cork, Ireland			100.00				71
Wilhelmshaven		Wilhelmshaven, Germany			100.00				260
MiRO*		Karlsruhe, Germany			18.75				58
Melaka		Melaka, Malaysia			47.00				61
									671

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

Characteristics

Sources

Medium

Heavy

High

Europe

Middle East

Sweet

Sour

Sour

TAN*

& FSU**

& Africa

Humber

•

•

•

•

Whitegate

•

•

•

Wilhelmshaven

•

•

•

MiRO

•

•

•

•

Melaka

•

•

•

•

•

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

Gasolines

Distillates

Capability

Intermediates

Natural Gas Liquids

Petroleum Coke

Asphalt

Humber

84

112

84%

•

•

•*

Whitegate

15

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.

In November 2009, we announced a delay in the planned upgrade of the Wilhelmshaven Refinery. During 2010, we expect to complete procurement of long lead items in anticipation of project commencement in 2012, contingent upon market conditions.

The project to expand the crude oil, conversion and treating unit capacity of the Melaka Refinery is expected to be completed by the fourth quarter of 2010. When complete, our net share of the refinery’s crude throughput capacity will increase from 61,000 to 80,000 barrels per day.

In 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. Final investment decision on this project is estimated to occur in 2010.

Marketing

At December 31, 2009, R&M had marketing operations in five European countries. Our 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, 2009, we had approximately 1,225 marketing outlets in our European operations, of which approximately 880 were company-owned and 345 were dealer-owned. Through our joint venture operations in Switzerland, we also have interests in 225 additional sites.

LUKOIL INVESTMENT

At December 31, 2009, 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 2009, 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 20.09 percent. We use the equity method of accounting for our investment in LUKOIL. See Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for additional information.

As reported in LUKOIL’s publicly available 2008 annual report, the majority of its 2008 upstream oil production was sourced within Russia, with 59 percent from the western Siberia Region, 18 percent from the Timan-Pechora Province and 12 percent from the Urals Region. Outside of Russia, LUKOIL had 2008 oil production in Kazakhstan, Uzbekistan, Egypt and Azerbaijan, and gas production in Uzbekistan, Azerbaijan and Kazakhstan. Seventy-five percent of LUKOIL’s natural gas production was sourced within Russia. In addition, LUKOIL has an active exploration program primarily focused in Russia, with additional activity in several countries. Downstream, LUKOIL has seven refineries, as well as a 49 percent interest in the ISAB refinery complex in Italy, resulting in total net crude oil throughput capacity of approximately 1.3 million barrels per day. In 2009, LUKOIL acquired a 45 percent interest in a Dutch refinery. LUKOIL also has a marketing network extending to 25 countries, with the majority of wholesale and retail sales in Russia, the United States and Europe.

CHEMICALS

At December 31, 2009, 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 manufacturing facilities are located in Belgium, Brazil, China, Colombia, Qatar, Saudi Arabia, Singapore, South Korea and the United States.

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 the second half of 2010.

In 2008, Jubail Chevron Phillips Company, a 50 percent owned joint venture of CPChem, commenced startup of an integrated styrene facility in Al Jubail, Saudi Arabia. The facility was built adjacent to the existing aromatics complex owned by Saudi Chevron Phillips Company (SCP), another 50 percent owned CPChem joint venture. Project completion was achieved in July 2009.

In 2007, CPChem formed a 50 percent owned joint venture, Saudi Polymers Company (SPCo), 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. In July 2009, an initial public offering of shares in CPChem’s joint venture partner’s company was completed, resulting in a corresponding increase in the partner’s ownership interest in SPCo, which reduced CPChem’s ownership to 35 percent.

EMERGING BUSINESSES

At December 31, 2009, our Emerging Businesses segment represented 1 percent of ConocoPhillips’ total assets. The segment encompasses the development of new technologies and businesses outside our normal operations. Activities within this segment are focused on power generation and new technologies 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 December 2009, commercial operation began on a 450-megawatt expansion, bringing total capacity to 1,180 megawatts.

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. Focus areas include advanced hydrocarbon processes, energy efficiency technologies, new petroleum-based products, renewable fuels and carbon capture and conversion technologies. We have commercialized production of renewable diesel, a new type of renewable fuel that utilizes existing infrastructure. Relationships with Iowa State University, Colorado Center for Biorefining and Biofuels, and Archer Daniels Midland to develop second-generation biofuels have also been initiated. In addition, we have formed an internal group to evaluate wind, solar and geothermal investment opportunities.

