ConocoPhillips - 10-K annual report 2010

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 “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” 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 65.

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:

At December 31, 2010, ConocoPhillips employed approximately 29,700 people.

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.

At December 31, 2010, our E&P segment represented 63 percent of ConocoPhillips’ total assets. This segment primarily explores for, produces, transports and markets crude oil, bitumen, natural gas and natural gas liquids on a worldwide basis. Operations to liquefy natural gas and transport the resulting LNG are also included in the E&P segment. At December 31, 2010, 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, Qatar and Russia.

The E&P segment does not include the financial results or statistics from our 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 following net proved reserves table, for periods before we ceased using equity-method accounting for this investment, which occurred at the end of the third quarter of 2010.

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:

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 75 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. See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance the understanding of the table below.

E&P’s worldwide annual average crude oil and natural gas liquids sales price increased 31 percent, from $55.63 per barrel in 2009 to $72.77 per barrel in 2010. Worldwide bitumen prices increased 18 percent, from $44.84 per barrel in 2009 to $53.06 per barrel in 2010. E&P’s average annual worldwide natural gas sales price increased 14 percent, from $4.37 per thousand cubic feet in 2009 to $4.98 per thousand cubic feet in 2010.

In 2010, U.S. E&P operations contributed 40 percent of E&P’s worldwide liquids production and 39 percent of natural gas production, compared with 40 and 41 percent in 2009, respectively.

Greater Kuparuk Area
We operate the Greater Kuparuk Area, which is made up of the Kuparuk Field and four satellite fields: Tarn, Tabasco, Meltwater and West Sak. Kuparuk is located 40 miles west of Prudhoe Bay on Alaska’s North Slope. 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 60,000 barrels per day in 2010, compared with 65,000 barrels per day in 2009.

Western North Slope
On the Western North Slope we operate the Colville River Unit, which includes the Alpine Field and three satellite fields: Nanuq, Fiord and Qannik. Alpine is located 34 miles west of Kuparuk. Our ownership interest in the area is 78 percent. Net production in 2010 was 59,000 barrels of oil per day, compared with 68,000 barrels per day in 2009. 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, was postponed due to the denial of a key permit from the U.S. Army Corps of Engineers in February 2010. We appealed their decision, and in December 2010, a ruling on our appeal remanded the matter back to the agency’s district office in Alaska for further review.

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 2010 from the Cook Inlet Area averaged 73 million cubic feet per day of natural gas, compared with 85 million cubic feet per day in 2009. Production from the North Cook Inlet Unit is used primarily to supply our share of natural 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 17 net billion cubic feet of LNG in 2010, compared with 21 billion cubic feet in 2009. On February 9, 2011, we announced that due to market conditions we will cease LNG exports from the Kenai LNG Plant, effective in the second quarter of 2011, and will begin mothballing the facility for potential future use.

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. Due to continued pending litigation and associated injunctions, our plans for drilling an exploration well on our Chukchi Sea leases remain under review.

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 deepwater Gulf of Mexico (GOM). In late 2010, we entered into an agreement to farm-down an additional 10 percent of our working interest in the same Chukchi

Sea leases, and that agreement is subject to regulatory approval. In addition, we participated in two appraisal wells in the Point Thomson Unit, where development options are currently being evaluated.

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 natural gas from Alaska’s North Slope to North American markets. Denali conducted an open season during 2010, a process in which the pipeline company solicits 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. Both projects are currently evaluating bids received from potential customers during their respective open seasons and are engaged in confidential negotiations with those bidders.

U.S. Lower 48
Gulf of Mexico
At year-end 2010, our portfolio of producing properties in the GOM mainly consisted of one operated field and three fields operated by co-venturers, including:

Net production from our GOM properties averaged 18,000 barrels per day of liquids and 20 million cubic feet per day of natural gas in 2010, compared with 21,000 barrels per day and 28 million cubic feet per day in 2009.

Onshore
Our 2010 onshore production principally consisted of natural gas and associated liquids production, with the majority of production located in the San Juan Basin, Permian Basin, Lobo Trend, Bossier Trend, Fort Worth Basin, panhandles of Texas and Oklahoma and Williston Basin. We also have operations in the Wind River and Anadarko Basins, as well as in East Texas and northern and southern Louisiana.

Onshore activities in 2010 were centered mostly on continued optimization and development of existing assets, with particular focus on areas with higher liquids production. Total net production from all Lower 48 onshore fields in 2010 averaged 1,675 million cubic feet per day of natural gas and 142,000 barrels per day of liquids, compared with 1,899 million cubic feet per day and 145,000 barrels per day in 2009.

Exploration
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 deepwater GOM. We were also the successful bidder on 10 blocks in the March 2010 federal offshore lease sale. At year end, we had interests in 274 lease blocks totaling 1.1 million net acres offshore GOM.

In May 2010, in response to the Deepwater Horizon incident in the GOM, the DOI issued a six-month drilling moratorium on new deepwater wells in the OCS, which was scheduled to expire on November 30, 2010. On October 12, 2010, the DOI lifted the ban, citing new regulatory requirements which would reduce the risks associated with deepwater drilling. The new rules are aimed at improving safety and environmental standards and include strengthened requirements on safety equipment, well control systems, blowout prevention practices and emergency response on offshore oil and gas operations.

The new regulations have created delays in the permitting process and deepwater exploratory drilling in the GOM. As a result, we have been unable to drill any GOM prospects or appraise the Tiber and Shenandoah discoveries, which occurred in 2009. Although there are no material impacts to our near-term production, the future effects of this incident, including any new or additional regulations that may be adopted in response, are not clearly known at this time. We will continue to evaluate the impact on our exploration prospects in the GOM.

