Table of Contents

2010
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
     
(Mark One)
   
[x]
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
  For the fiscal year ended               December 31, 2010                                                                       
 
  OR
[  ]
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
  For the transition period from                                                      to                                                     
Commission file number: 001-32395
ConocoPhillips
(Exact name of registrant as specified in its charter)
     
Delaware   01-0562944
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   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:
     
    Name of each exchange
Title of each class   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.
[x] Yes  [  ] 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.
[  ] Yes  [x] 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.                                                                                                                     [x] Yes  [  ] 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).
[x] Yes  [  ] 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. [x]
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 [x]
  Accelerated filer [  ]   Non-accelerated filer [  ]   Smaller reporting company [  ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).                                        [ ] Yes  [x] No
The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $49.09, was $72.8 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 827,349 and 37,798,903 shares, respectively, in determining the aggregate market value.
The registrant had 1,429,647,979 shares of common stock outstanding at January 31, 2011.
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 11, 2011 (Part III)
 
 

 


 

TABLE OF CONTENTS
             
Item       Page    
PART I
   
 
       
1 and 2.       1  
        1  
        2  
        2  
        14  
        16  
        20  
        21  
        21  
        22  
        23  
1A.       24  
1B.       26  
3.       26  
4.       28  
   
 
       
PART II
   
 
       
5.       30  
6.       31  
7.       32  
7A.       66  
8.       69  
9.       172  
9A.       172  
9B.       172  
   
 
       
PART III
   
 
       
10.       173  
11.       173  
12.       173  
13.       173  
14.       173  
   
 
       
PART IV
   
 
       
15.       174  
        179  
  EX-10.10.2
  EX-10.20.3
  EX-10.20.4
  EX-12
  EX-21
  EX-23.1
  EX-23.2
  EX-31.1
  EX-31.2
  EX-32
  EX-99
  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

 


Table of Contents

PART I
Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in this report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries. 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.
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, bitumen, natural gas, liquefied natural gas (LNG) and natural gas liquids 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 investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. At December 31, 2010, our ownership interest was 2.25 percent based on issued shares. See Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for information on sales of LUKOIL shares.
 
    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.
At December 31, 2010, ConocoPhillips employed approximately 29,700 people.

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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, 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:
    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.

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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.
                         
    Millions of Barrels of Oil Equivalent
Net Proved Reserves at December 31   2010     2009     2008
     
Crude oil and natural gas liquids
                       
Consolidated operations
    3,161       3,194       3,340
Equity affiliates
    231       1,710       1,677
 
Total Crude Oil and Natural Gas Liquids
    3,392       4,904       5,017
 
 
                       
Natural gas
                       
Consolidated operations
    3,039       3,161       3,360
Equity affiliates
    580       880       798
 
Total Natural Gas
    3,619       4,041       4,158
 
 
                       
Bitumen
                       
Consolidated operations
    455       417       100
Equity affiliates
    844       716       700
 
Total Bitumen
    1,299       1,133       800
 
 
                       
Synthetic oil
                       
Consolidated operations
    -       248       -
Equity affiliates
    -       -       -
 
Total Synthetic Oil
    -       248       -
 
 
                       
Total consolidated operations
    6,655       7,020       6,800
Total equity affiliates
    1,655       3,306       3,175
 
Total company
    8,310       10,326       9,975
 
Includes amounts related to LUKOIL investment:
    -       1,967       1,893
Excludes Syncrude mining-related reserves (synthetic oil):
    n/a       n/a       249
In 2010, E&P’s worldwide production, including its share of equity affiliates, averaged 1,752,000 barrels of oil equivalent per day (BOED), compared with 1,854,000 BOED in 2009. During 2010, 686,000 BOED were produced in the United States, a 9 percent decrease from 755,000 BOED in 2009. Production from our international E&P operations averaged 1,066,000 BOED in 2010, a 3 percent decrease from 1,099,000 BOED in 2009. Worldwide production decreased primarily due to field decline, the impact of higher prices on production sharing arrangements and the sale of our Syncrude oil sands mining operation. These decreases were partially offset by production from major projects in China, Canada, Qatar, the Lower 48 and Australia.
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.
E&P—UNITED STATES
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.

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Alaska
Greater Prudhoe Area
The Greater Prudhoe Area includes 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 113,000 barrels per day in 2010, compared with 119,000 barrels per day in 2009.
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

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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:
    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, sub-salt 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 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.
    Shale Plays
Exploration and development continues in our shale positions in Eagle Ford, Bakken and Barnett, which produced approximately 36,000 barrels of oil equivalent per day in 2010. We plan to drill approximately 150 exploration and development wells in the Eagle Ford in 2011 and, with subsequent investments, expect to achieve peak production in 2013 and long-term average production of 65,000 to 70,000 barrels per day. We acquired approximately 90,000 additional acres in various resource plays across the Lower 48 during 2010, further expanding our significant acreage position in Lower 48 shale plays.

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    San Juan
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 799 million cubic feet per day of natural gas and 50,000 barrels per day of liquids in 2010, compared with 903 million cubic feet per day and 49,000 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.
E&P—EUROPE
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.

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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.

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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—CANADA
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.

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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.
E&P—SOUTH AMERICA
Venezuela
In 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. 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.
E&P—ASIA PACIFIC/MIDDLE EAST
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.

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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.

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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

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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.
E&P—AFRICA
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.

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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.
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 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.
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 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.
E&P—OTHER
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

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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.
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, 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.
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, 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.
MIDSTREAM
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

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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:
    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. Our net share of capacity is 24,300 barrels per day. In October 2010, Gulf Coast Fractionators announced plans to expand the capacity of its fractionation facility to 145,000 barrels per day. The expansion is expected to be operational in the second quarter of 2012.
 
    A 40 percent interest in a fractionation plant in Conway, Kansas. Our net share of capacity is 43,200 barrels per day.
 
    A 12.5 percent equity interest in a fractionation plant in Mont Belvieu, Texas. Our net share of capacity is 26,000 barrels per day.
 
    Marketing operations that optimize 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 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.

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REFINING AND MARKETING (R&M)
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.
R&M—UNITED STATES
Refining
At December 31, 2010, 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
 

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Primary crude oil characteristics and sources of crude oil for our U.S. refineries are as follows:
                                                                 
    Characteristics     Sources
            Medium     Heavy     High         United           South     Europe    Middle East  
      Sweet     Sour     Sour     TAN*         States     Canada     America     & FSU**    & Africa  
                                                         
Bayway
    ·                                 ·           ·       ·    
                                                         
Trainer
    ·                                 ·                   ·    
                                                         
Alliance
    ·                           ·                         ·    
                                                         
Lake Charles
    ·     ·     ·     ·         ·           ·                  
                                                         
Sweeny
    ·           ·     ·                     ·             ·    
                                                         
Wood River
    ·     ·     ·     ·         ·     ·                   ·    
                                                         
Borger
          ·     ·               ·     ·                        
                                                         
Ponca City
    ·     ·     ·               ·     ·     ·                  
                                                         
Billings
          ·     ·               ·     ·                        
                                                         
Ferndale
    ·     ·                     ·     ·                        
                                                         
Los Angeles
          ·     ·     ·         ·     ·     ·             ·    
                                                         
San Francisco
    ·           ·     ·         ·           ·                  
                                                           
   *High TAN (Total Acid Number): acid content greater than or equal to 1.0 milligram of potassium hydroxide (KOH) per gram.
**Former Soviet Union.
Capacities for and yields of clean products, as well as other products produced, at our U.S. refineries are as follows:
                                                             
    Clean Product Capacity (MBD)       Other Refined Product Output
                  Clean           Fuel Oil &     Natural           Petro-          
                  Product Yield           Other Heavy     Gas     Petroleum     Chemical          
      Gasolines     Distillates     Capability           Intermediates     Liquids     Coke     Feedstock     Asphalt    
                                                         
Bayway
    145     110         90%           ·     ·           ·            
                                                         
Trainer
    105     65     85           ·     ·                        
                                                         
Alliance
    125     120     88           ·     ·     ·     ·            
                                                         
Lake Charles
    90     110     69           ·     ·            · **                  
                                                         
Sweeny
    130     120     86           ·     ·     ·     ·            
                                                         
Wood River*
    83     45     80           ·     ·     ·     ·       ·    
                                                         
Borger*
    55     28     89                 ·     ·     ·            
                                                         
Ponca City
    105     75     90           ·     ·     ·                  
                                                         
Billings
    35     25     89                 ·     ·                  
                                                         
Ferndale
    55     30     75           ·                              
                                                         
Los Angeles
    85     61     86                       ·                  
                                                         
San Francisco
    59     59     87           ·     ·     ·                  
                                                           
   *Represents our proportionate share.
**Includes specialty coke.
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. MSLP processes our long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. 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. PDVSA has initiated arbitration with the International Chamber of Commerce challenging our actions, and this arbitration is underway. We continue to use the equity method of accounting for our investment in MSLP.

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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 110 Flying 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.

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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.
R&M—INTERNATIONAL
Refining
At December 31, 2010, R&M owned or had an interest in five refineries outside the United States.
                                   
                    Net Crude Throughput  
                    Capacity (MBD)  
                    At     Effective  
Refinery   Location   Ownership     December 31, 2010     January 1, 2011  
Humber  
N. Lincolnshire, United Kingdom
    100.00 %     221       221  
Whitegate  
Cork, Ireland
    100.00       71       71  
Wilhelmshaven  
Wilhelmshaven, Germany
    100.00       260       -  
MiRO*  
Karlsruhe, Germany
    18.75       58       58  
Melaka  
Melaka, Malaysia
    47.00       61       76  
   
       
 
            671       426  
   
*Mineraloelraffinerie Oberrhein GmbH.
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
    ·                           ·       ·    
                                           
MiRO
    ·           ·               ·       ·    
                                           
Melaka
    ·     ·     ·     ·                 ·    
                                             
   *High TAN (Total Acid Number): acid content greater than or equal to 1.0 milligram of potassium hydroxide (KOH) per gram.
**Former Soviet Union.

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Capacities for and yields of clean products, as well as other products produced, at our international refineries are as follows:
                                                       
    Clean Product Capacity (MBD)       Other Refined Product Output
                  Clean           Fuel Oil &                      
                  Product Yield           Other Heavy     Natural Gas     Petroleum          
      Gasolines     Distillates     Capability           Intermediates     Liquids     Coke     Asphalt    
                                                   
Humber
    84     112         84%           ·     ·     · *            
                                                   
Whitegate
    15     30     65           ·                        
                                                   
MiRO
    25     26     85           ·     ·     ·       ·    
                                                   
Melaka
    14     36     85           ·     ·     ·       ·    
                                                     
*Includes specialty coke.
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.
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.
LUKOIL INVESTMENT
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.

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

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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:
    The Immingham Combined Heat and Power Plant, a wholly owned 1,180-megawatt facility in the United Kingdom, which provides steam and electricity to the Humber Refinery and steam to a neighboring refinery, as well as merchant power into the U.K. market.
 
    Sweeny Cogeneration LP, our 50 percent joint venture near the Sweeny Refinery complex.
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.
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.
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.

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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.
GENERAL
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 at http://www.sec.gov .

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Item 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.
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, 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.
Unless we successfully add to our existing proved reserves, our future crude oil, bitumen and natural gas production will decline, resulting in an adverse impact to our business.
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.
Any material change in the factors and assumptions underlying our estimates of crude oil, bitumen and natural gas reserves could impair the quantity and value of those reserves.
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.
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.
 
    Exploration and production activities in environmentally sensitive areas, such as offshore environments, arctic fields, oil sands reservoirs and shale gas plays.

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

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We do not insure against all potential losses; and therefore, we could be harmed by unexpected liabilities and increased costs.
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.
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 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.
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 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.

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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.

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EXECUTIVE OFFICERS OF THE REGISTRANT
         
Name   Position Held   Age *
 
       
John A. Carrig
  President   59
Willie C. W. Chiang
  Senior Vice President, Refining, Marketing, Transportation and Commercial   50
Greg C. Garland
  Senior Vice President, Exploration and Production—Americas   53
Alan J. Hirshberg
  Senior Vice President, Planning and Strategy   49
Janet L. Kelly
  Senior Vice President, Legal, General Counsel and Corporate Secretary   53
Ryan M. Lance
  Senior Vice President, Exploration and Production—International   48
James J. Mulva
  Chairman of the Board of Directors and Chief Executive Officer   64
Glenda M. Schwarz
  Vice President and Controller   45
Jeff W. Sheets
  Senior Vice President, Finance and Chief Financial Officer   53
 
     
*On February 15, 2011.
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.

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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.

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PART II
Item 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Quarterly Common Stock Prices and Cash Dividends Per Share
ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”
                         
    Stock Price        
    High     Low     Dividends  
             
2010
                       
First
  $ 53.80       46.63       .50  
Second
    60.53       48.51       .55  
Third
    58.03       48.06       .55  
Fourth
    68.58       56.80       .55  
   
 
                       
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  
   
 
                       
 
                       
Closing Stock Price at December 31, 2010
                  $ 68.10  
Closing Stock Price at January 31, 2011
                  $ 71.46  
Number of Stockholders of Record at January 31, 2011*
                    58,644  
   
*In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency or listing.
Issuer Purchases of Equity Securities
                                 
                          Millions of Dollars  
                    Total Number of     Approximate Dollar  
                    Shares Purchased     Value of Shares  
          Average     as Part of Publicly     that May Yet Be  
    Total Number of     Price Paid     Announced Plans     Purchased Under the  
Period   Shares Purchased *   Per Share     or Programs **   Plans or Programs  
   
   
October 1-31, 2010
    17,776,116       $              59.62       17,540,398       $              2,696  
November 1-30, 2010
    11,464,464       60.93       11,458,408       1,998  
December 1-31, 2010
    13,266,256       65.25       13,249,000       1,134  
   
Total
    42,506,836       $              61.73       42,247,806          
   
* Includes the repurchase of common shares from company employees in connection with the company’s broad-based employee incentive plans.
** On March 24, 2010, we announced plans to repurchase up to $5 billion of our common stock through 2011. On February 11, 2011, we announced plans to repurchase up to $10 billion of our common stock over the subsequent two years. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

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Item 6.        SELECTED FINANCIAL DATA
                                         
    Millions of Dollars Except Per Share Amounts  
    2010     2009 *   2008 *   2007 *   2006 *
       
Sales and other operating revenues
  $    189,441       149,341       240,842       187,437       183,650  
Net income (loss)
    11,417       4,492       (16,279 )     11,545       15,410  
Net income (loss) attributable to ConocoPhillips
    11,358       4,414       (16,349 )     11,458       15,334  
Per common share
                                       
Basic
    7.68       2.96       (10.73 )     7.06       9.67  
Diluted
    7.62       2.94       (10.73 )     6.96       9.53  
Total assets
    156,314       152,138       142,865       177,094       164,557  
Long-term debt
    22,656       26,925       27,085       20,289       23,091  
Joint venture acquisition obligation—long-term
    4,314       5,009       5,669       6,294       -  
Cash dividends declared per common share
    2.15       1.91       1.88       1.64       1.44  
   
*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
Many factors can impact the comparability of this information, such as:
    The financial data for 2010 includes the impact of $5,803 million before-tax ($4,583 million after-tax) related to gains on asset dispositions and LUKOIL share sales.
 
    The financial data for 2008 includes the impact of impairments related to goodwill and to our LUKOIL investment that together amount to $32,939 million before- and after-tax.
 
    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.
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.

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Item 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
February 23, 2011
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 “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 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 65.
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 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:
    Exploration and Production (E&P) —This segment primarily explores for, produces, transports and markets crude oil, bitumen, natural gas, liquefied natural gas (LNG) and natural gas liquids 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 investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. At December 31, 2010, our ownership interest was 2.25 percent based on issued shares. See Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for information on sales of LUKOIL shares.
 
    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.

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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:
    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 2010, our worldwide refining capacity utilization rate was 81 percent, compared with 84 percent in 2009. The lower rate primarily reflects run reductions at Wilhelmshaven in response to market conditions, partially offset by lower turnaround activity. Excluding Wilhelmshaven, the worldwide refining capacity utilization rate was 90 percent in 2010, compared with 88 percent in 2009.
 
      There has been heightened public focus on the safety of the oil and gas industry, as a result of the Deepwater Horizon incident in the Gulf of Mexico (GOM), which occurred in April 2010. Safety and environmental stewardship, including the operating integrity of our assets, remain our highest priorities. Therefore, in order to improve industry spill response, in 2010 we formed a non-profit organization, the Marine Well Containment Company LLC (MWCC), with Exxon Mobil Corporation, Chevron Corporation and Royal Dutch Shell plc to develop a new oil spill containment system. MWCC 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.

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    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 ended December 31, 2010, our reserve replacement was 111 percent, excluding LUKOIL. 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, is a high priority. We monitor these costs using various methodologies that are reported to senior management monthly, on both an absolute-dollar basis and a per-unit basis. Because 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 increased by 4 percent in 2010, compared with 2009, primarily as a result of market conditions and higher transportation costs.
 
    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, construct pipelines and LNG facilities, 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 the investment is operational and begins generating financial returns.
 
      Our total capital program in 2010 was $10.7 billion, which included $9.8 billion of capital expenditures and investments. Our 2011 capital program is expected to be approximately $13.5 billion, which includes $12.8 billion of capital expenditures and investments. The 2011 budget is consistent with our 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.
 
    Managing our asset portfolio. We continually evaluate our assets to determine whether they fit our strategic plans or should be sold or otherwise disposed. In 2009, we sold a majority of our U.S. retail marketing assets and announced our intention to raise $10 billion from asset dispositions through the end of 2011. In 2010, we completed the U.S. retail marketing disposition program. We also sold our 9.03 percent interest in the Syncrude oil sands mining operation; our 50 percent interest in CFJ Properties, a joint venture which owned and operated Flying J -branded truck and travel plazas; and several E&P properties located in the Lower 48 and western Canada. As part of a separate program, in 2010, we announced our intention to sell our entire interest in LUKOIL. As of year-end 2010, we sold approximately 90 percent of our interest in LUKOIL. We disposed of our remaining shares in the first quarter of 2011.

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    Developing and retaining a talented work force. We strive to attract, train, develop and retain individuals with the knowledge and skills to implement our business strategy and who support our values and ethics. Throughout the company, we focus on the continued learning, development and technical training of our employees. Professional new hires participate in structured development programs designed to accelerate their technical and functional skills.
Our key performance indicators are shown in the statistical tables provided at the beginning of the operating segment sections that follow. These include commodity prices, production and refining capacity utilization.
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, for example, our reserve estimates are revised downward, commodity prices or refining margins decline significantly for long periods of time, or 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 which, if exploratory drilling proves unsuccessful, could lead to a material impairment of leasehold values. Before-tax impairments in 2010 totaled $2.4 billion and primarily related to the $1.5 billion property impairment of our refinery in Wilhelmshaven, Germany (WRG), and a $0.6 billion impairment of our equity investment in Naraynmarneftegaz (NMNG). 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 NMNG.
 
    Goodwill. We had $3.6 billion of goodwill on our balance sheet at year-end 2010 and 2009. 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. 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. Our operations, primarily in E&P, can be affected by changing economic, regulatory and political environments in the various countries in which we operate, including the United States. 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. Our assets in Venezuela and Ecuador were expropriated in 2007 and 2009, respectively. In Canada, the Alberta provincial government changed the royalty structure in 2009 to tie a component of the new rate to prevailing prices. Our management carefully considers these events when evaluating projects or determining the level of activity in such countries.

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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.

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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   2010     2009     2008  
       
 
                       
Exploration and Production (E&P)
  $         9,198       3,604       (13,479 )
Midstream
    306       313       541  
Refining and Marketing (R&M)
    192       37       2,322  
LUKOIL Investment*
    2,503       1,219       (4,839 )
Chemicals
    498       248       110  
Emerging Businesses
    (59 )     3       30  
Corporate and Other
    (1,280 )     (1,010 )     (1,034 )
   
Net income (loss) attributable to ConocoPhillips
  $ 11,358       4,414       (16,349 )
   
*2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
2010 vs. 2009
The improved results in 2010 were primarily the result of:
    Higher prices for crude oil, natural gas, natural gas liquids and liquefied natural gas (LNG) in our E&P segment. Commodity price benefits were somewhat offset by increased production taxes.
 
    Gains of $4,583 million after-tax from asset dispositions and LUKOIL share sales.
 
    Improved results from our domestic R&M operations, reflecting higher refining margins.
These items were partially offset by:
    Impairments totaling $1,928 million after-tax.
 
    Lower production volumes from our E&P segment.
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 $7,496 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.

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Statement of Operations Analysis
2010 vs. 2009
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:
    Improved earnings from CPChem primarily due to higher margins in the olefins and polyolefins business line.
 
    Improved earnings from FCCL Partnership due to higher commodity prices and volumes.
 
    Improved earnings from Merey Sweeny, L.P. (MSLP) as a result of improved margins and volumes.
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.
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 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.

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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.

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Segment Results
E&P
                         
    2010     2009     2008  
    Millions of Dollars  
Net Income (Loss) Attributable to ConocoPhillips
                       
Alaska
  $         1,735       1,540       2,315  
Lower 48
    1,033       (37 )     2,673  
   
United States
    2,768       1,503       4,988  
International
    6,430       2,101       6,976  
Goodwill impairment
    -       -       (25,443 )
   
 
  $ 9,198       3,604       (13,479 )
   
 
                       
    Dollars Per Unit
 
       
Average Sales Prices
                       
Crude oil and natural gas liquids (per barrel)
                       
United States
  $ 69.73       53.21       89.38  
International
    74.95       57.40       89.32  
Total consolidated operations
    72.63       55.47       89.35  
Equity affiliates
    74.81       58.23       71.15  
Total E&P
    72.77       55.63       88.91  
Synthetic oil (per barrel)
                       
International
    77.56       62.01       103.31  
Bitumen (per barrel)
                       
International
    51.10       39.67       46.85  
Equity affiliates
    53.43       45.69       58.54  
Total E&P
    53.06       44.84       56.72  
Natural gas (per thousand cubic feet)*
                       
United States
    4.27       3.50       7.60  
International
    5.60       5.06       8.65  
Total consolidated operations
    5.07       4.40       8.20  
Equity affiliates
    2.79       2.35       2.04  
Total E&P
    4.98       4.37       8.18  
   
*Prior periods reclassified to conform to current year presentation which includes intrasegment transfer pricing.
 
                       
Average Production Costs Per Barrel of Oil Equivalent
                       
United States
  $ 8.30       7.73       8.34  
International
    7.96       7.72       8.03  
Total consolidated operations
    8.10       7.73       8.17  
Equity affiliates
    8.11       7.68       13.36  
Total E&P
    8.10       7.72       8.33  
   
 
                       
    Millions of Dollars
 
       
Worldwide Exploration Expenses
                       
General and administrative; geological and geophysical; and lease rentals
  $ 678       576       639  
Leasehold impairment
    241       247       273  
Dry holes
    236       359       425  
   
 
  $ 1,155       1,182       1,337  
   

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    2010     2009     2008  
    Thousands of Barrels Daily  
Operating Statistics
                       
Crude oil and natural gas liquids produced
                       
Alaska
           230       252       261  
Lower 48
    160       166       165  
   
United States
    390       418       426  
Canada
    38       40       44  
Europe
    211       241       233  
Asia Pacific/Middle East
    140       132       107  
Africa
    79       78       80  
Other areas
    -       4       9  
   
Total consolidated operations
    858       913       899  
Equity affiliates
                       
Russia
    52       55       24  
Asia Pacific/Middle East
    3       -       -  
   
 
    913       968       923  
   
 
                       
Synthetic oil produced
                       
Consolidated operations—Canada
    12       23       22  
   
 
                       
Bitumen produced
                       
Consolidated operations—Canada
    10       7       6  
Equity affiliates—Canada
    49       43       30  
   
 
    59       50       36  
   
 
                       
    Millions of Cubic Feet Daily
 
       
Natural gas produced*
                       
Alaska
    82       94       97  
Lower 48
    1,695       1,927       1,994  
   
United States
    1,777       2,021       2,091  
Canada
    984       1,062       1,054  
Europe
    815       876       954  
Asia Pacific/Middle East
    712       713       609  
Africa
    149       121       114  
Other areas
    -       -       14  
   
Total consolidated operations
    4,437       4,793       4,836  
Equity affiliates
                       
Asia Pacific/Middle East
    169       84       11  
   
 
    4,606       4,877       4,847  
   
*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, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. 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. Total E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 1,752,000 BOE per day in 2010, compared with 1,854,000 BOE per day in 2009.

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2010 vs. 2009
Earnings from our E&P segment were $9,198 million in 2010, compared with earnings of $3,604 million in 2009. The increase in 2010 earnings primarily resulted from higher prices for crude oil, natural gas, natural gas liquids and LNG. In addition, 2010 earnings benefitted from the $2,679 million after-tax gain on sale of Syncrude and higher gains from other asset rationalization efforts. These increases were partially offset by lower crude oil, natural gas and synthetic oil volumes, higher petroleum and export taxes as a result of higher prices, and the NMNG impairment. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.
U.S. E&P
U.S. E&P earnings increased 84 percent in 2010, from $1,503 million in 2009 to $2,768 million in 2010. The increase was primarily the result of higher prices for crude oil, natural gas and natural gas liquids. Earnings also benefitted from higher gains from asset sales in our Lower 48 portfolio and lower depreciation, depletion and amortization. These increases were partially offset by lower crude oil and natural gas volumes, higher production taxes, primarily in Alaska, and an unfavorable tax ruling.
U.S. E&P production averaged 686,000 BOE per day in 2010, a decrease of 9 percent from 755,000 BOE in 2009. The decrease was primarily due to field decline and unplanned downtime, which was somewhat offset by new production.
International E&P
International E&P earnings were $6,430 million in 2010, compared with $2,101 million in 2009. The increase in 2010 was mostly due to gains from the sale of Syncrude and other assets and higher crude oil, natural gas and LNG prices. These increases were partially offset by the NMNG impairment, lower synthetic oil and natural gas volumes, higher petroleum taxes as a result of higher prices and an $81 million after-tax charge to exploration expenses for project costs resulting from our decision to end participation in the Shah Gas Field Project in Abu Dhabi.
International E&P production averaged 1,066,000 BOE per day in 2010, a decrease of 3 percent from 1,099,000 BOE in 2009. The decrease was largely due to field decline, the impact of higher prices on production sharing arrangements and the sale of Syncrude. These decreases were partially offset by production from major projects, primarily in China, Canada, Qatar and Australia.
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.
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.
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 BOE per day in 2008. Less unplanned downtime and improved well performance were more than offset by field decline.

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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 BOE per day 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 planned downtime.
Midstream
                         
    2010     2009     2008  
    Millions of Dollars  
 
                       
Net Income Attributable to ConocoPhillips*
  $     306       313       541  
   
*Includes DCP Midstream-related earnings:
  $ 191       183       458  
   
Dollars Per Barrel
 
Average Sales Prices
                       
U.S. natural gas liquids*
                       
Consolidated
  $ 45.42       33.63       56.29  
Equity affiliates
    41.28       29.80       52.08  
   
*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*
    193       187       188  
Natural gas liquids fractionated**
    152       166       165  
   
   *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, trading and marketing businesses, primarily in the United States and Trinidad.
2010 vs. 2009
Midstream earnings decreased 2 percent in 2010. Higher natural gas liquids prices and, to a lesser extent, improved volumes from our equity affiliate, Phoenix Park Gas Processors Limited, were more than offset by the absence of the 2009 recognition of an $88 million after-tax benefit, which resulted from a DCP Midstream subsidiary converting subordinated units to common units. In addition, higher operating expenses resulting from higher turnaround activity contributed to the decrease in earnings.

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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 the $88 million after-tax benefit resulting from the conversion of subordinated units to common units.
R&M
                         
    2010     2009     2008  
    Millions of Dollars  
Net Income (Loss) Attributable to ConocoPhillips
                       
United States
  $      1,022       (192 )     1,540  
International
    (830 )     229       782  
   
 
  $ 192       37       2,322  
   
   
Dollars Per Gallon
 
U.S. Average Wholesale Prices*
                       
Gasoline
  $ 2.24       1.84       2.65  
Distillates
    2.30       1.76       3.06  
   
*Excludes excise taxes.
   
Thousands of Barrels Daily
 
Operating Statistics
                       
Refining operations*
                       
United States
                       
Crude oil capacity**
    1,986       1,986       2,008  
Crude oil processed
    1,782       1,731       1,849  
Capacity utilization (percent)
    90 %     87       92  
Refinery production
    1,958       1,891       2,035  
International
                       
Crude oil capacity**
    671       671       670  
Crude oil processed
    374       495       567  
Capacity utilization (percent)
    56 %     74       85  
Refinery production
    383       504       575  
Worldwide
                       
Crude oil capacity**
    2,657       2,657       2,678  
Crude oil processed
    2,156       2,226       2,416  
Capacity utilization (percent)
    81 %     84       90  
Refinery production
    2,341       2,395       2,610  
   
 
                       
Petroleum products sales volumes
                       
United States
                       
Gasoline
    1,120       1,130       1,128  
Distillates
    873       858       893  
Other products
    400       367       374  
   
 
    2,393       2,355       2,395  
International
    647       619       645  
   
 
    3,040       2,974       3,040  
   
   *Includes our share of equity affiliates, except LUKOIL, which is included in the LUKOIL Investment segment.
**Weighted-average crude oil capacity for the periods.
Our R&M segment refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buys, sells and transports crude oil; and buys, transports, distributes and markets petroleum products. R&M has operations mainly in the United States, Europe and Asia.

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2010 vs. 2009
R&M reported earnings of $192 million in 2010, compared with earnings of $37 million in 2009. Earnings for 2010 included the $1,124 million after-tax property impairment of WRG. Excluding the impact of this impairment, earnings were significantly improved during 2010 due to higher global refining margins. Results also benefitted from a $113 million after-tax gain on the sale of CFJ and higher refining and marketing volumes. These increases were partially offset by negative foreign currency impacts. See the “Business Environment and Executive Overview” section for additional information on industry refining margins.
U.S. R&M
Earnings from U.S. R&M were $1,022 million in 2010, compared with a loss of $192 million in 2009. The increase in 2010 primarily resulted from significantly higher refining margins and the gain on sale of CFJ. Higher refining and marketing volumes also contributed to the improvement in earnings.
Our U.S. refining crude oil capacity utilization rate was 90 percent in 2010, compared with 87 percent in 2009. The increase in 2010 was primarily due to lower turnaround activity, lower run reductions due to market conditions, and less unplanned downtime.
International R&M
International R&M reported a loss of $830 million in 2010, compared with earnings of $229 million in 2009. The loss in 2010 primarily resulted from the WRG impairment and a $29 million after-tax impairment resulting from our decision to end participation in the Yanbu Refinery Project. Excluding these impairments, earnings were improved due to higher refining margins, partially offset by foreign currency losses.
Our international refining crude oil capacity utilization rate was 56 percent in 2010, compared with 74 percent in 2009. The 2010 rate primarily reflects run reductions at WRG in response to market conditions.
We are currently exploring options to either pursue the sale of WRG or operate it as a terminal. As a result, effective January 1, 2011, we no longer include its capacity in our stated refining capacities or our capacity utilization metrics.
2009 vs. 2008
R&M reported earnings of $37 million in 2009, compared with $2,322 million in 2008. The decrease was primarily a result of significantly lower U.S. and international refining margins, lower volumes, lower international marketing margins and a lower net benefit from asset rationalization efforts. These decreases were partially offset by lower operating expenses, lower property impairments and positive foreign currency impacts. During 2008, our R&M segment had property impairments totaling $511 million after-tax, mostly due to a significantly diminished outlook for refining margins.
U.S. R&M
Our U.S. R&M operations reported a loss of $192 million in 2009, compared with earnings of $1,540 million in 2008. The decrease was primarily due to significantly lower U.S. refining margins, lower U.S. refining and marketing volumes and a lower net benefit from asset sales. These decreases were partially offset by lower operating expenses and lower property impairments.
Our U.S. refining capacity utilization rate was 87 percent in 2009, compared with 92 percent in 2008. The rate for 2009 was mainly affected by run reductions due to market conditions and increased turnaround activity, while the 2008 rate was impacted by downtime associated with hurricanes.
International R&M
International R&M reported earnings of $229 million in 2009 and earnings of $782 million in 2008. The decrease in earnings was primarily due to significantly lower international refining and marketing margins, lower international marketing volumes and a lower net benefit from asset sales. These decreases were partially offset by positive foreign currency impacts, lower property impairments and lower operating expenses.

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Our international refining capacity utilization rate was 74 percent in 2009, compared with 85 percent in 2008. The rate for 2009 reflected higher turnaround activity. In addition, the utilization rate for both periods reflected run reductions in response to market conditions.
LUKOIL Investment
                         
    Millions of Dollars  
    2010     2009 *   2008 *
       
 
                       
Net Income (Loss) Attributable to ConocoPhillips
  $      2,503       1,219       (4,839 )
   
 
                       
Operating Statistics
                       
Crude oil production (thousands of barrels daily)
    284       388       389  
Natural gas production (millions of cubic feet daily)
    254       295       330  
Refinery crude oil processed (thousands of barrels daily)
    189       240       226  
   
*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia.
Prior to 2010, our equity earnings for LUKOIL were estimated. Effective January 1, 2010, we changed our accounting to record our equity earnings for LUKOIL on a one-quarter-lag basis. This change in accounting principle has been applied retrospectively, by recasting prior period financial information. The performance metrics are also reported on a one-quarter-lag basis. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for more information.
In addition to our equity share of LUKOIL’s earnings, segment results include the amortization of the basis difference between our equity interest in the net assets of LUKOIL and the book value of our investment, as well as gains from the divestiture of our LUKOIL shares.
At year-end 2009, we had a 20 percent ownership interest in LUKOIL based on authorized and issued shares. In July 2010, we announced our intention to sell our entire interest in LUKOIL. During 2010, we sold approximately 151 million shares of LUKOIL, and as a result of these sales, our ownership interest in LUKOIL was 2.25 percent at December 31, 2010, based on authorized and issued shares. In 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 applying the equity method of accounting for our remaining investment. In addition, we will no longer report proved reserves or production related to our LUKOIL investment. See Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for more information.
In the first quarter of 2011, we sold our remaining interest in LUKOIL. As a result, our first quarter 2011 earnings from the LUKOIL Investment segment will primarily reflect the realized gain on share sales. The total unrealized gain on those shares at December 31, 2010, based on a closing price of LUKOIL shares on the London Stock Exchange of $56.50 per share, was $158 million after-tax, and this amount was included in accumulated other comprehensive income.
2010 vs. 2009
LUKOIL segment earnings increased $1,284 million in 2010, which primarily resulted from the $1,251 million after-tax gain on our LUKOIL shares sold during 2010.

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2009 vs. 2008
LUKOIL segment earnings were $1,219 million in 2009, compared with a loss of $4,839 million in 2008. Results for 2008 included a $7,496 million noncash, before- and after-tax impairment of our LUKOIL investment taken during the fourth quarter. Excluding the impact of this impairment, earnings decreased 54 percent in 2009. The decrease was primarily due to lower realized refined product and crude oil prices, which was partly offset by lower extraction taxes and export tariff rates, and a benefit from basis difference amortization.
Chemicals
                         
    Millions of Dollars  
    2010     2009     2008  
       
 
                       
Net Income Attributable to ConocoPhillips
  $    498       248       110  
   
The Chemicals segment consists of our 50 percent interest in CPChem, which we account for under the equity method. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals. These products are then marketed and sold, or used as feedstocks, to produce plastics and commodity chemicals.
2010 vs. 2009
Earnings from the Chemicals segment increased $250 million in 2010, primarily due to substantially higher margins in the olefins and polyolefins business line and, to a lesser extent, improved margins from the specialties, aromatics and styrenics business line. Higher operating costs partially offset these increases.
2009 vs. 2008
Earnings from the Chemicals segment increased $138 million in 2009 due to lower operating costs and higher margins in the specialties, aromatics and styrenics business line. These increases were partially offset by lower margins in the olefins and polyolefins business line.
Emerging Businesses
                         
    Millions of Dollars  
    2010     2009     2008  
       
Net Income (Loss) Attributable to ConocoPhillips
                       
Power
  $    49       105       106  
Other
    (108 )     (102 )     (76 )
   
 
  $ (59 )     3       30  
   
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.

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2010 vs. 2009
The Emerging Businesses segment reported a loss of $59 million in 2010, compared with earnings of $3 million in 2009. The decrease for 2010 was mainly due to lower domestic and international power generation results, which resulted from higher operating costs and impairment charges related to a U.S. cogeneration plant that was sold in December 2010. Lower margins in international power and higher technology development expenses also contributed to the decrease.
2009 vs. 2008
Emerging Businesses reported earnings of $3 million in 2009, compared with $30 million in 2008. The decrease in 2009 was primarily due to lower international power results and higher technology development expenses, which were mostly offset by the absence of an $85 million after-tax impairment of a U.S. cogeneration power plant in 2008.
Corporate and Other
                         
    Millions of Dollars  
    2010     2009     2008  
       
Net Loss Attributable to ConocoPhillips
                       
Net interest
  $    (965 )     (851 )     (558 )
Corporate general and administrative expenses
    (209 )     (108 )     (202 )
Other
    (106 )     (51 )     (274 )
   
 
  $ (1,280 )     (1,010 )     (1,034 )
   
2010 vs. 2009
Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 13 percent in 2010, mostly due to a $114 million after-tax premium on early debt retirement and a lower effective tax rate. These increases were partially offset by lower interest expense due to lower debt levels. Corporate general and administrative expenses increased $101 million in 2010, primarily as a result of costs related to compensation and benefit plans. The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment. Changes in the “Other” category primarily reflect foreign currency transaction losses.
2009 vs. 2008
Net interest increased 53 percent in 2009 as a result of higher average debt levels, partially offset by lower average interest rates. Capitalized interest was also lower in 2009. Corporate general and administrative expenses decreased 47 percent due to decreased costs related to compensation plans and overhead. Changes in the “Other” category are primarily due to foreign currency transaction gains in 2009, compared with foreign currency transaction losses in 2008.