Our technology center in Qatar, which we developed with General Electric Company to research water sustainability solutions for petroleum, petrochemical, municipal and agricultural applications, opened 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, substitute natural gas (SNG), hydrogen and chemicals. This clean, efficient technology facilitates carbon capture and storage as well as minimizes criteria pollutant emissions and reduces water consumption. E-Gas™ Technology has been utilized in commercial applications since 1987 and is currently licensed to several third parties. We are currently pursuing three projects that apply the E-Gas™ Technology, two in the United States and one in the United Kingdom. We are also pursuing several additional licensing opportunities, primarily in Asia and North America.

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, including state-owned companies, 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 2008 reserves statistics, we had the seventh-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 portfolio management; 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 21, 2009, issue of the Oil & Gas Journal, our R&M segment had the largest U.S. refining capacity of 17 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 2009 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 efficient 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 2009, we held a total of 1,435 active patents in 72 countries worldwide, including 565 active U.S. patents. During 2009, we received 30 patents in the United States and 59 foreign patents. Our products and processes generated licensing revenues of $14 million in 2009. 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 $190 million, $209 million, and $160 million in 2009, 2008 and 2007, respectively.

Our Health, Safety and Environment (HSE) organization provides tools and support to our business units and staff groups to help them ensure consistent health, safety and environmental excellence. In support of the goal of zero incidents, we have implemented an HSE Excellence process, which enables business units to measure their performance and compliance with our HSE Management System requirements, identify gaps, and develop improvement plans. Assessments are conducted annually to capture progress and set new targets. We are also committed to continuously improving process safety and preventing releases of hazardous materials.

The environmental information contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 58 through 61 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2009 and those expected for 2010 and 2011.

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 an adverse impact 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 experience 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 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:

	•		The discharge of pollutants into the environment.
	•		Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions, and greenhouse gas emissions as they are, or may become, regulated).
	•		The handling, use, storage, transportation, disposal and clean up of hazardous materials and hazardous and nonhazardous wastes.
	•		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.

In addition, our business operations are designed and operated to accommodate expected climatic conditions. To the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather conditions in the markets we serve or the areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.

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 may continue to do so in the future.

Local political and economic factors in international markets could have a material adverse effect on us. Approximately 67 percent of our hydrocarbon production in 2009 was derived from production outside the United States, and 64 percent of our proved reserves, as of December 31, 2009, 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.

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 present hazards and risks that 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.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 3. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the fourth quarter of 2009, as well as matters previously reported in our 2008 Form 10-K and our first-, second- and third-quarter 2009 Form 10-Qs that were not resolved prior to the fourth quarter of 2009. Material developments to the previously reported matters have been included in the descriptions below. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings was decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission’s (SEC) regulations.

Our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of the Federal Clean Air Act, with the U.S. Environmental Protection Agency (EPA), six states and one local air pollution agency. Some of the requirements and limitations contained in the decrees provide for stipulated penalties for violations. Stipulated penalties under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports under the decrees or other reports required by permits or regulations, we occasionally report matters that could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in SEC rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that matter and the amount of the proposed penalty.

New Matters
In May 2008, the EPA issued a Compliance Order to ConocoPhillips alleging our Argenta and Sunnyside Compressor Station facilities in Colorado violated provisions of the Clean Air Act and failed to comply with several permit conditions. On February 5, 2010, we settled this matter for a payment of $175,000 and agreement to install certain emission control equipment.

In 2009, ConocoPhillips notified the EPA and the U.S. Department of Justice (DOJ) that it had self-identified certain compliance issues related to Benzene Waste Operations National Emission Standard for Hazardous Air Pollutants requirements at its Trainer, Pennsylvania, and Borger, Texas, facilities. On January 6, 2010, the DOJ provided its initial penalty demand for this matter as part of our confidential settlement negotiations. We continue to work with the DOJ to resolve this matter.

On December 17, 2009, the San Francisco Regional Water Quality Control Board’s enforcement staff (SFRWQCB) issued an Administrative Civil Liability Complaint alleging 18 exceedances of the Rodeo facility’s stormwater permit that occurred during 2008 and 2009. The Complaint seeks a penalty of $490,000. We are working with the SFRWQCB to resolve this matter.