Onshore, we actively pursued the appraisal of our existing shale plays in Eagle Ford in South Texas, the Bakken in the Williston Basin and the Barnett in the Fort Worth Basin. We have seen encouraging results in these liquids-rich plays and plan to continue appraisal and development in 2011.

Transportation
We own a 25 percent interest in the Rockies Express Pipeline (REX). REX is a 1,679-mile natural gas pipeline stretching from northwestern Colorado to eastern Ohio, which became fully operational in November 2009. REX has the capacity to deliver 1.8 billion cubic feet of natural gas per day to eastern markets.

In 2010, E&P operations in Europe contributed 21 percent of E&P’s worldwide liquids production, compared with 23 percent in 2009. European operations contributed 18 percent of natural gas production in 2010 and 2009. 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 2010 from the Greater Ekofisk Area was 80,000 barrels of liquids per day and 79 million cubic feet of natural gas per day, compared with 92,000 barrels per day and 89 million cubic feet per day in 2009.

We also have varying ownership interests in eight other producing fields in the Norwegian sector of the North Sea and in the Norwegian Sea. Net production from these fields averaged 57,000 barrels of liquids per day and 130 million cubic feet of natural gas per day in 2010, compared with 68,000 barrels per day and 128 million cubic feet per day in 2009.

Exploration
We participated in two exploration wells during 2010. Both the Megalodon and Dalsnuten wells failed to find commercial hydrocarbons and were expensed as dry holes.

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.

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 302 million cubic feet of natural gas per day and 39,000 barrels of liquids per day in 2010, compared with 304 million cubic feet per day and 40,000 barrels per day in 2009.

We operate and hold a 36.5 percent interest in the Judy/Joanne/Jasmine Fields, which together make up J-Block, located in the U.K. central North Sea. 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. The Judy/Joanne/Jade Fields produced a net 11,000 barrels of liquids per day and 82 million cubic feet of natural gas per day in 2010, compared with 12,000 barrels per day and 96 million cubic feet per day in 2009. In 2010, we received government approval for the development of the Jasmine Field, which is expected to startup in 2012, and achieve average net peak production of 35,000 barrels of oil equivalent per day by 2013.

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 2010 of 150 million cubic feet per day of natural gas, compared with 185 million cubic feet per day in 2009.

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 2010 averaged 61 million cubic feet of natural gas per day, compared with 60 million cubic feet per day in 2009.

In the Atlantic Margin, we have a 24 percent interest in the Clair Field. Net production in 2010 averaged 9,000 barrels of liquids per day, compared with 12,000 barrels per day in 2009.

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 15,000 barrels of liquids per day and 11 million cubic feet of natural gas per day in 2010, compared with 16,000 barrels per day and 12 million cubic feet per day in 2009.

Exploration
We were awarded six blocks in the U.K. 26^th Licensing Round. Three are in close proximity to our producing J-Block infrastructure in the central North Sea, while one is adjacent to our Britannia Field. The remaining blocks represent growth opportunities in the Dutch Bank Basin of the North Sea.

Transportation
We have a 10 percent interest in the Interconnector Pipeline, which links the United Kingdom and Belgium and facilitates marketing natural gas produced in the United Kingdom throughout Europe. We have export capability to ship up to 220 million cubic feet of natural gas per day to markets in continental Europe via the Interconnector, and our reverse-flow rights provide 85 million cubic feet per day of 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.

Poland
Exploration
We are participating in 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 drilled two wells in 2010 and plan to continue appraisal of the play in 2011.

E&P operations in Canada contributed 11 percent of E&P’s worldwide liquids production in 2010 and 2009. Canadian operations contributed 21 percent of E&P’s worldwide natural gas production in 2010, compared with 22 percent in 2009.

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 984 million cubic feet per day of natural gas and 38,000 barrels per day of liquids in 2010, compared with 1,062 million cubic feet per day and 40,000 barrels per day in 2009. Our 2010 drilling program focused on the development and exploitation of several liquids-rich resource opportunities, which included the Cardium Formation that lies primarily on our existing land base within the Deep Basin and central Alberta. We initiated temporary production curtailments of approximately 150 million cubic feet equivalent per day from September through early December 2010, in response to continued low natural gas prices in western Canada.

Surmont
We operate and have a 50 percent interest in the Surmont oil sands lease, located approximately 35 miles south of Fort McMurray, Alberta. An enhanced thermal oil recovery method called steam-assisted gravity drainage (SAGD) is used at Surmont. The average net production of bitumen during 2010 was 10,000 barrels per day, compared with 7,000 barrels per day in 2009. Surmont Phase II construction began in 2010, with a targeted production startup in 2015. Surmont’s net production is expected to increase to 50,000 barrels per day by 2017.

FCCL
We have two 50/50 North American heavy oil business ventures with Cenovus Energy Inc.: FCCL Partnership, a Canadian upstream general partnership, and WRB Refining LP, a U.S. downstream limited partnership. FCCL’s assets, operated by Cenovus, include 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 49,000 barrels per day in 2010, compared with 43,000 barrels per day in 2009. In the third quarter of 2010, FCCL received regulatory approval for Phases F, G and H at Foster Creek. Construction of Christina Lake Phase C continued in 2010, with first production expected in the second half of 2011. Construction of Christina Lake Phase D also continued through 2010. See the “Refining and Marketing (R&M)” section for information on WRB.

Syncrude Canada Ltd.
We sold our 9.03 percent interest in the Syncrude Canada Ltd. joint venture in June 2010 for $4.6 billion. Syncrude had synthetic oil proved reserves of 248 million barrels at December 31, 2009. Production averaged 12,000 barrels per day in 2010, compared with 23,000 barrels per day in 2009.