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CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
                         
    Millions of Dollars  
    Except as Indicated  
    2010     2009     2008  
Net cash provided by operating activities
  $      17,045       12,479       22,658  
Short-term debt
    936       1,728       370  
Total debt
    23,592       28,653       27,455  
Total equity*
    69,109       62,613       56,265  
Percent of total debt to capital**
    25 %     31       33  
Percent of floating-rate debt to total debt***
    10 %     9       37  
   
     *2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
   **Capital includes total debt and total equity.
***Includes effect of interest rate swaps.
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from operating activities is the primary source of funding. In addition, during 2010, we received $15,372 million in proceeds from asset sales. During 2010, the primary uses of our available cash were: $9,761 million to support our ongoing capital expenditures and investments program, $5,202 million to repay debt, $3,866 million to repurchase common stock, $3,175 million to pay dividends on our common stock, and $982 million to purchase short-term investments. During 2010, cash and cash equivalents increased by $8,912 million to $9,454 million.
In addition to cash flows from operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility programs and our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash and short-term investment balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, dividend payments, required debt payments and the funding requirements to FCCL.
Significant Sources of Capital
Operating Activities
During 2010, cash of $17,045 million was provided by operating activities, a 37 percent increase from cash from operations of $12,479 million in 2009. The increase was primarily due to significantly higher crude oil prices in our E&P segment and higher refining margins in our R&M segment.
During 2009, cash flow from operations decreased $10,179 million, compared with 2008. The decline was primarily due to significantly lower commodity prices in our E&P segment and lower refining margins in our R&M segment.
While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids, as well as refining and marketing margins. Crude oil and natural gas prices deteriorated significantly in the fourth quarter of 2008. Crude oil prices trended higher in 2009 and 2010 although natural gas prices remained weak. Refining margins deteriorated significantly in the fourth quarter of 2008, remained low throughout 2009, and showed improvement during 2010. Prices and margins in our industry are typically volatile, and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.
The level of our production volumes of crude oil, bitumen, natural gas and natural gas liquids also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields,

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field production decline rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although historically this variability has not been as significant as that caused by commodity prices.
Our E&P production for 2010 averaged 1.75 million BOE per day. Future production is subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment, which may impact project investment decisions; the effects of price changes on production sharing and variable-royalty contracts; timing of project startups and major turnarounds; and weather-related disruptions. Our production in 2011, excluding the impact of any additional dispositions, is expected to be approximately 1.7 million BOE per day. We continue to evaluate various properties as potential candidates for our disposition program. The makeup and timing of our disposition program will also impact 2011 and future years’ production levels.
To maintain or grow our production volumes, we must continue to add to our proved reserve base. Our reserve replacement in 2010 was negative 160 percent, including a positive 41 percent from consolidated operations. The 2010 reserve replacement reflects a reduction of 2.2 billion BOE due to LUKOIL share sales and other asset dispositions. Excluding the impact of acquisitions and dispositions, the E&P segment’s reserve replacement was 138 percent of 2010 production. Over the five-year period ended December 31, 2010, our reserve replacement was 75 percent, including 105 percent from consolidated operations; however, excluding LUKOIL, our five-year reserve replacement would have been 111 percent. Over this period we added reserves through acquisitions and project developments, which were more than offset by the impact of asset expropriations in Venezuela and Ecuador and the sale of our investment in LUKOIL. The reserve replacement amounts above were based on the sum of our net additions (revisions, improved recovery, purchases, extensions and discoveries, and sales) divided by our production, as shown in our reserve table disclosures. For additional information about our proved reserves, including both developed and undeveloped reserves, see the “Oil and Gas Operations” section of this report.
We are developing and pursuing projects we anticipate will allow us to add to our reserve base. However, 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.
As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved reserves are imprecise; therefore, each year reserves may be revised upward or downward due to the impact of changes in commodity prices or as more technical data becomes available on reservoirs. In 2010 and 2009, revisions increased reserves, while in 2008 revisions decreased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future.
In our R&M segment, the level and quality of output from our refineries impacts our cash flows. The output at our refineries is impacted by such factors as operating efficiency, maintenance turnarounds, market conditions, feedstock availability and weather conditions. We actively manage the operations of our refineries, and typically, any variability in their operations has not been as significant to cash flows as that caused by refining margins.
Asset Sales
Proceeds from asset sales in 2010 were $15.4 billion, compared with $1.3 billion in 2009. The 2010 proceeds from asset sales included $8.3 billion from our interest in LUKOIL. The remaining sales consisted primarily of our interest in Syncrude Canada Ltd., CFJ Properties and North America E&P assets. We plan to raise an additional $3 billion through the end of 2011, as part of our previously announced $10 billion asset disposition program. The sale of our LUKOIL interest is not included in this program.

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Commercial Paper and Credit Facilities
At December 31, 2010, we had two revolving credit facilities totaling $7.85 billion, consisting of a $7.35 billion facility expiring in September 2012 and a $500 million facility expiring in July 2012. Our revolving credit facilities may be used as direct bank borrowings, as support for issuances of letters of credit totaling up to $750 million, or as support for our commercial paper programs. The revolving credit facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreements contain a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreements call for commitment fees on available, but unused, amounts. The agreements also contain early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.
Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to fund commitments relating to the Qatargas 3 (QG3) Project. At December 31, 2010 and 2009, we had no direct borrowings under the revolving credit facilities, but $40 million in letters of credit had been issued at both periods. In addition, under the two ConocoPhillips commercial paper programs, $1,182 million of commercial paper was outstanding at December 31, 2010, compared with $1,300 million at December 31, 2009. Since we had $1,182 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.6 billion in borrowing capacity under our revolving credit facilities at December 31, 2010.
Shelf Registration
We have a universal shelf registration statement on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
Our senior long-term debt is rated “A1” by Moody’s Investor Service and “A” by both Standard and Poor’s Rating Service and by Fitch. We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access funds under our $7.35 billion and $500 million revolving credit facilities.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. At December 31, 2010, we were liable for certain contingent obligations under the following contractual arrangements:
    Qatargas 3 : We own a 30 percent interest in QG3, an integrated project to produce and liquefy natural gas from Qatar’s North Field. The other participants in the project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent). Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. QG3 secured project financing of $4 billion in 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants, based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion. Upon completion certification, currently expected in 2011, all project loan facilities, including the

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      ConocoPhillips loan facilities, will become nonrecourse to the project participants. At December 31, 2010, QG3 had approximately $4 billion outstanding under all the loan facilities, including the $1.2 billion from ConocoPhillips.
 
    Rockies Express Pipeline : In June 2006, we issued a guarantee for 24 percent of $2 billion in credit facilities issued to Rockies Express Pipeline LLC, operated by Kinder Morgan Energy Partners, L.P. In the second quarter of 2010, the credit facilities were reduced, and our guarantee was released.
For additional information about guarantees, see Note 14—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
Capital Requirements
Our debt balance at December 31, 2010, was $23.6 billion, a decrease of $5.1 billion during 2010, and our debt-to-capital ratio was 25 percent at year-end 2010, versus 31 percent at the end of 2009. The change in the debt-to-capital ratio was due to a combination of a decrease in debt and an increase in equity. Our debt-to-capital ratio target range is 20 to 25 percent. On February 15, 2011, a $328 million 9.375% Note was repaid at maturity.
In 2007, we closed on a business venture with Cenovus Energy Inc. As part of this transaction, we are obligated to contribute $7.5 billion, plus accrued interest, over a 10-year period that began in 2007, to the upstream business venture, FCCL, formed as a result of the transaction. Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, approximately $695 million was short-term and was included in the “Accounts payable—related parties” line on our December 31, 2010, consolidated balance sheet. The principal portion of these payments, which totaled $659 million in 2010, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.
We have provided loan financing to WRB Refining LP, to assist it in meeting its operating and capital spending requirements. At December 31, 2010, $550 million of such financing was outstanding and $400 million was classified as long term.
In February 2011, we announced a 20 percent increase in the quarterly dividend rate to 66 cents per share. The dividend is payable March 1, 2011, to stockholders of record at the close of business February 22, 2011.
On March 24, 2010, our Board of Directors authorized the purchase of up to $5 billion of our common stock through 2011. Repurchase of shares under this authorization totaled 64.5 million shares at a cost of $3.9 billion, through December 31, 2010. On February 11, 2011, the Board authorized the additional purchase of up to $10 billion of our common stock over the subsequent two years. At year end we had a cash and short-term investment balance of $10.4 billion, a significant portion of which is expected to be directed toward the repurchase of common stock.

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Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2010:
                                         
    Millions of Dollars  
    Payments Due by Period  
            Up to     Years     Years     After  
    Total     1 Year     2-3     4-5     5 Years  
     
Debt obligations (a)
  $     23,553       924       3,354       3,137       16,138  
Capital lease obligations
    39       12       4       3       20  
   
Total debt
    23,592       936       3,358       3,140       16,158  
   
Interest on debt and other obligations
    20,060       1,404       2,649       2,274       13,733  
Operating lease obligations
    2,896       752       1,033       554       557  
Purchase obligations (b)
    139,575       61,136       14,326       9,044       55,069  
Joint venture acquisition obligation (c)
    5,009       695       1,504       1,672       1,138  
Other long-term liabilities (d)
                                       
Asset retirement obligations
    8,776       454       722       627       6,973  
Accrued environmental costs
    994       117       176       119       582  
Unrecognized tax benefits (e)
    160       160       (e )     (e )     (e )
   
Total
  $ 201,062       65,654       23,768       17,430       94,210  
   
(a)   Includes $457 million of net unamortized premiums and discounts. See Note 12—Debt, in the Notes to Consolidated Financial Statements, for additional information.
 
(b)   Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. Does not include purchase commitments for jointly owned fields and facilities where we are not the operator.
 
    The majority of the purchase obligations are market-based contracts, including exchanges and futures, for the purchase of products such as crude oil, unfractionated natural gas liquids, natural gas and power. The products are mostly used to supply our refineries and fractionators, optimize the supply chain, and resell to customers. Product purchase commitments with third parties totaled $73,138 million. In addition, $50,179 million are product purchases from CPChem, mostly for natural gas and natural gas liquids over the remaining term of 89 years, and Excel Paralubes, for base oil over the remaining initial term of 15 years.
 
    Purchase obligations of $12,806 million are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and LNG and product terminals, to transport, process, treat, and store products. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned fields and facilities where we are the operator.
 
(c)   Represents the remaining amount of contributions, excluding interest, due over a seven-year period to the FCCL upstream joint venture with Cenovus.
 
(d)   Does not include: Pensions—for the 2011 through 2015 time period, we expect to contribute an average of $530 million per year to our qualified and nonqualified pension and postretirement benefit plans in the United States and an average of $240 million per year to our non-U.S. plans, which are expected to be in excess of required minimums in many cases. The U.S. five-year average consists of $730 million for 2011 and then approximately $480 million per year for the remaining four years. Our required minimum funding in 2011 is expected to be $360 million in the United States and $160 million outside the United States.

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(e)   Excludes unrecognized tax benefits of $965 million because the ultimate disposition and timing of any payments to be made with regard to such amounts are not reasonably estimable. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.
Capital Spending
Capital Expenditures and Investments
                                 
    Millions of Dollars  
    2011                    
    Budget     2010     2009     2008  
     
E&P
                               
United States—Alaska
  $     900       730       810       1,414  
United States—Lower 48
    3,300       1,855       2,664       3,836  
International
    7,100       5,908       5,425       11,206  
   
 
    11,300       8,493       8,899       16,456  
   
Midstream
    -       3       5       4  
   
R&M
                               
United States
    1,000       790       1,299       1,643  
International
    200       266       427       626  
   
 
    1,200       1,056       1,726       2,269  
   
LUKOIL Investment
    -       -       -       -  
Chemicals
    -       -       -       -  
Emerging Businesses
    100       27       97       156  
Corporate and Other
    200       182       134       214  
   
 
  $ 12,800       9,761       10,861       19,099  
   
United States
  $ 5,400       3,576       4,921       7,111  
International
    7,400       6,185       5,940       11,988  
   
 
  $ 12,800       9,761       10,861       19,099  
   
Our capital expenditures and investments for the three-year period ending December 31, 2010, totaled $39.7 billion, with 85 percent allocated to our E&P segment.
Our capital expenditures and investments budget for 2011 is $12.8 billion. Included in this amount is approximately $0.4 billion in capitalized interest. We plan to direct 88 percent of the capital expenditures and investments budget to E&P and 9 percent to R&M. With the addition of loans to certain affiliated companies and principal contributions related to funding our portion of the FCCL business venture, our total capital program for 2011 is approximately $13.5 billion.
E&P
Capital expenditures and investments for E&P during the three-year period ended December 31, 2010, totaled $33.8 billion. The expenditures over this period supported key exploration and development projects including:
    Oil, natural gas liquids and natural gas developments in the Lower 48, including Texas, New Mexico, North Dakota, Oklahoma, Montana, Colorado, Wyoming, and offshore in the Gulf of Mexico (GOM).
 
    The initial investment in 2008 related to the Australia Pacific LNG (APLNG) 50/50 joint venture and subsequent expenditures to advance the associated coalbed methane (CBM) projects.
 
    Oil sands projects and ongoing natural gas projects in Canada.
 
    Alaska activities related to development drilling in the Greater Kuparuk Area, the Greater Prudhoe Area, the Western North Slope and the Cook Inlet Area; and exploration.
 
    Significant U.S. lease acquisitions in the federal waters of the Chukchi Sea offshore Alaska, as well as in the deepwater GOM.

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    Development drilling and facilities projects in the Greater Ekofisk Area, Alvheim, Heidrun and Statfjord, located in the Norwegian sector of the North Sea.
 
    The Peng Lai 19-3 development in China’s Bohai Bay.
 
    The Kashagan Field and satellite prospects in the Caspian Sea offshore Kazakhstan.
 
    In the U.K. sector of the North Sea, the development of the Britannia satellite fields, the development of the Jasmine discovery in the J-Block Area and development drilling on Clair and in the southern and central North Sea.
 
    Investment in Rockies Express Pipeline LLC.
 
    The North Belut Field, as well as other projects in offshore Block B and onshore South Sumatra in Indonesia.
 
    The QG3 Project, an integrated project to produce and liquefy natural gas from Qatar’s North Field.
 
    The Gumusut-Kakap development offshore Sabah, Malaysia.
 
    Exploration activities in Australia’s Browse Basin, deepwater GOM, onshore North American shale play and oil sands projects, offshore eastern Canada, North Sea and Kazakhstan’s Block N.
 
    The El Merk Project, comprised of wells, gathering lines and a shared Central Processing Facility to develop the EMK Field Unit in Algeria.
2011 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
E&P’s 2011 capital expenditures and investments budget is $11.3 billion, 33 percent higher than actual expenditures in 2010. Thirty-seven percent of E&P’s 2011 capital expenditures and investments budget is planned for the United States.
Capital spending for our Alaskan operations is expected to be directed toward the Prudhoe Bay and Kuparuk Fields, as well as the Alpine Field and satellites on the Western North Slope.
In the Lower 48, we expect to make capital expenditures and investments for ongoing development in the Williston, Permian and San Juan Basins, as well as the Eagle Ford, Barnett and Lobo Trends. Also, we expect to direct capital spending towards exploration and appraisal activities in the Eagle Ford shale position in Texas, the Bakken shale formation in North Dakota and the deepwater GOM.
E&P is directing $7.1 billion of its 2011 capital expenditures and investments budget to international projects. Funds in 2011 will be directed to developing major long-term projects including:
    Canadian oil sands projects and ongoing natural gas projects in the western Canada gas basins.
 
    Further development of CBM projects associated with the APLNG joint venture in Australia.
 
    Elsewhere in the Asia Pacific/Middle East Region, continued development of Bohai Bay in China, new fields offshore Malaysia, offshore Block B and onshore South Sumatra in Indonesia, and offshore Vietnam.
 
    In the North Sea, the Ekofisk Area, Greater Britannia Fields, Southern North Sea assets, development of the Jasmine discovery in the J-Block Area and the Clair Ridge Project.
 
    The Kashagan Field in the Caspian Sea.
 
    Onshore developments in Nigeria, Algeria and Libya.
 
    Exploration and appraisal activities in North American shale plays and oil sands projects, Australia’s Browse Basin, Kazakhstan’s Block N, deepwater GOM, offshore Indonesia and the North Sea.
For information on proved undeveloped reserves and the associated cost to develop these reserves, see the “Oil and Gas Operations” section.

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R&M
Capital spending for R&M during the three-year period ended December 31, 2010, was primarily for air emission reduction and clean fuels projects to meet new environmental standards, refinery upgrade projects to improve product yields and increase heavy crude oil processing capability, improving the operating integrity of key processing units, as well as for safety projects. During this three-year period, R&M capital spending was $5.1 billion, which represented 13 percent of our total capital expenditures and investments.
Key projects during the three-year period included:
    Installation of a 20,000-barrel-per-day hydrocracker at the Rodeo facility of our San Francisco Refinery.
 
    Installation of a 225-ton per day sulfur plant at the Sweeny Refinery.
 
    Installation of facilities to reduce sulfur dioxide emissions from the Fluid Catalytic Cracker at the Alliance Refinery.
 
    Completion of a gasoline benzene reduction project at the Borger Refinery.
 
    Investment to obtain an equity interest in four Keystone Pipeline entities, and associated investment to construct a crude oil pipeline from Hardisty, Alberta, to delivery points in the United States. We disposed of our interest in the Keystone Pipeline in 2009.
Major construction activities in progress include:
    Installation of a 65,000-barrel-per-day coker and a major reconfiguration of the Wood River Refinery to handle advantaged crude and increase capacity, partially funded through long-term advances from ConocoPhillips.
 
    Installations, revamps and expansions of equipment at several U.S. refineries to enable production of low benzene gasoline.
 
    U.S. programs aimed at air emission reductions.
2011 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
R&M’s 2011 capital expenditures and investments budget is $1.2 billion, a 14 percent increase from actual spending in 2010, with about $1 billion targeted in the United States and $0.2 billion internationally. These funds will be used primarily for projects related to sustaining and improving the existing business with a focus on safety, regulatory compliance and reliability.
Emerging Businesses
Capital spending for Emerging Businesses during the three-year period ended December 31, 2010, was primarily for an expansion of the Immingham combined heat and power cogeneration plant near our Humber Refinery in the United Kingdom.
Contingencies
A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position

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both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Legal and Tax Matters
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, are required. See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related contingencies.
Environmental
We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:
    U.S. Federal Clean Air Act, which governs air emissions.
 
    U.S. Federal Clean Water Act, which governs discharges to water bodies.
 
    European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH).
 
    U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.
 
    U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal of solid waste.
 
    U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States.
 
    U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments.
 
    U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells.
 
    U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages.
 
    European Union Trading Directive resulting in European Emissions Trading Scheme.
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may

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impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.
An example in the fuels area is the Energy Policy Act of 2005, which imposed obligations to provide increasing volumes of renewable fuels in transportation motor fuels through 2012. These obligations were changed with the enactment of the Energy Independence and Security Act of 2007. The 2007 law requires fuel producers and importers to provide additional renewable fuels for transportation motor fuels that include a mix of various types to be included through 2022. We have met the increased requirements to date while establishing implementation, operating and capital strategies, along with advanced technology development, to address projected future requirements.
We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater.
At RCRA-permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. We anticipate increased expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.
We, from time to time, receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2009, we reported we had been notified of potential liability under CERCLA and comparable state laws at 65 sites around the United States. At December 31, 2010, we had been notified of seven new sites, re-opened three sites and settled two sites, bringing the number to 73 unresolved sites with potential liability.
For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and

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amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.
Expensed environmental costs were $928 million in 2010 and are expected to be about $1,100 million per year in 2011 and 2012. Capitalized environmental costs were $574 million in 2010 and are expected to be about $650 million per year in 2011 and 2012.
Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA.
Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.
At December 31, 2010, our balance sheet included total accrued environmental costs of $994 million, compared with $1,017 million at December 31, 2009. We expect to incur a substantial amount of these expenditures within the next 30 years.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.
Climate Change
There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation or precursors for possible regulation that do or could affect our operations include:
    European Emissions Trading Scheme (ETS), the program through which many of the European Union (EU) member states are implementing the Kyoto Protocol.
 
    California’s Global Warming Solutions Act, which requires the California Air Resources Board to develop regulations and market mechanisms that will ultimately reduce California’s GHG emissions by 25 percent by 2020.
 
    Two regulations issued by the Alberta government in 2007 under the Climate Change and Emissions Act. These regulations require any existing facility with emissions equal to or greater than 100,000 metric tons of carbon dioxide or equivalent per year to reduce the net emissions intensity of that facility by 2 percent per year beginning July 1, 2007, with an ultimate reduction target of 12 percent of baseline emissions.
 
    The U.S. Supreme Court decision in Massachusetts v. EPA , 549 U.S. 497, 127 S.Ct. 1438 (2007), confirming that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act.

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    The EPA’s announcement on December 7, 2009, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, 74, Fed. Reg. 66,495,” finalizing its findings that GHG emissions threaten public health and the environment and that cars and light trucks cause or contribute to this threat. While these findings do not themselves impose any requirements on any industry or company at this time, these findings may lead to greater regulation of GHG emissions by the EPA, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects to determine the extent of climate change.
In the EU, we have assets that are subject to the ETS. The first phase of the EU ETS was completed at the end of 2007, with EU ETS Phase II running from 2008 through 2012. The European Commission has approved most of the Phase II national allocation plans. We are actively engaged to minimize any financial impact from the trading scheme.
In the United States, there is growing consensus that some form of regulation will be forthcoming at the federal level with respect to GHG emissions. Such regulation could take any of several forms that may result in the creation of additional costs in the form of taxes, the restriction of output, investments of capital to maintain compliance with laws and regulations, or required acquisition or trading of emission allowances. We are working to continuously improve operational and energy efficiency through resource and energy conservation throughout our operations.
Compliance with changes in laws and regulations that create a GHG emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate impact on our financial performance, either positive or negative, will depend on a number of factors, including but not limited to:
    Whether and to what extent legislation is enacted.
 
    The nature of the legislation (such as a cap and trade system or a tax on emissions).
 
    The GHG reductions required.
 
    The price and availability of offsets.
 
    The amount and allocation of allowances.
 
    Technological and scientific developments leading to new products or services.
 
    Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature).
 
    Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services.
Other
We have deferred tax assets related to certain accrued liabilities, loss carryforwards and credit carryforwards. Valuation allowances have been established to reduce these deferred tax assets to an amount that will, more likely than not, be realized. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable income.

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CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1—Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least annually. We believe the following discussions of critical accounting estimates, along with the discussions of contingencies and of deferred tax asset valuation allowances in this report, address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.
Oil and Gas Accounting
Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.
This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. At year-end 2010, the book value of the pools of property acquisition costs that individually are relatively small and thus subject to the above-described periodic leasehold impairment calculation was $1,581 million and the accumulated impairment reserve was $497 million. The weighted-average judgmental percentage probability of ultimate failure was approximately 58 percent, and the weighted-average amortization period was approximately three years. If that judgmental percentage were to be raised by 5 percent across all calculations, pretax leasehold impairment expense in 2011 would increase by approximately $23 million. The remaining $5,374 million of gross capitalized unproved property costs at year-end 2010 consisted of individually significant leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently drilling, and suspended exploratory wells. Management periodically assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for project commercialization. Of this amount, approximately $2.8 billion is concentrated in 10 major development areas. One of these major assets totaling $118 million is expected to move to proved properties in 2011.
Exploratory Costs
For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify completion of the find as a producing well.
If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but

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the accounting rules do prohibit continued capitalization of suspended well costs on the mere chance that future market conditions will improve or new technologies will be found that would make the project’s development economically profitable. Often, the ability to move the project into the development phase and record proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field or while we seek government or co-venturer approval of development plans or seek environmental permitting. Once a determination is made the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense.
Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole when it determines the potential field does not warrant further investment in the near term. Criteria utilized in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.
At year-end 2010, total suspended well costs were $1,013 million, compared with $908 million at year-end 2009. For additional information on suspended wells, including an aging analysis, see Note 8—Suspended Wells, in the Notes to Consolidated Financial Statements.
Proved Reserves
Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.
Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s E&P operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our reservoir engineering organization has policies and procedures in place consistent with these authoritative guidelines. We have trained and experienced internal engineering personnel who estimate our proved reserves held by consolidated companies, as well as our share of equity affiliates.
Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes occur, and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when a field will be permanently shut down for economic reasons is based on 12-month average prices and year-end costs. This estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes.
Our proved reserves include estimated quantities related to production sharing contracts, which are reported under the “economic interest” method and are subject to fluctuations in prices of crude oil, natural gas and natural gas liquids; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. The estimation of proved developed reserves also is important to the statement of operations because the proved developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of depreciation, depletion and amortization of the capitalized costs for that asset. At year-end 2010, the net book value of productive E&P properties, plants and equipment subject to a unit-of-production calculation was approximately $56 billion and the depreciation,

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depletion and amortization recorded on these assets in 2010 was approximately $7.8 billion. The estimated proved developed reserves for our consolidated operations were 5.6 billion BOE at the beginning of 2010 and were 5.2 billion BOE at the end of 2010. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 5 percent across all calculations, pretax depreciation, depletion and amortization in 2010 would have increased by an estimated $410 million. Impairments of producing properties resulting from downward revisions of proved reserves due to reservoir performance were not material in the last three years.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group and annually in the fourth quarter following updates to corporate planning assumptions. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets, or at an entire complex level for downstream assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes, commodity prices, operating costs, refining margins and capital project decisions, considering all available information at the date of review. See Note 10—Impairments, in the Notes to Consolidated Financial Statements, for additional information.
Investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment when there is evidence of a loss in value and annually following updates to corporate planning assumptions. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When it is determined such a loss in value is other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that will be sufficient to allow for any anticipated recovery in the market value of the investment. When quoted market prices are not available, the fair value is usually based on the present value of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period. For additional information, see the “LUKOIL” and “NMNG” sections of Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements.
Asset Retirement Obligations and Environmental Costs
Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal obligations involve removal and disposal of offshore oil and gas platforms around the world, oil and gas production facilities and pipelines in Alaska, and asbestos abatement at refineries. The fair values of obligations for dismantling and removing these facilities are accrued at the installation of the asset based on estimated discounted costs. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations,

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expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.
In addition, under the above or similar contracts, permits and regulations, we have certain obligations to complete environmental-related projects. These projects are primarily related to cleanup at domestic refineries and remediation activities required by Canada and the state of Alaska at exploration and production sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties.
Business Acquisitions
Assets Acquired and Liabilities Assumed
Accounting for the acquisition of a business requires the recognition of the consideration paid, as well as the various assets and liabilities of the acquired business. For most assets and liabilities, the asset or liability is recorded at its estimated fair value. The most difficult estimates of individual fair values are those involving properties, plants and equipment and identifiable intangible assets. We use all available information to make these fair value determinations. We have, if necessary, up to one year after the acquisition closing date to finalize these fair value determinations.
Intangible Assets and Goodwill
At December 31, 2010, we had $739 million of intangible assets determined to have indefinite useful lives, thus they are not amortized. This judgmental assessment of an indefinite useful life must be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines these intangible assets have definite useful lives, amortization will have to commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to periodic lower-of-cost-or-market tests that require management’s judgment of the estimated fair value of these intangible assets.
In the fourth quarter of 2008, we fully impaired the recorded goodwill associated with our Worldwide E&P reporting unit. At December 31, 2010, we had $3,633 million of goodwill remaining on our balance sheet, all of which was attributable to the Worldwide R&M reporting unit. See Note 9—Goodwill and Intangibles, in the Notes to Consolidated Financial Statements, for additional information on intangibles and goodwill, including a detailed discussion of the facts and circumstances leading to the goodwill impairment, as well as the judgments required by management in the analysis leading to the impairment determination.
Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the statement of operations. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. For Employee Retirement Income Security Act-qualified pension plans, the actuary exercises fiduciary care on behalf of plan participants in the determination of the judgmental assumptions used in determining required company contributions into the plan. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A 1 percent decrease in the discount rate assumption would increase annual benefit expense by $130 million, while a 1 percent decrease in the return on plan assets assumption would increase annual benefit expense by $70 million. In determining the discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows of our plans.

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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by 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.
We based the forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:
    Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices, refining and marketing margins and margins for our chemicals business.
 
    Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.
 
    Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.
 
    Failure of new products and services to achieve market acceptance.
 
    Unexpected changes in costs or technical requirements for constructing, modifying or operating facilities for exploration and production, manufacturing, refining or transportation projects.
 
    Unexpected technological or commercial difficulties in manufacturing, refining or transporting our products, including chemicals products.
 
    Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, bitumen, LNG and refined products.
 
    Inability to timely obtain or maintain permits, including those necessary for construction of LNG terminals or regasification facilities, or refinery projects; comply with government regulations; or make capital expenditures required to maintain compliance.
 
    Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future exploration and production, LNG, refinery and transportation projects.
 
    Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events or terrorism.
 
    International monetary conditions and exchange controls.
 
    Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.
 
    Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.
 
    Liability resulting from litigation.
 
    General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG, natural gas liquids or refined product pricing, regulation or taxation; other political, economic or diplomatic developments; and international monetary fluctuations.
 
    Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business.
 
    Limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets.
 
    Delays in, or our inability to implement, our asset disposition plan.
 
    Inability to obtain economical financing for projects, construction or modification of facilities and general corporate purposes.

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    The operation and financing of our midstream and chemicals joint ventures.
 
    The factors generally described in Item 1A—Risk Factors in this report.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Financial Instrument Market Risk
We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash flows or earnings to changes in commodity prices, foreign currency exchange rates or interest rates. We may use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of electric power, natural gas, crude oil and related products; fluctuations in interest rates and foreign currency exchange rates; or to capture market opportunities.
Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of Directors that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient liquidity for comparable valuations. The Authority Limitations document also establishes the Value at Risk (VaR) limits for the company, and compliance with these limits is monitored daily. The Chief Financial Officer monitors risks resulting from foreign currency exchange rates and interest rates and reports to the Chief Executive Officer. The Senior Vice President of Refining, Marketing and Transportation and Commercial monitors commodity price risk and also reports to the Chief Executive Officer. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, and monitors related risks of our upstream and downstream businesses.
Commodity Price Risk
We operate in the worldwide crude oil, bitumen, refined products, natural gas, natural gas liquids, LNG and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities.
Our Commercial organization uses futures, forwards, swaps and options in various markets to optimize the value of our supply chain, which may move our risk profile away from market average prices to accomplish the following objectives:
    Balance physical systems. In addition to cash settlement prior to contract expiration, exchange-traded futures contracts also may be settled by physical delivery of the commodity, providing another source of supply to meet our refinery requirements or marketing demand.
 
    Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we use swap contracts to convert fixed-price sales contracts, which are often requested by natural gas and refined product consumers, to a floating market price.
 
    Manage the risk to our cash flows from price exposures on specific crude oil, natural gas, refined product and electric power transactions.
 
    Enable us to use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades. Derivatives may be utilized to optimize these activities.
We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative commodity instruments held or issued, including commodity purchase and sales contracts recorded on the balance sheet at December 31, 2010, as derivative instruments. Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period, the VaR for those instruments issued or held for trading purposes at December 31, 2010 and 2009, was immaterial to our cash flows and net income attributable to ConocoPhillips.

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The VaR for instruments held for purposes other than trading at December 31, 2010 and 2009, was also immaterial to our cash flows and net income attributable to ConocoPhillips.
Interest Rate Risk
The following table provides information about our financial instruments that are sensitive to changes in U.S. interest rates. The debt portion of the table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at the reporting date. The carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices. The joint venture acquisition obligation portion of the table presents principal cash flows of the fixed-rate 5.3 percent joint venture acquisition obligation owed to FCCL Partnership. The fair value of the obligation is estimated based on the net present value of the future cash flows, discounted at a year-end 2010 and 2009 effective yield rate of 2.33 percent and 2.63 percent, respectively, based on yields of U.S. Treasury securities of a similar average duration adjusted for ConocoPhillips’ average credit risk spread and the amortizing nature of the obligation principal.
                                                 
    Millions of Dollars Except as Indicated  
                                    Joint Venture  
    Debt     Acquisition Obligation  
    Fixed     Average     Floating     Average     Fixed     Average  
Expected   Rate     Interest     Rate     Interest     Rate     Interest  
Maturity Date   Maturity     Rate     Maturity     Rate     Maturity     Rate  
Year-End 2010
                                               
2011
  $ 853       7.62 %   $ -       - %   $ 695       5.30 %
2012
    916       4.80       1,185       0.51       732       5.30  
2013
    1,262       5.33       -       -       772       5.30  
2014
    1,513       4.77       -       -       814       5.30  
2015
    1,514       4.62       64       2.05       858       5.30  
Remaining years
    15,291       6.44       498       0.38       1,138       5.30  
 
Total
  $ 21,349             $ 1,747             $ 5,009          
 
Fair value
  $ 24,397             $ 1,747             $ 5,600          
 
 
                                               
Year-End 2009
                                               
2010
  $ 1,439       8.82 %   $ -       - %   $ 660       5.30 %
2011
    3,183       6.72       750       0.45       695       5.30  
2012
    1,264       4.94       1,303       0.25       732       5.30  
2013
    1,262       5.33       -       -       772       5.30  
2014
    1,513       4.77       3       2.01       814       5.30  
Remaining years
    16,805       6.28       598       0.61       1,996       5.30  
 
Total
  $ 25,466             $ 2,654             $ 5,669          
 
Fair value
  $ 27,911             $ 2,654             $ 6,276          
 
During the second quarter of 2010, we executed interest rate swaps to synthetically convert $500 million of our 4.60% fixed-rate notes due in 2015 to a floating rate based on the London Interbank Offered Rate (LIBOR). These swaps qualify for and are designated as fair-value hedges using the short-cut method of hedge accounting. The short-cut method permits the assumption that changes in the value of the derivative perfectly offset changes in the value of the debt; therefore, no gain or loss has been recognized due to hedge ineffectiveness.

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The average pay rate is comprised of the LIBOR index rate and the swap spread. The swap spread consists primarily of the difference between the 4.60% fixed receive rate and the fixed rates for similar instruments at the time of execution.
                         
    Millions of Dollars Except as Indicated  
    Interest Rate Derivatives  
            Average     Average  
Expected Maturity Date   Notional     Pay Rate     Receive Rate  
Year-End 2010
                       
2011–2015
  $ -       - %     - %
2015–fixed to variable
    500       2.33       4.60  
Remaining years
    -       -       -  
 
Total
  $ 500                  
 
Fair Value
  $ 20                  
 
Foreign Currency Exchange Risk
We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to currency rate changes although we may choose to selectively hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends and cash returns from net investments in foreign affiliates to be remitted within the coming year.
At December 31, 2010 and 2009, we held foreign currency exchange forwards hedging cross-border commercial activity and foreign currency exchange swaps hedging short-term intercompany loans between European subsidiaries and a U.S. subsidiary. Although these forwards and swaps hedge exposures to fluctuations in exchange rates, we elected not to utilize hedge accounting. As a result, the change in the fair value of these foreign currency exchange derivatives is recorded directly in earnings. Since the gain or loss on the swaps is offset by the gain or loss from remeasuring the intercompany loans into the functional currency of the lender or borrower, and since our aggregate position in the forwards was not material, there would be no material impact to our income from an adverse hypothetical 10 percent change in the December 31, 2010 or 2009, exchange rates. The notional and fair market values of these positions at December 31, 2010 and 2009, were as follows:
                                     
    In Millions  
Foreign Currency Exchange Derivatives   Notional*     Fair Market Value**  
    2010     2009     2010     2009  
       
Sell U.S. dollar, buy euro
  USD     -       246     $ -       (2 )
Sell U.S. dollar, buy British pound
  USD     4       1,664       (3 )     (16 )
Sell U.S. dollar, buy Canadian dollar
  USD     562       554       8       34  
Sell U.S. dollar, buy Norwegian kroner
  USD     3       744       -       (4 )
Sell U.S. dollar, buy Australian dollar
  USD     -       3       -       -  
Sell euro, buy British pound
  EUR     253       267       1       (14 )
 
   *Denominated in U.S. dollars (USD) and euro (EUR).
**Denominated in U.S. dollars.
For additional information about our use of derivative instruments, see Note 16—Financial Instruments and Derivative Contracts, in the Notes to Consolidated Financial Statements.

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Item 8.       FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
INDEX TO FINANCIAL STATEMENTS
     
    Page
  70
 
   
  71
 
   
  72
 
   
  73
 
   
  74
 
   
  75
 
   
  76
 
   
  77
 
   
Supplementary Information
   
 
   
  137
 
   
  165
 
   
  166

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Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.
Assessment of Internal Control Over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2010. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework . Based on our assessment, we believe the company’s internal control over financial reporting was effective as of December 31, 2010.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2010, and their report is included herein.
     