On January 22, 2010, the Bay Area Air Quality Management District (BAAQMD) issued a settlement demand to resolve 16 Notices of Violation (NOVs) issued in 2008 and 2009 that allege violations of air pollution control regulations and/or facility permit conditions at the Rodeo facility. The amount of the settlement demand is $179,000. We are working with BAAQMD to resolve this matter.

Matters Previously Reported
ConocoPhillips Pipe Line Company (CPPL) received a Notice of Probable Violation and Proposed Civil Penalty (NOPV) from the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (DOT) dated March 30, 2009. The NOPV alleges that CPPL violated certain operation and

safety regulations regarding the control room response to a release on January 8, 2008, near Denver City, Texas. DOT’s proposed penalty for the alleged violation is $200,000. We are working with DOT to resolve this matter.

On October 23, 2008, ConocoPhillips received a demand from the Los Angeles Regional Water Quality Control Board (LARWQCB) to settle multiple alleged exceedances of National Pollutant Discharge Elimination System permit effluent limits at its Los Angeles lubricants plant dating back to 2000. We paid a negotiated settlement of $150,000 to the LARWQCB on January 25, 2010, 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 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.

In March 2005, CPPL received an NOPV from 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.

In 2006, Polar Tankers, Inc. and ConocoPhillips resolved and agreed to pay, with no admission of liability, civil penalties and response costs associated with a 2004 oil spill in Puget Sound. We remain in negotiations with the natural resource trustees regarding the natural resource damage assessment to better the environment.

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. ConocoPhillips transferred its interest in the terminal, and the current owner has ceased operations. The spills have been remediated in compliance with New Mexico Environmental Department standards. ConocoPhillips has withdrawn its settlement offer and requested that this Order be dismissed.

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

None.

EXECUTIVE OFFICERS OF THE REGISTRANT

Name		Position Held		Age*
John A. Carrig		President and Chief Operating Officer		58
W. C. W. Chiang		Senior Vice President, Refining, Marketing and Transportation		49
Sigmund L. Cornelius		Senior Vice President, Finance, and Chief Financial Officer		55
Janet L. Kelly		Senior Vice President, Legal, General Counsel and Corporate Secretary		52
Ryan M. Lance		Senior Vice President, Exploration and Production – International		47
Kevin O. Meyers		Senior Vice President, Exploration and Production – Americas		56
James J. Mulva		Chairman of the Board of Directors and Chief Executive Officer		63
Glenda M. Schwarz		Vice President and Controller		44
Jeff W. Sheets		Senior Vice President, Planning and Strategy		52

There are no family relationships among any of 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 12, 2010. Set forth below is information about the executive officers.

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 of Conoco and Phillips in 2002 (the merger).

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 and President, Global Gas since 2004.

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.

Ryan M. Lance was appointed Senior Vice President, Exploration and Production — International, in May 2009. Prior to that, he served as President, Exploration and Production — Asia, Africa, Middle East and Russia/Caspian since April 2009, having previously served as President, Exploration and Production— Europe, Asia, Africa and the Middle East since September 2007. He served as Senior Vice President, Technology since February 2007, and prior to that served as Senior Vice President, Technology and Major Projects since 2006. He served as President, Downstream Strategy, Integration and Specialty Businesses since 2005.

Kevin O. Meyers was appointed Senior Vice President, Exploration and Production — Americas, in May 2009, having previously served as President, Canada, Exploration & Production, since 2006. He served as President, ConocoPhillips Russia & Caspian Region, from 2004 to 2006.

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 the merger.

Glenda M. Schwarz was appointed Vice President and Controller in April 2009. She previously served as General Auditor and Chief Ethics Officer since 2008, having previously served as General Manager, Downstream Finance and Performance Analysis since 2005, and prior to that served as Assistant Controller, External Reporting and Accounting Policy since 2004.

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.

PART II

Quarterly Common Stock Prices and Cash Dividends Per Share

ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”

		Stock Price
		High				Low				Dividends
2009
First		$	57.44				34.12				.47
Second			48.71				37.52				.47
Third			47.30				38.62				.47
Fourth			54.13				44.88				.50
2008
First		$	89.71				67.85				.47
Second			95.96				75.52				.47
Third			94.65				67.31				.47
Fourth			72.25				41.27				.47
Closing Stock Price at December 31, 2009										$	51.07
Closing Stock Price at January 31, 2010										$	48.00
Number of Stockholders of Record at January 31, 2010*											61,039