Parsons Lake/Mackenzie Gas Project
We are involved 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 project is in the final stage of regulatory approval, anticipated in early 2011; however, detailed engineering work continues to be deferred pending resolution with the Canadian 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 2010, we completed drilling an exploration well in the Laurentian Basin, located offshore eastern Canada, which did not find commercial quantities of hydrocarbons and was expensed as a dry hole. In western Canada, we participated in 28 wells resulting in 20 discoveries.

Venezuela
In 2007, we announced we had been unable to reach agreement with respect to our migration to anempresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, we filed a request for international arbitration on November 2, 2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held during 2010 before ICSID. We are awaiting their decision.

Ecuador
In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before 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 ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. A hearing on case merits is scheduled for March 2011. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Exploration
In November 2010, Burlington Resources, Inc., and PetroEcuador signed termination agreements for exploration Blocks 23 and 24, ending our participation in both blocks.

Peru
Exploration
During 2010, we executed two farm-downs that reduced our interests in Blocks 123, 124 and 129, which are awaiting final government approval. We are currently completing the initial 2D seismic program for Blocks 123 and 129 and plan to analyze the results in 2011. We also own a 35 percent working interest in Block 39.

In 2010, E&P operations in the Asia Pacific/Middle East Region contributed 15 percent of E&P’s worldwide liquids production and 19 percent of natural gas production, compared with 13 percent and 16 percent in 2009, respectively.

Australia and Timor Sea
Australia Pacific LNG
Australia Pacific LNG (APLNG), our 50/50 joint venture with Origin Energy, is focused on producing CBM from the Bowen and Surat Basins in Queensland, Australia. Gas is currently sold to domestic customers, while progress continues on the development of an LNG processing and export sales business. Once established, this will enhance our LNG position and serve as an additional LNG hub targeting Asia Pacific markets. Two initial 4.2-million-tons-per-year LNG trains are anticipated, with over 10,000 gross wells ultimately envisioned to supply both the domestic gas market and the LNG development. The additional wells will be supported by expanded gas gathering systems, centralized gas processing and compression stations, and water treatment facilities, in addition to a new export pipeline from the gas fields to the LNG facilities.

Our share of the joint venture’s production in 2010 was 115 million cubic feet per day of natural gas, compared with 84 million cubic feet per day in 2009. CBM field development work is ongoing in parallel with front-end engineering associated with the planned LNG processing facilities. Engagement with potential LNG buyers continues to progress, and a final investment decision on the initial phase of the project is planned for mid-2011.

In November 2010, the APLNG LNG development project received environmental approval from Australia’s Queensland state. In late February 2011, the project received environmental approval from the Australian federal government.

Bayu-Undan
We operate and hold a 57.2 percent ownership interest in the Bayu-Undan Field located in the Timor Sea. Net production from the field averaged 31,000 barrels of liquids per day in 2010, compared with 35,000 barrels per day in 2009. Our share of natural gas production was 198 million cubic feet per day in 2010, compared with 216 million cubic feet per day in 2009. Produced natural gas is used to supply the Darwin LNG Plant, in which we own a 57.2 percent interest. In 2010, we sold 147 billion gross cubic feet of LNG to utility customers in Japan, compared with 156 billion cubic feet in 2009.

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 must be resolved before significant funding commitments can be made. These include gaining both governments’ approval of the development concept selected by the co-venturers and establishing fiscal stability arrangements.

Western Australia
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 in both 2010 and 2009.

Exploration
We operate and own a 60 percent interest in three permits located in the Browse Basin, offshore northwest Australia. During 2010, we continued the exploration and appraisal programs and drilled two wells, Poseidon-2 and Kronos-1, both of which encountered hydrocarbons. We intend to carry out a second phase of drilling in the Browse Basin during 2011 and 2012. Analysis of the recently acquired seismic survey over the discovered resource area is ongoing.

Qatar
Qatargas 3 (QG3) is an integrated project jointly owned by Qatar Petroleum (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). The project comprises upstream natural gas production facilities to produce approximately 1.4 billion gross cubic feet per day of natural gas from Qatar’s North Field over a 25 year life. The project also includes a 7.8-million-gross-ton-per-year LNG facility, from which LNG is shipped in leased LNG carriers destined for sale in the United States and other markets. First production was achieved in October 2010, with eight LNG cargoes loaded and shipped in 2010.

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. Definitive terminal and pipeline use agreements have been reached, which will provide us with terminal and pipeline capacity for the receipt, storage and regasification of the LNG purchased from QG3 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 averaged 463 million cubic feet per day of natural gas and 17,000 barrels per day of liquids in 2010, compared with 447 million cubic feet per day and 19,000 barrels per day in 2009. Our producing assets are primarily concentrated in two core areas: 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, 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.

South Sumatra
These onshore blocks consist 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. Unitization of the Suban natural gas field commenced in 2010, reflecting that approximately 8 percent of the field’s proved reserves are now attributable to an adjacent PSC. The unitization is expected to be finalized during 2011. 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, with interests ranging from 60 to 100 percent. We began exploration drilling in the fourth quarter of 2010. The first well drilled on these offshore PSCs was the Aru-1. We did not find recoverable resources with the well, and it was expensed as a dry hole in the fourth quarter of 2010. We also operate and own an 80 percent interest in 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 is used to accommodate production from these fields. Net production averaged 56,000 barrels of oil per day in 2010, compared with 33,000 barrels per day in 2009. Production from the Peng Lai area is expected to increase due to continued development of Peng Lai 19-3, with annual average net production of 60,000 barrels of oil per day anticipated in 2011.