 
   
 
   
/s/ James J. Mulva
  /s/ Jeff W. Sheets
 
   
James J. Mulva
  Jeff W. Sheets
Chairman and
  Senior Vice President, Finance
Chief Executive Officer
  and Chief Financial Officer
February 23, 2011

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Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
The Board of Directors and Stockholders
ConocoPhillips
We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the related condensed consolidating financial information listed in the Index at Item 8 and financial statement schedule listed in Item 15(a). These financial statements, condensed consolidating financial information, and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements, condensed consolidating financial information, and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of ConocoPhillips at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related condensed consolidating financial information and financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, in 2010 ConocoPhillips changed the method used to determine its equity method share of LUKOIL’s earnings. In addition, as discussed in Note 2, in 2009 ConocoPhillips changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), ConocoPhillips’ internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2011 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 23, 2011

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Report of Independent Registered Public Accounting Firm on
Internal Control Over Financial Reporting
The Board of Directors and Stockholders
ConocoPhillips
We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). ConocoPhillips’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Report of Management.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, ConocoPhillips maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2010 consolidated financial statements of ConocoPhillips and our report dated February 23, 2011 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 23, 2011

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Consolidated Statement of Operations   ConocoPhillips     
                         
Years Ended December 31   Millions of Dollars  
    2010     2009 **   2008 **
Revenues and Other Income
                       
Sales and other operating revenues*
  $ 189,441       149,341       240,842  
Equity in earnings of affiliates
    3,133       2,531       4,999  
Gain on dispositions
    5,803       160       891  
Other income
    278       358       199  
 
Total Revenues and Other Income
    198,655       152,390       246,931  
 
Costs and Expenses
                       
Purchased crude oil, natural gas and products
    135,751       102,433       168,663  
Production and operating expenses
    10,635       10,339       11,818  
Selling, general and administrative expenses
    2,005       1,830       2,229  
Exploration expenses
    1,155       1,182       1,337  
Depreciation, depletion and amortization
    9,060       9,295       9,012  
Impairments
                       
Goodwill
    -       -       25,443  
LUKOIL investment
    -       -       7,496  
Other
    1,780       535       1,686  
Taxes other than income taxes*
    16,793       15,529       20,637  
Accretion on discounted liabilities
    447       422       418  
Interest and debt expense
    1,187       1,289       935  
Foreign currency transaction (gains) losses
    92       (46 )     117  
 
Total Costs and Expenses
    178,905       142,808       249,791  
 
Income (loss) before income taxes
    19,750       9,582       (2,860 )
Provision for income taxes
    8,333       5,090       13,419  
 
Net income (loss)
    11,417       4,492       (16,279 )
Less: net income attributable to noncontrolling interests
    (59 )     (78 )     (70 )
 
Net Income (Loss) Attributable to ConocoPhillips
  $ 11,358       4,414       (16,349 )
 
 
                       
Net Income (Loss) Attributable to ConocoPhillips Per Share of
Common Stock
(dollars)
                       
Basic
  $ 7.68       2.96       (10.73 )
Diluted
    7.62       2.94       (10.73 )
 
 
                       
Average Common Shares Outstanding (in thousands)
                       
Basic
    1,479,330       1,487,650       1,523,432  
Diluted
    1,491,067       1,497,608       1,523,432  
 
    *Includes excise taxes on petroleum products sales:
  $ 13,689       13,325       15,418  
  **Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information. Also, certain amounts have been reclassified to conform to current-year presentation.
See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet   ConocoPhillips     
                 
At December 31   Millions of Dollars  
    2010     2009 **
Assets
               
Cash and cash equivalents
  $ 9,454       542  
Short-term investments*
    973       -  
Accounts and notes receivable (net of allowance of $32 million in 2010
and $76 million in 2009)
    13,787       11,861  
Accounts and notes receivable—related parties
    2,025       1,354  
Investment in LUKOIL
    1,083       -  
Inventories
    5,197       4,940  
Prepaid expenses and other current assets
    2,141       2,470  
 
Total Current Assets
    34,660       21,167  
Investments and long-term receivables
    31,581       35,742  
Loans and advances—related parties
    2,180       2,352  
Net properties, plants and equipment
    82,554       87,708  
Goodwill
    3,633       3,638  
Intangibles
    801       823  
Other assets
    905       708  
 
Total Assets
  $ 156,314       152,138  
 
 
               
Liabilities
               
Accounts payable
  $ 16,613       14,168  
Accounts payable—related parties
    1,786       1,317  
Short-term debt
    936       1,728  
Accrued income and other taxes
    4,874       3,402  
Employee benefit obligations
    1,081       846  
Other accruals
    2,129       2,234  
 
Total Current Liabilities
    27,419       23,695  
Long-term debt
    22,656       26,925  
Asset retirement obligations and accrued environmental costs
    9,199       8,713  
Joint venture acquisition obligation—related party
    4,314       5,009  
Deferred income taxes
    17,335       17,956  
Employee benefit obligations
    3,683       4,130  
Other liabilities and deferred credits
    2,599       3,097  
 
Total Liabilities
    87,205       89,525  
 
 
               
Equity
               
Common stock (2,500,000,000 shares authorized at $.01 par value)
               
Issued (2010—1,740,529,279 shares; 2009—1,733,345,558 shares)
               
Par value
    17       17  
Capital in excess of par
    44,132       43,681  
Grantor trusts (at cost: 2010—36,890,375 shares; 2009—38,742,261 shares)
    (633 )     (667 )
Treasury stock (at cost: 2010—272,873,537 shares; 2009—208,346,815 shares)
    (20,077 )     (16,211 )
Accumulated other comprehensive income
    4,773       3,065  
Unearned employee compensation
    (47 )     (76 )
Retained earnings
    40,397       32,214  
 
Total Common Stockholders’ Equity
    68,562       62,023  
Noncontrolling interests
    547       590  
 
Total Equity
    69,109       62,613  
 
Total Liabilities and Equity
  $ 156,314       152,138  
 
    *Includes marketable securities of:
  $ 602       -  
**Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
See Notes to Consolidated Financial Statements.

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Consolidated Statement of Cash Flows   ConocoPhillips   
                         
Years Ended December 31   Millions of Dollars  
    2010     2009 *   2008 *
Cash Flows From Operating Activities
                       
Net income (loss)
  $ 11,417       4,492       (16,279 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities
                       
Depreciation, depletion and amortization
    9,060       9,295       9,012  
Impairments
    1,780       535       34,625  
Dry hole costs and leasehold impairments
    477       606       698  
Accretion on discounted liabilities
    447       422       418  
Deferred taxes
    (878 )     (1,115 )     (414 )
Undistributed equity earnings
    (1,073 )     (1,254 )     (2,357 )
Gain on dispositions
    (5,803 )     (160 )     (891 )
Other
    (249 )     196       (1,135 )
Working capital adjustments
                       
Decrease (increase) in accounts and notes receivable
    (2,427 )     (1,106 )     4,225  
Decrease (increase) in inventories
    (363 )     320       (1,321 )
Decrease (increase) in prepaid expenses and other current assets
    43       282       (724 )
Increase (decrease) in accounts payable
    2,887       1,612       (3,874 )
Increase (decrease) in taxes and other accruals
    1,727       (1,646 )     675  
 
Net Cash Provided by Operating Activities
    17,045       12,479       22,658  
 
 
                       
Cash Flows From Investing Activities
                       
Capital expenditures and investments
    (9,761 )     (10,861 )     (19,099 )
Proceeds from asset dispositions
    15,372       1,270       1,640  
Purchases of short-term investments
    (982 )     -       -  
Long-term advances/loans—related parties
    (313 )     (525 )     (163 )
Collection of advances/loans—related parties
    115       93       34  
Other
    234       88       (28 )
 
Net Cash Provided by (Used in) Investing Activities
    4,665       (9,935 )     (17,616 )
 
 
                       
Cash Flows From Financing Activities
                       
Issuance of debt
    118       9,087       7,657  
Repayment of debt
    (5,320 )     (7,858 )     (1,897 )
Issuance of company common stock
    133       13       198  
Repurchase of company common stock
    (3,866 )     -       (8,249 )
Dividends paid on company common stock
    (3,175 )     (2,832 )     (2,854 )
Other
    (709 )     (1,265 )     (619 )
 
Net Cash Used in Financing Activities
    (12,819 )     (2,855 )     (5,764 )
 
 
                       
Effect of Exchange Rate Changes on Cash and Cash Equivalents
    21       98       21  
 
 
                       
Net Change in Cash and Cash Equivalents
    8,912       (213 )     (701 )
Cash and cash equivalents at beginning of year
    542       755       1,456  
 
Cash and Cash Equivalents at End of Year
  $ 9,454       542       755  
 
*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
See Notes to Consolidated Financial Statements.

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Consolidated Statement of Changes in Equity   ConocoPhillips   
                                                                                 
    Millions of Dollars  
    Attributable to ConocoPhillips              
    Common Stock     Accum. Other     Unearned                          
    Par     Capital in     Treasury     Grantor     Comprehensive     Employee     Retained     Comprehensive     Noncontrolling        
    Value     Excess of Par     Stock     Trusts     Income (Loss)     Compensation     Earnings     Income (Loss)     Interests     Total  
 
                                                                               
December 31, 2007*
  $ 17       42,724       (7,969 )     (731 )     4,560       (128 )     49,861               1,173       89,507  
 
                                                                           
Net income (loss)
                                                    (16,349 )     (16,349 )     70       (16,279 )
Other comprehensive income (loss)
                                                                               
Defined benefit pension plans
                                                                               
Net prior service cost
                                    22                       22               22  
Net actuarial loss
                                    (950 )                     (950 )             (950 )
Nonsponsored plans
                                    (41 )                     (41 )             (41 )
Foreign currency translation adjustments
                                    (5,464 )                     (5,464 )             (5,464 )
Hedging activities
                                    (2 )                     (2 )             (2 )
 
                                                                         
Comprehensive income (loss)
                                                            (22,784 )     70       (22,714 )
 
                                                                         
Cash dividends paid on company common stock
                                                    (2,854 )                     (2,854 )
Repurchase of company common stock
                    (8,242 )     1                                               (8,241 )
Distributions to noncontrolling interests and other
                                                                    (143 )     (143 )
Distributed under benefit plans
            672               28                                               700  
Recognition of unearned compensation
                                            26                               26  
Other
                                                    (16 )                     (16 )
 
December 31, 2008*
    17       43,396       (16,211 )     (702 )     (1,875 )     (102 )     30,642               1,100       56,265  
 
                                                                           
Net income
                                                    4,414       4,414       78       4,492  
Other comprehensive income (loss)
                                                                               
Defined benefit pension plans
                                                                               
Net prior service cost
                                    7                       7               7  
Net actuarial loss
                                    (99 )                     (99 )             (99 )
Nonsponsored plans
                                    22                       22               22  
Foreign currency translation adjustments
                                    5,007                       5,007               5,007  
Hedging activities
                                    3                       3               3  
 
                                                                         
Comprehensive income
                                                            9,354       78       9,432  
 
                                                                         
Cash dividends paid on company common stock
                                                    (2,832 )                     (2,832 )
Distributions to noncontrolling interests and other
                                                                    (588 )     (588 )
Distributed under benefit plans
            285               35                                               320  
Recognition of unearned compensation
                                            26                               26  
Other
                                                    (10 )                     (10 )
 
December 31, 2009*
    17       43,681       (16,211 )     (667 )     3,065       (76 )     32,214               590       62,613  
 
                                                                           
Net income
                                                    11,358       11,358       59       11,417  
Other comprehensive income (loss)
                                                                               
Defined benefit pension plans
                                                                               
Net prior service cost
                                    -                       -               -  
Net actuarial gain
                                    133                       133               133  
Nonsponsored plans
                                    13                       13               13  
Net unrealized gain on securities
                                    158                       158               158  
Foreign currency translation adjustments
                                    1,404                       1,404               1,404  
 
                                                                         
Comprehensive income
                                                            13,066       59       13,125  
 
                                                                         
Cash dividends paid on company common stock
                                                    (3,175 )                     (3,175 )
Repurchase of company common stock
                    (3,866 )                                                     (3,866 )
Distributions to noncontrolling interests and other
                                                                    (102 )     (102 )
Distributed under benefit plans
            451               34                                               485  
Recognition of unearned compensation
                                            29                               29  
 
December 31, 2010
  $ 17       44,132       (20,077 )     (633 )     4,773       (47 )     40,397               547       69,109  
 
*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements   ConocoPhillips
Note 1—Accounting Policies
n   Consolidation Principles and Investments— Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence, the investment is either classified as available-for-sale if fair value is readily determinable, or the cost method is used if fair value is not readily determinable. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost.
n   Foreign Currency Translation— Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive income in common stockholders’ equity. Foreign currency transaction gains and losses are included in current earnings. Most of our foreign operations use their local currency as the functional currency.
n   Use of Estimates— The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.
n   Revenue Recognition— Revenues associated with sales of crude oil, bitumen, natural gas, liquefied natural gas (LNG), natural gas liquids, petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.
    Revenues associated with producing properties in which we have an interest with other producers are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be nonrecoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.
    Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into “in contemplation” of one another, are combined and reported net (i.e., on the same statement of operations line).
n   Shipping and Handling Costs— Our Exploration and Production (E&P) segment includes shipping and handling costs in production and operating expenses for production activities. Transportation costs related to E&P marketing activities are recorded in purchased crude oil, natural gas and products. The Refining and Marketing (R&M) segment records shipping and handling costs in purchased crude oil, natural gas and products. Freight costs billed to customers are recorded as a component of revenue.
n   Cash Equivalents— Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have original maturities of 90 days or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value.
n   Short-Term Investments —Investments in bank time deposits and marketable securities (commercial paper and government obligations) with original maturities of greater than 90 days but less than one year

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    are classified as short-term investments. See Note 16—Financial Instruments and Derivative Contracts, for additional information on these held-to-maturity financial instruments.
n   Inventories— We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. Crude oil and petroleum products inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues and to meet tax-conformity requirements. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/nonrecurring costs or research and development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and well equipment, are valued under various methods, including the weighted-average-cost method, and the first-in, first-out (FIFO) method, consistent with industry practice.
n   Fair Value Measurements— We categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.
n   Derivative Instruments— Derivative instruments are recorded on the balance sheet at fair value. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the balance sheet and the collateral payable or receivable is netted against derivative assets and derivative liabilities, respectively.
    Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives not accounted for as hedges are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge or hedge of a net investment in a foreign entity are recognized in other comprehensive income and appear on the balance sheet in accumulated other comprehensive income until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses will be recognized immediately in earnings.
n   Oil and Gas Exploration and Development— Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.
    Property Acquisition Costs— Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption properties, plants and equipment. Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of all conditions necessary for reserves to be classified as proved, the associated leasehold costs are reclassified to proved properties.
    Exploratory Costs— Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the

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    potential oil and gas field or while we seek government or co-venturer approval of development plans or seek environmental permitting. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas resources are designated as proved reserves.
    Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as dry holes when it judges the potential field does not warrant further investment in the near term. See Note 8—Suspended Wells, for additional information on suspended wells.
    Development Costs— Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.
    Depletion and Amortization— Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves.
n   Capitalized Interest— Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.
n   Intangible Assets Other Than Goodwill— Intangible assets that have finite useful lives are amortized by the straight-line method over their useful lives. Intangible assets that have indefinite useful lives are not amortized but are tested at least annually for impairment. Each reporting period, we evaluate the remaining useful lives of intangible assets not being amortized to determine whether events and circumstances continue to support indefinite useful lives. These indefinite lived intangibles are considered impaired if the fair value of the intangible asset is lower than net book value. The fair value of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable.
n   Goodwill— Goodwill resulting from a business combination is not amortized but is tested at least annually for impairment. If the fair value of a reporting unit is less than the recorded book value of the reporting unit’s assets (including goodwill), less liabilities, then a hypothetical purchase price allocation is performed on the reporting unit’s assets and liabilities using the fair value of the reporting unit as the purchase price in the calculation. If the amount of goodwill resulting from this hypothetical purchase price allocation is less than the recorded amount of goodwill, the recorded goodwill is written down to the new amount. For purposes of goodwill impairment calculations, two reporting units have been determined: Worldwide Exploration and Production and Worldwide Refining and Marketing.
n   Depreciation and Amortization— Depreciation and amortization of properties, plants and equipment on producing hydrocarbon properties and certain pipeline assets (those which are expected to have a declining utilization pattern), are determined by the unit-of-production method. Depreciation and amortization of all other properties, plants and equipment are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).
n   Impairment of Properties, Plants and Equipment— Properties, plants and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group and annually in the fourth quarter following updates to corporate planning assumptions. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and

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    reported as impairments in the periods in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets, or at an entire complex level for downstream assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.
    The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices and costs, considering all available evidence at the date of review. If the future production price risk has been hedged, the hedged price is used in the calculations for the period and quantities hedged. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation.
n   Impairment of Investments in Nonconsolidated Entities— Investments in nonconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred and annually following updates to corporate planning assumptions. When such a condition is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.
n   Maintenance and Repairs— Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.
n   Advertising Costs— Production costs of media advertising are deferred until the first public showing of the advertisement. Advances to secure advertising slots at specific sporting or other events are deferred until the event occurs. All other advertising costs are expensed as incurred, unless the cost has benefits that clearly extend beyond the interim period in which the expenditure is made, in which case the advertising cost is deferred and amortized ratably over the interim periods that clearly benefit from the expenditure.
n   Property Dispositions— When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Gain on dispositions” line of our consolidated statement of operations. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.
n   Asset Retirement Obligations and Environmental Costs— Fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related properties, plants and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties, plants and equipment is depreciated over the useful life of the related asset. See Note 11—Asset Retirement Obligations and Accrued Environmental Costs, for additional information.

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    Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have a future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as assets when their receipt is probable and estimable.
n   Guarantees— Fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information that the liability is essentially relieved or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to the related statement of operations line item based on the nature of the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.
n   Stock-Based Compensation— We recognize stock-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award) or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement. We have elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.
n   Income Taxes— Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial reporting basis and the tax basis of our assets and liabilities, except for deferred taxes on income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes. Interest related to unrecognized tax benefits is reflected in interest expense, and penalties in production and operating expenses.
n   Taxes Collected from Customers and Remitted to Governmental Authorities— Excise taxes are reported gross within sales and other operating revenues and taxes other than income taxes, while other sales and value-added taxes are recorded net in taxes other than income taxes.
n   Net Income (Loss) Per Share of Common Stock— Basic net income (loss) per share of common stock is calculated based upon the daily weighted-average number of common shares outstanding during the year, including unallocated shares held by the stock savings feature of the ConocoPhillips Savings Plan. Also, this calculation includes fully vested stock and unit awards that have not been issued. Diluted net income per share of common stock includes the above, plus unvested stock, unit or option awards granted under our compensation plans and vested but unexercised stock options, but only to the extent these instruments dilute net income per share. For the purpose of the 2009 earnings per share calculation, net income attributable to ConocoPhillips was reduced by $12 million for the excess of the amount paid for the redemption of a noncontrolling interest over its carrying value, which was charged directly to retained earnings. Diluted net loss per share in 2008 is calculated the same as basic net loss per share—that is, it does not assume conversion or exercise of securities, totaling 17,354,959 shares in 2008 that would have an anti-dilutive effect. Treasury stock and shares held by the grantor trusts are excluded from the daily weighted-average number of common shares outstanding in both calculations.

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Note 2—Changes in Accounting Principles
LUKOIL Accounting
Effective January 1, 2010, we changed the method used to determine our equity-method share of OAO LUKOIL’s earnings. Prior to 2010, we estimated our LUKOIL equity earnings for the current quarter based on current market indicators, publicly available LUKOIL information and other objective data. This earnings estimation process was necessary because, historically, LUKOIL’s accounting cycle close and preparation of U.S. generally accepted accounting principles financial statements occurred subsequent to our reporting deadline, and for certain periods this timing gap exceeded 93 days. Although Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 323, “Investments—Equity Method and Joint Ventures,” provides that when financial statements of an investee are not sufficiently timely, then the investor should record its share of earnings or loss based on the most recently available financial statements, U.S. Securities and Exchange Commission (SEC) guidance indicates this timing gap generally should not exceed 93 days. When the timing gap was reduced to less than 93 days for all reporting periods, we believed it was preferable to implement a change in accounting principle to record our equity-method share of LUKOIL’s earnings on a one-quarter-lag basis, because it improves reporting reliability, while maintaining an acceptable level of relevance.
The following table summarizes the line items affected on the consolidated statement of operations for year ended December 31, 2010:
                         
    Millions of Dollars  
    Computed with     As Reported     Effect of  
    Estimate     with Lag     Change  
 
                       
Equity in earnings of affiliates
  $ 2,951       3,133       182  
Gain on dispositions
    5,593       5,803       210  
Provision for income taxes
    8,343       8,333       (10 )
Net income
    11,015       11,417       402  
Net income attributable to ConocoPhillips
    10,956       11,358       402  
 
 
                       
Net income attributable to ConocoPhillips per share of
common stock (dollars)
                       
Basic
  $ 7.41       7.68       .27  
Diluted
    7.35       7.62       .27  
 
The following table summarizes the line items affected on the consolidated balance sheet at December 31, 2010:
                         
    Millions of Dollars  
    Computed with     As Reported     Effect of  
    Estimate     with Lag     Change  
 
                       
Accrued income and other taxes
  $ 4,865       4,874       9  
Accumulated other comprehensive income
    4,741       4,773       32  
Retained earnings
    40,438       40,397       (41 )
 

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The following table summarizes the line items affected on the 2010 consolidated statement of cash flows for year ended December 31, 2010:
                         
    Millions of Dollars  
    Computed with     As Reported     Effect of  
    Estimate     with Lag     Change  
 
                       
Net income
  $ 11,015       11,417       402  
Deferred taxes
    (868 )     (878 )     (10 )
Undistributed equity earnings
    (891 )     (1,073 )     (182 )
Gain on dispositions
    (5,593 )     (5,803 )     (210 )
 
This change in accounting principle to a one-quarter lag under ASC Topic 323 has been applied retrospectively, by recasting prior period financial information. The following table summarizes the line items affected on the consolidated statement of operations for years ended December 31:
                                                 
    Millions of Dollars  
    2009     2008  
    As             Effect     As             Effect  
    Originally     As     of     Originally     As     of  
    Reported     Adjusted     Change     Reported     Adjusted     Change  
 
                                               
Equity in earnings of affiliates
  $ 2,981       2,531       (450 )     4,250       4,999       749  
Impairment LUKOIL investment
    -       -       -       7,410       7,496       86  
Provision for income taxes
    5,096       5,090       (6 )     13,405       13,419       14  
Net income (loss)
    4,936       4,492       (444 )     (16,928 )     (16,279 )     649  
Net income (loss) attributable to ConocoPhillips
    4,858       4,414       (444 )     (16,998 )     (16,349 )     649  
 
 
                                               
Net income (loss) attributable to ConocoPhillips per share of common stock (dollars)
                                               
Basic
  $ 3.26       2.96       (.30 )     (11.16 )     (10.73 )     .43  
Diluted
    3.24       2.94       (.30 )     (11.16 )     (10.73 )     .43  
 
The following table summarizes the line items affected on the consolidated balance sheet at December 31, 2009:
                         
    Millions of Dollars  
    As Originally     As Reported     Effect of  
    Reported     with Lag     Change  
 
                       
Investments and long-term receivables
  $ 36,192       35,742       (450 )
Deferred income taxes
    17,962       17,956       (6 )
Retained earnings
    32,658       32,214       (444 )
 
The cumulative impact to retained earnings as of January 1, 2008, was a decrease of $649 million as a result of the accounting change.

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The following table summarizes the line items affected on the consolidated statement of cash flows for years ended December 31:
                                                 
    Millions of Dollars  
    2009     2008  
    As             Effect     As             Effect  
    Originally     As     of     Originally     As     of  
    Reported     Adjusted     Change     Reported     Adjusted     Change  
 
                                               
Net income (loss)
  $ 4,936       4,492       (444 )     (16,928 )     (16,279 )     649  
Impairments
    535       535       -       34,539       34,625       86  
Deferred taxes
    (1,109 )     (1,115 )     (6 )     (428 )     (414 )     14  
Undistributed equity earnings
    (1,704 )     (1,254 )     450       (1,609 )     (2,357 )     (748 )
Other
    196       196       -       (1,134 )     (1,135 )     (1 )
 
See Note 6—Investments, Loans and Long-Term Receivables, for additional information relating to our LUKOIL investment.
Transfers of Financial Assets
In June 2009, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140,” which was codified into FASB ASC Topic 860, “Transfers and Servicing.” This Statement removed the concept of a qualifying special purpose entity (SPE) and the exception for qualifying SPEs from the consolidation guidance. Additionally, the Statement clarified the requirements for financial asset transfers eligible for sale accounting. This Statement was effective January 1, 2010, and did not impact our consolidated financial statements.
Variable Interest Entities (VIEs)
Also in June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” to address the effects of the elimination of the qualifying SPE concept in SFAS No. 166, and other concerns about the application of key provisions of consolidation guidance for VIEs. This Statement was codified into FASB ASC Topic 810, “Consolidation.” More specifically, Topic 810 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a VIE, it amended certain guidance pertaining to the determination of the primary beneficiary when related parties are involved, and it amended certain guidance for determining whether an entity is a VIE. Additionally, this Statement requires continuous assessments of whether an enterprise is the primary beneficiary of a VIE. This Statement was effective January 1, 2010, and its adoption did not impact our consolidated financial statements, other than the required disclosures. For additional information, see Note 3—Variable Interest Entities (VIEs).
Reserve Estimation and Disclosures
In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-03, “Oil and Gas Reserve Estimation and Disclosures.” This ASU amended the FASB’s ASC Topic 932, “Extractive Activities—Oil and Gas” to align the accounting requirements of Topic 932 with the SEC’s final rule, “Modernization of the Oil and Gas Reporting Requirements” issued on December 31, 2008. In summary, the revisions in ASU 2010-03 modernized the disclosure rules to better align with current industry practices and expanded the disclosure requirements for equity method investments so that more useful information is provided. More specifically, the main provisions include the following:
    An expanded definition of oil and gas producing activities to include nontraditional resources such as bitumen extracted from oil sands.
 
    The use of an average of the first-day-of-the-month price for the 12-month period, rather than a year-end price for determining whether reserves can be produced economically.
 
    Amended definitions of key terms such as “reliable technology” and “reasonable certainty” which are used in estimating proved oil and gas reserve quantities.

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    A requirement for disclosing separate information about reserve quantities and financial statement amounts for geographical areas representing 15 percent or more of proved reserves.
 
    Clarification that an entity’s equity investments must be considered in determining whether it has significant oil and gas activities and a requirement to disclose equity method investments in the same level of detail as is required for consolidated investments.
This ASU is effective for annual reporting periods ended on or after December 31, 2009, and it requires (1) the effect of the adoption to be included within each of the dollar amounts and quantities disclosed, (2) qualitative and quantitative disclosure of the estimated effect of adoption on each of the dollar amounts and quantities disclosed, if significant and practical to estimate and (3) the effect of adoption on the financial statements, if significant and practical to estimate. Adoption of these requirements did not significantly impact our reported reserves or our consolidated financial statements.
Business Combinations
In December 2007, the FASB issued SFAS No. 141 (Revised), “Business Combinations” (SFAS No. 141(R)), which was subsequently amended by FASB Staff Position (FSP) FAS 141(R)-1 in April 2009. This Statement was codified into FASB ASC Topic 805, “Business Combinations.” Topic 805 applies prospectively to all transactions in which an entity obtains control of one or more other businesses on or after January 1, 2009. In general, Topic 805 requires the acquiring entity in a business combination to recognize the fair value of all assets acquired and liabilities assumed in the transaction; establishes the acquisition date as the fair value measurement point; and modifies disclosure requirements. It also modifies the accounting treatment for transaction costs, in-process research and development, restructuring costs, changes in deferred tax asset valuation allowances as a result of a business combination, and changes in income tax uncertainties after the acquisition date. Additionally, effective January 1, 2009, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations impact tax expense instead of goodwill.
Noncontrolling Interests
Effective January 1, 2009, we implemented SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51.” This Statement was codified into FASB ASC Topic 810, “Consolidation.” Topic 810 requires noncontrolling interests, previously called minority interests, to be presented as a separate item in the equity section of the consolidated balance sheet. It also requires the amount of consolidated net income attributable to noncontrolling interests to be clearly presented on the face of the consolidated statement of operations. Additionally, Topic 810 clarified that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions, and that deconsolidation of a subsidiary requires gain or loss recognition in net income based on the fair value on the deconsolidation date. Topic 810 was applied prospectively with the exception of presentation and disclosure requirements, which were applied retrospectively for all periods presented, and did not significantly change the presentation of our consolidated financial statements. FASB ASU No. 2010-02, “Accounting and Reporting for Decreases in Ownership of a Subsidiary—a Scope Clarification,” clarified the decrease in ownership provision of Topic 810 applies to a group of assets or a subsidiary that is a business, but was not applicable to sales of in-substance real estate, or conveyances of oil and gas mineral rights.
Derivatives
Effective January 1, 2009, we implemented SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB No. 133.” This Statement was codified into FASB ASC Topic 815, “Derivatives and Hedging.” The amendments to Topic 815 expanded disclosure requirements to provide greater transparency for derivative instruments. In addition, we now must include an indication of the volume of derivative activity by category (e.g., interest rate, commodity and foreign currency); derivative assets, liabilities, gains and losses, by category, for the periods presented in the financial statements; and expanded disclosures about credit-risk-related contingent features. See Note 16—Financial Instruments and Derivative Contracts, for additional information.

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Fair Value Measurement
Effective January 1, 2008, we implemented SFAS No. 157, “Fair Value Measurements.” This Statement was codified primarily into FASB ASC Topic 820, “Fair Value Measurements and Disclosures.” This Topic defined fair value, established a framework for its measurement and expanded disclosures about fair value measurements. We elected to implement this guidance with the one-year deferral permitted for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). Following the allowed one-year deferral, effective January 1, 2009, we implemented Topic 820 for nonfinancial assets and nonfinancial liabilities measured at fair value on a nonrecurring basis. The implementation covers assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment, intangible assets and goodwill; initial recognition of asset retirement obligations; and restructuring costs for which we use fair value. There was no impact to our consolidated financial statements from the implementation of this Topic for nonfinancial assets and liabilities, other than additional disclosures.
Equity Method Accounting
In November 2008, the FASB reached a consensus on Emerging Issues Task Force (EITF) Issue No. 08-6, “Equity Method Investment Accounting Considerations” (EITF 08-6). EITF 08-6 was codified into FASB ASC Topic 323, “Investments—Equity Method and Joint Ventures.” EITF 08-6 was issued to clarify how the application of equity method accounting is affected by SFAS No. 141(R) and SFAS No. 160. Topic 323 clarified that an entity shall continue to use the cost accumulation model for its equity method investments. It also confirmed past accounting practices related to the treatment of contingent consideration and the use of the impairment model under Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” Additionally, it requires an equity method investor to account for a share issuance by an investee as if the investor had sold a proportionate share of the investment. This Topic was effective January 1, 2009, and applies prospectively. The adoption did not impact our consolidated financial statements.
Postretirement Benefit Plan Assets
In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” to improve the transparency associated with disclosures about the plan assets of a defined benefit pension or other postretirement plan. This Statement was codified into FASB ASC Topic 715, “Compensation—Retirement Benefits.” Topic 715 requires the disclosure of each major asset class at fair value using the fair value hierarchy in SFAS No. 157, “Fair Value Measurements.” This Topic is effective for annual financial statements beginning with the 2009 fiscal year, but did not impact our consolidated financial statements, other than requiring additional disclosures. For more information on this disclosure, see Note 19—Employee Benefit Plans.
Note 3—Variable Interest Entities (VIEs)
We hold significant variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on these VIEs follows.
We have a 30 percent ownership interest with a 50 percent governance interest in the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the Timan-Pechora province of Russia. The NMNG joint venture is a VIE because we and LUKOIL have disproportionate interests, and LUKOIL was a related party at inception of the joint venture. Since LUKOIL is no longer a related party, we do not believe NMNG would be a VIE if reconsidered today. LUKOIL owns 70 percent versus our 30 percent direct interest; therefore, we have determined we are not the primary beneficiary of NMNG, and we use the equity method of accounting for this investment. The funding of NMNG has been provided with equity contributions, primarily for the development of the Yuzhno Khylchuyu (YK) Field. At December 31, 2010, the book value of our investment in the venture was $735 million.

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We have an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in a liquefied natural gas (LNG) receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding as of December 31, 2010, was $653 million. Freeport LNG is a VIE because Freeport GP holds no equity in Freeport LNG, and the limited partners of Freeport LNG do not have any substantive decision making ability. We performed an analysis of the expected losses and determined we are not the primary beneficiary. This expected loss analysis took into account that the credit support arrangement requires Freeport LNG to maintain sufficient commercial insurance to mitigate any loan losses. The loan to Freeport LNG is accounted for as a financial asset, and our investment in Freeport GP is accounted for as an equity investment.
Note 4—Inventories
Inventories at December 31 were:
                 
    Millions of Dollars  
    2010     2009  
 
               
Crude oil and petroleum products
  $ 4,254       3,955  
Materials, supplies and other
    943       985  
 
 
  $ 5,197       4,940  
 
Inventories valued on the LIFO basis totaled $4,051 million and $3,747 million at December 31, 2010 and 2009, respectively. The excess of current replacement cost over LIFO cost of inventories amounted to $6,794 million and $5,627 million at December 31, 2010 and 2009, respectively.
Note 5—Assets Held for Sale
In the fourth quarter of 2009, we announced plans to raise approximately $10 billion from asset sales through the end of 2011. At December 31, 2009, we classified $323 million of Refining and Marketing (R&M) noncurrent assets, primarily investment in equity affiliates, and $75 million of R&M noncurrent deferred income tax liabilities as held for sale. During 2010, these assets and others were sold. While we continue to market and evaluate other assets for sale under this program that may be sold in 2011, we did not have significant assets meeting the criteria to be classified as held for sale as of December 31, 2010.
On June 25, 2010, we sold our 9.03 percent interest in the Syncrude Canada Ltd. joint venture for $4.6 billion. The $2.9 billion before-tax gain was included in the “Gain on dispositions” line of our consolidated statement of operations. The cash proceeds were included in the “Proceeds from asset dispositions” line within the investing cash flow section of our consolidated statement of cash flows. At the time of disposition, Syncrude had a net carrying value of $1.75 billion, which included $1.97 billion of properties, plants and equipment. During 2010 until its disposition, Syncrude contributed $327 million in intercompany sales and other operating revenues, and generated income before taxes of $127 million and net income of $93 million for the E&P segment.

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Note 6—Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
                 
    Millions of Dollars  
    2010     2009  
 
               
Equity investments*
  $ 30,055       34,280  
Loans and advances—related parties
    2,180       2,352  
Long-term receivables
    922       1,009  
Other investments
    604       453  
 
 
  $ 33,761       38,094  
 
*2009 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2010 include:
    Australia Pacific LNG—50 percent owned joint venture with Origin Energy—to develop coalbed methane production from the Bowen and Surat Basins in Queensland, Australia, as well as process and export LNG.
 
    FCCL Partnership—50 percent owned business venture with Cenovus Energy Inc.—produces bitumen in the Athabasca oil sands in northeastern Alberta and sells the bitumen blend.
 
    WRB Refining LP—50 percent owned business venture with Cenovus—owns the Wood River and Borger Refineries, which process crude oil into refined products.
 
    OOO Naryanmarneftegaz (NMNG)—30 percent ownership interest and a 50 percent governance interest—a joint venture with LUKOIL to explore for, develop and produce oil and gas resources in the northern part of Russia’s Timan-Pechora Province.
 
    DCP Midstream, LLC—50 percent owned joint venture with Spectra Energy—owns and operates gas plants, gathering systems, storage facilities and fractionation plants.
 
    Chevron Phillips Chemical Company LLC (CPChem)—50 percent owned joint venture with Chevron Corporation—manufactures and markets petrochemicals and plastics.
Summarized 100 percent financial information for equity method investments in affiliated companies, combined, was as follows (information includes LUKOIL until loss of significant influence):
                         
    Millions of Dollars  
    2010     2009     2008  
 
                       
Revenues
  $ 105,589       128,881       180,070  
Income before income taxes
    11,250       12,121       22,356  
Net income
    9,495       9,145       17,976  
Current assets
    14,039       36,139       34,838  
Noncurrent assets
    79,411       126,163       114,294  
Current liabilities
    9,325       22,483       21,150  
Noncurrent liabilities
    24,412       30,960       29,845  
 
Our share of income taxes incurred directly by the equity companies is reported in equity in earnings of affiliates, and as such is not included in income taxes in our consolidated financial statements.
At December 31, 2010, retained earnings included $1,991 million related to the undistributed earnings of affiliated companies.

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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, Australia Pacific LNG (APLNG), is focused on coalbed methane production from the Bowen and Surat Basins in Queensland, Australia, and LNG processing and export sales. This transaction gives us access to coalbed methane resources in Australia and enhances our LNG position with the expected creation of an additional LNG hub targeting the Asia Pacific markets.
Under the terms of our agreements with Origin Energy, we will potentially make up to four additional payments to Origin of $500 million each. The payments are conditional on up to four LNG trains being approved and developed by the joint venture and achievement of certain other financial and operating milestones.
At December 31, 2010, the book value of our equity method investment in APLNG was $9,159 million, which includes $3,244 million of cumulative translation effects due to a strengthening Australian dollar. Our 50 percent share of the historical cost basis net assets of APLNG on its books under U.S. generally accepted accounting principles (GAAP) was $1,187 million, resulting in a basis difference of $7,948 million on our books. The amortizable portion of the basis difference, $5,719 million associated with properties, plants and equipment, has been allocated on a relative fair value basis to individual exploration and production license areas owned by APLNG, most of which are not currently in production. Any future additional payments are expected to be allocated in a similar manner. Each exploration license area will periodically be reviewed for any indicators of potential impairment, which, if required, would result in acceleration of basis difference amortization. As the joint venture begins producing natural gas from each license, we amortize the basis difference allocated to that license using the unit-of-production method. Included in net income attributable to ConocoPhillips for 2010, 2009 and 2008 was after-tax expense of $5 million, $4 million and $7 million, respectively, representing the amortization of this basis difference on currently producing licenses.
FCCL and WRB
In January 2007, we closed on a business venture with Cenovus to create an integrated North American heavy oil business. The transaction consists of two 50/50 business ventures, a Canadian upstream general partnership, FCCL Partnership, and a U.S. downstream limited partnership, WRB Refining LP. We use the equity method of accounting for both entities, with the operating results of our investment in FCCL reflecting its use of the full-cost method of accounting for oil and gas exploration and development activities.
At December 31, 2010, the book value of our investment in FCCL was $8,674 million. FCCL’s operating assets consist of the Foster Creek and Christina Lake steam-assisted gravity drainage bitumen projects, both located in the eastern flank of the Athabasca oil sands in northeastern Alberta. Cenovus is the operator and managing partner of FCCL. We are obligated to contribute $7.5 billion, plus accrued interest, to FCCL over a 10-year period that began in 2007. For additional information on this obligation, see Note 13—Joint Venture Acquisition Obligation.
At December 31, 2010, the book value of our investment in WRB was $3,222 million. WRB’s operating assets consist of the Wood River and Borger Refineries, located in Roxana, Illinois, and Borger, Texas, respectively. As a result of our contribution of these two assets to WRB, a basis difference was created due to the fair value of the contributed assets recorded by WRB exceeding their historical book value. The difference is primarily amortized and recognized as a benefit evenly over a period of 26 years, which is the estimated remaining useful life of the refineries’ property, plant and equipment at the closing date. The basis difference at December 31, 2010, was $4,101 million. Equity earnings in 2010, 2009 and 2008 were increased by $243 million, $209 million and $246 million, respectively, due to amortization of the basis difference. We are the operator and managing partner of WRB. Cenovus is obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period that began in 2007. For the Wood River Refinery, operating results are shared 50/50 starting upon formation. For the Borger Refinery, we were entitled to 85 percent of the operating results in 2007, with our share decreasing to 65 percent in 2008, and 50 percent in all years thereafter.
LUKOIL
LUKOIL is an integrated energy company headquartered in Russia. Our ownership interest was 2.25 percent at December 31, 2010, and 20 percent at December 31, 2009 and 2008, based on 851 million shares authorized and issued. For financial reporting under U.S. GAAP, treasury shares held by LUKOIL are not considered

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outstanding for determining equity method ownership interest. Our ownership interest, based on estimated shares outstanding at December 31, 2009 and 2008, was 20.09 percent and 20.06 percent, respectively.
On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL, then consisting of 163.4 million shares. This decision was implemented as follows:
    On July 28, 2010, we entered into a stock purchase and option agreement (the Agreement) with a wholly owned subsidiary of LUKOIL, pursuant to which such subsidiary purchased 64.6 million shares from us at a price of $53.25 per share, or $3,442 million in total. This transaction closed on August 16, 2010.
 
    Also pursuant to the Agreement, the LUKOIL subsidiary had a 60-day option, expiring on September 26, 2010, to purchase any or all of our interest remaining at the time of exercise of the option, at a price of $56 per share. Upon exercise of this option, we sold 42.5 million shares on September 29, 2010, for proceeds of $2,380 million.
 