Issuer Purchases of Equity Securities

														Millions of Dollars
										Total Number of				Approximate Dollar
										Shares Purchased as				Value of Shares
										Part of Publicly				that May Yet Be
		Total Number of				Average Price Paid Per				Announced Plans or				Purchased Under the
Period		Shares Purchased *				Share				Programs				Plans or Programs
October 1-31, 2009			157,478			$	50.72				—				—
November 1-30, 2009			17,369				51.98				—				—
December 1-31, 2009			3,324				50.75				—				—
Total			178,171			$	50.85				—

Item 6. SELECTED FINANCIAL DATA

		Millions of Dollars Except Per Share Amounts
		2009				2008				2007				2006				2005
Sales and other operating revenues		$	149,341				240,842				187,437				183,650				179,442
Income (loss) from continuing operations			4,936				(16,928	)			11,978				15,626				13,673
Income (loss) from continuing operations attributable to ConocoPhillips			4,858				(16,998	)			11,891				15,550				13,640
Per common share
Basic			3.26				(11.16	)			7.32				9.80				9.79
Diluted			3.24				(11.16	)			7.22				9.66				9.63
Net income (loss)			4,936				(16,928	)			11,978				15,626				13,562
Net income (loss) attributable to ConocoPhillips			4,858				(16,998	)			11,891				15,550				13,529
Per common share
Basic			3.26				(11.16	)			7.32				9.80				9.71
Diluted			3.24				(11.16	)			7.22				9.66				9.55
Total assets			152,588				142,865				177,757				164,781				106,999
Long-term debt			26,925				27,085				20,289				23,091				10,758
Joint venture acquisition obligation—long-term			5,009				5,669				6,294				—				—
Cash dividends declared per common share			1.91				1.88				1.64				1.44				1.18

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 6—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.

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

February 25, 2010

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 “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 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 66.

The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to ConocoPhillips.

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 30,000 employees worldwide, and at year-end 2009 had assets of $153 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

Our business is organized into six operating segments:

•

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

•

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.

•

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

•

LUKOIL Investment—This segment consists of our equity investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. At December 31, 2009, our ownership interest was 20 percent based on issued shares and 20.09 percent based on estimated shares outstanding.

•

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).

•

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

The business environment for the energy industry in 2009 continued to experience volatility associated with the supply/demand factors that drive its commodity prices and margins. During 2008, 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 by mid-year, with the benchmark West Texas Intermediate (WTI) peaking at almost $150 per barrel. This was followed by an abrupt shift into a severe global financial recession, which drove crude oil prices to the low-$30-per-barrel range by the end of 2008. As the global economy began to recover, oil prices steadily improved during 2009 and have remained fairly strong due to demand in Asia. The recovery from the recession in the United States, however, has been slower and has impacted demand for U.S. natural gas and refined products.

In response to this challenging business environment, ConocoPhillips announced several strategic initiatives in late 2009 designed to improve its financial position and increase returns on capital. This will be accomplished primarily through a combination of enhanced capital discipline and asset portfolio rationalization, consistent with our objectives of creating shareholder value and improving financial flexibility, while pursuing long-term strategic projects. Our total capital program in 2010 is expected to be $11.2 billion, down from a budgeted $12.5 billion in 2009. To improve our financial position and strengthen the balance sheet, we intend to raise approximately $10 billion from asset dispositions over the next two years. Proceeds will be targeted to debt reduction, accelerating the return to our targeted debt-to-capital ratio of 20 percent to 25 percent. After these initiatives, we intend to continue to replace reserves and increase production from a reduced, but more strategic, asset base.

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. As noted above, these prices and margins are subject to extreme volatility. However, from a competitive perspective, there are other important factors we must manage well to be successful, including:

•

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. Optimizing 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 2009, our worldwide refining capacity utilization rate was 84 percent, compared with 90 percent in 2008. The lower rate primarily reflects reduced throughput at our U.S. and German refineries due to economic conditions, as well as higher planned downtime, efficiently utilizing periods of lower margins for maintenance. Although certain North America production was shut-in during part of 2009 due to the natural gas pricing environment, we increased total production on a barrel-of-oil-equivalent basis in 2009 by 2 percent. Finally, we strive to conduct our operations in a manner consistent with our environmental stewardship principles.

•

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

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

Through a combination of the methods listed above, we have been successful in the past in maintaining or adding to our production and proved reserve base, and we anticipate being able to do so in the future. In the five years ending December 31, 2009, our reserve replacement was 145 percent. Over this period we added reserves through acquisitions and project developments, partially offset by the impact of asset expropriations in Venezuela and Ecuador.