The Xijiang development consisted 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 1,000 barrels per day in 2010, compared with 5,000 barrels per day in 2009. 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 ended in November 2010. Our ownership in these fields was 24.5 percent and 12.3 percent, respectively.

We have a 24.5 percent interest in the offshore Panyu development, also located in the South China Sea, which produced 11,000 net barrels of oil per day in both 2010 and 2009. We plan to expand the scope and capacity of the existing two fields and anticipate government approval of the expansion in the first half of 2011.

Exploration
In 2009, we entered a pilot evaluation program in a CBM play in the onshore Qinshui Basin. The pilot program was expected to last between 12-18 months and involved drilling and monitoring the production performance of a series of horizontal wells. In the fourth quarter of 2010, we terminated our involvement in this program.

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, and our activities are focused around three producing fields: Su Tu Den, Su Tu Den Northeast and Su Tu Vang; and two fields in development: Su Tu Trang and Su Tu Nau. First production on the Su Tu Den Northeast Field occurred in May 2010, averaging a net 4,000 barrels of oil

per day and 4 million cubic feet per day of natural gas. Net production from the three producing fields averaged 18,000 barrels of oil per day in 2010, compared with 22,000 barrels per day in 2009.

We have a 36 percent interest in the Rang Dong Field in Block 15-2. Net production in 2010 was 6,000 barrels per day of liquids and 12 million cubic feet per day of natural gas, compared with 7,000 barrels per day and 15 million cubic feet per day in 2009.

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 own interests in three deepwater PSCs located off the eastern Malaysian state of Sabah: Block G, Block J, and the Kebabangan Cluster. We have a 35 percent interest in Block G, 40 percent in Block J, and 30 percent in the Kebabangan Cluster. Development of the Gumusut deepwater oil discovery in Block J continues and includes the installation of a semi-submersible oil production platform. First production for Gumusut is anticipated in 2013, with estimated net peak production of 29,000 barrels of liquids per day occurring in 2014.

Exploration
During 2010, we participated in the Ubah-4 appraisal well in Block G. The well was suspended in order to evaluate development options for the area.

Bangladesh
Exploration
We were formally awarded two deepwater blocks offshore Bangladesh in 2009. PSC negotiations are currently underway with government authorities.

Abu Dhabi
In April 2010, we decided to end participation in development of the Shah Gas Field in Abu Dhabi, United Arab Emirates.

During 2010, E&P operations in Africa contributed 8 percent of E&P’s worldwide liquids production and 3 percent of natural gas production, compared with 7 percent and 2 percent, respectively, in 2009.

Nigeria
We have a 20 percent nonoperating interest in four onshore Oil Mining Leases (OMLs). In 2010, net production from these leases was 20,000 barrels of liquids per day and 141 million cubic feet of natural gas per day, compared with 19,000 barrels per day and 111 million cubic feet per day in 2009.

Natural gas is sourced from our proved reserves in the OMLs and provides fuel for a 480-megawatt gas-fired power plant in Kwale, Nigeria. We have a 20 percent interest in this power plant, which supplies electricity to Nigeria’s national electricity supplier. In 2010, the plant consumed 5 million net cubic feet per day of natural gas.

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

Exploration
We drilled one exploration well during 2010, the Tuomo C. The well found commercial hydrocarbons and is being incorporated into the ongoing Tuomo/Tuomo West Field development.

Libya
We hold a 16.3 percent interest in the Waha concessions in Libya, which encompass nearly 13 million gross acres. Net oil production averaged 46,000 barrels per day in 2010, versus 45,000 barrels per day in 2009.

Algeria
Our activities in Algeria are centered around three fields in Block 405a: the Menzel Lejmat North Field (MLN), the Ourhoud Field, and the EMK Field. We operate and have a 65 percent interest in MLN, and we have a 3.7 percent interest in Ourhoud and a 16.9 percent interest in EMK. The El Merk Project was sanctioned in 2009 to develop the EMK Field, and engineering, procurement and construction is ongoing. Net production from MLN and Ourhoud averaged 13,000 barrels of oil per day in 2010, compared with 14,000 barrels per day in 2009.

NMNG
We have a 30 percent ownership interest with a 50 percent governance interest in OOO Naryanmarneftegaz (NMNG), a joint venture with LUKOIL. NMNG achieved initial production of the Yuzhno Khylchuyu (YK) Field in June 2008, and development was completed in 2010. Net production averaged 45,000 barrels per day in 2010, compared with 46,000 barrels per day in 2009. Production from the NMNG joint venture fields is transported via pipeline to LUKOIL’s terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets.

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 7,000 barrels of oil per day in 2010, compared with 9,000 barrels per day in 2009.

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 lasts until 2041, with options to extend the agreement an additional 20 years. A joint operating company, North Caspian Operating Company, oversees the Kashagan development, and expects first production in late 2012.

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

Exploration
We have a 24.5 percent interest in the N Block, located offshore Kazakhstan. In the fourth quarter of 2010, drilling operations were completed on the Rak More well. The well encountered oil and gas but requires further evaluation to determine commerciality. Further exploration drilling is planned in 2011 to determine development potential of a second area of interest within the block. In addition, appraisal drilling and development studies continue for the next phase of Kashagan and the satellite fields of Kalamkas, Kairan and Aktote.

Greenland
Exploration
We were formally awarded a license in 2010 for oil and gas exploration in Baffin Bay, offshore Greenland. We will serve as operator, with a 61.3 percent interest in the Qamut Block. Planned activities in 2011 include field work, environmental assessments, and seismic data acquisition and evaluation.