    Finally, we sold our remaining shares in the open market subject to the terms of the Shareholder Agreement, with the final disposition of all shares occurring in the first quarter of 2011.
During 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 applying the equity method of accounting for our remaining investment in LUKOIL, and we reclassified the investment from “Investments and long-term receivables” to current assets on our consolidated balance sheet as an available-for-sale equity security.
In total, during 2010, we sold 151 million shares of LUKOIL for $8,345 million, realizing a before-tax gain on disposition of $1,749 million, which was included in the “Gain on dispositions” line of our consolidated statement of operations. Included in these amounts are sales proceeds of $1,793 million and a realized before-tax gain of $437 million incurred subsequent to classifying the investment as available-for-sale. The cost basis for shares sold is average cost.
At December 31, 2010, our remaining investment in LUKOIL was carried at fair value of $1,083 million, reflecting a closing price of LUKOIL American Depositary Receipts (ADRs) on the London Stock Exchange of $56.50 per share. The carrying value reflects a pretax unrealized gain over our cost basis of $247 million. This unrealized gain, net of related income taxes, is reported as a component of accumulated other comprehensive income. The fair value is categorized as Level 1 in the fair value hierarchy.
Prior to 2010, our equity earnings for LUKOIL were estimated. Effective January 1, 2010, we changed our accounting to record our equity earnings for LUKOIL on a one-quarter-lag basis. See Note 2—Changes in Accounting Principles, for additional information about this change in accounting principle for our LUKOIL investment.
While applying the equity method of accounting, a negative basis difference existed which was primarily amortized on a straight-line basis over a 22-year useful life as an increase to equity earnings. Equity earnings in 2010 and 2009 were increased $155 million and $157 million, respectively, while equity earnings in 2008 were reduced $86 million due to amortization of the positive basis difference that existed prior to the 2008 year-end investment impairment discussed below.
Since the inception of our investment and through June 30, 2008, the market value of our investment in LUKOIL exceeded book value, based on the price of LUKOIL ADRs on the London Stock Exchange. However, the price of LUKOIL ADRs experienced significant decline during the second half of 2008, and traded for most of the fourth quarter and into early 2009 in the general range of $25 to $40 per share. The ADR price at year-end 2008 was $32.05 per share, or 67 percent lower than the June 30, 2008, price. This resulted in a December 31, 2008, market value of our investment of $5,452 million, or 58 percent lower than our book value. Based on a review of the facts and circumstances surrounding this decline in the market value of our investment during the second half of 2008, we concluded that an impairment of our investment was necessary. In reaching this conclusion, we considered the length of time market value had been below book value and the severity of the decline in market value to be important factors. In combination, these two items

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caused us to conclude that the decline was other than temporary. Accordingly, we recorded a noncash $7,496 million, before- and after-tax impairment, in our fourth-quarter 2008 results. This impairment had the effect of reducing our book value to $5,452 million, based on the market value of LUKOIL ADRs on December 31, 2008.
NMNG
NMNG is a joint venture with LUKOIL, created in June 2005, to develop resources in the northern part of Russia’s Timan-Pechora province. We have a 30 percent direct ownership interest with a 50 percent governance interest. At December 31, 2010, the book value of our equity method investment in NMNG was $735 million. NMNG achieved initial production of the YK Field in June 2008, and development was completed in 2010. Production from the NMNG joint venture fields is transported via pipeline to LUKOIL’s existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. During 2010 and 2009, we reduced the carrying value of our NMNG investment, reflecting other-than-temporary declines in fair value.
DCP Midstream
DCP Midstream owns and operates gas plants, gathering systems, storage facilities and fractionation plants. At December 31, 2010, the book value of our equity method investment in DCP Midstream was $1,038 million. DCP Midstream markets a portion of its natural gas liquids to us and CPChem under a supply agreement that continues at the current volume commitment with a primary term ending December 31, 2014. This purchase commitment is on an “if-produced, will-purchase” basis and so has no fixed production schedule, but has had, and is expected over the remaining term of the contract to have, a relatively stable purchase pattern. Natural gas liquids are purchased under this agreement at various published market index prices, less transportation and fractionation fees.
CPChem
CPChem manufactures and markets petrochemicals and plastics. At December 31, 2010, the book value of our equity method investment in CPChem was $2,518 million. We have multiple supply and purchase agreements in place with CPChem, ranging in initial terms from one to 99 years, with extension options. These agreements cover sales and purchases of refined products, solvents, and petrochemical and natural gas liquids feedstocks, as well as fuel oils and gases. Delivery quantities vary by product, and are generally on an “if-produced, will-purchase” basis. All products are purchased and sold under specified pricing formulas based on various published pricing indices, consistent with terms extended to third-party customers.
Loans and Long-term Receivables
As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities. Included in such activity are loans and long-term receivables to certain affiliated and non-affiliated companies. Loans are recorded when cash is transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan balance may not be fully recovered.
At December 31, 2010, significant loans to affiliated companies include the following:
    $653 million in loan financing to Freeport LNG Development, L.P. for the construction of an LNG receiving terminal that became operational in June 2008. Freeport began making repayments in 2008 and is required to continue making repayments through full repayment of the loan in 2026. Repayment by Freeport is supported by “process-or-pay” capacity service payments made by us to Freeport under our terminal use agreement.
    $1,118 million of project financing and an additional $96 million of accrued interest to Qatar Liquefied Gas Company Limited (3) (QG3), which is an integrated project to produce and liquefy natural gas from Qatar’s North Field. We own a 30 percent interest in QG3, for which we use the equity method of accounting. The other participants in the project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent). QG3 secured project financing of $4.0 billion in

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      December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion. Upon completion certification, which is expected in 2011, all project loan facilities, including the ConocoPhillips loan facilities, will become nonrecourse to the project participants. At December 31, 2010, QG3 had approximately $4.0 billion outstanding under all the loan facilities. Bi-annual repayments began in January 2011 and will extend through July 2022.
    $550 million of loan financing to WRB Refining LP to assist it in meeting its operating and capital spending requirements. We have certain creditor rights in case of default or insolvency.
The long-term portion of these loans are included in the “Loans and advances—related parties” line on the consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”
At September 30, 2010, the Varandey Terminal Company was no longer considered a related party. Accordingly, the long-term portion of this loan is included in the “Investments and long-term receivables” line of the consolidated balance sheet, while the short-term portion is in “Prepaid expenses and other current assets.”
At December 31, 2010, significant long-term receivables and loans to non-affiliated companies included $372 million related to seller financing of U.S. retail marketing assets. In January 2009, we closed on the sale of a large part of our U.S. retail marketing assets which included a five-year note to finance the sale of certain assets. The note is collateralized by the underlying assets related to the sale.
Long-term receivables and the long-term portion of these loans are included in the “Investments and long-term receivables” line on the consolidated balance sheet, while the short-term portion related to non-affiliate loans is in “Accounts and notes receivable.”
Other
We have investments remeasured at fair value on a recurring basis to support certain nonqualified deferred compensation plans. The fair value of these assets at December 31, 2010, was $325 million, and at December 31, 2009, was $338 million. Substantially the entire value is categorized in Level 1 of the fair value hierarchy. These investments are measured at fair value using a market approach based on quotations from national securities exchanges.
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. MSLP processes our long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by us and Petróleos de Venezuela S.A. (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. PDVSA has initiated arbitration with the International Chamber of Commerce challenging our actions, and this arbitration is underway. We continue to use the equity method of accounting for our investment in MSLP.

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Note 7—Properties, Plants and Equipment
Properties, plants and equipment (PP&E) are recorded at cost. Within the E&P segment, depreciation is mainly on a unit-of-production basis, so depreciable life will vary by field. In the R&M segment, investments in refining manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life, and pipeline assets over a 45-year life. The company’s investment in PP&E, with accumulated depreciation, depletion and amortization (Accum. DD&A), at December 31 was:
                                                 
    Millions of Dollars  
    2010     2009  
    Gross     Accum.     Net     Gross     Accum.     Net  
    PP&E     DD&A     PP&E     PP&E     DD&A     PP&E  
             
 
                                               
E&P
  $ 116,805       50,501       66,304       115,224       45,577       69,647  
Midstream
    128       80       48       123       74       49  
R&M
    23,579       8,999       14,580       23,047       6,714       16,333  
LUKOIL Investment
    -       -       -       -       -       -  
Chemicals
    -       -       -       -       -       -  
Emerging Businesses
    981       161       820       1,198       300       898  
Corporate and Other
    1,732       930       802       1,650       869       781  
 
 
  $ 143,225       60,671       82,554       141,242       53,534       87,708  
 
Note 8—Suspended Wells
The following table reflects the net changes in suspended exploratory well costs during 2010, 2009 and 2008:
                         
    Millions of Dollars  
    2010     2009     2008  
       
 
                       
Beginning balance at January 1
  $ 908       660       589  
Additions pending the determination of proved reserves
    216       342       160  
Reclassifications to proved properties
    (106 )     (39 )     (37 )
Sales of suspended well investment
    (4 )     (21 )     (10 )
Charged to dry hole expense
    (1 )     (34 )     (42 )
 
Ending balance at December 31
  $ 1,013       908       660  
 
The following table provides an aging of suspended well balances at December 31, 2010, 2009 and 2008:
                         
    Millions of Dollars  
    2010     2009     2008  
       
 
                       
Exploratory well costs capitalized for a period of one year or less
  $ 220       319       182  
Exploratory well costs capitalized for a period greater than one year
    793       589       478  
 
Ending balance
  $ 1,013       908       660  
 
Number of projects that have exploratory well costs that have been
capitalized for a period greater than one year
    40       34       31  
 

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The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year since the completion of drilling as of December 31, 2010:
                                 
      Millions of Dollars  
            Suspended Since  
Project   Total     2007-2009     2004-2006     2001-2003  
 
 
                               
Aktote—Kazakhstan (1)
  $ 19       -       8       11  
Alpine satellite—Alaska (1)
    23       -       -       23  
Browse Basin—Australia (2)
    93       93       -       -  
Caldita/Barossa—Australia (2)
    77       -       77       -  
Clair—U.K. (1)
    46       29       17       -  
Fiord West—Alaska (1)
    16       16       -       -  
Harrison—U.K. (1)
    15       15       -       -  
Kairan—Kazakhstan (1)
    27       14       13       -  
Kalamkas—Kazakhstan (2)
    13       4       5       4  
Kashagan—Kazakhstan (2)
    44       34       -       10  
Malikai—Malaysia (1)
    53       -       53       -  
NPR-A—Alaska (1)
    17       17       -       -  
Petai/Pisagon—Malaysia (2)
    43       33       10       -  
Saleski—Canada (2)
    14       14       -       -  
Shenandoah—Lower 48 (2)
    43       43       -       -  
Sunrise 3—Australia (1)
    13       13       -       -  
Surmont Beyond Phase II—Canada (2)
    28       19       9       -  
Thornbury—Canada (2)
    20       20       -       -  
Tiber—Lower 48 (2)
    40       40       -       -  
Titan—Norway (1)
    12       12       -       -  
Ubah—Malaysia (1)
    24       24       -       -  
Uge—Nigeria (2)
    30       16       14       -  
Eighteen projects of $10 million or less each (1)(2)
    83       59       24       -  
 
Total of 40 projects
  $ 793       515       230       48  
 
(1) Appraisal drilling complete; costs being incurred to assess development.
(2) Additional appraisal wells planned.
Note 9—Goodwill and Intangibles
Goodwill
Changes in the carrying amount of goodwill were as follows:
                                                 
    Millions of Dollars  
    2010     2009  
    E&P     R&M     Total     E&P     R&M     Total  
             
Balance as of January 1
                                               
Goodwill
  $ 25,443       3,638       29,081       25,443       3,778       29,221  
Accumulated impairment losses
    (25,443 )     -       (25,443 )     (25,443 )     -       (25,443 )
 
 
    -       3,638       3,638       -       3,778       3,778  
Goodwill allocated to assets held for sale or sold
    -       -       -       -       (135 )     (135 )
Tax and other adjustments
    -       (5 )     (5 )     -       (5 )     (5 )
 
Balance as of December 31
                                               
Goodwill
    25,443       3,633       29,076       25,443       3,638       29,081  
Accumulated impairment losses
    (25,443 )     -       (25,443 )     (25,443 )     -       (25,443 )
 
 
  $ -       3,633       3,633       -       3,638       3,638  
 

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Goodwill Impairment
We perform our annual goodwill impairment review in the fourth quarter of each year. During the fourth quarter of 2008, there were severe disruptions in the credit markets and reductions in global economic activity which had significant adverse impacts on stock markets and oil-and-gas-related commodity prices, both of which contributed to a significant decline in our company’s stock price and corresponding market capitalization. For most of the fourth quarter of 2008, our market capitalization value was significantly below the recorded net book value of our balance sheet, including goodwill.
Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units for purposes of performing the annual goodwill impairment test. Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of these net present value calculations to our market capitalization. We use an average of our market capitalization over the 30 calendar days preceding the impairment testing date as being more reflective of our stock price trend than a single day, point-in-time market price. Because, in our judgment, Worldwide E&P is considered to have a higher valuation volatility than Worldwide R&M, the long-term free cash flow growth rate implied from this reconciliation to our recent average market capitalization is applied to the Worldwide E&P net present value calculation.
The accounting principles regarding goodwill acknowledge that the observed market prices of individual trades of a company’s stock (and thus its computed market capitalization) may not be representative of the fair value of the company as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual common stock. In most industries, including ours, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above net present value calculations have been determined, we also add a control premium to the calculations. This control premium is judgmental and is based on observed acquisitions in our industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in our industry to determine whether those valuations, in our judgment, appear reasonable.
After determining the fair values of our various reporting units as of December 31, 2008, it was determined that our Worldwide R&M reporting unit passed the first step of the goodwill impairment test, while our Worldwide E&P reporting unit did not pass the first step. As described above, the second step of the goodwill impairment test uses the estimated fair value of Worldwide E&P from the first step as the purchase price in a hypothetical acquisition of the reporting unit. The significant hypothetical purchase price allocation adjustments made to the assets and liabilities of Worldwide E&P in this second step calculation were in the areas of:
    Adjusting the carrying value of major equity method investments to their estimated fair values.
 
    Adjusting the carrying value of PP&E to the estimated aggregate fair value of all oil and gas property interests.
 
    Recalculating deferred income taxes under FASB ASC Topic 740, “Income Taxes,” after considering the likely tax basis a hypothetical buyer would have in the assets and liabilities.
When determining the above adjustment for the estimated aggregate fair value of PP&E, it was noted that in order for any residual purchase price to be allocated to goodwill, the purchase price assigned to PP&E would have to be well below the value of the PP&E implied by recently-observed metrics from other sales of major oil and gas properties.
Based on the above analysis, we concluded that a $25.4 billion before- and after-tax noncash impairment of the entire amount of recorded goodwill for the Worldwide E&P reporting unit was required. This impairment was recorded in the fourth quarter of 2008.

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Intangible Assets
Information at December 31 on the carrying value of intangible assets follows:
                 
    Millions of Dollars  
    Gross Carrying Amount  
    2010     2009  
Indefinite-Lived Intangible Assets
               
Trade names and trademarks
  $ 494       494  
Refinery air and operating permits
    245       246  
 
 
  $ 739       740  
 
At year-end 2010, our amortized intangible asset balance was $62 million, compared with $83 million at year-end 2009. Amortization expense was not material for 2010 and 2009, and is not expected to be material in future years.
Note 10—Impairments
Goodwill
See the “Goodwill Impairment” section of Note 9—Goodwill and Intangibles, for information on the complete impairment of our E&P segment goodwill.
LUKOIL
See the “LUKOIL” section of Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for information on the impairment of our LUKOIL investment.
Other Impairments
During 2010, 2009 and 2008, we recognized the following before-tax impairment charges, excluding the goodwill and LUKOIL investment impairments noted above:
                         
    Millions of Dollars  
    2010     2009     2008  
 
E&P
                       
United States
  $ 25       5       620  
International
    56       463       173  
R&M
                       
United States
    52       63       534  
International
    1,616       3       181  
Emerging Businesses
    31       -       130  
Corporate
    -       1       48  
 
 
  $ 1,780       535       1,686  
 
2010
During 2010, we recorded a $1,514 million impairment of our refinery in Wilhelmshaven, Germany, due to canceled plans for a project to upgrade the refinery, as well as a $98 million impairment as a result of our decision to end our participation in a new refinery project in Yanbu Industrial City, Saudi Arabia. We also recorded various property impairments of $81 million in our E&P segment.
2009
During 2009, we recorded property impairments of $417 million in our E&P segment, primarily as a result of lower natural gas price assumptions, reduced volume forecasts, and higher royalty, operating costs and capital expenditure assumptions. Additionally, we recorded a noncash charge of $51 million before- and after-tax related to the full impairment of our exploration and production investments in Ecuador, due to their

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expropriation. An arbitration hearing on case merits regarding the expropriation is scheduled for March 2011. Property impairments of $66 million in our R&M segment, primarily associated with planned asset dispositions, were also recorded during 2009.
2008
As a result of the economic downturn in the fourth quarter of 2008, the outlook for crude oil and natural gas prices, refining margins, and power spreads sharply deteriorated, which resulted in revised capital spending plans. Because of these factors, certain E&P, R&M and Emerging Businesses properties no longer passed the undiscounted cash flow tests and had to be written down to fair value. Consequently, we recorded property impairments of approximately $1,480 million, primarily consisting of various producing fields in the U.S. Lower 48 and Canada, one U.S. and one European refinery and a U.S. power generation facility. In addition, we recorded property impairments for increased asset retirement obligations, vacant office buildings in the United States and canceled R&M capital projects.
Fair Value Remeasurements
The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition:
                                 
    Millions of Dollars  
            Fair Value          
            Measurements Using          
            Level 1     Level 3     Before-Tax  
    Fair Value *   Inputs     Inputs     Loss  
Year ended December 31, 2010
                               
Net properties, plants and equipment (held for use)
  $ 307       -       307       1,604 **
Net properties, plants and equipment (held for sale)
    23       5       18       43  
Equity method investments
    735       -       735       645  
 
 
                               
Year ended December 31, 2009
                               
Net properties, plants and equipment (held for use)
  $ 210       -       210       385  
Net properties, plants and equipment (held for sale)
    121       35       86       62  
Equity method investments
    1,784       -       1,784       286  
 
   *Represents the fair value at the time of the impairment.
**Includes a $55 million leasehold impairment charged to exploration expenses.
2010
During 2010, net properties, plants and equipment held for use with a carrying amount of $1,911 million were written down to a fair value of $307 million, resulting in a before-tax loss of $1,604 million. The fair values were determined by the use of internal discounted cash flow models using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants and cash flow multiples for similar assets and alternative use.
Also during 2010, net properties, plants and equipment held for sale with a carrying amount of $64 million were written down to their fair value of $23 million less cost to sell of $2 million for a net $21 million, resulting in a before-tax loss of $43 million. The fair values were primarily determined by binding negotiated selling prices with third parties, with some adjusted for the fair value of certain liabilities retained.
In addition, an equity method investment associated with our E&P segment was determined to have a fair value below carrying amount, and the impairment was considered to be other than temporary. This investment with a book value of $1,380 million was written down to a fair value of $735 million, resulting in a charge of $645 million before-tax, which is included in the “Equity in earnings of affiliates” line of our consolidated statement of operations. The fair value was determined by the application of an internal discounted cash flow model using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants. In addition, the equity investment fair value considered market analysis of certain similar undeveloped properties.

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2009
In 2009, net properties, plants and equipment held for use with a carrying amount of $610 million were written down to a fair value of $210 million, resulting in a before-tax loss of $385 million (including impact of exchange rates). The fair values were determined by the application of an internal discounted cash flow model using estimates of future production, prices and a discount rate believed to be consistent with those used by principal market participants.
Also during 2009, net properties, plants and equipment held for sale with a carrying amount of $178 million were written down to a fair value of $121 million ($91 million still unsold at year-end 2009), less cost to sell of $5 million for a net $116 million, resulting in a before-tax loss of $62 million. The fair values were largely based on binding negotiated prices with third parties, with some adjusted for the fair value of certain liabilities retained.
At December 31, 2009, certain equity method investments associated with our E&P segment were determined to have a fair value below carrying amount and the impairment was considered to be other than temporary. As a result, those investments with a book value of $2,070 million were written down to a fair value of $1,784 million resulting in a charge of $286 million before-tax, which is included in the “Equity in earnings of affiliates” line of the consolidated statement of operations. The fair values were determined by the application of an internal discounted cash flow model using estimates of future production, prices and a discount rate believed to be consistent with those used by principal market participants, as well as reference to market analysis of certain similar undeveloped properties.
Note 11—Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
                 
    Millions of Dollars  
    2010     2009  
     
 
               
Asset retirement obligations
  $ 8,776       8,295  
Accrued environmental costs
    994       1,017  
 
Total asset retirement obligations and accrued environmental costs
    9,770       9,312  
Asset retirement obligations and accrued environmental costs due within one year*
    (571 )     (599 )
 
Long-term asset retirement obligations and accrued environmental costs
  $ 9,199       8,713  
 
*Classified as a current liability on the balance sheet, under the caption “Other accruals.”
Asset Retirement Obligations
We record the fair value of a liability for an asset retirement obligation when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize the associated asset retirement cost by increasing the carrying amount of the related properties, plants and equipment. Over time, the liability increases for the change in its present value, while the capitalized cost depreciates over the useful life of the related asset.
We have numerous asset removal obligations that we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future and will be funded from general company resources at the time of removal. Our largest individual obligations involve removal and disposal of offshore oil and gas platforms around the world, oil and gas production facilities and pipelines in Alaska, and asbestos abatement at refineries.

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During 2010 and 2009, our overall asset retirement obligation changed as follows:
                 
    Millions of Dollars  
    2010     2009  
     
 
               
Balance at January 1
  $ 8,295       6,615  
Accretion of discount
    422       394  
New obligations
    64       113  
Changes in estimates of existing obligations
    744       905  
Spending on existing obligations
    (314 )     (322 )
Property dispositions
    (394 )     (82 )
Foreign currency translation
    (41 )     672  
 
Balance at December 31
  $ 8,776       8,295  
 
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2010 and 2009, were $994 million and $1,017 million, respectively. The 2010 decrease in total accrued environmental costs is due to payments and settlements during the year exceeding new accruals, accrual adjustments and accretion.
We had accrued environmental costs of $624 million and $632 million at December 31, 2010 and 2009, respectively, primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations, and remediation activities required by Canada and the state of Alaska at exploration and production sites. We had also accrued in Corporate and Other $278 million and $292 million of environmental costs associated with nonoperator sites at December 31, 2010 and 2009, respectively. In addition, $92 million and $93 million were included at both December 31, 2010 and 2009, respectively, where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities are expected to be paid over periods extending up to 30 years.
Because a large portion of the accrued environmental costs were acquired in various business combinations, they are discounted obligations. Expected expenditures for acquired environmental obligations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $452 million at December 31, 2010. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $54 million in 2011, $38 million in 2012, $41 million in 2013, $30 million in 2014, $28 million in 2015, and $342 million for all future years after 2015.

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Note 12—Debt
Long-term debt at December 31 was:
                 
    Millions of Dollars  
    2010     2009  
     
 
               
9.875% Debentures due 2010
  $ -       150  
9.375% Notes due 2011
    328       328  
9.125% Debentures due 2021
    150       150  
8.75% Notes due 2010
    -       1,264  
8.20% Debentures due 2025
    150       150  
8.125% Notes due 2030
    600       600  
7.9% Debentures due 2047
    100       100  
7.8% Debentures due 2027
    300       300  
7.68% Notes due 2012
    15       23  
7.65% Debentures due 2023
    88       88  
7.625% Debentures due 2013
    100       100  
7.40% Notes due 2031
    500       500  
7.375% Debentures due 2029
    92       92  
7.25% Notes due 2031
    500       500  
7.20% Notes due 2031
    575       575  
7% Debentures due 2029
    200       200  
6.95% Notes due 2029
    1,549       1,549  
6.875% Debentures due 2026
    67       67  
6.68% Notes due 2011
    -       400  
6.65% Debentures due 2018
    297       297  
6.50% Notes due 2011
    500       500  
6.50% Notes due 2039
    2,250       2,250  
6.50% Notes due 2039
    500       500  
6.40% Notes due 2011
    -       178  
6.35% Notes due 2011
    -       1,750  
6.00% Notes due 2020
    1,000       1,000  
5.951% Notes due 2037
    645       645  
5.95% Notes due 2036
    500       500  
5.90% Notes due 2032
    505       505  
5.90% Notes due 2038
    600       600  
5.75% Notes due 2019
    2,250       2,250  
5.625% Notes due 2016
    1,250       1,250  
5.50% Notes due 2013
    750       750  
5.30% Notes due 2012
    -       350  
5.20% Notes due 2018
    500       500  
4.75% Notes due 2012
    897       897  
4.75% Notes due 2014
    1,500       1,500  
4.60% Notes due 2015
    1,500       1,500  
4.40% Notes due 2013
    400       400  
Commercial paper at 0.14% – 0.34% at year-end 2010 and 0.06% – 0.29% at year-end 2009
    1,182       1,300  
Floating Rate Five-Year Term Note due 2011 at 0.575% at year-end 2010 and 0.45% at year-end 2009
    -       750  
Industrial Development Bonds due 2012 through 2038 at 0.33% – 5.75% at year-end 2010 and 0.24% – 5.75% at year-end 2009
    252       252  
Guarantee of savings plan bank loan payable due 2015 at 2.06% at year-end 2010 and 2.01% at year-end 2009
    64       103  
Note payable to Merey Sweeny, L.P. due 2020 at 7% (related party)
    144       154  
Marine Terminal Revenue Refunding Bonds due 2031 at 0.33% – 0.48% at year-end 2010 and 0.26% – 0.40% at year-end 2009
    265       265  
Other
    31       38  
 
Debt at face value
    23,096       28,120  
Capitalized leases
    39       31  
Net unamortized premiums and discounts
    457       502  
 
Total debt
    23,592       28,653  
Short-term debt
    (936 )     (1,728 )
 
Long-term debt
  $ 22,656       26,925  
 

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Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2011 through 2015 are: $936 million, $2,081 million, $1,277 million, $1,530 million and $1,610 million, respectively. At December 31, 2010, we had classified $1,125 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities.
During 2010, the following debt instruments were repaid prior to their maturity:
    The $400 million 6.68% Notes due 2011.
 
    The $178 million 6.40% Notes due 2011.
 
    The $1,750 million 6.35% Notes due 2011.
 
    The $350 million 5.30% Notes due 2012.
 
    The $750 million remaining balance of the Floating Rate Five-Year Term Note due 2011.
During 2010, the following debt instruments were repaid at their maturity:
    The $150 million 9.875% Debentures due 2010.
 
    The $1,264 million 8.75% Notes due 2010.
At December 31, 2010, we had two revolving credit facilities totaling $7.85 billion, consisting of a $7.35 billion facility expiring in September 2012 and a $500 million facility expiring in July 2012. Our revolving credit facilities may be used as direct bank borrowings, as support for issuances of letters of credit totaling up to $750 million, or as support for our commercial paper programs. The revolving credit facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreements contain a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreements call for commitment fees on available, but unused, amounts. The agreements also contain early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.
We have two commercial paper programs: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to fund commitments relating to the Qatargas 3 Project. Commercial paper maturities are generally limited to 90 days. At both December 31, 2010 and 2009, we had no direct outstanding borrowings under the revolving credit facilities, but $40 million in letters of credit had been issued. In addition, under the two commercial paper programs, there was $1,182 million of commercial paper outstanding at December 31, 2010, compared with $1,300 million at December 31, 2009. Since we had $1,182 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.6 billion in borrowing capacity under our revolving credit facilities at December 31, 2010.
Note 13—Joint Venture Acquisition Obligation
In 2007, we closed on a business venture with Cenovus. As a part of the transaction, we are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to the upstream business venture, FCCL Partnership, formed as a result of the transaction.
Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, $695 million was short-term and was included in the “Accounts payable—related parties” line on our December 31, 2010, consolidated balance sheet. The principal portion of these payments, which totaled $659 million in 2010, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed

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annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.
Note 14—Guarantees
At December 31, 2010, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In addition, unless otherwise stated we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.
Construction Completion Guarantees
In December 2005, we issued a construction completion guarantee for 30 percent of the $4 billion in loan facilities of Qatargas 3, which are being used to finance the construction of an LNG train in Qatar. Of the $4 billion in loan facilities, we committed to provide $1.2 billion. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $850 million, which could become payable if the full debt financing is utilized and completion of the Qatargas 3 Project is not achieved. The project financing will be nonrecourse to ConocoPhillips upon certified completion, expected in 2011. At December 31, 2010, the carrying value of the guarantee to third-party lenders was $11 million.
Guarantees of Joint Venture Debt
At December 31, 2010, we had guarantees outstanding for our portion of joint venture debt obligations, which have terms of up to 15 years. The maximum potential amount of future payments under the guarantees is approximately $80 million. Payment would be required if a joint venture defaults on its debt obligations.
Other Guarantees
    In conjunction with our purchase of a 50 percent ownership interest in APLNG from Origin Energy in October 2008, we agreed to participate, if and when requested, in any parent company guarantees that were outstanding at the time we purchased our interest in APLNG. These parent company guarantees cover the obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 6 to 21 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1,578 million ($3,477 million in the event of intentional or reckless breach) at December 2010 exchange rates based on our 50 percent share of the remaining contracted volumes, which could become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG.
 
    We have other guarantees with maximum future potential payment amounts totaling $400 million, which consist primarily of guarantees to fund the short-term cash liquidity deficits of certain joint ventures, a guarantee of minimum charter revenue for two LNG vessels, one small construction completion guarantee, guarantees relating to the startup of a refining joint venture, guarantees of the lease payment obligations of a joint venture, and guarantees of the residual value of leased corporate aircraft. These guarantees generally extend up to 14 years or life of the venture.
Indemnifications
Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The

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majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at December 31, 2010, was $386 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount were $250 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at December 31, 2010. For additional information about environmental liabilities, see Note 15—Contingencies and Commitments.
Note 15—Contingencies and Commitments
A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 20—Income Taxes, for additional information about income-tax-related contingencies.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Environmental
We are subject to federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date

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in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly.
As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar limits and time limits. We have not recorded accruals for any potential contingent liabilities that we expect to be funded by the prior owners under these indemnifications.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. See Note 11—Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.
Legal Proceedings
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, are required.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at December 31, 2010, we had performance obligations secured by letters of credit of $1,784 million (of which $40 million was issued under the provisions of our revolving credit facility, and the remainder was issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.
In 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. As a result, Venezuela’s national oil company, 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. See Note 10—Impairments, for additional information about expropriated assets in Ecuador.
Long-Term Throughput Agreements and Take-or-Pay Agreements
We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The agreements typically provide for natural gas or crude oil transportation to be used in the ordinary course of the company’s business. The aggregate amounts of estimated payments under these various agreements are: 2011—$369 million; 2012—$410 million; 2013—$408 million; 2014—$408 million; 2015—$400 million; and 2016 and after—$4,402 million. Total payments under the agreements were $216 million in 2010, $114 million in 2009 and $119 million in 2008.

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Note 16—Financial Instruments and Derivative Contracts
Financial Instruments
We invest excess cash in financial instruments with maturities based on our cash forecasts for the various currency pools we manage. The maturities of these investments may from time to time extend beyond 90 days. The types of financial instruments in which we currently invest include:
    Time Deposits: Interest bearing deposits placed with approved financial institutions.
 
    Commercial Paper: Unsecured promissory notes issued by a corporation, commercial bank, or government agency purchased at a discount to mature at par.
 
    Government or government agency obligations: Negotiable debt obligations issued by a government or government agency.
These financial instruments appear in the “Cash and cash equivalents” line of our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these held-to-maturity investments are included in the “Short-term investments” line. At December 31, 2010, we held the following financial instruments:
                 
    Millions of Dollars  
    Carrying Amount  
    Cash & Cash     Short-Term  
    Equivalents     Investments *
     
 
               
Cash
  $ 1,284       -  
 
               
Time Deposits
               
Remaining maturities from 1 to 90 days
    6,154       302  
Remaining maturities from 91 to 180 days
    -       69  
Commercial Paper
               
Remaining maturities from 1 to 90 days
    1,566       525  
Remaining maturities from 91 to 180 days
    -       -  
Government Obligations
               
Remaining maturities from 1 to 90 days
    450       77  
Remaining maturities from 91 to 180 days
    -       -  
 
 
  $ 9,454       973  
 
*Carrying value approximates fair value.
Derivative Instruments
We use financial and commodity-based derivative contracts to manage exposures to fluctuations in foreign currency exchange rates, commodity prices, and interest rates, or to capture market opportunities. Since we are not currently using cash-flow hedge accounting, all gains and losses, realized or unrealized, from derivative contracts have been recognized in the consolidated statement of operations. Gains and losses from derivative contracts held for trading not directly related to our physical business, whether realized or unrealized, have been reported net in other income.
Purchase and sales contracts with fixed minimum notional volumes for commodities that are readily convertible to cash (e.g., crude oil, natural gas and gasoline) are recorded on the balance sheet as derivatives unless the contracts are eligible for and we elect the normal purchases and normal sales exception (i.e., contracts to purchase or sell quantities we expect to use or sell over a reasonable period in the normal course of business). We record most of our contracts to buy or sell natural gas and the majority of our contracts to sell power as derivatives, but we do apply the normal purchases and normal sales exception to certain long-term contracts to sell our natural gas production. We generally apply this normal purchases and normal sales exception to eligible crude oil and refined product commodity purchase and sales contracts; however, we may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of

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the purchase or sales contract but hedge accounting will not be applied, in which case both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value).
We value our exchange-cleared derivatives using closing prices provided by the exchange as of the balance sheet date, and these are classified as Level 1 in the fair value hierarchy. Over-the-counter (OTC) financial swaps and physical commodity forward purchase and sales contracts are generally valued using quotations provided by brokers and price index developers such as Platts and Oil Price Information Service. These quotes are corroborated with market data and are classified as Level 2. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC swaps and physical commodity purchase and sales contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3. A contract that is initially classified as Level 3 due to absence or insufficient corroboration of broker quotes over a material portion of the contract will transfer to Level 2 when the portion of the trade having no quotes or insufficient corroboration becomes an insignificant portion of the contract. A contract would also transfer to Level 2 if we began using a corroborated broker quote that has become available. Conversely, if a corroborated broker quote ceases to be available or used by us, the contract would transfer from Level 2 to Level 3. There were no transfers in or out of Level 1.
Financial OTC and physical commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the options are classified as Level 2 or 3.
We use a mid-market pricing convention (the mid-point between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.
The fair value hierarchy for our derivative assets and liabilities accounted for at fair value on a recurring basis was:
                                                                 
    Millions of Dollars  
    December 31, 2010     December 31, 2009  
    Level 1     Level 2     Level 3     Total     Level 1     Level 2     Level 3     Total  
Assets
                                                               
Commodity derivatives
  $ 1,957       1,243       63       3,263       1,710       1,659       61       3,430  
Interest rate derivatives
    -       20       -       20       -       -       -       -  
Foreign currency exchange derivatives
    -       15       -       15       -       45       -       45  
 
Total assets
    1,957       1,278       63       3,298       1,710       1,704       61       3,475  
 
 
                                                               
Liabilities
                                                               
Commodity derivatives
    2,230       1,118       36       3,384       1,797       1,496       24       3,317  
Foreign currency exchange derivatives
    -       9       -       9       -       47       -       47  
 
Total liabilities
    2,230       1,127       36       3,393       1,797       1,543       24       3,364  
 
Net assets (liabilities)
  $ (273 )     151       27       (95 )     (87 )     161       37       111  
 
The derivative values above are based on analysis of each contract as the fundamental unit of account; therefore, derivative assets and liabilities with the same counterparty are not reflected net where the legal right of offset exists. Gains or losses from contracts in one level may be offset by gains or losses on contracts in another level or by changes in values of physical contracts or positions that are not reflected in the table above.
As reflected in the table above, Level 3 activity is not material.

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Commodity Derivative Contracts —We operate in the worldwide crude oil, bitumen, refined product, natural gas, LNG, natural gas liquids and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities; however, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial amount of trading not directly related to our physical business. We also use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades. Derivatives may be used to optimize these activities which may move our risk profile away from market average prices.
The fair value of commodity derivative assets and liabilities and the line items where they appear on our consolidated balance sheet were:
                 
    Millions of Dollars  
    2010     2009  
     
Assets
               
Prepaid expenses and other current assets
  $ 3,073       3,084  
Other assets
    211       359  
Liabilities
               
Other accruals
    3,212       3,006  
Other liabilities and deferred credits
    193       324  
 
Hedge accounting has not been used for any items in the table. The amounts shown are presented gross (i.e., without netting assets and liabilities with the same counterparty where the right of offset and intent to net exist).
The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated statement of operations were:
                 
    Millions of Dollars  
    2010     2009  
     
 
               
Sales and other operating revenues
  $ (1,154 )     1,964  
Other income
    (38 )     19  
Purchased crude oil, natural gas and products
    1,036       (2,624 )
 
Hedge accounting has not been used for any items in the table.
The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts. These financial and physical derivative contracts are primarily used to manage price exposure on our underlying operations. The underlying exposures may be from non-derivative positions such as inventory volumes or firm natural gas transport contracts. Financial derivative contracts may also offset physical derivative contracts, such as forward sales contracts.
                 
    Open Position  
    Long / (Short)  
    2010     2009  
     
Commodity
               
Crude oil, refined products and natural gas liquids (millions of barrels)
    (16 )     (16 )
Natural gas and power (billions of cubic feet equivalent)
               
Fixed price
    (69 )     (60 )
Basis
    (43 )     154  
 

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Interest Rate Derivative Contracts —During the second quarter of 2010, we executed interest rate swaps to synthetically convert $500 million of our 4.60% fixed-rate notes due in 2015 to a London Interbank Offered Rate (LIBOR)-based floating rate. These swaps qualify for and are designated as fair-value hedges using the short-cut method of hedge accounting. The short-cut method permits the assumption that changes in the value of the derivative perfectly offset changes in the value of the debt; therefore, no gain or loss has been recognized due to hedge ineffectiveness.
The fair value of interest rate derivative assets and liabilities and the line items where they appear on our consolidated balance sheet were:
                 
    Millions of Dollars  
    2010     2009  
     
Assets
               
Prepaid expenses and other current assets
  $ 11       -  
Other assets
    9       -  
 
Hedge accounting was used for all items in the table. The amounts shown are presented gross.
The (gains) and losses from interest rate derivatives used in a fair-value hedge, losses and (gains) from changes in the fair value of the hedged debt, and the line item where they appear on our consolidated statement of operations were:
                 
    Millions of Dollars  
    2010     2009  
     
 
               
Recorded in interest and debt expense
               
From the interest rate derivatives
  $ (23 )     -  
From the hedged debt
    16       -  
 
Hedge accounting was used for all items in the table. The amounts shown are presented gross.
The extent to which the change in value of the interest rate derivatives differs from the change in value of the hedged debt is an adjustment to recorded interest expense on the fixed-rate debt that effectively results in interest expense for the period being recorded at floating-rate LIBOR plus the swap spread.
Foreign Currency Exchange Derivatives —We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to movements in currency exchange rates, although we may choose to selectively hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year.
The fair value of foreign currency exchange derivative assets and liabilities, and the line items where they appear on our consolidated balance sheet were:
                 
    Millions of Dollars  
    2010     2009  
     
Assets
               
Prepaid expenses and other current assets
  $ 14       38  
Other assets
    1       7  
Liabilities
               
Other accruals
    7       40  
Other liabilities and deferred credits
    2       7  
 
Hedge accounting has not been used for any items in the table. The amounts shown are presented gross.