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.

•

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. Operating and overhead costs were reduced 13 percent in 2009, compared with 2008, reflecting both market conditions and our continued emphasis on cost control throughout the year.

•

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 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.

The capital expenditures and investments portion of our capital program totaled $10.9 billion in 2009, and we anticipate capital expenditures and investments to be approximately $10.5 billion in 2010. The 2010 budget is consistent with our recently announced plan to improve returns through increased capital discipline, while still funding existing projects and enabling us to preserve flexibility to develop major projects in the future. In addition to our capital program, we paid dividends on our common stock of $2.8 billion in 2009.

•

Managing our asset portfolio. We continually evaluate our assets to determine whether they no longer fit our strategic plans and should be sold or otherwise disposed. In 2008, we sold our retail marketing assets in Norway, Sweden and Denmark, in addition to our E&P properties in Argentina and the Netherlands. In 2009, we sold a majority of our U.S. retail marketing assets. Also in 2009, we announced our intention to raise approximately $10 billion from asset dispositions over the next two years.

•

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 and natural gas liquids prices, natural gas prices, production, refining capacity utilization, and refinery output.

Other significant factors that can affect our profitability include:

•

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 prices, natural gas prices or refining 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 2009 totaled $0.8 billion and primarily related to certain natural gas properties in western Canada and our equity investment in Naraynmarneftegaz (NMNG). 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.

•

Goodwill. At year-end 2009 and 2008, we had $3.6 billion and $3.8 billion, respectively, 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.

•

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.

•

Fiscal and regulatory environment. As commodity prices and refining margins fluctuated upward over the last several years, certain governments 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. In the second quarter of 2009, our assets in Ecuador were effectively expropriated, and we recorded a $51 million before- and after-tax impairment (see the “Expropriated Assets” section of Note 10—Impairments, in the Notes to Consolidated Financial Statements). We were also negatively impacted by increased production taxes enacted by the state of Alaska in the fourth quarter of 2007. 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 were lower in 2009, compared with 2008, averaging $61.69 per barrel in 2009, a decrease of 38 percent. Crude oil prices steadily trended upward during 2009, as global crude inventories were reduced due to lower production and economic recovery that stimulated the resumption of global oil demand growth. Industry natural gas prices for Henry Hub decreased 56 percent during 2009 to an average price of $3.99 per million British thermal units, primarily as a result of lower demand due to the U.S. recession and higher domestic production due to increased shale gas production.

The Midstream segment’s results are most closely linked to natural gas liquids prices. The most important factor affecting the profitability of this segment is the results from our 50 percent equity investment in DCP Midstream. DCP Midstream’s natural gas liquids prices decreased 43 percent in 2009.

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. Global refining margins remained weak in 2009. The U.S. benchmark 3:2:1 crack spread decreased almost 20 percent in 2009, while the N.W. Europe benchmark declined 54 percent. Demand, particularly for distillates, continued to be suppressed by the global economic slowdown. In addition, the compressed differential in prices for high-quality crude oil, compared with those of lower-quality crude oil, reduced margins for those refineries configured to capitalize on the ability to process lower-quality crudes.

The LUKOIL Investment segment consists of our investment in the ordinary shares of LUKOIL. At December 31, 2009, our ownership interest in LUKOIL was 20 percent based on issued shares and 20.09 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

Consolidated Results

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

		Millions of Dollars
Years Ended December 31		2009				2008				2007
Exploration and Production (E&P)		$	3,604				(13,479	)			4,615
Midstream			313				541				453
Refining and Marketing (R&M)			37				2,322				5,923
LUKOIL Investment			1,663				(5,488	)			1,818
Chemicals			248				110				359
Emerging Businesses			3				30				(8	)
Corporate and Other			(1,010	)			(1,034	)			(1,269	)
Net income (loss) attributable to ConocoPhillips		$	4,858				(16,998	)			11,891

2009 vs. 2008

The improved results in 2009 were primarily the result of:

•

The absence of a $25,443 million before- and after-tax impairment of all E&P segment goodwill in 2008.

•

The absence of a $7,410 million before- and after-tax impairment of our LUKOIL investment in 2008.

•

Lower production taxes.

•

Reduced operating and overhead expenses.

These items were partially offset by:

•

Lower crude oil, natural gas and natural gas liquids prices, which impacted our E&P, Midstream and LUKOIL Investment segments.