Marine Well Containment Company
During 2010, we formed a non-profit organization with Exxon Mobil Corporation, Chevron Corporation and Royal Dutch Shell plc to develop a new oil spill containment system and improve industry spill response in the GOM. The

Marine Well Containment Company plans to build and deploy a rapid response system that will be available to capture and contain oil in the event of a potential future underwater well blowout in the deepwater GOM.

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

We have not filed any information with any other federal authority or agency with respect to our estimated total proved reserves at December 31, 2010. No difference exists between our estimated total proved reserves for year-end 2009 and year-end 2008, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2010.

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, including approximately 700 billion cubic feet related to the noncontrolling interests of consolidated subsidiaries, and 120 million barrels of crude oil in the future. These contracts have various expiration dates through the year 2029. 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.

At December 31, 2010, our Midstream segment represented 2 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 such as ethane, butane and propane—and marketed as chemical feedstock, fuel or blendstock. Total natural gas liquids extracted in 2010, including our share of DCP Midstream, were 193,000 barrels per day, compared with 187,000 barrels per day in 2009.

DCP Midstream markets a portion of its natural gas liquids to us and CPChem under a supply agreement whose volume commitments remain steady until December 31, 2014. 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, 2010, DCP Midstream owned or operated 55 natural gas liquids extraction and 10 natural gas liquids fractionation plants, and its gathering and

transmission systems included approximately 61,000 miles of pipeline. In 2010, DCP Midstream’s raw natural gas throughput averaged 6.1 billion cubic feet per day, and natural gas liquids extraction averaged 369,000 barrels per day, compared with 6.1 billion cubic feet per day and 358,000 barrels per day in 2009. 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 includes the following:

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 throughout the Atlantic Basin. Its facilities include a 2-billion-cubic-feet-per-day gas processing plant and a 70,000-barrel-per-day natural gas liquids fractionator. Our share of natural gas liquids extracted averaged 9,000 barrels per day in 2010, compared with 8,000 barrels per day in 2009. Our share of fractionated liquids averaged 18,000 barrels per day in 2010, compared with 17,000 barrels per day in 2009.

At December 31, 2010, our R&M segment represented 24 percent of ConocoPhillips’ total assets. Our R&M segment primarily refines crude oil and other feedstocks into petroleum products (such as gasolines, distillates and aviation fuels); buys, sells and transports crude oil; and buys, transports, distributes and markets petroleum products. R&M has operations in the United States, Europe and Asia. 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.

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

WRB
We have two 50/50 North American heavy oil business ventures with Cenovus Energy Inc.: FCCL Partnership, a Canadian upstream general partnership, and WRB Refining LP, a U.S. downstream limited partnership. 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.

WRB’s processing capability of heavy Canadian crude is currently 145,000 barrels per day. We continue to progress the coker and refinery expansion (CORE) project at the Wood River Refinery, with operational startup anticipated in the fourth quarter of 2011. Upon completion of the CORE Project, total processing capability of heavy Canadian or similar crudes within WRB will increase to 275,000 barrels per day. The majority of the existing asphalt production at Wood River will be replaced with production of upgraded products.

Excel Paralubes
We own a 50 percent interest in the Excel Paralubes joint venture, which 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.

Marketing
In the United States, as of December 31, 2010, we marketed gasoline, diesel and aviation fuel through approximately 8,300 marketer-owned outlets in 49 states. The majority of these sites utilize the Phillips 66, Conoco or 76 brands.

Wholesale
At December 31, 2010, our wholesale operations utilized a network of marketers operating approximately 7,150 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. In addition, we held brand-licensing agreements with approximately 400 sites. 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, 2010, aviation gasoline and jet fuel were sold through independent marketers at approximately 750 Phillips 66-branded locations in the United States.

Retail
In June 2010, we sold our interest in CFJ Properties, a joint venture which owned and operated 110Flying J-branded truck travel plazas.

In December 2006, we announced plans to divest approximately 830 of our U.S. company-owned outlets. This program was completed during 2010.

Lubricants
We manufacture and sell automotive, commercial and industrial lubricants which are marketed under the Phillips 66, Conoco, 76 and Kendall brands, as well as other private label brands.

Transportation
We distribute refined products to our customers via company-owned and common-carrier pipelines, barges, railcars and trucks.

Pipelines and Terminals
At December 31, 2010, R&M managed approximately 24,000 miles of common-carrier crude oil, raw natural gas liquids, natural gas and petroleum products pipeline systems in the United States, including those partially owned or operated by affiliates. In addition, we owned or operated 44 finished product terminals, 7 liquefied petroleum gas terminals, 5 crude oil terminals and 1 coke exporting facility.

Tankers
At December 31, 2010, we had 19 double-hulled crude oil tankers under charter, with capacities ranging in size from 713,000 to 2,100,000 barrels. These tankers are primarily used to transport feedstocks to certain of our U.S. refineries. In addition, we utilized four double-hulled product tankers, with capacities ranging from 315,000 to 332,000 barrels, 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 “Exploration and Production (E&P)” section, as well as an owned tanker on lease to a third party for use in the North Sea.

Specialty Businesses
We manufacture and sell a variety of specialty products including petroleum cokes, polypropylene, pipeline flow improvers and anode material for high-power lithium-ion batteries. 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.

Refining
At December 31, 2010, R&M owned or had an interest in five refineries outside the United States.

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

The project to expand the crude oil, conversion and treating unit capacity of the Melaka Refinery was completed in the fourth quarter of 2010. As a result, effective January 1, 2011, our net share of the refinery’s crude throughput capacity will increase from 61,000 to 76,000 barrels per day, and clean product capacity for gasoline and distillates will increase to 17,500 and 47,000 barrels per day, respectively.