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Gains and losses from foreign currency exchange derivatives and the line item where they appear on our consolidated statement of operations were:
                 
    Millions of Dollars  
    2010     2009  
     
 
               
Foreign currency transaction (gains) losses
  $ 118       (121 )
 
Hedge accounting has not been used for any items in the table.
We had the following net notional position of outstanding foreign currency exchange derivatives:
                         
    In Millions  
    Notional Currency *
    2010     2009  
       
Foreign Currency Exchange Derivatives
                       
Sell U.S. dollar, buy other currencies**
  USD     569       3,211  
Sell Euro, buy British pound
  EUR     253       267  
 
*Denominated in U.S. dollars (USD) and euros (EUR).
**Primarily euro, Canadian dollar, Norwegian krone and British pound.
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, OTC derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, money market funds, government debt securities and time deposits with major international banks and financial institutions.
The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures contracts, but futures have a negligible credit risk because they are traded on the New York Mercantile Exchange or the IntercontinentalExchange (ICE) Futures.
Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments, and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due us.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral.
The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on December 31, 2010, was $225 million, for which no collateral was posted. If our credit rating were lowered one level from its “A” rating (per Standard and Poor’s) on December 31, 2010, we would be required to post no additional collateral to our counterparties. If we were downgraded below investment grade, we would be required to post $225 million of additional collateral, either with cash or letters of credit.

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Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:
    Cash, cash equivalents, and short-term investments: The carrying amount reported on the balance sheet approximates fair value.
 
    Accounts and notes receivable: The carrying amount reported on the balance sheet approximates fair value.
 
    Investment in LUKOIL shares: See Note 6—Investments, Loans and Long-Term Receivables, for a discussion of the carrying value and fair value of our investment in LUKOIL shares.
 
    Debt: The carrying amount of our floating-rate debt approximates fair value. The fair value of the fixed-rate debt is estimated based on quoted market prices.
 
    Fixed-rate 5.3 percent joint venture acquisition obligation: Fair value is estimated based on the net present value of the future cash flows, discounted at a December 31 effective yield rate of 1.87 percent, based on yields of U.S. Treasury securities of similar average duration adjusted for our average credit risk spread and the amortizing nature of the obligation principal. See Note 13—Joint Venture Acquisition Obligation, for additional information.
 
    Commodity swaps: Fair value is estimated based on forward market prices and approximates the exit price at period end. When forward market prices are not available, they are estimated using the forward prices of a similar commodity with adjustments for differences in quality or location.
 
    Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange, the ICE Futures, or other traded exchanges.
 
    Interest rate swap contracts: Fair value is estimated based on a pricing model and market observable interest rate swap curves obtained from a third-party market data provider.
 
    Forward-exchange contracts: Fair value is estimated by comparing the contract rate to the forward rate in effect on December 31 and approximates the exit price at that date.
Our commodity derivative and financial instruments were:
                                 
    Millions of Dollars  
    Carrying Amount     Fair Value  
    2010     2009     2010     2009  
Financial assets
                               
Foreign currency exchange derivatives
  $ 15       45       15       45  
Interest rate derivatives
    20       -       20       -  
Commodity derivatives
    624       823       624       823  
Investment in LUKOIL*
    1,083       -       1,083       -  
Financial liabilities
                               
Total debt, excluding capital leases
    23,553       28,622       26,144       30,565  
Joint venture acquisition obligation
    5,009       5,669       5,600       6,276  
Foreign currency exchange derivatives
    9       47       9       47  
Commodity derivatives
    426       632       426       632  
 
*Prior to September 30, 2010, our investment in LUKOIL was accounted for using the equity method. See Note 6—Investments, Loans and Long-Term Receivables, for more   information.
The amounts shown for derivatives in the preceding table are presented net (i.e., assets and liabilities with the same counterparty are netted where the right of offset and intent to net exist). In addition, the 2010 commodity derivative assets and liabilities appear net of $5 million of obligations to return cash collateral and $324 million of rights to reclaim cash collateral, respectively. The 2009 commodity derivative assets and liabilities appear net of $70 million of obligations to return cash collateral and $148 million of rights to reclaim cash collateral, respectively. No collateral was deposited or held for the foreign currency exchange derivatives.

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Note 17—Equity
Common Stock
The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:
                         
    Shares  
    2010     2009     2008  
       
Issued
                       
Beginning of year
    1,733,345,558       1,729,264,859       1,718,448,829  
Distributed under benefit plans
    7,183,721       4,080,699       10,816,030  
 
End of year
    1,740,529,279       1,733,345,558       1,729,264,859  
 
 
                       
Held in Treasury
                       
Beginning of year
    208,346,815       208,346,815       104,607,149  
Repurchase of common stock
    64,526,722       -       103,739,666  
 
End of year
    272,873,537       208,346,815       208,346,815  
 
 
                       
Held in Grantor Trusts
                       
Beginning of year
    38,742,261       40,739,129       42,411,331  
Distributed under benefit plans
    (1,776,873 )     (2,018,692 )     (1,668,456 )
Repurchase of common stock
    -       -       (13,600 )
Other
    (75,013 )     21,824       9,854  
 
End of year
    36,890,375       38,742,261       40,739,129  
 
Preferred Stock
We have 500 million shares of preferred stock authorized, par value $.01 per share, none of which was issued or outstanding at December 31, 2010 or 2009.
Noncontrolling Interests
At December 31, 2010 and 2009, we had outstanding $547 million and $590 million, respectively, of equity in less-than-wholly owned consolidated subsidiaries held by noncontrolling interest owners. The noncontrolling interest amounts are primarily related to operating joint ventures we control. The largest of these, amounting to $520 million at December 31, 2010, and $565 million at December 31, 2009, was related to Darwin LNG operations, located in Australia’s Northern Territory.
Preferred Share Purchase Rights
In 2002, our Board of Directors authorized and declared a dividend of one preferred share purchase right for each common share outstanding, and authorized and directed the issuance of one right per common share for any newly issued shares. The rights have certain anti-takeover effects. The rights will cause substantial dilution to a person or group that attempts to acquire ConocoPhillips on terms not approved by the Board of Directors. However, since the rights may either be redeemed or otherwise made inapplicable by ConocoPhillips prior to an acquirer obtaining beneficial ownership of 15 percent or more of ConocoPhillips’ common stock, the rights should not interfere with any merger or business combination approved by the Board of Directors prior to that occurrence. The rights, which expire June 30, 2012, will be exercisable only if a person or group acquires 15 percent or more of the company’s common stock or commences a tender offer that would result in ownership of 15 percent or more of the common stock. Each right would entitle stockholders to buy one one-hundredth of a share of preferred stock at an exercise price of $300. If an acquirer obtains 15 percent or more of ConocoPhillips’ common stock, then each right will be adjusted so that it will entitle the holder (other than the acquirer, whose rights will become void) to purchase, for the then exercise price, a number of shares of ConocoPhillips’ common stock equal in value to two times the exercise price of the right. In addition, the rights enable holders to purchase the stock of an acquiring company at a discount, depending on specific circumstances. We may redeem the rights in whole, but not in part, for one cent per right.

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Note 18—Non-Mineral Leases
The company leases ocean transport vessels, tugboats, barges, pipelines, railcars, corporate aircraft, service stations, drilling equipment, computers, office buildings and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property for the fair market value at the end of the lease term. There are no significant restrictions imposed on us by the leasing agreements in regards to dividends, asset dispositions or borrowing ability. Leased assets under capital leases were not significant in any period presented.
At December 31, 2010, future minimum rental payments due under noncancelable leases were:
         
    Millions  
    of Dollars  
 
       
2011
  $ 752  
2012
    573  
2013
    460  
2014
    309  
2015
    245  
Remaining years
    557  
 
Total
    2,896  
Less income from subleases
    (140 )*
 
Net minimum operating lease payments
  $ 2,756  
 
*Includes $72 million related to railcars subleased to CPChem, a related party.
Operating lease rental expense for the years ended December 31 was:
                         
    Millions of Dollars  
    2010     2009     2008  
     
 
                       
Total rentals*
  $ 925       1,024       1,033  
Less sublease rentals
    (34 )     (34 )     (125 )
 
 
  $ 891       990       908  
 
*Includes $22 million, $21 million and $22 million of contingent rentals in 2010, 2009 and 2008, respectively. Contingent rentals primarily are related to production and refining equipment, and are based on throughput or volume of product sold.

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Note 19—Employee Benefit Plans
Pension and Postretirement Plans
An analysis of the projected benefit obligations for our pension plans and accumulated benefit obligations for our postretirement health and life insurance plans follows:
                                                 
    Millions of Dollars  
    Pension Benefits     Other Benefits  
    2010     2009     2010     2009  
    U.S.     Int’l.     U.S.     Int’l.                  
                       
Change in Benefit Obligation
                                               
Benefit obligation at January 1
  $ 5,042       3,101       4,620       2,307       839       768  
Service cost
    229       90       194       79       11       9  
Interest cost
    260       169       277       144       46       47  
Plan participant contributions
    -       4       -       8       20       22  
Medicare Part D subsidy
    -       -       -       -       -       1  
Plan amendments
    12       -       -       -       -       -  
Actuarial loss
    305       59       456       366       14       63  
Benefits paid
    (309 )     (115 )     (505 )     (103 )     (70 )     (75 )
Curtailment
    -       (1 )     -       -       -       -  
Recognition of termination benefits
    -       -       -       5       -       -  
Foreign currency exchange rate change
    -       (101 )     -       295       2       4  
 
Benefit obligation at December 31*
  $ 5,539       3,206       5,042       3,101       862       839  
 
*Accumulated benefit obligation portion of above
at December 31:
  $ 4,905       2,711       4,359       2,595                  
 
                                               
Change in Fair Value of Plan Assets
                                               
Fair value of plan assets at January 1
  $ 3,144       2,281       2,373       1,728       -       2  
Actual return on plan assets
    458       259       574       245       -       -  
Company contributions
    597       216       702       159       50       50  
Plan participant contributions
    -       4       -       8       20       22  
Medicare Part D subsidy
    -       -       -       -       -       1  
Benefits paid
    (309 )     (115 )     (505 )     (103 )     (70 )     (75 )
Curtailment
    -       (1 )     -       -       -       -  
Foreign currency exchange rate change
    -       (63 )     -       244       -       -  
 
Fair value of plan assets at December 31
  $ 3,890       2,581       3,144       2,281       -       -  
 
 
                                               
Funded Status
  $ (1,649 )     (625 )     (1,898 )     (820 )     (862 )     (839 )
 

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    Millions of Dollars  
    Pension Benefits     Other Benefits  
    2010     2009     2010     2009  
    U.S.     Int’l.     U.S.     Int’l.                  
                       
Amounts Recognized in the Consolidated Balance Sheet at December 31
                                               
Noncurrent assets
  $ -       156       -       96       -       -  
Current liabilities
    (74 )     (4 )     (6 )     (12 )     (51 )     (60 )
Noncurrent liabilities
    (1,575 )     (777 )     (1,892 )     (904 )     (811 )     (779 )
 
Total recognized
  $ (1,649 )     (625 )     (1,898 )     (820 )     (862 )     (839 )
 
                                                 
Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31
                                               
Discount rate
    4.65 %     5.40       5.35       5.80       5.00       5.60  
Rate of compensation increase
    4.00       4.10       4.00       4.50       -       -  
 
                                                 
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
                                               
Discount rate
    5.35 %     5.80       6.25       6.00       5.60       6.30  
Expected return on plan assets
    7.00       6.50       7.00       6.60       -       7.00  
Rate of compensation increase
    4.00       4.50       4.00       4.20       -       -  
 
For both U.S. and international pensions, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.
Included in other comprehensive income at December 31 were the following before-tax amounts that had not been recognized in net periodic postretirement benefit cost:
                                                 
    Millions of Dollars  
    Pension Benefits     Other Benefits  
    2010     2009     2010     2009  
    U.S.     Int’l.     U.S.     Int’l.                  
                       
 
                                               
Unrecognized net actuarial loss (gain)
  $ 1,567       444       1,664       574       (51 )     (72 )
Unrecognized prior service cost
    61       (25 )     58       (24 )     (54 )     (51 )
 

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    Millions of Dollars  
    Pension Benefits     Other Benefits  
    2010     2009     2010     2009  
    U.S.     Int’l.     U.S.     Int’l.                  
                       
Sources of Change in Other Comprehensive Income
                                               
Net gain (loss) arising during the period
  $ (70 )     75       (52 )     (274 )     (14 )     (62 )
Amortization of (gain) loss included in income
    167       55       186       35       (7 )     (15 )
 
Net gain (loss) during the period
  $ 97       130       134       (239 )     (21 )     (77 )
 
 
Prior service cost arising during the period
  $ (12 )     (1 )     -       1       -       (1 )
Amortization of prior service cost included in income
    10       2       11       1       3       9  
 
Net prior service cost during the period
  $ (2 )     1       11       2       3       8  
 
Amounts included in accumulated other comprehensive income at December 31, 2010, that are expected to be amortized into net periodic postretirement cost during 2011 are provided below:
                         
    Millions of Dollars  
    Pension Benefits     Other Benefits  
    U.S.     Int’l.          
             
 
                       
Unrecognized net actuarial loss (gain)
  $ 165       44       (5 )
Unrecognized prior service cost
    9       -       (7 )
 
For our tax-qualified pension plans with projected benefit obligations in excess of plan assets, the projected benefit obligation, the accumulated benefit obligation, and the fair value of plan assets were $7,661 million, $6,718 million, and $5,706 million, respectively, at December 31, 2010, and $7,145 million, $5,653 million, and $4,748 million, respectively, at December 31, 2009.
For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and the accumulated benefit obligation were $479 million and $407 million, respectively, at December 31, 2010, and were $419 million and $355 million, respectively, at December 31, 2009.
The components of net periodic benefit cost of all defined benefit plans are presented in the following table:
                                                                         
    Millions of Dollars  
    Pension Benefits     Other Benefits  
    2010     2009     2008     2010     2009     2008  
    U.S.     Int’l.     U.S.     Int’l.     U.S.     Int’l.                          
                               
Components of Net
Periodic Benefit Cost
                                                                       
Service cost
  $ 229       90       194       79       186       85       11       9       11  
Interest cost
    260       169       277       144       247       170       46       47       47  
Expected return on plan assets
    (224 )     (147 )     (184 )     (125 )     (223 )     (170 )     -       -       -  
Amortization of prior service cost
    10       2       11       1       10       1       3       9       11  
Recognized net actuarial
loss (gain)
    167       55       186       35       64       17       (7 )     (15 )     (17 )
 
Net periodic benefit cost
  $ 442       169       484       134       284       103       53       50       52  
 

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We recognized pension settlement losses of $15 million and $18 million and special termination benefits of $5 million and $2 million in 2009 and 2008, respectively. None were recognized in 2010.
In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year.
We have multiple nonpension postretirement benefit plans for health and life insurance. The health care plans are contributory and subject to various cost sharing features, with participant and company contributions adjusted annually; the life insurance plans are noncontributory. The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 8 percent in 2011 that declines to 5 percent by 2023. A one-percentage-point change in the assumed health care cost trend rate would have the following effects on the 2010 amounts:
                 
    Millions of Dollars  
    One-Percentage-Point  
    Increase     Decrease  
 
               
Effect on total of service and interest cost components
  $ 1       (1 )
Effect on the postretirement benefit obligation
    2       (2 )
 
Plan Assets— We follow a policy of broadly diversifying pension plan assets across asset classes, investment managers, and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include U.S. equities, non-U.S. equities, U.S. fixed income, non-U.S. fixed income, real estate and private equity investments. Plan fiduciaries may consider and add other asset classes to the investment program from time to time. The target allocations for plan assets are 56 percent equity securities, 35 percent debt securities, 6 percent real estate and 3 percent in all other types of investments. Generally, the investments in the plans are publicly traded, therefore minimizing liquidity risk in the portfolio.
Following is a description of the valuation methodologies used for the pension plan assets. There have been no changes in the methodologies used at December 31, 2010 and 2009.
Fair values of equity securities and government debt securities categorized in Level 1 are primarily based on quoted market prices.
Fair values of corporate debt securities, agency and mortgage-backed securities and government debt securities categorized in Level 2 are estimated using recently executed transactions and market price quotations. If there have been no market transactions in a particular fixed income security, its fair market value is calculated by pricing models that benchmark the security against other securities with actual market prices. When observable price quotations are not available, fair value is based on pricing models that use something other than actual market prices (e.g., observable inputs such as benchmark yields, reported trades and issuer spreads for similar securities), and these securities are categorized in Level 3 of the fair value hierarchy.
Fair values of investments in common/collective trusts are determined by the issuer of each fund based on the fair value of the underlying assets.
Fair values of mutual funds are valued based on quoted market prices, which represent the net asset value of shares held.
Cash is valued at cost, which approximates fair value. Fair values of cash equivalents categorized in Level 2 are valued using observable yield curves, discounting and interest rates.

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Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices. For other derivatives classified in Level 2, the values are generally calculated from pricing models with market input parameters from third-party sources.
Private equity funds are valued at net asset value as determined by the issuer based on the fair value of the underlying assets.
Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the Plans’ participants.
Fair values of real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party sources and sales comparables where available.
A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity contract. This participating interest is calculated as the market value of investments held under this contract, less the accumulated benefit obligation covered by the contract. The participation interest is classified as Level 3 in the fair value hierarchy as the fair value is determined via a combination of comparison to quoted market prices and estimation using recently executed transactions and market price quotations for contract assets, and an actuarial present value computation for contract obligations. At December 31, 2010, the participating interest in the annuity contract was valued at $92 million and consisted of $357 million in debt securities, less $265 million for the accumulated benefit obligation covered by the contract. At December 31, 2009, the participating interest in the annuity contract was valued at $94 million and consisted of $349 million in debt securities, less $255 million for the accumulated benefit obligation covered by the contract. The net change from 2009 to 2010 is due to an increase in the fair market value of the underlying investments of $8 million and an increase in the present value of the contract obligation of $10 million. The participating interest is not available for meeting general pension benefit obligations in the near term. No future company contributions are required and no new benefits are being accrued under this insurance annuity contract.

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The fair values of our pension plan assets at December 31, by asset class were as follows:
                                                                 
    Millions of Dollars  
    U.S.     International  
    Level     Level     Level             Level     Level     Level        
    1     2     3     Total     1     2     3     Total  
             
2010
                                                               
Equity Securities
                                                               
U.S.
  $     1,250       -       -       1,250       378       -       -       378  
International
    818       -       -       818       498       -       -       498  
Common/collective trusts
    -       635       -       635       -       246       -       246  
Mutual funds
    -       -       -       -       282       -       -       282  
Debt Securities
                                                               
Government
    251       56       -       307       390       -       -       390  
Corporate
    -       420       3       423       -       171       2       173  
Agency and mortgage-backed securities
    -       81       -       81       -       -       -       -  
Common/collective trusts
    -       270       -       270       -       329       -       329  
Mutual funds
    -       -       -       -       122       -       -       122  
Cash and cash equivalents
    -       -       -       -       9       10       -       19  
Private equity funds
    -       -       6       6       -       -       8       8  
Derivatives
    -       -       -       -       -       12       -       12  
Insurance contacts
    -       -       -       -       -       -       16       16  
Real estate
    -       -       -       -       -       -       101       101  
                   
Total*
  $ 2,319       1,462       9       3,790       1,679       768       127       2,574  
                   
*Excludes the participating interest in the annuity contract with a net asset value of $92 million and net receivables related to security transactions of $15 million.
 
                                                               
2009
                                                               
Equity Securities
                                                               
U.S.
  $ 1,021       -       -       1,021       56       -       -       56  
International
    571       -       -       571       240       -       -       240  
Common/collective trusts
    -       556       -       556       -       545       -       545  
Mutual funds
    -       -       -       -       293       -       -       293  
Debt Securities
                                                               
Government
    120       48       -       168       222       -       -       222  
Corporate
    -       327       3       330       -       341       3       344  
Agency and mortgage-backed securities
    -       83       -       83       -       24       -       24  
Common/collective trusts
    -       332       -       332       -       280       -       280  
Mutual funds
    -       -       -       -       139       -       -       139  
Cash and cash equivalents
    3       -       -       3       20       11       -       31  
Private equity funds
    -       -       9       9       -       -       3       3  
Derivatives
    -       -       -       -       -       12       -       12  
Insurance contacts
    -       -       -       -       -       -       16       16  
Real estate
    -       -       -       -       -       -       67       67  
             
Total*
  $ 1,715       1,346       12       3,073       970       1,213       89       2,272  
                   
*Excludes the participating interest in the annuity contract with a net asset value of $94 million and net payables related to security transactions of $(14) million.
As reflected in the table above, Level 3 activity is not material.

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Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to foreign plans are dependent upon local laws and tax regulations. In 2011, we expect to contribute approximately $730 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $230 million to our international qualified and nonqualified pension and postretirement benefit plans.
The following benefit payments, which are exclusive of amounts to be paid from the participating annuity contract and which reflect expected future service, as appropriate, are expected to be paid:
                         
    Millions of Dollars  
    Pension Benefits     Other Benefits  
    U.S.     Int’l.          
 
                       
2011
  $ 464       95       55  
2012
    417       100       57  
2013
    498       107       59  
2014
    474       115       62  
2015
    517       123       63  
2016-2020
    2,811       719       339  
         
Defined Contribution Plans
Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can deposit up to 75 percent of their eligible pay up to the statutory limit ($16,500 in 2010) in the thrift feature of the CPSP to a choice of approximately 39 investment funds. ConocoPhillips matches contribution deposits, up to 1.25 percent of eligible pay. Company contributions charged to expense for the CPSP and predecessor plans, excluding the stock savings feature (discussed below), were $24 million in 2010, $23 million in 2009, and $28 million in 2008.
The stock savings feature of the CPSP is a leveraged employee stock ownership plan. Employees may elect to participate in the stock savings feature by contributing 1 percent of eligible pay and receiving an allocation of shares of common stock proportionate to the amount of contribution.
In 1990, the Long-Term Stock Savings Plan of Phillips Petroleum Company (now the stock savings feature of the CPSP) borrowed funds that were used to purchase previously unissued shares of company common stock. Since the company guarantees the CPSP’s borrowings, the unpaid balance is reported as a liability of the company and unearned compensation is shown as a reduction of common stockholders’ equity. Dividends on all shares are charged against retained earnings. The debt is serviced by the CPSP from company contributions and dividends received on certain shares of common stock held by the plan, including all unallocated shares. The shares held by the stock savings feature of the CPSP are released for allocation to participant accounts based on debt service payments on CPSP borrowings. In addition, during the period from 2011 through 2014, when no debt principal payments are scheduled to occur, we have committed to make direct contributions of stock to the stock savings feature of the CPSP, or make prepayments on CPSP borrowings, to ensure a certain minimum level of stock allocation to participant accounts.
We recognize interest expense as incurred and compensation expense based on the fair market value of the stock contributed or on the cost of the unallocated shares released, using the shares-allocated method. We recognized total CPSP expense related to the stock savings feature of $92 million, $83 million and $111 million in 2010, 2009 and 2008, respectively, all of which was compensation expense. In 2010, 2009 and 2008, we contributed 1,776,873 shares, 2,018,692 shares and 1,668,456 shares, respectively, of company common stock from the Compensation and Benefits Trust. The shares had a fair market value of $103 million, $94 million and $120 million, respectively. Dividends used to service debt were $41 million, $39 million and $41 million in 2010, 2009 and 2008, respectively. These dividends reduced the amount of compensation expense recognized each period. Interest incurred on the CPSP debt in 2010, 2009 and 2008 was $2 million, $2 million and $6 million, respectively.

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The total CPSP stock savings feature shares as of December 31 were:
                 
    2010     2009  
 
               
Unallocated shares
    3,385,778       5,364,887  
Allocated shares
    19,198,502       19,008,169  
       
Total shares
    22,584,280       24,373,056  
       
The fair value of unallocated shares at December 31, 2010 and 2009, was $231 million and $274 million, respectively.
We have several defined contribution plans for our international employees, each with its own terms and eligibility depending on location. Total compensation expense recognized for these international plans was approximately $52 million in 2010, $51 million in 2009 and $53 million in 2008.
Share-Based Compensation Plans
The 2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by shareholders in May 2009. Over its 10-year life, the Plan allows the issuance of up to 70 million shares of our common stock for compensation to our employees, directors and consultants; however, as of the effective date of the Plan, (i) any shares of common stock available for future awards under the prior plans and (ii) any shares of common stock represented by awards granted under the prior plans that are forfeited, expire or are canceled without delivery of shares of common stock or which result in the forfeiture of shares of common stock back to the company shall be available for awards under the Plan, and no new awards shall be granted under the prior plans. Of the 70 million shares available for issuance under the Plan, no more than 40 million shares of common stock are available for incentive stock options, and no more than 40 million shares are available for awards in stock.
Our share-based compensation programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time of their retirement. For share-based awards granted prior to our adoption of SFAS No. 123(R), codified into FASB ASC Topic 718, “Compensation—Stock Compensation,” we recognize expense over the period of time during which the employee earns the award, accelerating the recognition of expense only when an employee actually retires. For share-based awards granted after our adoption of ASC 718 on January 1, 2006, we recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award); or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months, as this is the minimum period of time required for an award to not be subject to forfeiture.
Some of our share-based awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). For awards granted prior to our adoption of ASC 718 that vest ratably, we recognize expense on a straight-line basis over the service period for each separate vesting portion of the award (i.e., as if the award was multiple awards with different requisite service periods). For share-based awards granted after our adoption of ASC 718, we recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

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Total share-based compensation expense recognized in income and the associated tax benefit for the years ended December 31, were as follows:
                         
    Millions of Dollars  
    2010     2009     2008  
       
 
                       
Compensation cost
  $ 211       121       193  
Tax benefit
    78       42       67  
         
Stock Options— Stock options granted under the provisions of the Plan and earlier plans permit purchase of our common stock at exercise prices equivalent to the average market price of the stock on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third of the options awarded vesting and becoming exercisable on each anniversary date following the date of grant. Options awarded to employees already eligible for retirement vest within six months of the grant date, but those options do not become exercisable until the end of the normal vesting period.
The following summarizes our stock option activity for the three years ended December 31, 2010:
                                 
            Weighted-     Weighted-Average     Millions of Dollars  
            Average     Grant-Date     Aggregate  
    Options     Exercise Price     Fair Value     Intrinsic Value  
 
                               
Outstanding at December 31, 2007
    44,104,855     $ 32.06                  
Granted
    2,211,202       79.35     $ 18.66          
Exercised
    (9,493,818 )     28.39             $ 535  
Forfeited
    (184,148 )     73.91                  
Expired or canceled
    (22,338 )     42.65                  
           
Outstanding at December 31, 2008
    36,615,753     $ 35.65                  
Granted
    3,311,200       45.47     $ 11.18          
Exercised
    (2,919,118 )     24.10             $ 67  
Forfeited
    (332,941 )     52.04                  
Expired or canceled
    (241,421 )     63.49                  
           
Outstanding at December 31, 2009
    36,433,473     $ 37.13                  
Granted
    3,040,500       48.39     $ 11.70          
Exercised
    (6,401,483 )     29.08             $ 183  
Forfeited
    (255,889 )     48.42                  
Expired or canceled
    (204,727 )     58.94                  
           
Outstanding at December 31, 2010
    32,611,874     $ 39.54                  
           
Vested at December 31, 2010
    30,421,177     $ 38.45             $ 906  
             
Exercisable at December 31, 2010
    27,252,683     $ 37.39             $ 837  
             
The weighted-average remaining contractual term of vested options and exercisable options at December 31, 2010, was 3.56 years and 2.98 years, respectively.
During 2010, we received $168 million in cash and realized a tax benefit of $54 million from the exercise of options. At December 31, 2010, the remaining unrecognized compensation expense from unvested options was $15 million, which will be recognized over a weighted-average period of 17 months, the longest period being 25 months.

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The significant assumptions used to calculate the fair market values of the options granted over the past three years, as calculated using the Black-Scholes-Merton option-pricing model, were as follows:
                         
    2010     2009     2008  
     
Assumptions used
                       
Risk-free interest rate
    3.23 %     2.90       3.21  
Dividend yield
    4.00 %     3.50       2.50  
Volatility factor
    33.80 %     32.90       27.78  
Expected life (years)
    6.65       6.53       5.82  
         
The ranges in the assumptions used were as follows:
                                                 
    2010     2009     2008  
    High     Low     High     Low     High     Low  
                   
Ranges used
                                               
Risk-free interest rate
    3.23 %     3.23       2.90       2.90       3.45       2.27  
Dividend yield
    4.00       4.00       3.50       3.50       2.50       2.50  
Volatility factor
    33.80       33.80       32.90       32.90       32.10       26.70  
   
We calculate volatility using the most recent ConocoPhillips end-of-week closing stock prices spanning a period equal to the expected life of the options granted. We periodically calculate the average period of time lapsed between grant dates and exercise dates of past grants to estimate the expected life of new option grants.
Stock Unit Program— Stock units granted under the provisions of the Plan vest ratably, with one-third of the units vesting in 36 months, one-third vesting in 48 months, and the final third vesting 60 months from the date of grant. Upon vesting, the units are settled by issuing one share of ConocoPhillips common stock per unit. Units awarded to employees already eligible for retirement vest within six months of the grant date, but those units are not issued as shares until the end of the normal vesting period. Until issued as stock, most recipients of the units receive a quarterly cash payment of a dividend equivalent that is charged to expense. The grant date fair value of these units is deemed equal to the average ConocoPhillips stock price on the date of grant. The grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal to the average ConocoPhillips stock price on the grant date, less the net present value of the dividends that will not be received.
The following summarizes our stock unit activity for the three years ended December 31, 2010:
                         
            Weighted-Average     Millions of Dollars  
    Stock Units     Grant-Date Fair Value     Total Fair Value  
 
                       
Outstanding at December 31, 2007
    5,669,911     $ 51.28          
Granted
    1,797,803       77.42          
Forfeited
    (128,888 )     62.82          
Issued
    (1,411,128 )           $ 109  
           
Outstanding at December 31, 2008
    5,927,698     $ 61.14          
Granted
    2,910,095       43.41          
Forfeited
    (207,932 )     51.84          
Issued
    (1,910,309 )           $ 88  
           
Outstanding at December 31, 2009
    6,719,552     $ 57.08          
Granted
    2,890,010       46.38          
Forfeited
    (233,212 )     53.11          
Issued
    (1,573,487 )           $ 79  
           
Outstanding at December 31, 2010
    7,802,863     $ 53.04          
                 
Not Vested at December 31, 2010
    5,810,124     $ 52.97          
                   

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At December 31, 2010, the remaining unrecognized compensation cost from the unvested units was $165 million, which will be recognized over a weighted-average period of 25 months, the longest period being 49 months.
Performance Share Program— Under the Plan, we also annually grant to senior management restricted stock units that do not vest until either (i) with respect to awards for periods beginning before 2010, the employee becomes eligible for retirement by reaching age 55 with five years of service or (ii) with respect to awards for periods beginning in 2010, five years after the grant date of the award (although recipients can elect to defer the lapsing of restrictions until retirement after reaching age 55 with five years of service), so we recognize compensation expense for these awards beginning on the date of grant and ending on the date the units are scheduled to vest. Since these awards are authorized three years prior to the grant date, for employees eligible for such retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. These units are settled by issuing one share of ConocoPhillips common stock per unit. Until issued as stock, recipients of the units receive a quarterly cash payment of a dividend equivalent that is charged to expense. In its current form, the first grant of units under this program was in 2006.
The following summarizes our Performance Share Program activity for the three years ended December 31, 2010:
                         
    Performance     Weighted-Average     Millions of Dollars  
    Share Stock Units     Grant-Date Fair Value     Total Fair Value  
 
                       
Outstanding at December 31, 2007
    2,605,297     $ 62.49          
Granted
    1,291,453       79.38          
Forfeited
    (30,862 )     69.24          
Issued
    (689,710 )           $ 58  
           
Outstanding at December 31, 2008
    3,176,178     $ 68.13          
Granted
    659,812       45.47          
Forfeited
    (23,670 )     65.00          
Issued
    (407,442 )           $ 19  
           
Outstanding at December 31, 2009
    3,404,878     $ 64.63          
Granted
    317,072       48.39          
Forfeited
    (53,243 )     62.66          
Issued
    (234,121 )           $ 12  
           
Outstanding at December 31, 2010
    3,434,586     $ 63.43          
                 
Not Vested at December 31, 2010
    1,075,496     $ 35.17          
                   
At December 31, 2010, the remaining unrecognized compensation cost from unvested Performance Share awards was $38 million, which will be recognized over a weighted-average period of 42 months, the longest period being 16 years.
Other— In addition to the above active programs, we have outstanding shares of restricted stock and restricted stock units that were either issued to replace awards held by employees of companies we acquired or issued as part of a compensation program that has been discontinued. Generally, the recipients of the restricted shares or units receive a quarterly dividend or dividend equivalent.

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The following summarizes the aggregate activity of these restricted shares and units for the three years ended December 31, 2010:
                         
            Weighted-Average     Millions of Dollars  
    Stock Units     Grant-Date Fair Value     Total Fair Value  
 
                       
Outstanding at December 31, 2007
    3,487,144     $ 34.41          
Granted
    237,642       78.59          
Issued
    (128,803 )           $ 9  
Canceled
    (231,963 )     40.08          
           
Outstanding at December 31, 2008
    3,364,020     $ 36.75          
Granted
    78,299       45.72          
Issued
    (204,160 )           $ 10  
Canceled
    (101,642 )     52.91          
           
Outstanding at December 31, 2009
    3,136,517     $ 35.11          
Granted
    73,395       53.33          
Issued
    (181,035 )           $ 9  
Canceled
    (58,441 )     44.23          
           
Outstanding at December 31, 2010
    2,970,436     $ 34.06          
                   
Not Vested at December 31, 2010
    114,860     $ 79.38          
                   
At December 31, 2010, the remaining unrecognized compensation cost from the unvested units was $0.3 million, which was recognized by February 2011.
Compensation and Benefits Trust
The Compensation and Benefits Trust (CBT) is an irrevocable grantor trust, administered by an independent trustee and designed to acquire, hold and distribute shares of our common stock to fund certain future compensation and benefit obligations of the company. The CBT does not increase or alter the amount of benefits or compensation that will be paid under existing plans, but offers us enhanced financial flexibility in providing the funding requirements of those plans. We also have flexibility in determining the timing of distributions of shares from the CBT to fund compensation and benefits, subject to a minimum distribution schedule. The trustee votes shares held by the CBT in accordance with voting directions from eligible employees, as specified in a trust agreement with the trustee.
We sold 58.4 million shares of previously unissued company common stock to the CBT in 1995 for $37 million of cash, previously contributed to the CBT by us, and a promissory note from the CBT to us of $952 million. The CBT is consolidated by ConocoPhillips; therefore, the cash contribution and promissory note are eliminated in consolidation. Shares held by the CBT are valued at cost and do not affect earnings per share or total common stockholders’ equity until after they are transferred out of the CBT. In 2010 and 2009, shares transferred out of the CBT were 1,776,873 and 2,018,692, respectively. At December 31, 2010, the CBT had 36.7 million shares remaining. All shares are required to be transferred out of the CBT by January 1, 2021. The CBT, together with two smaller grantor trusts, comprise the “Grantor trusts” line in the equity section of the consolidated balance sheet.

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Note 20—Income Taxes
Income taxes charged to income (loss) were:
                           
    Millions of Dollars  
    2010     2009     2008  
Income Taxes
                       
Federal
                       
Current
  $ 1,312       575       3,245  
Deferred
    781       52       (227 )
Foreign
                       
Current
    7,469       5,584       10,268  
Deferred*
    (1,546 )     (1,245 )     (298 )
State and local
                       
Current
    320       82       543  
Deferred
    (3 )     42       (112 )
   
 
  $ 8,333       5,090       13,419  
   
*2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:
                 
    Millions of Dollars  
    2010     2009  
Deferred Tax Liabilities
               
Properties, plants and equipment, and intangibles
  $ 20,344       21,281  
Investment in joint ventures
    2,201       2,039  
Inventory
    43       13  
Partnership income deferral
    434       660  
Other*
    586       807  
       
Total deferred tax liabilities*
    23,608       24,800  
       
Deferred Tax Assets
               
Benefit plan accruals
    1,691       1,802  
Asset retirement obligations and accrued environmental costs
    3,971       3,874  
Deferred state income tax
    257       251  
Other financial accruals and deferrals
    394       465  
Loss and credit carryforwards
    1,344       2,105  
Other
    717       484  
       
Total deferred tax assets
    8,374       8,981  
Less valuation allowance
    (1,400 )     (1,540 )
   
Net deferred tax assets
    6,974       7,441  
   
Net deferred tax liabilities*
  $ 16,634       17,359  
       
*2009 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
Current assets, long-term assets, current liabilities and long-term liabilities included deferred taxes of $562 million, $160 million, $21 million and $17,335 million, respectively, at December 31, 2010, and $581 million, $21 million, $5 million and $17,956 million, respectively, at December 31, 2009.
We have loss and credit carryovers in multiple taxing jurisdictions. These attributes generally expire between 2011 and 2030 with some carryovers having indefinite carryforward periods.