•

Lower refining margins in our R&M segment.

2008 vs. 2007

The lower results in 2008 were primarily the result of:

•

The goodwill and LUKOIL impairments, noted above.

•

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

•

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

These items were partially offset by:

•

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

•

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

Statement of Operations Analysis

2009 vs. 2008

Sales and other operating revenues decreased 38 percent in 2009, while purchased crude oil, natural gas and products decreased 39 percent. These decreases were mainly the result of significantly lower prices for petroleum products, crude oil, natural gas and natural gas liquids.

Equity in earnings of affiliates decreased 30 percent in 2009, primarily due to reduced earnings from DCP Midstream; LUKOIL; Merey Sweeny, L.P. (MSLP); Malaysian Refining Company Sdn. Bhd.; and Excel Paralubes, which were partially offset by higher earnings from Chevron Phillips Chemical Company LLC. The decreases were mainly the result of lower commodity prices and refining margins.

Other income decreased 52 percent during 2009. The decrease was primarily due to 2008 gains related to asset dispositions in our E&P and R&M segments.

Production and operating expenses decreased 13 percent in 2009, as a result of lower utilities costs, favorable foreign exchange impacts, and our cost reduction efforts.

Selling, general and administrative expense decreased 18 percent in 2009, primarily due to disposition of U.S. and international marketing assets.

Taxes other than income taxes decreased 25 percent in 2009, primarily due to lower production taxes resulting from lower crude oil prices, as well as reduced excise taxes on petroleum product sales.

Impairments decreased from $34,539 million in 2008 to $535 million in 2009, primarily reflecting the 2008 goodwill and LUKOIL impairments. Other impairments decreased $1,202 million during 2009. For additional information, see Note 6—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 increased 38 percent in 2009, as a result of a higher average debt level, partially offset by lower interest rates. Interest expense also increased as a result of lower capitalized interest.

See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our income tax expense and effective tax rate.

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 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:

•

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.

•

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

•

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

•

Increased losses related to our 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 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 primarily reflects the 2008 goodwill and LUKOIL impairments, partially offset by a 2007 impairment of $4,588 million related to the expropriation of our oil interests in Venezuela.

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

Segment Results

E&P

		2009				2008				2007
		Millions of Dollars
Net Income (Loss) Attributable to ConocoPhillips
Alaska		$	1,540				2,315				2,255
Lower 48			(37	)			2,673				1,993
United States			1,503				4,988				4,248
International			2,101				6,976				367
Goodwill impairment			—				(25,443	)			—
		$	3,604				(13,479	)			4,615

		Dollars Per Unit
Average Sales Prices
Crude oil and natural gas liquids (per barrel)
United States		$	53.21				89.38				63.87
International			57.40				89.32				68.09
Total consolidated operations			55.47				89.35				66.01
Equity affiliates			58.23				71.15				48.72
Total E&P			55.63				88.91				64.99
Synthetic oil (per barrel)
International			62.01				103.31				74.32
Bitumen (per barrel)
International			39.67				46.85				—
Equity affiliates			45.69				58.54				37.94
Total E&P			44.84				56.72				37.94
Natural gas (per thousand cubic feet)
United States			3.45				7.67				5.98
International			4.94				8.76				6.51
Total consolidated operations			4.30				8.28				6.26
Equity affiliates			2.35				2.04				.30
Total E&P			4.26				8.27				6.26
Average Production Costs Per Barrel of Oil Equivalent
United States		$	7.73				8.34				6.52
International*			7.72				8.03				7.64
Total consolidated operations*			7.73				8.17				7.11
Equity affiliates			7.68				13.36				8.92
Total E&P*			7.72				8.33				7.19

*		Amounts in 2008 and 2007 were adjusted for certain production cost reclassifications.