In the second quarter of 2010, due to ongoing unfavorable market conditions and consistent with our strategy of maintaining capital discipline and reducing our downstream portfolio over time, we canceled plans for a project to upgrade our refinery in Wilhelmshaven, Germany. We are currently evaluating offers to sell the facility. If sufficient value is not achievable from a sale, we plan to operate the facility as a terminal. As a result, effective January 1, 2011, we will no longer include Wilhelmshaven’s capacity in our stated refining capacities or our capacity utilization metrics.

Also consistent with our strategy of reducing our downstream portfolio, in the first quarter of 2010, we ended our participation in a new refinery project in Yanbu Industrial City, Saudi Arabia.

Marketing
At December 31, 2010, 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 approach. 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, 2010, we had approximately 1,450 marketing outlets in our European operations, of which approximately 890 were company-owned and 360 were dealer-owned. We also held brand-licensing agreements with approximately 200 sites. Through our joint venture operations in Switzerland, we also have interests in 245 additional sites.

At year-end 2009, we had a 20 percent ownership interest in OAO LUKOIL. In July 2010, we announced our intention to sell our entire interest. During 2010, we sold approximately 151 million shares of LUKOIL, and as a result of these sales, our ownership interest was 2.25 percent at December 31, 2010, based on authorized and issued shares. By the end of the third quarter of 2010, our ownership interest declined to a level at which we were no longer able to exercise significant influence over the operating and financial policies of LUKOIL. Accordingly, at the end of the third quarter of 2010, we stopped reporting equity earnings, proved reserves and production related to our LUKOIL investment. In the first quarter of 2011, we sold our remaining interest.

See Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for more information.

At December 31, 2010, our Chemicals segment represented 2 percent of ConocoPhillips’ total assets. The Chemicals segment consists of our 50 percent equity investment in CPChem, a joint venture with Chevron Corporation, headquartered in The Woodlands, Texas.

CPChem’s business is structured around two primary operating segments: Olefins & Polyolefins (O&P) and Specialties, Aromatics & Styrenics (SAS). The O&P 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 SAS segment manufactures and markets aromatics products, such as benzene, styrene, paraxylene and cyclohexane, as well as polystyrene and styrene-butadiene copolymers. SAS also 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, 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. The 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, an ethylene cracker that provides ethylene feedstock via pipeline to the Q-Chem II plants was developed in Ras Laffan Industrial City, Qatar. The ethylene cracker and pipeline are owned by Ras Laffan Olefins Company, a joint venture of Q-Chem II and Qatofin Company Limited. Collectively, Q-Chem II’s interest in the ethylene cracker and pipeline and the polyethylene and normal alpha olefins plants are referred to as the “Q-Chem II Project.” Operational startup of the Q-Chem II Project was achieved in 2010.

Saudi Chevron Phillips Company (SCP) is a 50-percent-owned joint venture of CPChem that owns and operates an aromatics complex at Jubail Industrial City, Saudi Arabia. Jubail Chevron Phillips Company, another 50-percent-owned joint venture of CPChem, owns and operates an integrated styrene facility adjacent to the SCP aromatics complex.

Saudi Polymers Company (SPCo), a 35-percent-owned joint venture company of CPChem, is constructing an integrated petrochemicals complex at Jubail Industrial City, Saudi Arabia. SPCo will produce ethylene, propylene, polyethylene, polypropylene, polystyrene and 1-hexene. Construction began in January 2008, and commercial production is scheduled to begin in late 2011.

CPChem plans to build a 1-hexene plant capable of producing in excess of 200,000 metric tons per year at its Cedar Bayou Chemical Complex in Baytown, Texas. Project planning has begun, with startup anticipated in 2014.

At December 31, 2010, 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, refining, alternative energy, biofuels and the environment.

Power Generation
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, the following projects have a significant merchant component and are included in the Emerging Businesses segment:

In December 2010, we sold a gas-fired cogeneration plant located in Orange, Texas.

Technology Development
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 are progressing the technology development of second-generation biofuels with Iowa State University, the Colorado Center for Biorefining and Biofuels and Archer Daniels Midland. We have also established a relationship with the University of Texas Energy Institute to collaborate on emerging technologies. Internally, we are continuing to evaluate wind, solar and geothermal investment opportunities.

In early 2011, we announced we will partner with General Electric Capital and NRG Energy, Inc., to form a new joint venture, Energy Technology Ventures (ETV), which will focus on development of next generation energy technology. ETV will invest in, and offer commercial collaboration opportunities to, venture- and growth-stage energy technology companies in the renewable power generation, smart grid, energy efficiency, oil, natural gas, coal and nuclear energy, emission controls and biofuels sectors.

In addition, we are equal co-venturers with General Electric Company in a Global Water Sustainability Center in Qatar, which researches and develops water solutions for the petroleum, petrochemical, municipal and agricultural sectors.

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 have also licensed E-Gas™ to third parties in Asia and North America, and are pursuing several additional licensing opportunities.

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.

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 2009 reserves statistics, we had the sixth-largest total of worldwide proved reserves of nongovernment-controlled companies. We deliver our production into the worldwide 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 extractor 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.

Our R&M segment competes primarily in the United States, Europe and Asia. Based on the statistics published in the December 6, 2010, 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 2010 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.

At the end of 2010, we held a total of 1,398 active patents in 62 countries worldwide, including 597 active U.S. patents. During 2010, we received 34 patents in the United States and 69 foreign patents. Our products and processes generated licensing revenues of $90 million in 2010. 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 $230 million, $190 million and $209 million in 2010, 2009 and 2008, 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 57 through 60 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2010 and those expected for 2011 and 2012.