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Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. During 2010, valuation allowances decreased a total of $140 million. This reflects decreases of $554 million primarily related to utilization of U.S. foreign tax credit and foreign loss carryforwards, partially offset by increases of $414 million, primarily related to foreign tax loss carryforwards and unrealized foreign exchange losses. Based on our historical taxable income, expectations for the future, and available tax-planning strategies, management expects remaining net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as offsets to the tax consequences of future taxable income.
At December 31, 2010 and 2009, income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled approximately $4,134 million and $2,129 million, respectively. Deferred income taxes have not been provided on this income, as we do not plan to initiate any action that would require the payment of income taxes. It is not practicable to estimate the amount of additional tax that might be payable on this foreign income if distributed.
The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2010, 2009 and 2008:
                         
    Millions of Dollars  
    2010     2009     2008  
       
Balance at January 1
  $ 1,208       1,068       1,143  
Additions based on tax positions related to the current year
    63       18       7  
Additions for tax positions of prior years
    344       177       186  
Reductions for tax positions of prior years
    (199 )     (33 )     (249 )
Settlements
    (215 )     (19 )     (16 )
Lapse of statute
    (76 )     (3 )     (3 )
   
Balance at December 31
  $ 1,125       1,208       1,068  
   
Included in the balance of unrecognized tax benefits for 2010, 2009 and 2008 were $914 million, $931 million and $862 million, respectively, which, if recognized, would affect our effective tax rate.
At December 31, 2010, 2009 and 2008, accrued liabilities for interest and penalties totaled $171 million, $166 million and $147 million, respectively, net of accrued income taxes. Interest and penalties benefitted earnings in 2010 by $2 million, and resulted in a charge to earnings in 2009 and 2008 of $18 million and $25 million, respectively.
We and our subsidiaries file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in major jurisdictions are generally complete as follows: United Kingdom (2007), Canada (2005), United States (2006) and Norway (2008). Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion in the many jurisdictions in which we operate around the world. As a consequence, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably possible such changes could be significant when compared with our total unrecognized tax benefits, but the amount of change is not estimable.

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The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:
                                                 
                            Percent of  
    Millions of Dollars     Pretax Income  
    2010     2009 *   2008 *   2010     2009 *   2008 *
             
Income (loss) before income taxes
                                               
United States
  $ 6,214       2,456       10,055       31.5 %     25.6       (351.6 )
Foreign
    13,536       7,126       12,528       68.5       74.4       (438.0 )
Goodwill impairment
    -       -       (25,443 )     -       -       889.6  
   
 
  $ 19,750       9,582       (2,860 )     100.0 %     100.0       100.0  
   
                                                 
Federal statutory income tax
  $ 6,912       3,354       (1,001 )     35.0 %     35.0       35.0  
Goodwill impairment
    -       -       8,905       -       -       (311.4 )
Foreign taxes in excess of federal statutory rate
    1,308       1,716       5,452       6.6       17.9       (190.6 )
Federal manufacturing deduction
    (82 )     (19 )     (182 )     (0.4 )     (0.2 )     6.4  
State income tax
    206       81       280       1.0       0.8       (9.8 )
Other
    (11 )     (42 )     (35 )     -       (0.4 )     1.2  
   
 
  $ 8,333       5,090       13,419       42.2 %     53.1       (469.2 )
   
*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
The change in the effective tax rate from 2009 was primarily due to the effect of asset dispositions in 2010 and a higher proportion of income in higher tax jurisdictions in 2009, offset in part by the effect of asset impairments occurring in 2010.
Statutory tax rate changes did not have a significant impact on our income tax expense in 2010, 2009 or 2008.

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Note 21—Other Comprehensive Income (Loss)
The components and allocated tax effects of other comprehensive income (loss) follow:
                         
    Millions of Dollars  
            Tax Expense        
    Before-Tax     (Benefit )   After-Tax  
2010
                       
Defined benefit pension plans:
                       
Prior service cost arising during the year
  $ (13 )     (4 )     (9 )
Reclassification adjustment for amortization of prior service cost
included in net income
    15       6       9  
   
Net prior service cost
    2       2       -  
   
Net loss arising during the year
    (9 )     (7 )     (2 )
Reclassification adjustment for amortization of prior net losses included
in net income
    215       80       135  
   
Net actuarial gain
    206       73       133  
   
Nonsponsored plans*
    5       (8 )     13  
   
Unrealized holding gain arising during the year
    631       228       403  
Reclassification adjustment for gain included in net income
    (384 )     (139 )     (245 )
   
Net unrealized gain on securities**
    247       89       158  
   
Foreign currency translation adjustments
    1,417       13       1,404  
   
Other comprehensive income
  $ 1,877       169       1,708  
   
 
                       
2009
                       
Defined benefit pension plans:
                       
Prior service cost arising during the year
  $ -       -       -  
Reclassification adjustment for amortization of prior service cost
included in net income
    21       14       7  
   
Net prior service cost
    21       14       7  
   
Net loss arising during the year
    (388 )     (160 )     (228 )
Reclassification adjustment for amortization of prior net losses included
in net income
    206       77       129  
   
Net actuarial loss
    (182 )     (83 )     (99 )
   
Nonsponsored plans*
    39       17       22  
Foreign currency translation adjustments
    5,092       85       5,007  
Hedging activities
    (2 )     (5 )     3  
   
Other comprehensive income
  $ 4,968       28       4,940  
   
 
                       
2008
                       
Defined benefit pension plans:
                       
Prior service cost arising during the year
  $ 30       22       8  
Reclassification adjustment for amortization of prior service cost
included in net loss
    22       8       14  
   
Net prior service cost
    52       30       22  
   
Net loss arising during the year
    (1,523 )     (535 )     (988 )
Reclassification adjustment for amortization of prior net losses included
in net loss
    64       26       38  
   
Net actuarial loss
    (1,459 )     (509 )     (950 )
   
Nonsponsored plans*
    (41 )     -       (41 )
Foreign currency translation adjustments
    (5,552 )     (88 )     (5,464 )
Hedging activities
    (4 )     (2 )     (2 )
   
Other comprehensive loss
  $ (7,004 )     (569 )     (6,435 )
   
* Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.
** Available-for-sale securities of LUKOIL.

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Deferred taxes have not been provided on temporary differences related to foreign currency translation adjustments for investments in certain foreign subsidiaries and foreign corporate joint ventures that are considered permanent in duration.
Accumulated other comprehensive income in the equity section of the balance sheet included:
                 
    Millions of Dollars  
    2010     2009  
 
               
Defined benefit pension liability adjustments
  $ (1,358 )     (1,504 )
Net unrealized gain on securities
    158       -  
Foreign currency translation adjustments
    5,980       4,576  
Deferred net hedging loss
    (7 )     (7 )
   
Accumulated other comprehensive income
  $ 4,773       3,065  
       
Note 22—Cash Flow Information
                         
    Millions of Dollars  
    2010     2009     2008  
Noncash Investing and Financing Activities
                       
Increase in PP&E related to an increase in asset retirement obligations
  $ 808       974       1,117  
         
 
                       
Cash Payments
                       
Interest
  $ 1,210       998       858  
Income taxes
    8,474       6,641       13,122  
         

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Note 23—Other Financial Information
                         
    Millions of Dollars  
    Except Per Share Amounts  
    2010     2009     2008  
Interest and Debt Expense
                       
Incurred
                       
Debt
  $ 1,414       1,485       1,189  
Other
    244       291       314  
   
 
    1,658       1,776       1,503  
Capitalized
    (471 )     (487 )     (568 )
   
Expensed
  $ 1,187       1,289       935  
   
 
                       
Other Income
                       
Interest income
  $ 187       227       245  
Other, net
    91       131       (46 )
   
 
  $ 278       358       199  
   
 
                       
Research and Development Expenditures— expensed
  $ 230       190       209  
   
 
                       
Advertising Expenses
  $ 66       60       96  
   
 
                       
Shipping and Handling Costs*
  $ 1,366       1,185       1,443  
   
*Amounts included in production and operating expenses.
 
                       
Cash Dividends paid per common share
  $ 2.15       1.91       1.88  
   
 
                       
Foreign Currency Transaction (Gains) Losses— after-tax
                       
E&P
  $ (60 )     111       (216 )
Midstream
    -       -       (1 )
R&M
    60       (36 )     173  
LUKOIL Investment
    15       (20 )     27  
Chemicals
    -       -       -  
Emerging Businesses
    1       (2 )     7  
Corporate and Other
    15       (97 )     72  
   
 
  $ 31       (44 )     62  
   

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Note 24—Related Party Transactions
Significant transactions with related parties were:
                         
    Millions of Dollars  
    2010     2009     2008  
 
                       
Operating revenues and other income (a)
  $ 7,333       7,200       13,097  
Gain on dispositions (b)
    1,149       -       -  
Purchases (c)
    15,819       12,779       19,409  
Operating expenses and selling, general and administrative expenses (d)
    344       322       515  
Net interest expense (e)
    73       74       66  
   
(a)   We sold natural gas to DCP Midstream and crude oil to the Malaysian Refining Company Sdn. Bhd. (MRC), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks were sold to CPChem, gas oil and hydrogen feedstocks were sold to Excel Paralubes and refined products were sold primarily to CFJ Properties and LUKOIL. Beginning in the third quarter of 2010, CFJ was no longer considered a related party due to the sale of our interest. Natural gas, crude oil, blendstock and other intermediate products were sold to WRB Refining LP. In addition, we charged several of our affiliates, including CPChem and MSLP, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.
 
(b)   During 2010, we sold a portion of our LUKOIL shares under a stock purchase and option agreement with a wholly owned subsidiary of LUKOIL, resulting in a before-tax gain of $1,149 million.
 
(c)   We purchased refined products from WRB. We purchased natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased crude oil from LUKOIL and refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products and natural gas, as well as a price upgrade to MSLP for heavy crude processing. We purchased base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses.
 
(d)   We paid processing fees to various affiliates. Additionally, we paid transportation fees to pipeline equity companies.
 
(e)   We paid and/or received interest to/from various affiliates, including FCCL Partnership. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.
Beginning in the fourth quarter of 2010, transactions with LUKOIL and its subsidiaries were no longer considered related party transactions. See Note 6—Investments, Loans and Long-Term Receivables, for additional information.

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Note 25—Segment Disclosures and Related Information
We have organized our reporting structure based on the grouping of similar products and services, resulting in six operating segments:
  1)   E&P—This segment primarily explores for, produces, transports and markets crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. 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’s U.S. and international operations are disclosed separately for reporting purposes.
 
  2)   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.
 
  3)   R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At December 31, 2010, we owned or had an interest in 12 refineries in the United States, one in the United Kingdom, one in Ireland, two in Germany, and one in Malaysia. The R&M segment’s U.S. and international operations are disclosed separately for reporting purposes.
 
  4)   LUKOIL Investment—This segment represents our investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. At December 31, 2010, our ownership interest was 2.25 percent based on issued shares. See Note 6—Investments, Loans and Long-Term Receivables, for information on sales of LUKOIL shares.
 
  5)   Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in CPChem.
 
  6)   Emerging Businesses—This 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.
Corporate and Other includes general corporate overhead, most interest expense and various other corporate activities. Corporate assets include all cash and cash equivalents and short-term investments.
We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Segment accounting policies are the same as those in Note 1—Accounting Policies. Intersegment sales are at prices that approximate market.

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Analysis of Results by Operating Segment
                         
    Millions of Dollars  
    2010     2009     2008  
Sales and Other Operating Revenues
                       
E&P*
                       
United States
  $ 28,934       24,287       51,378  
International
    27,992       24,222       36,972  
Intersegment eliminations—U.S.
    (5,653 )     (4,649 )     (8,034 )
Intersegment eliminations—international
    (7,748 )     (6,763 )     (10,498 )
   
E&P
    43,525       37,097       69,818  
   
Midstream
                       
Total sales
    7,714       5,199       6,791  
Intersegment eliminations
    (407 )     (307 )     (227 )
   
Midstream
    7,307       4,892       6,564  
   
R&M*
                       
United States
    94,564       73,871       117,727  
International
    44,721       34,025       47,520  
Intersegment eliminations—U.S.
    (763 )     (613 )     (965 )
Intersegment eliminations—international
    (101 )     (50 )     (52 )
   
R&M
    138,421       107,233       164,230  
   
LUKOIL Investment
    -       -       -  
   
Chemicals
    11       11       11  
   
Emerging Businesses
                       
Total sales
    746       593       1,060  
Intersegment eliminations
    (595 )     (507 )     (861 )
   
Emerging Businesses
    151       86       199  
   
Corporate and Other
    26       22       20  
   
Consolidated sales and other operating revenues
  $   189,441       149,341       240,842  
   
*2010 includes $20,344 million in our E&P and R&M segments which resulted from transactions with a single, external customer.
                         
Depreciation, Depletion, Amortization and Impairments
E&P
                       
United States
  $ 2,909       3,346       3,725  
International
    5,268       5,459       5,096  
Goodwill impairment
    -       -       25,443  
   
Total E&P
    8,177       8,805       34,264  
   
Midstream
    6       6       6  
   
R&M
                       
United States
    711       707       1,129  
International
    1,789       215       425  
   
Total R&M
    2,500       922       1,554  
   
LUKOIL Investment*
    -       -       7,496  
Chemicals
    -       -       -  
Emerging Businesses
    78       21       193  
Corporate and Other
    79       76       124  
   
Consolidated depreciation, depletion, amortization and impairments
  $ 10,840       9,830       43,637  
   
* 2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

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    Millions of Dollars  
    2010     2009     2008  
Equity in Earnings of Affiliates
                       
E&P
                       
United States
  $ 39       (2 )     57  
International
    (14 )     233       235  
   
Total E&P
    25       231       292  
   
Midstream
    411       342       810  
   
R&M
                       
United States
    607       428       836  
International
    113       13       178  
   
Total R&M
    720       441       1,014  
   
LUKOIL Investment*
    1,295       1,219       2,760 (1)
Chemicals
    684       298       128  
Emerging Businesses
    (2 )     -       (5 )
Corporate and Other
    -       -       -  
   
Consolidated equity in earnings of affiliates
  $ 3,133       2,531       4,999  
   
(1) Does not include a $7,496 million impairment of our LUKOIL investment which is presented as a separate line item in the consolidated statement of operations.
                         
Income Taxes
                       
E&P
                       
United States
  $ 1,570       786       2,617  
International
    6,124       4,325       9,621  
   
Total E&P
    7,694       5,111       12,238  
   
Midstream
    158       171       261  
   
R&M
                       
United States
    645       32       934  
International
    (414 )     9       214  
   
Total R&M
    231       41       1,148  
   
LUKOIL Investment*
    514       12       63  
Chemicals
    182       47       15  
Emerging Businesses
    (54 )     (16 )     (6 )
Corporate and Other
    (392 )     (276 )     (300 )
   
Consolidated income taxes
  $ 8,333       5,090       13,419  
   
 
                       
Net Income (Loss) Attributable to ConocoPhillips
                       
E&P
                       
United States
  $ 2,768       1,503       4,988  
International
    6,430       2,101       6,976  
Goodwill impairment
    -       -       (25,443 )
   
Total E&P
    9,198       3,604       (13,479 )
   
Midstream
    306       313       541  
   
R&M
                       
United States
    1,022       (192 )     1,540  
International
    (830 )     229       782  
   
Total R&M
    192       37       2,322  
   
LUKOIL Investment*
    2,503       1,219       (4,839 )
Chemicals
    498       248       110  
Emerging Businesses
    (59 )     3       30  
Corporate and Other
    (1,280 )     (1,010 )     (1,034 )
   
Consolidated net income (loss) attributable to ConocoPhillips
  $ 11,358       4,414       (16,349 )
   
* 2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

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    Millions of Dollars  
    2010     2009     2008  
Investments In and Advances To Affiliates
                       
E&P
                       
United States
  $ 1,989       1,978       1,368  
International
    21,049       19,646       16,772  
   
Total E&P
    23,038       21,624       18,140  
   
Midstream
    1,240       1,199       1,033  
   
R&M
                       
United States
    4,059       3,982       3,677  
International
    1,304       1,142       1,326  
   
Total R&M
    5,363       5,124       5,003  
   
LUKOIL Investment*
    -       6,411       5,452  
Chemicals
    2,518       2,446       2,186  
Emerging Businesses
    76       77       75  
Corporate and Other
    -       -       -  
   
Consolidated investments in and advances to affiliates (1)
  $    32,235       36,881       31,889  
   
(1) Includes amounts classified as held for sale:
  $ -       249       2  
                         
Total Assets
                       
E&P
                       
United States
  $ 35,607       36,122       36,962  
International
    63,086       64,831       58,912  
   
Total E&P
    98,693       100,953       95,874  
   
Midstream
    2,506       2,054       1,455  
   
R&M
                       
United States
    26,028       24,963       22,554  
International
    8,463       8,446       7,942  
Goodwill
    3,633       3,638       3,778  
   
Total R&M
    38,124       37,047       34,274  
   
LUKOIL Investment*
    1,129       6,416       5,455  
Chemicals
    2,732       2,451       2,217  
Emerging Businesses
    964       1,069       924  
Corporate and Other
    12,166       2,148       2,666  
   
Consolidated total assets
  $ 156,314       152,138       142,865  
   
                         
Capital Expenditures and Investments
                       
E&P
                       
United States
  $ 2,585       3,474       5,250  
International
    5,908       5,425       11,206  
   
Total E&P
    8,493       8,899       16,456  
   
Midstream
    3       5       4  
   
R&M
                       
United States
    790       1,299       1,643  
International
    266       427       626  
   
Total R&M
    1,056       1,726       2,269  
   
LUKOIL Investment
    -       -       -  
Chemicals
    -       -       -  
Emerging Businesses
    27       97       156  
Corporate and Other
    182       134       214  
   
Consolidated capital expenditures and investments
  $ 9,761       10,861       19,099  
   
* 2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

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    Millions of Dollars  
    2010     2009     2008  
Interest Income and Expense
                       
Interest income
                       
Corporate
  $ 64       89       128  
E&P
    81       91       115  
R&M
    42       47       2  
         
Interest and debt expense
                       
Corporate
  $ 1,047       1,133       762  
E&P
    140       156       173  
         
Geographic Information
                                                 
    Millions of Dollars  
    Sales and Other Operating Revenues (1)     Long-Lived Assets (2)  
    2010     2009     2008     2010     2009     2008  
 
       
United States
  $ 124,173       97,674       166,496       53,706       53,761       52,972  
Australia (3)
    2,789       2,229       2,735       12,461       10,729       8,656  
Canada
    4,784       3,617       5,226       20,439       22,451       20,429  
Norway
    2,248       1,749       3,036       5,664       5,797       5,002  
Russia (4)
    -       -       -       815       8,383       7,604  
United Kingdom
    26,693       20,671       29,699       4,885       5,778       5,844  
Other foreign countries
    28,754       23,401       33,650       16,819       17,441       15,919  
               
Worldwide consolidated
  $   189,441       149,341       240,842       114,789       124,340       116,426  
               
(1) Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues.
 
(2) Defined as net properties, plants and equipment plus investments in and advances to affiliated companies.
 
(3) Includes amounts related to the joint petroleum development area with shared ownership held by Australia and Timor-Leste.
 
(4) 2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

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Oil and Gas Operations (Unaudited)
In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the U.S. Securities and Exchange Commission (SEC), we are making certain supplemental disclosures about our oil and gas exploration and production operations.
These disclosures include information about our consolidated oil and gas activities and our proportionate share of our equity affiliates’ oil and gas activities, covering both those in our Exploration and Production (E&P) segment, as well as in our LUKOIL Investment segment. As a result, amounts reported as Equity Affiliates in Oil and Gas Operations may differ from those shown in the individual segment disclosures reported elsewhere in this report.
Our proved reserves include estimated quantities related to production sharing contracts (PSCs), which are reported under the “economic interest” method and are subject to fluctuations in prices of crude oil, natural gas and natural gas liquids; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. At December 31, 2010, approximately 12 percent of our total proved reserves were under PSCs, primarily in our Asia Pacific/Middle East geographic reporting area.
Our disclosures by geographic area include the United States, Canada, Europe (primarily Norway and the United Kingdom), Russia, Asia Pacific/Middle East, Africa, and Other Areas. Other Areas primarily consists of the Caspian Region.
On December 31, 2008, the SEC issued its final rules to modernize the supplemental oil and gas disclosures, and in January 2010, the FASB issued Accounting Standards Update No. 2010-03, “Oil and Gas Reserve Estimation and Disclosures.” As a result of these two new rules, our disclosures reflect the expanded definitions for oil and gas producing activities, including nontraditional resources such as Syncrude operations. The inclusion of Syncrude as part of our oil and gas producing activities, effective January 1, 2009, did not have a significant impact on our disclosures. In the following disclosures, the synthetic oil classification includes Syncrude mining operations, and the bitumen classification includes our Surmont operations and the FCCL Partnership. In June 2010, we sold our interest in the Syncrude Canada Ltd. joint venture; accordingly, as of December 31, 2010, we no longer held synthetic oil reserves.
Two items occurred during 2010 that impact the disclosure of our investment in OAO LUKOIL in the supplemental oil and gas disclosures:
    Effective January 1, 2010, we changed the method used to determine our equity-method share of LUKOIL’s earnings. Prior to 2010, we estimated our LUKOIL equity earnings for the current quarter. Beginning in 2010, we implemented a change in accounting principle to record our LUKOIL equity earnings on a one-quarter-lag basis. Prior periods have been recast to reflect this change, including those in the supplemental oil and gas disclosures (other than the proved reserves tables, which continue to reflect LUKOIL on a current basis).
 
    On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL over a period of time through the end of 2011. As a result of this sell down of our interest, at the end of the third quarter of 2010 we ceased using equity-method accounting for our investment in LUKOIL. Accordingly, the supplemental oil and gas disclosures reflect activity for LUKOIL through June 30, 2010, which, on a lag basis, results in three quarters of activity being included in the year 2010 (the fourth quarter of 2009 and the first two quarters of 2010). Since the proved reserves tables are not on a lag basis, they reflect activity for the first three quarters of 2010, at which point LUKOIL’s reserves were removed from our reserve quantities.

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See Note 2—Changes in Accounting Principles, and Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for more information about both of these items.
Reserves Governance
The recording and reporting of proved reserves are governed by criteria established by regulations of the SEC and FASB. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
We have a companywide, comprehensive, SEC-compliant internal policy that governs the determination and reporting of proved reserves. This policy is applied by the geologists and reservoir engineers in our E&P business units around the world. As part of our internal control process, each business unit’s reserves are reviewed annually by an internal team which is headed by the company’s Manager of Reserves Compliance and Reporting. This team, composed of internal reservoir engineers, geologists and finance personnel, reviews the business units’ reserves for adherence to SEC guidelines and company policy through on-site visits and review of documentation. In addition to providing independent reviews, this internal team also ensures reserves are calculated using consistent and appropriate standards and procedures. This team is independent of business unit line management and is responsible for reporting its findings to senior management and our internal audit group. The team is responsible for maintaining and communicating our reserves policy and procedures and is available for internal peer reviews and consultation on major projects or technical issues throughout the year. All of our proved reserves held by consolidated companies and our share of equity affiliates have been estimated by ConocoPhillips.
The technical person primarily responsible for overseeing the preparation of the company’s reserve estimates is the Manager of Reserves Compliance and Reporting. This individual is a petroleum engineer with a bachelor’s degree in petroleum engineering. He is an active member of the Society of Petroleum Engineers (SPE) with over 30 years of oil and gas industry experience, including drilling and production engineering assignments in several field locations. He is currently serving a three-year term on the Oil & Gas Reserves Committee of the SPE and has held positions of increasing responsibility in reservoir engineering, reserves reporting and compliance, and business management.

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During 2010, our processes and controls used to assess over 90 percent of proved reserves as of December 31, 2010, were reviewed by DeGolyer and MacNaughton (D&M), a third-party petroleum engineering consulting firm. The purpose of their review was to assess whether the adequacy and effectiveness of our internal processes and controls used to determine estimates of proved reserves are in accordance with SEC regulations. In such review, ConocoPhillips’ technical staff presented D&M with an overview of the reserves data, as well as the methods and assumptions used in estimating reserves. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures and relevant economic criteria. Management’s intent in retaining D&M to review its processes and controls was to provide objective third-party input on these processes and controls. D&M’s opinion was that the general processes and controls employed by ConocoPhillips in estimating its December 31, 2010, proved reserves for the properties reviewed are in accordance with the SEC reserves definitions. D&M’s report is included as Exhibit 99 of this Annual Report on Form 10-K.
Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical Accounting Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the sensitivities surrounding these estimates.

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Proved Reserves
                                                                                 
Years Ended   Crude Oil and Natural Gas Liquids
December 31   Millions of Barrels
            Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
     
Developed and Undeveloped
                                                                               
Consolidated operations
                                                                               
End of 2007
    1,468       774       2,242       101       643       -       375       291       126       3,778  
Revisions
    (206 )     (17 )     (223 )     4       (16 )     -       15       15       9       (196 )
Improved recovery
    23       5       28       -       -       -       -       -       -       28  
Purchases
    -       -       -       -       -       -       -       -       -       -  
Extensions and discoveries
    13       25       38       4       9       -       13       5       -       69  
Production
    (96 )     (61 )     (157 )     (16 )     (84 )     -       (39 )     (29 )     (3 )     (328 )
Sales
    -       -       -       -       -       -       -       -       (11 )     (11 )
   
End of 2008
    1,202       726       1,928       93       552       -       364       282       121       3,340  
Revisions
    84       1       85       -       29       -       (12 )     10       (8 )     104  
Improved recovery
    13       2       15       -       -       -       2       -       -       17  
Purchases
    -       -       -       -       -       -       -       -       -       -  
Extensions and discoveries
    14       17       31       3       7       -       26       3       -       70  
Production
    (93 )     (60 )     (153 )     (15 )     (87 )     -       (48 )     (28 )     -       (331 )
Sales
    -       (1 )     (1 )     -       -       -       -       -       (5 )     (6 )
   
End of 2009
    1,220       685       1,905       81       501       -       332       267       108       3,194  
Revisions
    81       8       89       15       28       -       7       21       -       160  
Improved recovery
    51       2       53       -       -       -       5       -       -       58  
Purchases
    -       1       1       -       -       -       -       -       -       1  
Extensions and discoveries
    17       30       47       4       18       -       7       10       -       86  
Production
    (84 )     (55 )     (139 )     (14 )     (78 )     -       (51 )     (28 )     -       (310 )
Sales
    -       (22 )     (22 )     (6 )     -       -       -       -       -       (28 )
   
End of 2010
    1,285       649       1,934       80       469       -       300       270       108       3,161  
   
 
                                                                               
Equity affiliates
                                                                               
End of 2007
    -       -       -       -       -       1,725       109       -       -       1,834  
Revisions
    -       -       -       -       -       (36 )     -       -       -       (36 )
Improved recovery
    -       -       -       -       -       -       -       -       -       -  
Purchases
    -       -       -       -       -       2       -       -       -       2  
Extensions and discoveries
    -       -       -       -       -       71       -       -       -       71  
Production
    -       -       -       -       -       (153 )     -       -       -       (153 )
Sales
    -       -       -       -       -       (41 )     -       -       -       (41 )
   
End of 2008
    -       -       -       -       -       1,568       109       -       -       1,677  
Revisions
    -       -       -       -       -       33       (3 )     -       -       30  
Improved recovery
    -       -       -       -       -       54       -       -       -       54  
Purchases
    -       -       -       -       -       21       -       -       -       21  
Extensions and discoveries
    -       -       -       -       -       94       -       -       -       94  
Production
    -       -       -       -       -       (166 )     -       -       -       (166 )
Sales
    -       -       -       -       -       -       -       -       -       -  
   
End of 2009
    -       -       -       -       -       1,604       106       -       -       1,710  
Revisions
    -       -       -       -       -       6       51       -       -       57  
Improved recovery
    -       -       -       -       -       -       -       -       -       -  
Purchases
    -       -       -       -       -       -       -       -       -       -  
Extensions and discoveries
    -       -       -       -       -       -       -       -       -       -  
Production
    -       -       -       -       -       (114 )     (1 )     -       -       (115 )
Sales
    -       -       -       -       -       (1,421 )     -       -       -       (1,421 )
   
End of 2010
    -       -       -       -       -       75       156       -       -       231  
   
 
                                                                               
Total company
                                                                               
End of 2007
    1,468       774       2,242       101       643       1,725       484       291       126       5,612  
End of 2008
    1,202       726       1,928       93       552       1,568       473       282       121       5,017  
End of 2009
    1,220       685       1,905       81       501       1,604       438       267       108       4,904  
End of 2010
    1,285       649       1,934       80       469       75       456       270       108       3,392  
   

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Years Ended   Crude Oil and Natural Gas Liquids
December 31   Millions of Barrels
            Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
     
Developed
                                                                               
Consolidated operations
                                                                               
End of 2007
    1,371       624       1,995       87       370       -       200       260       9       2,921  
End of 2008
    1,104       572       1,676       85       342       -       217       264       6       2,590  
End of 2009
    1,130       558       1,688       77       312       -       221       246       -       2,544  
End of 2010
    1,155       534       1,689       75       290       -       218       251       -       2,523  
   
 
                                                                               
Equity affiliates
                                                                               
End of 2007
    -       -       -       -       -       1,354       -       -       -       1,354  
End of 2008
    -       -       -       -       -       1,228       -       -       -       1,228  
End of 2009
    -       -       -       -       -       1,213       -       -       -       1,213  
End of 2010
    -       -       -       -       -       73       156       -       -       229  
   
 
                                                                               
Undeveloped
                                                                               
Consolidated operations
                                                                               
End of 2007
    97       150       247       14       273       -       175       31       117       857  
End of 2008
    98       154       252       8       210       -       147       18       115       750  
End of 2009
    90       127       217       4       189       -       111       21       108       650  
End of 2010
    130       115       245       5       179       -       82       19       108       638  
   
 
                                                                               
Equity affiliates
                                                                               
End of 2007
    -       -       -       -       -       371       109       -       -       480  
End of 2008
    -       -       -       -       -       340       109       -       -       449  
End of 2009
    -       -       -       -       -       391       106       -       -       497  
End of 2010
    -       -       -       -       -       2       -       -       -       2  
   
Notable changes in proved crude oil and natural gas liquids reserves in the three years ended December 31, 2010, included:
    Revisions : In 2009 and 2008, revisions in Alaska were primarily due to higher prices in 2009, versus 2008; and lower prices in 2008, compared with 2007, respectively.
 
    Sales : In 2010 for our equity affiliates in Russia, sales were primarily due to the disposition of our interest in LUKOIL.

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Years Ended   Natural Gas
December 31   Billions of Cubic Feet
            Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
     
Developed and Undeveloped
                                                                               
Consolidated operations
                                                                               
End of 2007
    3,431       9,203       12,634       2,838       2,583       -       3,251       1,030       163       22,499  
Revisions
    (852 )     (270 )     (1,122 )     45       119       -       249       19       (1 )     (691 )
Improved recovery
    15       2       17       -       -       -       -       -       -       17  
Purchases
    -       13       13       -       -       -       -       -       -       13  
Extensions and discoveries
    2       273       275       118       45       -       3       -       -       441  
Production
    (108 )     (788 )     (896 )     (385 )     (391 )     -       (249 )     (51 )     (5 )     (1,977 )
Sales
    -       (1 )     (1 )     (2 )     (53 )     -       (17 )     -       (69 )     (142 )
   
End of 2008
    2,488       8,432       10,920       2,614       2,303       -       3,237       998       88       20,160  
Revisions
    400       126       526       (23 )     19       -       (94 )     (2 )     (32 )     394  
Improved recovery
    3       -       3       -       -       -       -       -       -       3  
Purchases
    -       -       -       2       -       -       -       -       -       2  
Extensions and discoveries
    -       146       146       95       24       -       54       -       -       319  
Production
    (111 )     (739 )     (850 )     (388 )     (337 )     -       (285 )     (46 )     -       (1,906 )
Sales
    -       (3 )     (3 )     (4 )     -       -       -       -       -       (7 )
   
End of 2009
    2,780       7,962       10,742       2,296       2,009       -       2,912       950       56       18,965  
Revisions
    155       365       520       309       86       -       (39 )     36       -       912  
Improved recovery
    24       1       25       -       -       -       -       -       -       25  
Purchases
    -       9       9       -       -       -       -       -       -       9  
Extensions and discoveries
    4       122       126       84       89       -       24       -       -       323  
Production
    (101 )     (663 )     (764 )     (358 )     (323 )     -       (289 )     (60 )     -       (1,794 )
Sales
    -       (179 )     (179 )     (26 )     -       -       -       -       -       (205 )
   
End of 2010
    2,862       7,617       10,479       2,305       1,861       -       2,608       926       56       18,235  
   
 
                                                                               
Equity affiliates
                                                                               
End of 2007
    -       -       -       -       -       1,014       1,925       -       -       2,939  
Revisions
    -       -       -       -       -       1,394       -       -       -       1,394  
Improved recovery
    -       -       -       -       -       -       -       -       -       -  
Purchases
    -       -       -       -       -       -       598       -       -       598  
Extensions and discoveries
    -       -       -       -       -       37       -       -       -       37  
Production
    -       -       -       -       -       (114 )     (4 )     -       -       (118 )
Sales
    -       -       -       -       -       (62 )     -       -       -       (62 )
   
End of 2008
    -       -       -       -       -       2,269       2,519       -       -       4,788  
Revisions
    -       -       -       -       -       436       (203 )     -       -       233  
Improved recovery
    -       -       -       -       -       -       -       -       -       -  
Purchases
    -       -       -       -       -       25       -       -       -       25  
Extensions and discoveries
    -       -       -       -       -       89       294       -       -       383  
Production
    -       -       -       -       -       (114 )     (33 )     -       -       (147 )
Sales
    -       -       -       -       -       -       -       -       -       -  
   
End of 2009
    -       -       -       -       -       2,705       2,577       -       -       5,282  
Revisions
    -       -       -       -       -       19       683       -       -       702  
Improved recovery
    -       -       -       -       -       -       -       -       -       -  
Purchases
    -       -       -       -       -       -       -       -       -       -  
Extensions and discoveries
    -       -       -       -       -       -       269       -       -       269  
Production
    -       -       -       -       -       (91 )     (65 )     -       -       (156 )
Sales
    -       -       -       -       -       (2,616 )     -       -       -       (2,616 )
   
End of 2010
    -       -       -       -       -       17       3,464       -       -       3,481  
   
 
                                                                               
Total company
                                                                               
End of 2007
    3,431       9,203       12,634       2,838       2,583       1,014       5,176       1,030       163       25,438  
End of 2008
    2,488       8,432       10,920       2,614       2,303       2,269       5,756       998       88       24,948  
End of 2009
    2,780       7,962       10,742       2,296       2,009       2,705       5,489       950       56       24,247  
End of 2010
    2,862       7,617       10,479       2,305       1,861       17       6,072       926       56       21,716  
   

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Table of Contents

                                                                                 
Years Ended   Natural Gas
December 31   Billions of Cubic Feet
            Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
     
Developed
                                                                               
Consolidated operations
                                                                               
End of 2007
    3,344       7,417       10,761       2,328       2,177       -       2,857       963       26       19,112  
End of 2008
    2,413       6,875       9,288       2,272       2,036       -       2,877       936       -       17,409  
End of 2009
    2,744       6,633       9,377       2,173       1,772       -       2,537       889       -       16,748  
End of 2010
    2,785       6,399       9,184       2,134       1,529       -       2,136       865       -       15,848  
   
 
                                                                               
Equity affiliates
                                                                               
End of 2007
    -       -       -       -       -       698       -       -       -       698  
End of 2008
    -       -       -       -       -       1,458       361       -       -       1,819  
End of 2009
    -       -       -       -       -       1,506       307       -       -       1,813  
End of 2010
    -       -       -       -       -       17       3,114       -       -       3,131  
   
 
                                                                               
Undeveloped
                                                                               
Consolidated operations
                                                                               
End of 2007
    87       1,786       1,873       510       406       -       394       67       137       3,387  
End of 2008
    75       1,557       1,632       342       267       -       360       62       88       2,751  
End of 2009
    36       1,329       1,365       123       237       -       375       61       56       2,217  
End of 2010
    77       1,218       1,295       171       332       -       472       61       56       2,387  
   
 
                                                                               
Equity affiliates
                                                                               
End of 2007
    -       -       -       -       -       316       1,925       -       -       2,241  
End of 2008
    -       -       -       -       -       811       2,158       -       -       2,969  
End of 2009
    -       -       -       -       -       1,199       2,270       -       -       3,469  
End of 2010
    -       -       -       -       -       -       350       -       -       350  
   
Natural gas production in the reserves table may differ from gas production (delivered for sale) in our statistics disclosure, primarily because the quantities above include gas consumed at the lease.
Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
Notable changes in proved natural gas reserves in the three years ended December 31, 2010, included:
    Revisions : In 2010, revisions in Alaska, Lower 48 and Canada were primarily due to higher prices in 2010, versus 2009, as well as improved well performance. In 2009 and 2008, revisions in Alaska were primarily due to higher prices in 2009, versus 2008; and lower prices in 2008, compared with 2007, respectively. In 2009, for our equity affiliate operations in Asia Pacific/Middle East, revisions resulted from modified coalbed methane drilling plans in Australia. In Russia, revisions were attributable to positive performance in various LUKOIL fields. In 2008, revisions in Russia primarily resulted from a revised assessment of the reasonable certainty of project development and of the marketability of non-contracted gas volumes.
 
    Purchases : In 2008, for our equity affiliate operations in Asia Pacific/Middle East, purchases relate to our Australia Pacific LNG joint venture to develop coalbed methane.
 
    Extensions and Discoveries : In 2010, extensions and discoveries in Lower 48 and Canada were primarily due to continued drilling success in various fields. In 2009, for our equity affiliate operations in Asia Pacific/Middle East, extensions and discoveries primarily resulted from drilling success in Australia related to a coalbed methane project.
 
    Sales : In 2010, for our equity affiliates in Russia, sales were primarily due to the disposition of our interest in LUKOIL.

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Table of Contents

                 
Years Ended   Other Products  
December 31   Millions of Barrels  
    Synthetic Oil     Bitumen  
    Canada     Canada  
Developed and Undeveloped
               
Consolidated operations
               
End of 2007
    -       85  
Revisions
    -       17  
Improved recovery
    -       -  
Purchases
    -       -  
Extensions and discoveries
    -       -  
Production
    -       (2 )
Sales
    -       -  
           
End of 2008
    -       100  
Revisions
    256       152  
Improved recovery
    -       -  
Purchases
    -       -  
Extensions and discoveries
    -       167  
Production
    (8 )     (2 )
Sales
    -       -  
           
End of 2009
    248       417  
Revisions
    -       42  
Improved recovery
    -       -  
Purchases
    -       -  
Extensions and discoveries
    -       -  
Production
    (4 )     (4 )
Sales
    (244 )     -  
           
End of 2010
    -       455  
           
 
               
Equity affiliates
               
End of 2007
    -       623  
Revisions
    -       70  
Improved recovery
    -       -  
Purchases
    -       -  
Extensions and discoveries
    -       18  
Production
    -       (11 )
Sales
    -       -  
           
End of 2008
    -       700  
Revisions
    -       (87 )
Improved recovery
    -       -  
Purchases
    -       -  
Extensions and discoveries
    -       118  
Production
    -       (15 )
Sales
    -       -  
           
End of 2009
    -       716  
Revisions
    -       13  
Improved recovery
    -       -  
Purchases
    -       -  
Extensions and discoveries
    -       133  
Production
    -       (18 )
Sales
    -       -  
           
End of 2010
    -       844  
           
 
               
Total company
               
End of 2007
    -       708  
End of 2008
    -       800  
End of 2009
    248       1,133  
End of 2010
    -       1,299  
           

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Table of Contents

                 
Years Ended   Other Products  
December 31   Millions of Barrels  
    Synthetic Oil     Bitumen  
    Canada     Canada  
Developed
               
Consolidated operations
               
End of 2007
    -       17  
End of 2008
    -       24  
End of 2009
    248       24  
End of 2010
    -       34  
           
 
               
Equity affiliates
               
End of 2007
    -       45  
End of 2008
    -       105  
End of 2009
    -       116  
End of 2010
    -       142  
           
 
               
Undeveloped
               
Consolidated operations
               
End of 2007
    -       68  
End of 2008
    -       76  
End of 2009
    -       393  
End of 2010
    -       421  
           
 
               
Equity affiliates
               
End of 2007
    -       578  
End of 2008
    -       595  
End of 2009
    -       600  
End of 2010
    -       702  
           
Notable changes in proved synthetic oil and bitumen reserves in the three years ended December 31, 2010, included:
    Revisions : In 2009, for synthetic oil consolidated operations, revisions reflect our Syncrude Canada Ltd. operations, which are now considered an oil and gas activity under the new FASB and SEC rules and regulations. For our bitumen consolidated operations, revisions primarily were related to the sanction of the Surmont Phase II Project. For our bitumen equity affiliate operations, revisions were mainly the result of the effect of higher prices on sliding scale royalty provisions.
 