		Millions of Dollars
Worldwide Exploration Expenses
General and administrative; geological and geophysical; and lease rentals		$	576				639				544
Leasehold impairment			247				273				254
Dry holes			359				425				209
		$	1,182				1,337				1,007

		2009				2008				2007
		Thousands of Barrels Daily
Operating Statistics
Crude oil and natural gas liquids produced
Alaska			252				261				280
Lower 48			166				165				181
United States			418				426				461
Canada			40				44				46
Europe			241				233				224
Asia Pacific/Middle East			132				107				106
Africa			78				80				78
Other areas			4				9				10
Total consolidated operations			913				899				925
Equity affiliates
Russia			55				24				15
Other areas			—				—				42
			968				923				982
Synthetic oil produced
Consolidated operations—Canada			23				22				23
Bitumen produced
Consolidated operations—Canada			7				6				—
Equity affiliates—Canada			43				30				27
			50				36				27

		Millions of Cubic Feet Daily
Natural gas produced*
Alaska			94				97				110
Lower 48			1,927				1,994				2,182
United States			2,021				2,091				2,292
Canada			1,062				1,054				1,106
Europe			876				954				961
Asia Pacific/Middle East			713				609				579
Africa			121				114				125
Other areas			—				14				19
Total consolidated operations			4,793				4,836				5,082
Equity affiliates
Asia Pacific/Middle East			84				11				—
Other areas			—				—				5
			4,877				4,847				5,087

*		Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above.

Equity affiliate statistics exclude our share of LUKOIL, which is reported in the LUKOIL Investment segment.

The E&P segment primarily explores for, produces, transports and markets crude oil, natural gas, natural gas liquids and bitumen on a worldwide basis. At December 31, 2009, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria and Russia.

2009 vs. 2008

The E&P segment had earnings of $3,604 million during 2009. In 2008, the E&P segment had a loss of $13,479 million, which included a $25,443 million before- and after-tax complete impairment of E&P segment goodwill. For additional information, see the “Goodwill Impairment” section of Note 9—Goodwill and Intangibles, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Excluding the impact from the goodwill impairment, earnings from the E&P segment decreased 70 percent during 2009, primarily due to substantially lower crude oil, natural gas and natural gas liquids prices. Our E&P segment also recognized property impairment charges. These decreases were partially offset by lower Alaska and Lower 48 production taxes due to lower prices, as well as higher international volumes and improved operating costs. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.

Proved reserves at year-end 2009 were 8.36 billion barrels of oil equivalent (BOE), compared with 8.08 billion at year-end 2008. This excludes the estimated 1,967 million BOE and 1,893 million BOE included in the LUKOIL Investment segment at year-end 2009 and 2008, respectively. Also excluded for 2008 is our share of Canadian Syncrude reserves of 249 million barrels.

U.S. E&P

Earnings from our U.S. E&P operations decreased 70 percent, due to significantly lower crude oil, natural gas and natural gas liquids prices. Lower production taxes, lower property impairments in the Lower 48 and improved operating costs partially offset the decrease.

U.S. E&P production averaged 755,000 BOE per day in 2009, a decrease of 3 percent from 775,000 in 2008. Less unplanned downtime and improved well performance were more than offset by field decline.

International E&P

Earnings from our international E&P operations were $2,101 million in 2009, compared with $6,976 million in 2008. The decline was primarily a result of significantly lower crude oil, natural gas and natural gas liquids prices and higher impairments. These decreases were partially offset by higher volumes and lower operating costs.

International E&P production averaged 1,099,000 BOE per day in 2009, an increase of 8 percent from 1,014,000 in 2008. The increase was predominantly due to new production in the United Kingdom, Russia, China, Canada, Norway and Vietnam. In addition, production increased due to the impacts from the royalty framework in Alberta, Canada, as well as less unplanned downtime and the impact of lower prices on production sharing arrangements. These increases were partially offset by field decline and more planned downtime.

2008 vs. 2007

The E&P segment recorded a loss of $13,479 million during 2008. This amount included a $25,443 million before- and after-tax complete impairment of E&P segment goodwill. In 2007, the E&P segment had earnings of $4,615 million, which included the impact of a $4,588 million before-tax impairment ($4,512 million after-tax) related to the expropriation of our oil interests in Venezuela. For additional information, see the “Goodwill Impairment” section of Note 9—Goodwill and Intangibles, and the “Expropriated Assets” section of Note 10—Impairments, in the Notes to Consolidated Financial Statements, which are incorporated herein by reference.

The decrease in earnings resulted from the goodwill impairment, higher taxes other than income (mainly in Alaska), lower production volumes, higher operating and exploration costs, increased property impairments and depreciation expense, and the absence of a 2007 benefit related to release of escrowed funds associated with our Hamaca joint venture in Venezuela. The decrease was partially offset by the absence of the 2007 Venezuela impairment, as well as higher crude oil, natural gas and natural gas liquids prices. During 2008, our E&P segment recognized property impairment charges totaling $511 million after-tax, mostly due to revised capital spending plans as a result of current project economics, as well as a significantly diminished outlook for commodity prices. A large portion of these impairments relate to fields in the U.S. Lower 48 and Canada.