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 athttp://www.sec.gov.

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 revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil, bitumen, natural gas, natural gas liquids, LNG and refined products. The factors influencing these prices are beyond our control. Lower crude oil, bitumen, natural gas, natural gas liquids, LNG 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.

The rate of production from upstream fields 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.

Our proved reserve information included in this annual report has been derived from engineering estimates prepared or reviewed by our personnel. Any significant future price changes could 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, bitumen 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.

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

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected.

Although 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.

In addition, in response to the Deepwater Horizon incident, the United States, as well as other countries where we do business, may make changes to their laws or regulations governing offshore operations that could have a material adverse effect on our business.

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 was derived from production outside the United States in both 2009 and 2010, and 56 percent of our proved reserves, as of December 31, 2010, 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, bitumen, natural gas, natural gas liquids or refined product pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations.

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, bitumen 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.

We conduct many of our operations through joint ventures in which we may share control with our joint venture participants. There is a risk 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 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.

We maintain insurance against many, but not all, potential losses or liabilities arising from operating risks. As such, our insurance coverage may not be sufficient to fully cover us against potential losses arising from such risks. Uninsured losses and liabilities arising from operating risks could reduce the funds available to us for capital, exploration and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 exploration, production, 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.

None.

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 2010, as well as matters previously reported in our 2009 Form 10-K and our first-, second- and third-quarter 2010 Form 10-Qs that were not resolved prior to the fourth quarter of 2010. 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 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
There are no new matters to report.

Matters Previously Reported
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 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.

ConocoPhillips has reached an agreement with the EPA and DOJ regarding an appropriate penalty amount, which will be reflected in the third amendment to the consent decree in Civil Action No. H-05-258 (the agreed-upon penalty amount remains confidential until that time).

On May 19, 2010, the Lake Charles Louisiana Refinery received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ) alleging various violations of applicable air emission regulations, as well as certain provisions of the consent decree in Civil Action No. H-01-4430. ConocoPhillips will work with the LDEQ to resolve this matter.

On September 23, 2010, the Los Angeles County Fire Department Health and Hazardous Materials Division (HHMD) issued a proposed penalty of $127,000 to ConocoPhillips. The penalty pertains to alleged violations of hazardous waste regulations at the Los Angeles Refinery noted by HHMD during its refinery compliance inspections in November and December 2009. ConocoPhillips resolved this matter with a settlement payment of $102,880 to HHMD.

On January 22, 2010, the Bay Area Air Quality Management District (BAAQMD) issued a penalty demand to resolve 16 Notices of Violation issued in 2008 and 2009 that allege violations of air pollution control regulations and/or facility permit conditions at the Rodeo facility in San Francisco, California. ConocoPhillips resolved this matter with a settlement payment of $125,050 to BAAQMD.

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 continue to contest this lawsuit.

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 the 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 11, 2011. Set forth below is information about the executive officers.

John A. Carrig has served as President since October 2010, having previously served as President and Chief Operating Officer from 2008 to October 2010. Prior to that, he served as Executive Vice President, Finance and Chief Financial Officer since the merger of Conoco and Phillips in 2002 (the merger).

Willie C. W. Chiang was appointed Senior Vice President, Refining, Marketing, Transportation and Commercial in October 2010. He previously served as Senior Vice President, Refining, Marketing and Transportation from 2008 to October 2010; Senior Vice President, Commercial from 2007 to 2008; and President, Americas Supply & Trading, Commercial, from 2005 through 2007.

Greg C. Garland was appointed Senior Vice President, Exploration and Production—Americas in October 2010, having previously served as President and Chief Executive Officer of CPChem since 2008. Prior to that, he served as Senior Vice President, Planning and Specialty Products at CPChem from 2000 to 2008.

Alan J. Hirshberg was appointed Senior Vice President, Planning and Strategy in October 2010. Prior to that, he was employed by Exxon Mobil Corporation and served as Vice President, Worldwide Deepwater and Africa Projects since 2009; Vice President, Worldwide Deepwater Projects from 2008 to 2009; Vice President, Established Areas Projects from 2006 to 2008; and Vice President, Operated by Others Projects in 2006.

Janet L. Kelly was appointed Senior Vice President, Legal, General Counsel and Corporate Secretary in 2007, having previously served as Deputy General Counsel since 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; President, Exploration and Production— Europe, Asia, Africa and the Middle East from 2007 to 2009; Senior Vice President, Technology in 2007; and Senior Vice President, Technology and Major Projects since 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 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 2009. She previously served as General Auditor and Chief Ethics Officer from 2008 to 2009, having previously served as General Manager, Downstream Finance and Performance Analysis since 2005.

Jeff W. Sheets was appointed Senior Vice President, Finance and Chief Financial Officer in October 2010. Prior to that, he served as Senior Vice President, Planning and Strategy since 2008, having previously served as Vice President and Treasurer since the merger.

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

Item 6.      SELECTED FINANCIAL DATA

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

February 23, 2011

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 29,700 employees worldwide, and at year-end 2010 had assets of $156 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

Our business is organized into six operating segments:

In 2010, as the global economy continued to recover from the recession, the business environment for certain parts of the energy industry also recovered. Oil prices continued to increase in 2010, reflecting strong oil demand growth, especially in China, and an improved economic outlook for the United States. U.S. natural gas prices, however, remained under pressure during 2010, despite a colder-than-normal winter and hotter-than-normal summer. U.S. natural gas production continues to increase at a faster rate than the demand recovery from the economic crisis, primarily as a result of increased production from shale plays. Storage levels are below 2009 levels, but remain historically high. We expect these factors will continue to moderate natural gas prices, resulting in limited U.S. LNG imports in the near- to mid-term, and potentially impacting the timing of commercialization of our Alaska North Slope and Canadian Arctic gas resources.