    Extensions and Discoveries : In 2009, for our bitumen consolidated operations, extensions and discoveries were related to the sanction of the Surmont Phase II Project. In 2010 and 2009, for our equity affiliate operations, extensions and discoveries mainly reflect the continued development of FCCL.
 
    Sales : In 2010, for synthetic oil consolidated operations, sales reflect the disposition of our interest in Syncrude.

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Table of Contents

                                                                                 
Years Ended   Total Proved Reserves
December 31   Millions of Barrels of Oil Equivalent
            Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
     
Developed and Undeveloped
                                                                               
Consolidated operations
                                                                               
End of 2007
    2,040       2,308       4,348       659       1,073       -       917       463       153       7,613  
Revisions
    (348 )     (62 )     (410 )     28       4       -       57       18       9       (294 )
Improved recovery
    26       5       31       -       -       -       -       -       -       31  
Purchases
    -       2       2       -       -       -       -       -       -       2  
Extensions and discoveries
    13       70       83       24       17       -       14       5       -       143  
Production
    (114 )     (192 )     (306 )     (82 )     (149 )     -       (81 )     (38 )     (4 )     (660 )
Sales
    -       -       -       -       (9 )     -       (3 )     -       (23 )     (35 )
   
End of 2008
    1,617       2,131       3,748       629       936       -       904       448       135       6,800  
Revisions
    151       22       173       404       32       -       (28 )     10       (13 )     578  
Improved recovery
    14       2       16       -       -       -       2       -       -       18  
Purchases
    -       -       -       -       -       -       -       -       -       -  
Extensions and discoveries
    14       41       55       186       11       -       35       3       -       290  
Production
    (112 )     (183 )     (295 )     (89 )     (143 )     -       (96 )     (36 )     -       (659 )
Sales
    -       (1 )     (1 )     (1 )     -       -       -       -       (5 )     (7 )
   
End of 2009
    1,684       2,012       3,696       1,129       836       -       817       425       117       7,020  
Revisions
    107       68       175       109       42       -       1       27       -       354  
Improved recovery
    55       2       57       -       -       -       5       -       -       62  
Purchases
    -       2       2       -       -       -       -       -       -       2  
Extensions and discoveries
    17       51       68       18       33       -       11       10       -       140  
Production
    (101 )     (165 )     (266 )     (82 )     (132 )     -       (99 )     (38 )     -       (617 )
Sales
    -       (52 )     (52 )     (254 )     -       -       -       -       -       (306 )
   
End of 2010
    1,762       1,918       3,680       920       779       -       735       424       117       6,655  
   
 
                                                                               
Equity affiliates
                                                                               
End of 2007
    -       -       -       623       -       1,894       430       -       -       2,947  
Revisions
    -       -       -       70       -       196       -       -       -       266  
Improved recovery
    -       -       -       -       -       -       -       -       -       -  
Purchases
    -       -       -       -       -       2       100       -       -       102  
Extensions and discoveries
    -       -       -       18       -       77       -       -       -       95  
Production
    -       -       -       (11 )     -       (172 )     (1 )     -       -       (184 )
Sales
    -       -       -       -       -       (51 )     -       -       -       (51 )
   
End of 2008
    -       -       -       700       -       1,946       529       -       -       3,175  
Revisions
    -       -       -       (87 )     -       106       (37 )     -       -       (18 )
Improved recovery
    -       -       -       -       -       54       -       -       -       54  
Purchases
    -       -       -       -       -       25       -       -       -       25  
Extensions and discoveries
    -       -       -       118       -       109       49       -       -       276  
Production
    -       -       -       (15 )     -       (185 )     (6 )     -       -       (206 )
Sales
    -       -       -       -       -       -       -       -       -       -  
   
End of 2009
    -       -       -       716       -       2,055       535       -       -       3,306  
Revisions
    -       -       -       13       -       9       165       -       -       187  
Improved recovery
    -       -       -       -       -       -       -       -       -       -  
Purchases
    -       -       -       -       -       -       -       -       -       -  
Extensions and discoveries
    -       -       -       133       -       -       45       -       -       178  
Production
    -       -       -       (18 )     -       (129 )     (12 )     -       -       (159 )
Sales
    -       -       -       -       -       (1,857 )*     -       -       -       (1,857 )
   
End of 2010
    -       -       -       844       -       78       733       -       -       1,655  
   
 
                                                                               
Total company
                                                                               
End of 2007
    2,040       2,308       4,348       1,282       1,073       1,894       1,347       463       153       10,560  
End of 2008
    1,617       2,131       3,748       1,329       936       1,946       1,433       448       135       9,975  
End of 2009
    1,684       2,012       3,696       1,845       836       2,055       1,352       425       117       10,326  
End of 2010
    1,762       1,918       3,680       1,764       779       78       1,468       424       117       8,310  
   
*Includes 594 million barrels of oil equivalent due to the cessation of equity accounting.

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Years Ended   Total Proved Reserves
December 31   Millions of Barrels of Oil Equivalent
            Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
     
Developed
                                                                               
Consolidated operations
                                                                               
End of 2007
    1,928       1,860       3,788       492       733       -       676       421       13       6,123  
End of 2008
    1,506       1,718       3,224       488       681       -       697       420       6       5,516  
End of 2009
    1,588       1,663       3,251       711       608       -       644       394       -       5,608  
End of 2010
    1,619       1,601       3,220       465       545       -       574       396       -       5,200  
   
 
                                                                               
Equity affiliates
                                                                               
End of 2007
    -       -       -       45       -       1,470       -       -       -       1,515  
End of 2008
    -       -       -       105       -       1,471       60       -       -       1,636  
End of 2009
    -       -       -       116       -       1,464       51       -       -       1,631  
End of 2010
    -       -       -       142       -       76       675       -       -       893  
   
 
                                                                               
Undeveloped
                                                                               
Consolidated operations
                                                                               
End of 2007
    112       448       560       167       340       -       241       42       140       1,490  
End of 2008
    111       413       524       141       255       -       207       28       129       1,284  
End of 2009
    96       349       445       418       228       -       173       31       117       1,412  
End of 2010
    143       317       460       455       234       -       161       28       117       1,455  
   
 
                                                                               
Equity affiliates
                                                                               
End of 2007
    -       -       -       578       -       424       430       -       -       1,432  
End of 2008
    -       -       -       595       -       475       469       -       -       1,539  
End of 2009
    -       -       -       600       -       591       484       -       -       1,675  
End of 2010
    -       -       -       702       -       2       58       -       -       762  
   
Natural gas reserves are converted to barrels of oil equivalent (BOE) based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE.
Proved Undeveloped Reserves
We had 2,217 million BOE of proved undeveloped reserves at year-end 2010, compared with 3,087 million BOE at year-end 2009. The disposition of our investment in LUKOIL resulted in the removal of 589 million BOE of undeveloped reserves. We also converted 844 million BOE of undeveloped reserves to developed during 2010 as we achieved startup of major development projects. Finally, we added 563 million BOE of undeveloped reserves in 2010 mainly through exploratory success and revisions. As a result, at December 31, 2010, our proved undeveloped reserves represented 27 percent of total proved reserves, compared with 30 percent at December 31, 2009. Costs incurred for the year ended December 31, 2010, relating to the development of proved undeveloped reserves were $3.3 billion.
Approximately 75 percent of our proved undeveloped reserves at year-end 2010 were associated with eight major development areas. Seven of the major development areas are currently producing and are expected to have proved undeveloped reserves convert to developed over time as development activities continue and/or production facilities are expanded or upgraded, and include:
    FCCL oil sands—Christina Lake and Foster Creek in Canada.
 
    The Surmont oil sands project in Canada.
 
    The Ekofisk Field in the North Sea.
 
    Certain fields in the United States.
The remaining major project, the Kashagan Field in Kazakhstan, will have proved undeveloped reserves convert to developed as this project begins production.

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At the end of 2010, we did not have any material amounts of proved undeveloped reserves in individual fields or countries that have remained undeveloped for five years or more. However, our largest concentrations of proved undeveloped reserves at year-end 2010 are located in the Athabasca oil sands in Canada, consisting of the FCCL and Surmont steam-assisted gravity drainage (SAGD) projects. The majority of our proved undeveloped reserves in this area were first recorded in 2006 and 2007, and we expect a material portion of these reserves will remain undeveloped for more than five years.
Our SAGD projects are large, multi-year projects with steady, long-term production at consistent levels. The associated reserves are expected to be developed over many years as additional well pairs are drilled across the extensive resource base to maintain throughput at the central processing facilities.

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Results of Operations
                                                                                 
Year Ended   Millions of Dollars
December 31, 2010           Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
     
Consolidated operations
                                                                               
Sales
  $      3,645       3,600       7,245       2,379       5,967       -       4,958       1,743       -       22,292  
Transfers
    2,693       2,389       5,082       246       2,278       -       770       450       -       8,826  
Other revenues
    -       559       559       3,216       142       -       55       172       18       4,162  
   
Total revenues
    6,338       6,548       12,886       5,841       8,387       -       5,783       2,365       18       35,280  
Production costs excluding taxes
    849       1,230       2,079       873       1,004       -       538       296       -       4,790  
Taxes other than income taxes
    1,570       498       2,068       74       6       1       355       18       1       2,523  
Exploration expenses
    37       292       329       295       146       2       260       29       101       1,162  
Depreciation, depletion and amortization
    529       2,231       2,760       1,666       1,972       2       1,206       202       -       7,808  
Impairments
    4       19       23       13       43       -       -       -       -       79  
Transportation costs
    528       424       952       134       281       -       119       23       -       1,509  
Other related expenses
    (38 )     112       74       41       42       17       (48 )     (10 )     62       178  
Accretion
    58       55       113       50       192       -       24       -       4       383  
   
 
    2,801       1,687       4,488       2,695       4,701       (22 )     3,329       1,807       (150 )     16,848  
Provision for income taxes
    1,014       555       1,569       108       3,066       (23 )     1,361       1,458       (28 )     7,511  
   
Results of operations for producing activities
    1,787       1,132       2,919       2,587       1,635       1       1,968       349       (122 )     9,337  
Other earnings
    (52 )     (99 )     (151 )     (72 )     76       16       139       29       8       45  
   
Net income (loss) attributable to ConocoPhillips
  $      1,735       1,033       2,768       2,515       1,711       17       2,107       378       (114 )     9,382  
   
 
                                                                               
Equity affiliates
                                                                               
Sales
  $      -       -       -       955       -       5,189       249       -       -       6,393  
Transfers
    -       -       -       -       -       1,876       -       -       -       1,876  
Other revenues
    -       -       -       7       -       1,219       10       -       -       1,236  
   
Total revenues
    -       -       -       962       -       8,284       259       -       -       9,505  
Production costs excluding taxes
    -       -       -       265       -       544       59       -       -       868  
Taxes other than income taxes
    -       -       -       4       -       3,463       42       -       -       3,509  
Exploration expenses
    -       -       -       -       -       61       (2 )     -       -       59  
Depreciation, depletion and amortization
    -       -       -       190       -       568       55       -       -       813  
Impairments
    -       -       -       -       -       645       -       -       -       645  
Transportation costs
    -       -       -       -       -       784       25       -       -       809  
Other related expenses
    -       -       -       (3 )     -       -       44       -       -       41  
Accretion
    -       -       -       2       -       7       2       -       -       11  
   
 
    -       -       -       504       -       2,212       34       -       -       2,750  
Provision for income taxes
    -       -       -       128       -       647       (25 )     -       -       750  
   
Results of operations for producing activities
    -       -       -       376       -       1,565       59       -       -       2,000  
Other earnings
    -       -       -       -       -       405       (86 )     -       -       319  
   
Net income (loss) attributable to ConocoPhillips
  $      -       -       -       376       -       1,970       (27 )     -       -       2,319  
   

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Year Ended   Millions of Dollars
December 31, 2009           Lower     Total                             Asia Pacific/             Other        
    Alaska *   48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
     
Consolidated operations
                                                                               
Sales
  $      3,353       3,144       6,497       2,179       4,995       -       3,830       1,562       11       19,074  
Transfers
    2,261       1,937       4,198       345       2,305       -       500       257       -       7,605  
Other revenues
    30       54       84       168       (66 )     -       10       136       54       386  
   
Total revenues
    5,644       5,135       10,779       2,692       7,234       -       4,340       1,955       65       27,065  
Production costs excluding taxes
    864       1,266       2,130       1,011       1,048       -       445       270       8       4,912  
Taxes other than income taxes
    1,135       422       1,557       75       3       1       165       17       7       1,825  
Exploration expenses
    74       426       500       201       156       4       212       32       75       1,180  
Depreciation, depletion and amortization
    611       2,615       3,226       1,689       2,016       2       910       201       11       8,055  
Impairments
    -       5       5       296       104       -       12       -       51       468  
Transportation costs
    548       392       940       135       267       -       111       24       5       1,482  
Other related expenses
    251       60       311       (3 )     62       3       121       23       14       531  
Accretion
    49       55       104       41       191       -       19       3       3       361  
   
 
    2,112       (106 )     2,006       (753 )     3,387       (10 )     2,345       1,385       (109 )     8,251  
Provision for income taxes
    716       (79 )     637       (309 )     2,280       (3 )     1,093       1,186       (21 )     4,863  
   
Results of operations for producing activities
    1,396       (27 )     1,369       (444 )     1,107       (7 )     1,252       199       (88 )     3,388  
Other earnings
    144       (10 )     134       (91 )     (59 )     (5 )     132       4       (1 )     114  
   
Net income (loss) attributable to ConocoPhillips
  $      1,540       (37 )     1,503       (535 )     1,048       (12 )     1,384       203       (89 )     3,502  
   
 
                                                                               
Equity affiliates
                                                                               
Sales
  $      -       -       -       713       -       3,783       74       -       -       4,570  
Transfers
    -       -       -       -       -       1,946       -       -       -       1,946  
Other revenues
    -       -       -       (2 )     -       -       1       -       -       (1 )
   
Total revenues
    -       -       -       711       -       5,729       75       -       -       6,515  
Production costs excluding taxes
    -       -       -       213       -       501       26       -       -       740  
Taxes other than income taxes
    -       -       -       3       -       2,270       4       -       -       2,277  
Exploration expenses
    -       -       -       -       -       37       2       -       -       39  
Depreciation, depletion and amortization
    -       -       -       133       -       455       21       -       -       609  
Impairments**
    -       -       -       -       -       83       -       -       -       83  
Transportation costs
    -       -       -       -       -       703       3       -       -       706  
Other related expenses
    -       -       -       17       -       3       1       -       -       21  
Accretion
    -       -       -       1       -       6       1       -       -       8  
   
 
    -       -       -       344       -       1,671       17       -       -       2,032  
Provision for income taxes
    -       -       -       89       -       326       9       -       -       424  
   
Results of operations for producing activities
    -       -       -       255       -       1,345       8       -       -       1,608  
Other earnings**
    -       -       -       -       -       (201 )     (86 )     -       -       (287 )
   
Net income (loss) attributable to ConocoPhillips
  $      -       -       -       255       -       1,144       (78 )     -       -       1,321  
   
   *Certain amounts were reclassified between “Sales” and “Transfers,” as well as between “Other revenues” and “Other related expenses.” Total Results of operations was unchanged.
**Goodwill considered to be a non-oil-and-gas producing activity was reclassified from “Impairments” to “Other earnings.”

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Year Ended   Millions of Dollars
December 31, 2008           Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
     
Consolidated operations
                                                                               
Sales
  $      5,771       6,726       12,497       4,386       8,061       -       4,787       2,075       290       32,096  
Transfers
    3,444       3,401       6,845       -       3,415       -       579       669       -       11,508  
Other revenues
    (25 )     98       73       317       477       -       40       230       (16 )     1,121  
   
Total revenues
    9,190       10,225       19,415       4,703       11,953       -       5,406       2,974       274       44,725  
Production costs excluding taxes
    960       1,405       2,365       887       1,157       -       428       245       34       5,116  
Taxes other than income taxes
    3,432       764       4,196       61       29       2       295       27       205       4,815  
Exploration expenses
    99       469       568       240       235       4       148       41       103       1,339  
Depreciation, depletion and amortization
    559       2,426       2,985       1,802       1,917       2       733       215       24       7,678  
Impairments*
    -       620       620       92       72       -       9       -       -       793  
Transportation costs
    409       519       928       140       302       -       115       29       10       1,524  
Other related expenses
    (38 )     108       70       56       (306 )     18       113       6       53       10  
Accretion
    40       59       99       33       196       -       14       4       3       349  
   
 
    3,729       3,855       7,584       1,392       8,351       (26 )     3,551       2,407       (158 )     23,101  
Provision for income taxes
    1,317       1,310       2,627       371       5,241       7       1,640       2,094       (46 )     11,934  
   
Results of operations for producing activities
    2,412       2,545       4,957       1,021       3,110       (33 )     1,911       313       (112 )     11,167  
Other earnings
    (97 )     128       31       243       314       66       46       (35 )     (11 )     654  
   
Net income (loss) attributable to ConocoPhillips
  $      2,315       2,673       4,988       1,264       3,424       33       1,957       278       (123 )     11,821  
   
 
                                                                               
Equity affiliates
                                                                               
Sales
  $      -       -       -       644       -       6,890       9       -       -       7,543  
Transfers
    -       -       -       -       -       4,660       -       -       -       4,660  
Other revenues
    -       -       -       45       -       -       -       -       -       45  
   
Total revenues
    -       -       -       689       -       11,550       9       -       -       12,248  
Production costs excluding taxes
    -       -       -       182       -       730       4       -       -       916  
Taxes other than income taxes
    -       -       -       3       -       5,725       -       -       -       5,728  
Exploration expenses
    -       -       -       -       -       87       -       -       -       87  
Depreciation, depletion and amortization
    -       -       -       84       -       550       9       -       -       643  
Impairments
    -       -       -       -       -       7,038       -       -       -       7,038  
Transportation costs
    -       -       -       -       -       910       1       -       -       911  
Other related expenses
    -       -       -       1       -       7       5       -       -       13  
Accretion
    -       -       -       1       -       5       -       -       -       6  
   
 
    -       -       -       418       -       (3,502 )     (10 )     -       -       (3,094 )
Provision for income taxes
    -       -       -       132       -       1,070       (11 )     -       1       1,192  
   
Results of operations for producing activities
    -       -       -       286       -       (4,572 )     1       -       (1 )     (4,286 )
Other earnings
    -       -       -       3       -       (410 )     (3 )     -       -       (410 )
   
Net income (loss) attributable to ConocoPhillips
  $      -       -       -       289       -       (4,982 )     (2 )     -       (1 )     (4,696 )
   
*Excludes goodwill impairment of $25,443 million.

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    Results of operations for producing activities consist of all activities within the E&P organization and producing activities within the LUKOIL Investment segment, except for pipeline and marine operations, liquefied natural gas operations, and crude oil and gas marketing activities, which are included in other earnings. Also excluded are our Midstream segment, downstream petroleum and chemical activities, as well as general corporate administrative expenses and interest.
 
    Transfers are valued at prices that approximate market.
 
    Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of hydrocarbons, and other miscellaneous income.
 
    Production costs are those incurred to operate and maintain wells and related equipment and facilities used to produce proved reserves. These costs also include depreciation of support equipment and administrative expenses related to the production activity.
 
    Taxes other than income taxes include production, property and other non-income taxes.
 
    Exploration expenses include dry hole costs, leasehold impairments, geological and geophysical expenses, the costs of retaining undeveloped leaseholds, and depreciation of support equipment and administrative expenses related to the exploration activity.
 
    Depreciation, depletion and amortization (DD&A) in Results of Operations differs from that shown for total E&P in Note 25—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, mainly due to depreciation of support equipment being reclassified to production or exploration expenses, as applicable, in Results of Operations. In addition, other earnings include certain E&P activities, including their related DD&A charges.
 
    Transportation costs include costs to transport our produced hydrocarbons to their points of sale, as well as processing fees paid to process natural gas to natural gas liquids. The profit element of transportation operations in which we have an ownership interest are deemed to be outside oil and gas producing activities. The net income of the transportation operations is included in other earnings.
 
    Other related expenses include foreign currency transaction gains and losses, and other miscellaneous expenses.
 
    The provision for income taxes is computed by adjusting each country’s income before income taxes for permanent differences related to oil and gas producing activities that are reflected in our consolidated income tax expense for the period, multiplying the result by the country’s statutory tax rate, and adjusting for applicable tax credits.
 
    The equity affiliate results in Russia for 2009 reflect only three quarters of activity for our share of LUKOIL. Under the lag accounting method used for our investment in LUKOIL, equity earnings were not recorded in the first quarter of 2009, since our LUKOIL investment was written down in the fourth quarter of 2008 to its fair value at December 31, 2008. This approach was consistently followed in Results of Operations (RESOP), such that LUKOIL’s fourth-quarter 2008 results are not reflected in RESOP. For supplemental information, the fourth-quarter 2008 amounts excluded for selected line items were: total revenues—$1,371 million; production costs—$171 million; taxes other than income taxes—$867 million; and DD&A—$127 million. These amounts were included in the numerator of the per-unit calculations included in the “Statistics” section.

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Statistics
                         
Net Production   2010     2009     2008  
    Thousands of Barrels Daily  
Crude Oil and Natural Gas Liquids
                       
Consolidated operations
                       
Alaska
    230       252       261  
Lower 48
    160       166       165  
   
United States
    390       418       426  
Canada
    38       40       44  
Europe
    211       241       233  
Asia Pacific/Middle East
    140       132       107  
Africa
    79       78       80  
Other areas
    -       4       9  
   
Total consolidated operations
    858       913       899  
   
Equity affiliates
                       
Russia
    336       443       413  
Asia Pacific/Middle East
    3       -       -  
   
Total equity affiliates
    339       443       413  
   
Total company
    1,197       1,356       1,312  
   
 
                       
Synthetic Oil
                       
Consolidated operations— Canada
    12       23       22  
   
 
                       
Bitumen
                       
Consolidated operations— Canada
    10       7       6  
Equity affiliates— Canada
    49       43       30  
   
Total company
    59       50       36  
   
 
                       
    Millions of Cubic Feet Daily  
       
Natural Gas*
                       
Consolidated operations
                       
Alaska
    82       94       97  
Lower 48
    1,695       1,927       1,994  
   
United States
    1,777       2,021       2,091  
Canada
    984       1,062       1,054  
Europe
    815       876       954  
Asia Pacific/Middle East
    712       713       609  
Africa
    149       121       114  
Other areas
    -       -       14  
   
Total consolidated operations
    4,437       4,793       4,836  
   
Equity affiliates
                       
Russia
    254       295       330  
Asia Pacific/Middle East
    169       84       11  
   
Total equity affiliates
    423       379       341  
   
Total company
    4,860       5,172       5,177  
   
*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above.

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Average Sales Prices   2010     2009     2008  
           
 
                       
Crude Oil and Natural Gas Liquids Per Barrel
                       
Consolidated operations
                       
Alaska
  $      78.61       59.23       99.10  
Lower 48
    57.69       44.12       74.70  
United States
    69.73       53.21       89.38  
Canada
    55.70       41.76       76.53  
Europe
    77.35       58.92       92.10  
Asia Pacific/Middle East
    75.50       57.59       87.32  
Africa
    76.80       60.83       91.54  
Other areas
    -       32.01       84.74  
Total international
    74.95       57.40       89.32  
Total consolidated operations
    72.63       55.47       89.35  
   
Equity affiliates
                       
Russia
    56.65       43.19       75.90  
Asia Pacific/Middle East
    83.82       -       -  
Total equity affiliates
    56.87       43.19       75.90  
   
 
                       
Synthetic Oil Per Barrel
                       
Consolidated operations— Canada
  $      77.56       62.01       103.31  
   
 
                       
Bitumen Per Barrel
                       
Consolidated operations— Canada
  $      51.10       39.67       46.85  
Equity affiliates— Canada
    53.43       45.69       58.54  
   
 
                       
Natural Gas Per Thousand Cubic Feet*
                       
Consolidated operations
                       
Alaska
  $      4.62       5.33       5.36  
Lower 48
    4.25       3.42       7.71  
United States
    4.27       3.50       7.60  
Canada
    3.74       3.33       7.92  
Europe
    6.94       6.81       10.55  
Asia Pacific/Middle East
    7.39       6.00       8.45  
Africa
    1.81       1.56       1.09  
Other areas
    -       -       1.41  
Total international
    5.60       5.06       8.65  
Total consolidated operations
    5.07       4.40       8.20  
   
Equity affiliates
                       
Russia
    1.18       1.16       1.04  
Asia Pacific/Middle East
    2.79       2.35       2.04  
Total equity affiliates
    1.82       1.43       1.07  
   
*Prior periods reclassified to conform to current year presentation of including intrasegment transfer pricing.

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    2010     2009     2008  
       
Average Production Costs Per Barrel of Oil Equivalent*
                       
Consolidated operations
                       
Alaska
  $      9.55       8.84       9.46  
Lower 48
    7.62       7.12       7.72  
United States
    8.30       7.73       8.34  
Canada
    10.68       11.21       10.74  
Europe
    7.93       7.42       8.06  
Asia Pacific/Middle East
    5.70       4.86       5.61  
Africa
    7.81       7.54       6.76  
Other areas
    -       5.48       8.20  
Total international
    7.96       7.72       8.03  
Total consolidated operations
    8.10       7.73       8.17  
         
Equity affiliates
                       
Canada
    14.82       13.57       16.58  
Russia
    3.94       3.74       4.26  
Asia Pacific/Middle East
    5.19       5.09       5.96  
Total equity affiliates
    5.19       4.54       5.01  
         
 
                       
Average Production Costs Per Barrel—Bitumen
                       
Consolidated operations— Canada
  $      19.45       30.92       39.62  
Equity affiliates— Canada
    14.82       13.57       16.58  
         
 
                       
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent*
                       
Consolidated operations
                       
Alaska
  $      17.65       11.62       33.83  
Lower 48
    3.08       2.37       4.20  
United States
    8.26       5.65       14.80  
Canada
    .91       .83       .74  
Europe
    .05       .02       .20  
Asia Pacific/Middle East
    3.76       1.80       3.87  
Africa
    .47       .47       .75  
Other areas
    -       4.79       49.42  
Total international
    1.34       .74       1.81  
Total consolidated operations
    4.27       2.87       7.69  
         
Equity affiliates
                       
Canada
    .22       .19       .27  
Russia
    25.08       17.46       33.42  
Asia Pacific/Middle East
    3.69       .78       -  
Total equity affiliates
    20.97       15.69       31.31  
         
 
                       
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent*
                       
Consolidated operations
                       
Alaska
  $      5.95       6.25       5.51  
Lower 48
    13.81       14.71       13.33  
United States
    11.02       11.71       10.53  
Canada
    20.38       18.73       21.82  
Europe
    15.58       14.27       13.36  
Asia Pacific/Middle East
    12.77       9.94       9.61  
Africa
    5.33       5.61       5.93  
Other areas
    -       7.53       5.79  
Total international
    14.82       13.40       13.69  
Total consolidated operations
    13.21       12.67       12.26  
         
Equity affiliates
                       
Canada
    10.62       8.47       7.65  
Russia
    4.11       3.24       3.21  
Asia Pacific/Middle East
    4.83       4.11       13.41  
Total equity affiliates
    4.86       3.67       3.51  
         
*Includes bitumen. For 2008, excludes our Canadian synthetic oil operations.

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Net Wells Completed (1)   Productive     Dry  
    2010     2009     2008     2010     2009     2008  
                 
Exploratory (2)
                                               
Consolidated operations
                                               
Alaska
    -       -       -       -       2       1  
Lower 48
    23       33       81       1       14       22  
   
United States
    23       33       81       1       16       23  
Canada
    15       17       49       7       19       36  
Europe
    1       1       *       *       2       1  
Asia Pacific/Middle East
    3       3       1       1       3       *  
Africa
    1       *       *       *       *       1  
Other areas
    -       -       -       -       -       1  
   
Total consolidated operations
    43       54       131       9       40       62  
   
Equity affiliates
                                               
Russia
    -       1       1       -       -       1  
Asia Pacific/Middle East
    2       -       -       -       -       *  
   
Total equity affiliates (3)
    2       1       1       -       -       1  
   
Includes step-out wells of:
    23       40       127       1       29       27  
 
    Productive     Dry  
    2010     2009     2008     2010     2009     2008  
                 
Development
                                               
Consolidated operations
                                               
Alaska
    47       47       47       *       -       -  
Lower 48
    269       592       690       2       4       8  
   
United States
    316       639       737       2       4       8  
Canada
    186       227       465       12       20       32  
Europe
    6       9       10       -       -       -  
Asia Pacific/Middle East
    59       47       26       *       -       -  
Africa
    9       3       4       -       -       -  
Other areas
    -       -       -       -       -       -  
   
Total consolidated operations
    576       925       1,242       14       24       40  
   
Equity affiliates
                                               
Canada
    112       61       148       -       -       -  
Russia
    2       6       7       -       *       -  
Asia Pacific/Middle East
    25       28       *       -       -       -  
   
Total equity affiliates (3)
    139       95       155       -       *       -  
   
(1)Excludes farmout arrangements.
(2)Includes step-out wells, as well as other types of exploratory wells. Step-out exploratory wells are wells drilled in areas near or offsetting current production, for which we cannot demonstrate with certainty that there is continuity of production from an existing productive formation. These are classified as exploratory wells because we cannot attribute proved reserves to these locations.
(3)Excludes LUKOIL.
*Our total proportionate interest was less than one.

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Wells at December 31, 2010                   Productive (2)  
    In Progress (1)     Oil     Gas  
    Gross     Net     Gross     Net     Gross     Net  
                   
Consolidated operations
                                               
Alaska
    24       13       1,886       849       32       21  
Lower 48
    276       185       12,599       4,606       25,081       15,990  
   
United States
    300       198       14,485       5,455       25,113       16,011  
Canada
    228 (3)     166 (3)     1,647       995       12,875       7,646  
Europe
    31       6       611       109       273       111  
Asia Pacific/Middle East
    79       33       466       199       107       49  
Africa
    93       16       1,131       196       11       2  
Other areas
    38       3       -       -       -       -  
   
Total consolidated operations
    769       422       18,340       6,954       38,379       23,819  
   
Equity affiliates
                                               
Canada
    15       8       202       101       -       -  
Russia
    7       2       107       38       2       1  
Asia Pacific/Middle East
    753       205       -       -       569       174  
   
Total equity affiliates
    775       215       309       139       571       175  
   
(1)Includes wells that have been temporarily suspended.
(2)Includes 6,000 gross and 3,802 net multiple completion wells.
(3)Includes 191 gross and 138 net stratigraphic test wells for heavy oil projects.
                                 
Acreage at December 31, 2010   Thousands of Acres  
    Developed     Undeveloped  
    Gross     Net     Gross     Net  
             
Consolidated operations
                               
Alaska
    647       328       1,720       1,361  
Lower 48
    5,932       5,304       10,323       8,859  
   
United States
    6,579       5,632       12,043       10,220  
Canada
    6,958       4,464       6,970       4,581  
Europe
    868       242       3,271       1,393  
Asia Pacific/Middle East
    4,123       1,777       20,052       12,646  
Africa
    528       132       14,729       2,575  
Other areas
    -       -       14,646       9,522  
   
Total consolidated operations
    19,056       12,247       71,711       40,937  
   
Equity affiliates
                               
Canada
    33       14       518       209  
Russia
    291       90       1,173       476  
Asia Pacific/Middle East
    1,108       288       8,823       3,570  
   
Total equity affiliates
    1,432       392       10,514       4,255  
   

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Costs Incurred
                                                                                 
Years Ended   Millions of Dollars
December 31           Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
     
2010
                                                                               
Consolidated operations
                                                                               
Unproved property acquisition
  $      (26 )     286       260       113       9       -       -       -       -       382  
Proved property acquisition
    -       100       100       1       -       -       -       -       -       101  
   
 
    (26 )     386       360       114       9       -       -       -       -       483  
Exploration
    119       487       606       269       144       3       356       45       143       1,566  
Development
    588       1,439       2,027       927       1,351       -       858       375       729       6,267  
   
 
  $      681       2,312       2,993       1,310       1,504       3       1,214       420       872       8,316  
   
 
                                                                               
Equity affiliates
                                                                               
Unproved property acquisition
  $      -       -       -       81       -       15       -       -       -       96  
Proved property acquisition
    -       -       -       -       -       173       379       -       -       552  
   
 
    -       -       -       81       -       188       379       -       -       648  
Exploration
    -       -       -       -       -       92       123       -       -       215  
Development
    -       -       -       621       -       751       403       -       -       1,775  
   
 
  $      -       -       -       702       -       1,031       905       -       -       2,638  
   
 
                                                                               
2009
                                                                               
Consolidated operations
                                                                               
Unproved property acquisition
  $      -       78       78       62       5       -       30       -       55       230  
Proved property acquisition
    1       6       7       7       -       -       -       -       -       14  
   
 
    1       84       85       69       5       -       30       -       55       244  
Exploration
    137       476       613       251       184       4       342       33       90       1,517  
Development
    790       1,726       2,516       1,114       1,108       -       1,244       240       685       6,907  
   
 
  $      928       2,286       3,214       1,434       1,297       4       1,616       273       830       8,668  
   
 
                                                                               
Equity affiliates
                                                                               
Unproved property acquisition
  $      -       -       -       -       -       18       -       -       -       18  
Proved property acquisition
    -       -       -       -       -       176       219       -       -       395  
   
 
    -       -       -       -       -       194       219       -       -       413  
Exploration
    -       -       -       -       -       62       53       -       -       115  
Development
    -       -       -       446       -       820       376       -       -       1,642  
   
 
  $      -       -       -       446       -       1,076       648       -       -       2,170  
   

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Years Ended   Millions of Dollars
December 31           Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
     
2008
                                                                               
Consolidated operations
                                                                               
Unproved property acquisition
  $      514       505       1,019       195       -       -       5       -       -       1,219  
Proved property acquisition
    -       37       37       -       -       -       -       -       -       37  
   
 
    514       542       1,056       195       -       -       5       -       -       1,256  
Exploration
    124       733       857       306       279       3       224       42       94       1,805  
Development
    823       2,458       3,281       1,300       2,056       -       1,314       175       619       8,745  
   
 
  $      1,461       3,733       5,194       1,801       2,335       3       1,543       217       713       11,806  
   
 
                                                                               
Equity affiliates
                                                                               
Unproved property acquisition
  $      -       -       -       -       -       35       4,505       -       -       4,540  
Proved property acquisition
    -       -       -       7       -       144       245       -       -       396  
   
 
    -       -       -       7       -       179       4,750       -       -       4,936  
Exploration
    -       -       -       -       -       134       5       -       -       139  
Development
    -       -       -       569       -       1,767       214       -       -       2,550  
   
 
  $      -       -       -       576       -       2,080       4,969       -       -       7,625  
   
  Costs incurred include capitalized and expensed items.
 
  Acquisition costs include the costs of acquiring proved and unproved hydrocarbon properties. In 2008, equity affiliate acquisition costs were due to the Australia Pacific LNG joint venture with Origin Energy.
 
  Exploration costs include geological and geophysical expenses, the cost of retaining undeveloped leaseholds, exploratory drilling costs, and costs incurred to assess the commerciality of potential discoveries.
 
  Development costs include the cost of drilling and equipping development wells and building related production facilities for extracting, treating, gathering and storing hydrocarbons.

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Capitalized Costs
                                                                                 
At December 31   Millions of Dollars
            Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia *   Middle East     Africa     Areas     Total  
     
2010
                                                                               
Consolidated operations
                                                                               
Proved properties
  $      12,268       32,076       44,344       20,037       21,547       9       11,199       3,595       3,921       104,652  
Unproved properties
    1,471       1,700       3,171       1,930       328       1       1,113       163       249       6,955  
   
 
    13,739       33,776       47,515       21,967       21,875       10       12,312       3,758       4,170       111,607  
Accumulated depreciation, depletion and amortization
    5,758       13,362       19,120       10,281       13,636       7       4,690       1,370       10       49,114  
   
 
  $ 7,981       20,414       28,395       11,686       8,239       3       7,622       2,388       4,160       62,493  
   
 
                                                                               
Equity affiliates
                                                                               
Proved properties
  $ -       -       -       4,812       -       1,923       2,320       -       -       9,055  
Unproved properties
    -       -       -       1,794       -       146       8,144       -       -       10,084  
   
 
    -       -       -       6,606       -       2,069       10,464       -       -       19,139  
Accumulated depreciation, depletion and amortization
    -       -       -       512       -       1,584       84       -       -       2,180  
   
 
  $ -       -       -       6,094       -       485       10,380       -       -       16,959  
   
 
                                                                               
2009
                                                                               
Consolidated operations
                                                                               
Proved properties
  $ 11,678       33,408       45,086       21,070       20,759       9       10,398       3,170       3,235       103,727  
Unproved properties
    1,421       1,407       2,828       1,899       396       -       970       195       218       6,506  
   
 
    13,099       34,815       47,914       22,969       21,155       9       11,368       3,365       3,453       110,233  
Accumulated depreciation, depletion and amortization
    5,218       13,464       18,682       8,919       11,995       5       3,578       1,167       43       44,389  
   
 
  $ 7,881       21,351       29,232       14,050       9,160       4       7,790       2,198       3,410       65,844  
   
 
                                                                               
Equity affiliates
                                                                               
Proved properties
  $ -       -       -       3,912       -       12,796       1,511       -       -       18,219  
Unproved properties
    -       -       -       1,681       -       956       6,840       -       -       9,477  
   
 
    -       -       -       5,593       -       13,752       8,351       -       -       27,696  
Accumulated depreciation, depletion and amortization
    -       -       -       299       -       9,026       36       -       -       9,361  
   
 
  $ -       -       -       5,294       -       4,726       8,315       -       -       18,335  
   
* 2009 equity affiliates adjusted to reclassify certain costs between proved and unproved, as well as to include amounts determined to be capitalized.
  Capitalized costs include the cost of equipment and facilities for oil and gas producing activities. These costs include the activities of our E&P and LUKOIL Investment segments, excluding pipeline and marine operations, liquefied natural gas operations, crude oil and natural gas marketing activities and downstream operations.
 