U.S. E&P

Earnings from our U.S. E&P operations increased 17 percent, primarily due to higher crude oil, natural gas and natural gas liquids prices. The increase was partially offset by higher production taxes (mainly in Alaska), lower volumes, an increase in impairments of properties in the Lower 48, and higher operating costs.

E&P production on a BOE basis averaged 775,000 per day in 2008, a decrease of 8 percent from 843,000 in 2007. The production decrease was primarily attributable to field decline and unplanned downtime in the Lower 48 due to hurricane disruptions.

International E&P

Earnings from our international E&P operations increased from $367 million in 2007 to $6,976 million in 2008. The increase was attributed to the impact of the Venezuelan impairment on our prior-year results and higher crude oil, natural gas and natural gas liquids prices. The increase was partially offset by higher depreciation expense due to increased rates and new assets being placed in service, increased taxes other than income, higher operating costs, and the absence of a 2007 benefit related to release of escrowed funds associated with our Hamaca joint venture in Venezuela.

International E&P production averaged 1,014,000 BOE per day in 2008, a decrease of 2 percent from 1,037,000 in 2007. Decreases in production were caused by field decline and the expropriation of our Venezuelan oil interests. These decreases were mostly offset by increased production from new developments in the United Kingdom, Indonesia, Russia, Norway and Canada.

Midstream

		2009				2008				2007
		Millions of Dollars
Net Income Attributable to ConocoPhillips*		$	313				541				453
*       Includes DCP Midstream-related earnings:		$	183				458				336

		Dollars Per Barrel
Average Sales Prices
U.S. natural gas liquids*
Consolidated		$	33.63				56.29				47.93
Equity affiliates			29.80				52.08				46.80

*		Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by natural gas liquids component and location mix.

		Thousands of Barrels Daily
Operating Statistics
Natural gas liquids extracted*			187				188				211
Natural gas liquids fractionated**			166				165				173

*		Includes our share of equity affiliates, except LUKOIL, which is included in the LUKOIL Investment segment.
**		Excludes DCP Midstream.

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel or blendstock. The Midstream segment consists of our 50 percent equity investment in DCP Midstream, as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses, primarily in the United States and Trinidad.

2009 vs. 2008

Earnings from the Midstream segment decreased 42 percent in 2009. The decrease was primarily due to substantially lower realized natural gas liquids prices, partially offset by the recognition of an $88 million after-tax benefit in the first quarter of 2009 resulting from a DCP Midstream subsidiary converting subordinated units to common units.

2008 vs. 2007

Earnings from the Midstream segment increased 19 percent in 2008. The increase was primarily due to higher realized natural gas liquids prices, partially offset by higher operating costs and higher depreciation expense.

R&M

		2009				2008				2007
		Millions of Dollars
Net Income (Loss) Attributable to ConocoPhillips
United States		$	(192	)			1,540				4,615
International			229				782				1,308
		$	37				2,322				5,923

		Dollars Per Gallon
U.S. Average Wholesale Prices*
Gasoline		$	1.84				2.65				2.27
Distillates			1.76				3.06				2.29

*		Excludes excise taxes.

		Thousands of Barrels Daily
Operating Statistics
Refining operations*
United States
Crude oil capacity**			1,986				2,008				2,035
Crude oil processed			1,731				1,849				1,944
Capacity utilization (percent)			87	%			92				96
Refinery production			1,891				2,035				2,146
International
Crude oil capacity**			671				670				687
Crude oil processed			495				567				616
Capacity utilization (percent)			74	%			85				90
Refinery production			504				575				633
Worldwide
Crude oil capacity**			2,657				2,678				2,722
Crude oil processed			2,226				2,416				2,560
Capacity utilization (percent)			84	%			90				94
Refinery production			2,395				2,610				2,779
Petroleum products sales volumes
United States
Gasoline			1,130				1,128				1,244
Distillates			858				893				872
Other products			367				374				432
			2,355				2,395				2,548
International			619				645				697
			2,974				3,040				3,245

*		Includes our share of equity affiliates, except LUKOIL, which is included in the LUKOIL Investment segment.
**		Weighted-average crude oil capacity for the periods. Actual capacity at year-end 2007 was 2,037,000 barrels per day for our domestic refineries and 669,000 barrels per day for our international refineries.