In late 2009, we announced several strategic initiatives designed to improve our financial position and increase returns on capital. We announced plans to raise $10 billion from asset dispositions through the end of 2011, reduce our debt and increase shareholder distributions. As of year-end 2010, we have generated approximately $7 billion from asset dispositions, the proceeds of which were primarily targeted toward debt reduction. This accelerated the return to our target debt-to-capital ratio of 20 to 25 percent. In addition, we increased the amount of our quarterly dividend rate by 10 percent, and we paid dividends on our common stock of $3.2 billion for the full year. We also announced plans to sell our entire interest in LUKOIL, and our Board of Directors authorized the purchase of up to $5 billion of our common stock through 2011. As of year-end 2010, we had sold approximately 90 percent of our interest in LUKOIL, which generated cash proceeds of approximately $8 billion, while we repurchased approximately $4 billion of our common stock. In February 2011, our Board authorized the additional purchase of up to $10 billion of our common stock over the next two years.

Our total capital program in 2011 is expected to be $13.5 billion, a $2.8 billion increase from $10.7 billion in 2010. We also expect 2011 production to be approximately 1.7 million barrels of oil equivalent per day, excluding the impact of any additional asset sales.

Crude oil, bitumen, natural gas and LNG 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. These prices and margins can be subject to extreme volatility. However, from a competitive perspective, there are other important factors we must manage well to be successful, including:

Our key performance indicators are shown in the statistical tables provided at the beginning of the operating segment sections that follow. These include commodity prices, production and refining capacity utilization.

Other significant factors that can affect our profitability include:

Segment Analysis
The E&P segment’s results are most closely linked to crude oil and natural gas prices. These are commodity products, the prices of which are subject to factors external to our company and over which we have no control. Industry crude oil prices for West Texas Intermediate (WTI) were higher in 2010, compared with 2009, averaging $79.39 per barrel in 2010, an increase of 29 percent. Uncertainty about economic growth in developed countries, especially in the United States, and concerns about the debt crisis in Europe were more than offset by increased demand from China and other developing countries. Industry natural gas prices at Henry Hub increased 10 percent during 2010 to an average price of $4.39 per million British thermal units, primarily as a result of weather-related events. An increase in demand was offset by higher natural gas production levels, and as a result, natural gas storage levels remain high and have adversely impacted Henry Hub prices.

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 increased 39 percent in 2010.

Refining margins, refinery capacity utilization and cost control 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 improved during 2010, compared with 2009. The U.S. benchmark 3:2:1 crack spread increased 9 percent in 2010, while the N.W. Europe benchmark increased 16 percent. Demand for refined products improved globally in 2010, driven by the improved economic environment, particularly in the developing nations. In addition, a wider differential in prices for high-quality crude oil relative to lower-quality crude oil improved margins for 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 year-end 2009, we had a 20 percent ownership interest in LUKOIL based on authorized and issued shares. At the end of the third quarter of 2010, as a result of our plan to divest of our entire interest in LUKOIL, our ownership interest declined to a level at which we were no longer able to exercise significant influence over the operating and financial policies of LUKOIL. Accordingly, at the end of the third quarter of 2010, we stopped recording equity earnings from LUKOIL. Starting in the fourth quarter of 2010, earnings from the LUKOIL Investment segment primarily reflect the realized gain on share sales. We disposed of our remaining interest in LUKOIL in the first quarter of 2011.

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, refining, alternative energy, biofuels and the environment. Some of these technologies have the potential to become important drivers of profitability in future years.

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

The improved results in 2010 were primarily the result of:

These items were partially offset by:

The improved results in 2009 were primarily the result of:

These items were partially offset by:

Sales and other operating revenues increased 27 percent in 2010, while purchased crude oil, natural gas and products increased 33 percent. These increases were primarily due to higher prices for petroleum products, crude oil, natural gas, natural gas liquids and LNG.

Equity in earnings of affiliates increased 24 percent in 2010. The increase primarily resulted from:

These increases were partially offset by a $645 million impairment of our equity investment in NMNG.

Gain on dispositions increased $5,643 million in 2010. The increase primarily reflects the $2,878 million gain realized from the June 2010 sale of our 9.03 percent interest in the Syncrude oil sands mining operation; the $1,749 million gain on the divestiture of our LUKOIL shares; gains on the disposition of certain E&P assets located in the Lower 48 and Canada; and the gain on sale of our 50 percent interest in CFJ Properties. For additional information, see Note 5—Assets Held for Sale and Note 6—Investment, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements.

Impairments increased $1,245 million in 2010, primarily as a result of the second quarter impairment of WRG. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes increased 8 percent during 2010, primarily due to higher production taxes as a result of higher crude oil prices and higher excise taxes on petroleum product sales.

Interest and debt expense decreased 8 percent during 2010, primarily due to lower debt levels.

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

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 49 percent in 2009, primarily due to reduced earnings from LUKOIL; DCP Midstream; MSLP; Malaysian Refining Company Sdn. Bhd.; and Excel Paralubes, which were partially offset by higher earnings from CPChem. The decreases were mainly the result of lower commodity prices and refining margins.

Gain on dispositions decreased 82 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 currency 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.

Impairments decreased from $34,625 million in 2008 to $535 million in 2009, primarily reflecting the 2008 goodwill and LUKOIL impairments. Other impairments decreased $1,151 million during 2009. For additional information, see Note 6—Investments, Loans and Long-Term Receivables and Note 9—Goodwill and Intangibles, in the Notes to Consolidated Financial Statements.

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.

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.