  Proved properties include capitalized costs for leaseholds holding proved reserves, development wells and related equipment and facilities (including uncompleted development well costs), mining facilities associated with our synthetic oil operations and support equipment.
 
  Unproved properties include capitalized costs for leaseholds under exploration (including where hydrocarbons were found but determination of the economic viability of the required infrastructure is dependent upon further exploratory work under way or firmly planned) and for uncompleted exploratory well costs, including exploratory wells under evaluation.

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities
In accordance with SEC and FASB requirements, amounts for 2010 and 2009 were computed using 12-month average prices and end-of-year costs (adjusted only for existing contractual changes), appropriate statutory tax rates and a prescribed 10 percent discount factor. Twelve-month average prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Amounts for 2008 were computed using end-of-year prices and costs. For all years, continuation of year-end economic conditions was assumed. The calculations were based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, were not considered. The calculations also require assumptions as to the timing of future production of proved reserves, and the timing and amount of future development, including dismantlement, and production costs.
While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production.
Discounted Future Net Cash Flows
                                                                                 
    Millions of Dollars  
            Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa     Areas     Total  
       
2010
                                                                               
Consolidated operations
                                                                               
Future cash inflows
  $ 102,743       68,949       171,692       38,083       49,270       -       37,673       24,487       8,466       329,671  
Less:
                                                                               
Future production and transportation costs*
    57,899       29,749       87,648       16,753       12,899       -       10,480       4,142       3,007       134,929  
Future development costs
    8,792       12,700       21,492       11,161       10,295       -       2,226       1,133       3,050       49,357  
Future income tax provisions
    13,383       9,024       22,407       2,416       16,765       -       9,211       16,217       384       67,400  
   
Future net cash flows
    22,669       17,476       40,145       7,753       9,311       -       15,756       2,995       2,025       77,985  
10 percent annual discount
    10,723       7,551       18,274       3,890       2,597       -       4,889       1,025       2,368       33,043  
   
Discounted future net cash flows
  $ 11,946       9,925       21,871       3,863       6,714       -       10,867       1,970       (343 )     44,942  
   
 
                                                                               
Equity affiliates
                                                                               
Future cash inflows
  $ -       -       -       47,169       -       5,610       32,845       -       -       85,624  
Less:
                                                                               
Future production and transportation costs*
    -       -       -       16,492       -       4,809       21,036       -       -       42,337  
Future development costs
    -       -       -       4,684       -       85       295       -       -       5,064  
Future income tax provisions
    -       -       -       6,649       -       (80 )     2,082       -       -       8,651  
   
Future net cash flows
    -       -       -       19,344       -       796       9,432       -       -       29,572  
10 percent annual discount
    -       -       -       13,453       -       293       4,732       -       -       18,478  
   
Discounted future net cash flows
  $ -       -       -       5,891       -       503       4,700       -       -       11,094  
   
 
                                                                               
Total company
                                                                               
Discounted future net cash flows
  $ 11,946       9,925       21,871       9,754       6,714       503       15,567       1,970       (343 )     56,036  
   
*Includes taxes other than income taxes.

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    Millions of Dollars  
            Lower     Total                             Asia Pacific/             Other        
    Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa *   Areas     Total  
       
2009
                                                                               
Consolidated operations
                                                                               
Future cash inflows
  $ 74,359       51,007       125,366       45,965       41,832       -       31,276       19,618       6,416       270,473  
Less:
                                                                               
Future production and transportation costs**
    44,789       32,491       77,280       23,625       13,559       -       9,058       3,832       2,071       129,425  
Future development costs
    7,829       8,350       16,179       12,769       10,369       -       2,284       1,142       3,879       46,622  
Future income tax provisions
    7,519       2,992       10,511       2,183       10,676       -       7,288       12,396       71       43,125  
   
Future net cash flows
    14,222       7,174       21,396       7,388       7,228       -       12,646       2,248       395       51,301  
10 percent annual discount
    6,474       2,300       8,774       3,703       1,878       -       4,108       879       1,566       20,908  
   
Discounted future net cash flows
  $ 7,748       4,874       12,622       3,685       5,350       -       8,538       1,369       (1,171 )     30,393  
   
 
                                                                               
Equity affiliates
                                                                               
Future cash inflows
  $ -       -       -       36,540       -       69,277       19,420       -       -       125,237  
Less:
                                                                               
Future production and transportation costs*
    -       -       -       13,689       -       49,874       13,891       -       -       77,454  
Future development costs
    -       -       -       4,481       -       7,795       350       -       -       12,626  
Future income tax provisions
    -       -       -       4,785       -       2,265       694       -       -       7,744  
   
Future net cash flows
    -       -       -       13,585       -       9,343       4,485       -       -       27,413  
10 percent annual discount
    -       -       -       9,512       -       4,002       2,018       -       -       15,532  
   
Discounted future net cash flows
  $ -       -       -       4,073       -       5,341       2,467       -       -       11,881  
   
 
                                                                               
Total company
                                                                               
Discounted future net cash flows
  $ 7,748       4,874       12,622       7,758       5,350       5,341       11,005       1,369       (1,171 )     42,274  
   
    *Restated to include amounts omitted and to reclassify between production costs, development costs and taxes.
**Includes taxes other than income taxes.

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    Millions of Dollars  
            Lower     Total                             Asia Pacific/             Other        
2008   Alaska     48     U.S.     Canada     Europe     Russia     Middle East     Africa *   Areas     Total  
     
Consolidated operations
                                                                               
Future cash inflows
  $ 54,662       51,354       106,016       19,632       42,230       -       22,626       12,478       4,357       207,339  
Less:
                                                                               
Future production and transportation costs**
    35,150       30,508       65,658       9,357       12,217       -       6,960       3,229       2,000       99,421  
Future development costs
    9,681       10,443       20,124       4,188       8,835       -       2,859       800       2,084       38,890  
Future income tax provisions
    3,227       3,439       6,666       401       11,679       -       4,880       6,919       248       30,793  
   
Future net cash flows
    6,604       6,964       13,568       5,686       9,499       -       7,927       1,530       25       38,235  
10 percent annual discount
    2,159       2,886       5,045       1,222       3,178       -       2,998       541       703       13,687  
   
Discounted future net cash flows
  $ 4,445       4,078       8,523       4,464       6,321       -       4,929       989       (678 )     24,548  
   
 
                                                                               
Equity affiliates
                                                                               
Future cash inflows
  $ -       -       -       17,055       -       36,679       15,798       -       -       69,532  
Less:
                                                                               
Future production and transportation costs*
    -       -       -       12,820       -       30,137       10,536       -       -       53,493  
Future development costs
    -       -       -       3,010       -       5,200       611       -       -       8,821  
Future income tax provisions
    -       -       -       252       -       260       379       -       -       891  
   
Future net cash flows
    -       -       -       973       -       1,082       4,272       -       -       6,327  
10 percent annual discount
    -       -       -       894       -       119       2,281       -       -       3,294  
   
Discounted future net cash flows
  $ -       -       -       79       -       963       1,991       -       -       3,033  
   
 
                                                                               
Total company
                                                                               
Discounted future net cash flows
  $ 4,445       4,078       8,523       4,543       6,321       963       6,920       989       (678 )     27,581  
   
    *Restated to include amounts omitted and to reclassify between production costs, development costs and taxes.
**Includes taxes other than income taxes.
Excludes discounted future net cash flows from Canadian Syncrude of $435 million.

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Sources of Change in Discounted Future Net Cash Flows
                                                                         
    Millions of Dollars  
    Consolidated Operations     Equity Affiliates     Total Company  
    2010     2009 *   2008 *   2010     2009     2008     2010     2009     2008  
                   
Discounted future net cash flows at the beginning of the year
  $ 30,393       24,548       67,162       11,881       3,033       20,027       42,274       27,581       87,189  
               
Changes during the year
                                                                       
Revenues less production and transportation costs for the year**
    (22,296 )     (18,460 )     (32,149 )     (3,083 )     (2,793 )     (4,648 )     (25,379 )     (21,253 )     (36,797 )
Net change in prices, and production and transportation costs***
    39,532       19,208       (72,850 )     3,478       14,386       (20,766 )     43,010       33,594       (93,616 )
Extensions, discoveries and improved recovery, less estimated future costs
    4,517       2,312       1,759       297       1,342       181       4,814       3,654       1,940  
Development costs for the year
    5,617       6,148       7,715       1,758       1,623       2,622       7,375       7,771       10,337  
Changes in estimated future development costs
    (3,722 )     (7,036 )     (3,270 )     (129 )     (2,197 )     (813 )     (3,851 )     (9,233 )     (4,083 )
Purchases of reserves in place, less estimated future costs
    19       3       10       -       96       321       19       99       331  
Sales of reserves in place, less estimated future costs
    (3,729 )     (75 )     (52 )     (5,405 )     -       (33 )     (9,134 )     (75 )     (85 )
Revisions of previous quantity estimates**
    3,062       5,149       1,904       372       (1,597 )     (1,689 )     3,434       3,552       215  
Accretion of discount
    5,000       3,972       11,765       1,404       365       2,456       6,404       4,337       14,221  
Net change in income taxes
    (13,451 )     (5,376 )     42,554       521       (2,377 )     5,375       (12,930 )     (7,753 )     47,929  
   
Total changes
    14,549       5,845       (42,614 )     (787 )     8,848       (16,994 )     13,762       14,693       (59,608 )
   
Discounted future net cash flows at year end
  $ 44,942       30,393       24,548       11,094       11,881       3,033       56,036       42,274       27,581  
   
      *Restated to include amounts omitted in the Africa geographic area.
   **Includes taxes other than income taxes.
***Includes amounts resulting from changes in the timing of production.
  The net change in prices, and production and transportation costs is the beginning-of-year reserve-production forecast multiplied by the net annual change in the per-unit sales price, and production and transportation cost, discounted at 10 percent.
 
  For 2010 and 2009, as required, purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using production forecasts of the applicable reserve quantities for the year multiplied by the 12-month average sales prices, less future estimated costs, discounted at 10 percent. For 2008, the end-of-year sales prices were used, as required.
 
  The accretion of discount is 10 percent of the prior year’s discounted future cash inflows, less future production, transportation and development costs.
 
  The net change in income taxes is the annual change in the discounted future income tax provisions.

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Selected Quarterly Financial Data (Unaudited)
                                                 
    Millions of Dollars        
    Sales and                             Per Share of Common Stock  
    Other     Income             Net Income     Net Income Attributable to  
    Operating     Before     Net     Attributable to     ConocoPhillips  
    Revenues   Income Taxes       Income     ConocoPhillips     Basic     Diluted  
2010
                                               
First
  $ 44,821       3,990       2,112       2,098       1.41       1.40  
Second
    45,686       6,194       4,183       4,164       2.79       2.77  
Third
    47,208       5,274       3,069       3,055       2.06       2.05  
Fourth
    51,726       4,292       2,053       2,041       1.40       1.39  
   
 
                                               
2009
                                               
First
  $ 30,741       1,992       816       800       .54       .54  
Second
    35,448       1,938       875       859       .58       .57  
Third
    40,173       2,913       1,487       1,470       .98       .97  
Fourth
    42,979       2,739       1,314       1,285       .86       .86  
   
*Includes excise taxes on petroleum products sales.
Certain amounts in 2009 have been recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for more information.

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Supplementary Information—Condensed Consolidating Financial Information
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to publicly held debt securities. ConocoPhillips Company is wholly owned by ConocoPhillips. ConocoPhillips Australia Funding Company is an indirect, wholly owned subsidiary of ConocoPhillips Company. ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II are indirect, wholly owned subsidiaries of ConocoPhillips. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to their publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:
    ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
    All other nonguarantor subsidiaries of ConocoPhillips.
    The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.
In February 2009, we filed a universal shelf registration statement with the SEC under which ConocoPhillips, as a well-known seasoned issuer, has the ability to issue and sell an indeterminate amount of various types of debt and equity securities, with certain debt securities guaranteed by ConocoPhillips Company. Also as part of that registration statement, ConocoPhillips Trust I and ConocoPhillips Trust II have the ability to issue and sell preferred trust securities, guaranteed by ConocoPhillips. ConocoPhillips Trust I and ConocoPhillips Trust II have not issued any trust-preferred securities under this registration statement, and thus have no assets or liabilities. Accordingly, columns for these two trusts are not included in the condensed consolidating financial information.
To facilitate the restructuring of certain legal entities within the Canada operating unit, ConocoPhillips Canada Funding Company I (CFC I) entered into a transaction with another wholly owned subsidiary of ConocoPhillips (included in the “All Other Subsidiaries” column) whereby it acquired an investment in certain preferred shares of a Canadian legal entity within the ConocoPhillips group, in exchange for a non-interest-bearing demand note payable. The value ascribed to the preferred shares and note payable represented the redemption price for both. This noncash transaction was effective December 31, 2009. As a result, the balance sheet of CFC I reflects a short-term investment of $2,973 million and a corresponding amount in short-term debt. In January 2010, the preferred shares acquired under the above transaction were resold to the original holder at the same value as the original purchase price, as satisfaction of the obligation under the demand note payable. As these transactions were completed between wholly owned subsidiaries of ConocoPhillips, there is no impact on the consolidated results in either period.
This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.
Certain amounts in 2009 and 2008 have been recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for more information.

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    Millions of Dollars  
    Year Ended December 31, 2010  
                    ConocoPhillips     ConocoPhillips     ConocoPhillips                    
                    Australia     Canada     Canada                    
            ConocoPhillips     Funding     Funding     Funding     All Other     Consolidating     Total  
Statement of Operations   ConocoPhillips     Company     Company     Company I     Company II     Subsidiaries     Adjustments     Consolidated  
 
                                                               
Revenues and Other Income
                                                               
Sales and other operating revenues
  $ -       116,220       -       -       -       73,221       -       189,441  
Equity in earnings of affiliates
    11,977       13,433       -       -       -       2,195       (24,472 )     3,133  
Gain on dispostions
    -       388       -       -       -       5,415       -       5,803  
Other income (loss)
    1       275       -       -       (28 )     30       -       278  
Intercompany revenues
    5       1,394       46       86       66       25,971       (27,568 )     -  
   
Total Revenues and Other Income
    11,983       131,710       46       86       38       106,832       (52,040 )     198,655  
   
 
                                                               
Costs and Expenses
                                                               
Purchased crude oil, natural gas and products
    -       105,105       -       -       -       57,091       (26,445 )     135,751  
Production and operating expenses
    -       4,646       -       -       -       6,087       (98 )     10,635  
Selling, general and administrative expenses
    12       1,392       -       -       -       629       (28 )     2,005  
Exploration expenses
    -       247       -       -       -       908       -       1,155  
Depreciation, depletion and amortization
    -       1,597       -       -       -       7,463       -       9,060  
Impairments
    -       51       -       -       -       1,729       -       1,780  
Taxes other than income taxes
    -       5,157       -       -       -       11,638       (2 )     16,793  
Accretion on discounted liabilities
    -       63       -       -       -       384       -       447  
Interest and debt expense
    946       475       42       77       45       597       (995 )     1,187  
Foreign currency transaction (gains) losses
    -       20       -       47       50       (25 )     -       92  
   
Total Costs and Expenses
    958       118,753       42       124       95       86,501       (27,568 )     178,905  
   
Income (loss) before income taxes
    11,025       12,957       4       (38 )     (57 )     20,331       (24,472 )     19,750  
Provision for income taxes
    (333 )     980       1       7       (6 )     7,684       -       8,333  
   
Net income (loss)
    11,358       11,977       3       (45 )     (51 )     12,647       (24,472 )     11,417  
Less: net income attributable to
noncontrolling interests
    -       -       -       -       -       (59 )     -       (59 )
   
Net Income (Loss) Attributable to ConocoPhillips
  $ 11,358       11,977       3       (45 )     (51 )     12,588       (24,472 )     11,358  
   
                                                                 
Statement of Operations   Year Ended December 31, 2009  
 
                                                               
Revenues and Other Income
                                                               
Sales and other operating revenues
  $ -       90,916       -       -       -       58,425       -       149,341  
Equity in earnings of affiliates
    4,815       5,459       -       -       -       1,666       (9,409 )     2,531  
Gain on dispositions
    -       157       -       -       -       3       -       160  
Other income (loss)
    -       396       -       -       -       (38 )     -       358  
Intercompany revenues
    30       1,119       51       78       48       18,478       (19,804 )     -  
   
Total Revenues and Other Income
    4,845       98,047       51       78       48       78,534       (29,213 )     152,390  
   
 
                                                               
Costs and Expenses
                                                               
Purchased crude oil, natural gas and products
    -       80,280       -       -       -       41,122       (18,969 )     102,433  
Production and operating expenses
    2       4,421       -       -       -       6,013       (97 )     10,339  
Selling, general and administrative expenses
    15       1,194       -       -       -       639       (18 )     1,830  
Exploration expenses
    -       295       -       -       -       887       -       1,182  
Depreciation, depletion and amortization
    -       1,710       -       -       -       7,585       -       9,295  
Impairments
    -       63       -       -       -       472       -       535  
Taxes other than income taxes
    -       4,875       -       -       -       10,674       (20 )     15,529  
Accretion on discounted liabilities
    -       59       -       -       -       363       -       422  
Interest and debt expense
    631       155       46       77       53       1,027       (700 )     1,289  
Foreign currency transaction (gains) losses
    -       (35 )     -       171       216       (398 )     -       (46 )
   
Total Costs and Expenses
    648       93,017       46       248       269       68,384       (19,804 )     142,808  
   
Income (loss) before income taxes
    4,197       5,030       5       (170 )     (221 )     10,150       (9,409 )     9,582  
Provision for income taxes
    (217 )     215       2       4       (24 )     5,110       -       5,090  
   
Net income (loss)
    4,414       4,815       3       (174 )     (197 )     5,040       (9,409 )     4,492  
Less: net income attributable to
noncontrolling interests
    -       -       -       -       -       (78 )     -       (78 )
   
Net Income (Loss) Attributable to ConocoPhillips
  $ 4,414       4,815       3       (174 )     (197 )     4,962       (9,409 )     4,414  
   

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    Millions of Dollars  
    Year Ended December 31, 2008  
                    ConocoPhillips     ConocoPhillips     ConocoPhillips                    
                    Australia     Canada     Canada                    
            ConocoPhillips     Funding     Funding     Funding     All Other     Consolidating     Total  
Statement of Operations   ConocoPhillips     Company     Company     Company I     Company II     Subsidiaries     Adjustments     Consolidated  
 
                                                               
Revenues and Other Income
                                                               
Sales and other operating revenues
  $ -       153,695       -       -       -       87,147       -       240,842  
Equity in earnings of affiliates
    (16,140 )     (11,424 )     -       -       -       4,991       27,572       4,999  
Gain (loss) on dispositions
    -       (17 )     -       -       -       908       -       891  
Other income (loss)
    (3 )     814       -       -       -       (612 )     -       199  
Intercompany revenues
    26       3,390       86       85       52       30,348       (33,987 )     -  
   
Total Revenues and Other Income
    (16,117 )     146,458       86       85       52       122,782       (6,415 )     246,931  
   
 
                                                               
Costs and Expenses
                                                               
Purchased crude oil, natural gas and products
    -       139,857       -       -       -       61,165       (32,359 )     168,663  
Production and operating expenses
    -       5,028       -       -       -       6,910       (120 )     11,818  
Selling, general and administrative expenses
    12       1,365       -       -       -       909       (57 )     2,229  
Exploration expenses
    -       278       -       -       -       1,059       -       1,337  
Depreciation, depletion and amortization
    -       1,525       -       -       -       7,487       -       9,012  
Impairments
    -       9,863       -       -       -       24,762       -       34,625  
Taxes other than income taxes
    -       5,040       -       -       -       15,831       (234 )     20,637  
Accretion on discounted liabilities
    -       59       -       -       -       359       -       418  
Interest and debt expense
    334       603       79       77       53       1,006       (1,217 )     935  
Foreign currency transaction (gains) losses
    -       50       -       (254 )     (295 )     616       -       117  
   
Total Costs and Expenses
    346       163,668       79       (177 )     (242 )     120,104       (33,987 )     249,791  
   
Income (loss) before income taxes
    (16,463 )     (17,210 )     7       262       294       2,678       27,572       (2,860 )
Provision for income taxes
    (114 )     1,301       3       (10 )     20       12,219       -       13,419  
   
Net income (loss)
    (16,349 )     (18,511 )     4       272       274       (9,541 )     27,572       (16,279 )
Less: net income attributable to
noncontrolling interests
    -       -       -       -       -       (70 )     -       (70 )
   
Net Income (Loss) Attributable to ConocoPhillips
  $ (16,349 )     (18,511 )     4       272       274       (9,611 )     27,572       (16,349 )
   

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    Millions of Dollars  
    At December 31, 2010  
                    ConocoPhillips     ConocoPhillips     ConocoPhillips                    
                    Australia     Canada     Canada                    
            ConocoPhillips     Funding     Funding     Funding     All Other     Consolidating     Total  
Balance Sheet   ConocoPhillips     Company     Company     Company I     Company II     Subsidiaries     Adjustments     Consolidated  
 
                                                               
Assets
                                                               
Cash and cash equivalents
  $ -       718       -       29       4       8,703       -       9,454  
Short-term investments
    -       -       -       -       -       973       -       973  
Accounts and notes receivable
    36       9,126       1       -       -       16,625       (9,976 )     15,812  
Investment in LUKOIL
    -       -       -       -       -       1,083       -       1,083  
Inventories
    -       3,121       -       -       -       2,076       -       5,197  
Prepaid expenses and other current assets
    23       824       -       2       -       1,292       -       2,141  
   
Total Current Assets
    59       13,789       1       31       4       30,752       (9,976 )     34,660  
Investments, loans and long-term receivables*
    84,446       111,993       762       1,445       577       50,563       (216,025 )     33,761  
Net properties, plants and equipment
    -       19,524       -       -       -       63,030       -       82,554  
Goodwill
    -       3,633       -       -       -       -       -       3,633  
Intangibles
    -       760       -       -       -       41       -       801  
Other assets
    55       254       1       3       3       589       -       905  
   
Total Assets
  $ 84,560       149,953       764       1,479       584       144,975       (226,001 )     156,314  
   
 
                                                               
Liabilities and Stockholders’ Equity
                                                               
Accounts payable
  $ -       14,939       -       2       -       13,434       (9,976 )     18,399  
Short-term debt
    (5 )     354       -       -       -       587       -       936  
Accrued income and other taxes
    -       431       -       -       6       4,437       -       4,874  
Employee benefit obligations
    -       773       -       -       -       308       -       1,081  
Other accruals
    242       620       9       15       6       1,237       -       2,129  
   
Total Current Liabilities
    237       17,117       9       17       12       20,003       (9,976 )     27,419  
Long-term debt
    11,832       3,674       750       1,250       499       4,651       -       22,656  
Asset retirement obligations and accrued environmental costs
    -       1,686       -       -       -       7,513       -       9,199  
Joint venture acquisition obligation
    -       -       -       -       -       4,314       -       4,314  
Deferred income taxes
    (1 )     3,659       -       16       (2 )     13,663       -       17,335  
Employee benefit obligations
    -       2,779       -       -       -       904       -       3,683  
Other liabilities and deferred credits*
    10,752       32,268       -       114       61       19,169       (59,765 )     2,599  
   
Total Liabilities
    22,820       61,183       759       1,397       570       70,217       (69,741 )     87,205  
Retained earnings
    33,897       21,584       3       (94 )     (81 )     20,162       (35,074 )     40,397  
Other common stockholders’ equity
    27,843       67,186       2       176       95       54,049       (121,186 )     28,165  
Noncontrolling interests
    -       -       -       -       -       547       -       547  
   
Total Liabilities and Stockholders’ Equity
  $ 84,560       149,953       764       1,479       584       144,975       (226,001 )     156,314  
   
*Includes intercompany loans.
                                                                 
Balance Sheet   At December 31, 2009  
 
                                                               
Assets
                                                               
Cash and cash equivalents
  $ -       122       -       18       1       554       (153 )     542  
Short-term investments
    -       -       -       2,973       -       -       (2,973 )     -  
Accounts and notes receivable
    26       6,495       -       -       -       13,712       (7,018 )     13,215  
Inventories
    -       2,911       -       -       -       2,029       -       4,940  
Prepaid expenses and other current assets
    13       835       -       4       3       1,621       (6 )     2,470  
   
Total Current Assets
    39       10,363       -       2,995       4       17,916       (10,150 )     21,167  
Investments, loans and long-term receivables*
    70,769       91,643       759       1,376       933       47,886       (175,272 )     38,094  
Net properties, plants and equipment
    -       19,838       -       -       -       67,870       -       87,708  
Goodwill
    -       3,638       -       -       -       -       -       3,638  
Intangibles
    -       770       -       -       -       53       -       823  
Other assets
    55       240       1       3       4       509       (104 )     708  
   
Total Assets
  $ 70,863       126,492       760       4,374       941       134,234       (185,526 )     152,138  
   
 
                                                               
Liabilities and Stockholders’ Equity
                                                               
Accounts payable
  $ 7       11,590       -       1       1       10,904       (7,018 )     15,485  
Short-term debt
    235       1,286       -       2,973       -       207       (2,973 )     1,728  
Accrued income and other taxes
    -       298       -       (1 )     -       3,105       -       3,402  
Employee benefit obligations
    -       588       -       -       -       258       -       846  
Other accruals
    262       643       9       15       10       1,301       (6 )     2,234  
   
Total Current Liabilities
    504       14,405       9       2,988       11       15,775       (9,997 )     23,695  
Long-term debt
    12,561       4,053       749       1,250       849       7,463       -       26,925  
Asset retirement obligations and accrued environmental costs
    -       1,406       -       -       -       7,307       -       8,713  
Joint venture acquisition obligation
    -       -       -       -       -       5,009       -       5,009  
Deferred income taxes
    (4 )     2,785       -       10       10       15,155       -       17,956  
Employee benefit obligations
    -       2,960       -       -       -       1,170       -       4,130  
Other liabilities and deferred credits*
    2,560       25,819       -       68       37       17,296       (42,683 )     3,097  
   
Total Liabilities
    15,621       51,428       758       4,316       907       69,175       (52,680 )     89,525  
Retained earnings
    25,714       9,607       -       (49 )     (30 )     10,240       (13,268 )     32,214  
Other common stockholders’ equity
    29,528       65,457       2       107       64       54,229       (119,578 )     29,809  
Noncontrolling interests
    -       -       -       -       -       590       -       590  
   
Total Liabilities and Stockholders’ Equity
  $ 70,863       126,492       760       4,374       941       134,234       (185,526 )     152,138  
   
*Includes intercompany loans.

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    Millions of Dollars  
    Year Ended December 31, 2010  
                    ConocoPhillips     ConocoPhillips     ConocoPhillips                    
                    Australia     Canada     Canada                    
            ConocoPhillips     Funding     Funding     Funding     All Other     Consolidating     Total  
Statement of Cash Flows   ConocoPhillips     Company     Company     Company I     Company II     Subsidiaries     Adjustments     Consolidated  
 
                                                               
Cash Flows From Operating Activities
                                                               
Net Cash Provided by (Used in)
Operating Activities
  $ 7,901       2,311       -       11       (3 )     9,338       (2,513 )     17,045  
   
 
                                                               
Cash Flows From Investing Activities
                                                               
Capital expenditures and investments
    -       (1,863 )     -       -       -       (8,221 )     323       (9,761 )
Proceeds from asset dispositions
    -       781       -       -       -       14,690       (99 )     15,372  
Net purchases of short-term investments
    -       -       -       -       -       (982 )     -       (982 )
Long-term advances/loans—related parties
    -       (335 )     -       -       -       (2,279 )     2,301       (313 )
Collection of advances/loans—related parties
    -       107       -       -       384       1,379       (1,755 )     115  
Other
    -       28       -       -       -       206       -       234  
   
Net Cash Provided by (Used in)
Investing Activities
    -       (1,282 )     -       -       384       4,793       770       4,665  
   
 
                                                               
Cash Flows From Financing Activities
                                                               
Issuance of debt
    -       2,159       -       -       -       260       (2,301 )     118  
Repayment of debt
    (990 )     (2,660 )     -       -       (378 )     (3,047 )     1,755       (5,320 )
Issuance of company common stock
    133       -       -       -       -       -       -       133  
Repurchase of company common stock
    (3,866 )     -       -       -       -       -       -       (3,866 )
Dividends paid on common stock
    (3,175 )     -       -       -       -       (2,666 )     2,666       (3,175 )
Other
    (3 )     52       -       -       -       (534 )     (224 )     (709 )
   
Net Cash Provided by (Used in)
Financing Activities
    (7,901 )     (449 )     -       -       (378 )     (5,987 )     1,896       (12,819 )
   
 
                                                               
Effect of Exchange Rate Changes on Cash and Cash Equivalents
    -       16       -       -       -       5       -       21  
   
 
                                                               
Net Change in Cash and Cash Equivalents
    -       596       -       11       3       8,149       153       8,912  
Cash and cash equivalents at beginning of year
    -       122       -       18       1       554       (153 )     542  
   
Cash and Cash Equivalents at End of Year
  $ -       718       -       29       4       8,703       -       9,454  
   
                                                                 
Statement of Cash Flows   Year Ended December 31, 2009  
 
                                                               
Cash Flows From Operating Activities
                                                               
Net Cash Provided by (Used in)
Operating Activities
  $ (2,205 )     6,451       -       8       -       10,309       (2,084 )     12,479  
   
 
                                                               
Cash Flows From Investing Activities
                                                               
Capital expenditures and investments
    -       (3,157 )     -       -       -       (8,384 )     680       (10,861 )
Proceeds from asset dispositions
    -       629       -       -       -       960       (319 )     1,270  
Long-term advances/loans—related parties
    -       (425 )     -       -       -       (681 )     581       (525 )
Collection of advances/loans—related parties
    -       168       950       -       -       3,808       (4,833 )     93  
Other
    -       46       -       -       -       42       -       88  
   
Net Cash Provided by (Used in)
Investing Activities
    -       (2,739 )     950       -       -       (4,255 )     (3,891 )     (9,935 )
   
 
                                                               
Cash Flows From Financing Activities
                                                               
Issuance of debt
    8,909       490       -       -       -       269       (581 )     9,087  
Repayment of debt
    (3,826 )     (4,106 )     (950 )     -       -       (3,809 )     4,833       (7,858 )
Issuance of company common stock
    13       -       -       -       -       -       -       13  
Dividends paid on common stock
    (2,832 )     -       -       -       -       (1,945 )     1,945       (2,832 )
Other
    (59 )     18       -       -       -       (863 )     (361 )     (1,265 )
   
Net Cash Provided by (Used in)
Financing Activities
    2,205       (3,598 )     (950 )     -       -       (6,348 )     5,836       (2,855 )
   
 
                                                               
Effect of Exchange Rate Changes on Cash and Cash Equivalents
    -       -       -       -       -       98       -       98  
   
 
                                                               
Net Change in Cash and Cash Equivalents
    -       114       -       8       -       (196 )     (139 )     (213 )
Cash and cash equivalents at beginning of year
    -       8       -       10       1       750       (14 )     755  
   
Cash and Cash Equivalents at End of Year
  $ -       122       -       18       1       554       (153 )     542  
   

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    Millions of Dollars  
    Year Ended December 31, 2008  
                    ConocoPhillips     ConocoPhillips     ConocoPhillips                    
                    Australia     Canada     Canada                    
            ConocoPhillips     Funding     Funding     Funding     All Other     Consolidating     Total  
Statement of Cash Flows   ConocoPhillips     Company     Company     Company I     Company II     Subsidiaries     Adjustments     Consolidated  
 
                                                               
Cash Flows From Operating Activities
                                                               
Net Cash Provided by Operating Activities
  $ 12,641       2,077       6       3       -       10,815       (2,884 )     22,658  
   
 
                                                               
Cash Flows From Investing Activities
                                                               
Capital expenditures and investments
    -       (5,131 )     -       -       -       (14,848 )     880       (19,099 )
Proceeds from asset dispositions
    -       271       -       -       -       1,549       (180 )     1,640  
Long-term advances/loans—related parties
    (5,000 )     (5,815 )     -       -       -       (3,396 )     14,048       (163 )
Collection of advances/loans—related parties
    -       293       -       -       -       17       (276 )     34  
Other
    -       (8 )     -       -       -       (20 )     -       (28 )
   
Net Cash Provided by (Used in)
Investing Activities
    (5,000 )     (10,390 )     -       -       -       (16,698 )     14,472       (17,616 )
   
 
                                                               
Cash Flows From Financing Activities
                                                               
Issuance of debt
    4,779       8,266       -       -       -       8,660       (14,048 )     7,657  
Repayment of debt
    (1,500 )     (361 )     -       -       -       (312 )     276       (1,897 )
Issuance of company common stock
    198       -       -       -       -       -       -       198  
Repurchase of company common stock
    (8,249 )     -       -       -       -       -       -       (8,249 )
Dividends paid on common stock
    (2,854 )     -       (6 )     -       -       (3,237 )     3,243       (2,854 )
Other
    (15 )     134       -       -       -       (38 )     (700 )     (619 )
   
Net Cash Provided by (Used in)
Financing Activities
    (7,641 )     8,039       (6 )     -       -       5,073       (11,229 )     (5,764 )
   
 
                                                               
Effect of Exchange Rate Changes on Cash and Cash Equivalents
    -       87       -       -       -       (66 )     -       21  
   
 
                                                               
Net Change in Cash and Cash Equivalents
    -       (187 )     -       3       -       (876 )     359       (701 )
Cash and cash equivalents at beginning of year
    -       195       -       7       1       1,626       (373 )     1,456  
   
Cash and Cash Equivalents at End of Year
  $ -       8       -       10       1       750       (14 )     755  
   

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Item 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 9A.   CONTROLS AND PROCEDURES
As of December 31, 2010, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Senior Vice President, Finance and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the Act), of the effectiveness of the design and operation of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Senior Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of December 31, 2010.
There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the quarterly period ended December 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
This report is included in Item 8 on page 70 and is incorporated herein by reference.
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
This report is included in Item 8 on page 72 and is incorporated herein by reference.
Item 9B.   OTHER INFORMATION
None.

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PART III
Item 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding our executive officers appears in Part I of this report on pages 28 and 29.
Code of Business Ethics and Conduct for Directors and Employees
We have a Code of Business Ethics and Conduct for Directors and Employees (Code of Ethics), including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. We have posted a copy of our Code of Ethics on the “Corporate Governance” section of our Internet Web site at www.conocophillips.com (within the Investor Relations>Governance section) . Any waivers of the Code of Ethics must be approved, in advance, by our full Board of Directors. Any amendments to, or waivers from, the Code of Ethics that apply to our executive officers and directors will be posted on the “Corporate Governance” section of our Internet Web site.
All other information required by Item 10 of Part III will be included in our Proxy Statement relating to our 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2011, and is incorporated herein by reference.*
Item 11.   EXECUTIVE COMPENSATION
Information required by Item 11 of Part III will be included in our Proxy Statement relating to our 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2011, and is incorporated herein by reference.*
Item 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by Item 12 of Part III will be included in our Proxy Statement relating to our 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2011, and is incorporated herein by reference.*
Item 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required by Item 13 of Part III will be included in our Proxy Statement relating to our 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2011, and is incorporated herein by reference.*
Item 14.   PRINCIPAL ACCOUNTING FEES AND SERVICES
Information required by Item 14 of Part III will be included in our Proxy Statement relating to our 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2011, and is incorporated herein by reference.*
 
* Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in our 2011 Proxy Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a part of this report.

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Schedule
PART IV
Item 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES
             
(a)
    1.     Financial Statements and Supplementary Data
 
          The financial statements and supplementary information listed in the Index to Financial Statements, which appears on page 69, are filed as part of this annual report.
 
           
 
    2.     Financial Statement Schedules
 
          Schedule II—Valuation and Qualifying Accounts, appears below. All other schedules are omitted because they are not required, not significant, not applicable or the information is shown in another schedule, the financial statements or the notes to consolidated financial statements.
 
           
 
    3.     Exhibits
 
          The exhibits listed in the Index to Exhibits, which appears on pages 175 through 178 are filed as part of this annual report.
 
           
(c)     Financial statements of OAO LUKOIL will be filed by amendment to this Annual Report on Form 10-K no later than June 30, 2011, in accordance with Rule 3-09 of Regulation S-X.
SCHEDULE II— VALUATION AND QUALIFYING ACCOUNTS (Consolidated)
ConocoPhillips
                                         
  Millions of Dollars  
    Balance at     Charged to                     Balance at  
Description   January 1     Expense     Other (a)   Deductions     December 31  
   
2010
                                       
Deducted from asset accounts:
                                       
Allowance for doubtful accounts and notes receivable
  $ 76       (31 )     (1 )     (12) (b)     32  
Deferred tax asset valuation allowance
    1,540       414       (12 )     (542)       1,400  
Included in other liabilities:
                                       
Restructuring accruals
    73       78       1       (47) (c)     105  
   
2009
                                       
Deducted from asset accounts:
                                       
Allowance for doubtful accounts and notes receivable
  $ 61       69       2       (56) (b)     76  
Deferred tax asset valuation allowance
    1,340       200       2       (2)       1,540  
Included in other liabilities:
                                       
Restructuring accruals
    196       41       (76 )     (88) (c)     73  
   
2008
                                       
Deducted from asset accounts:
                                       
Allowance for doubtful accounts and notes receivable
  $ 58       38       (4 )     (31) (b)     61  
Deferred tax asset valuation allowance
    1,269       220       1       (150)       1,340  
Included in other liabilities:
                                       
Restructuring accruals
    117       125       11       (57) (c)     196  
   
(a)Represents acquisitions/dispositions/revisions and the effect of translating foreign financial statements.
(b)Amounts charged off less recoveries of amounts previously charged off.
(c)Benefit payments.

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Table of Contents

CONOCOPHILLIPS
INDEX TO EXHIBITS
     
Exhibit    
Number   Description
 
   
3.1
  Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2008; File No. 001-32395).
 
   
3.2
  Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips (incorporated by reference to Exhibit 3.2 to the Current Report of ConocoPhillips on Form 8-K filed on August 30, 2002; File No. 000-49987).
 
   
3.3
  By-Laws of ConocoPhillips, as amended on December 12, 2008 (incorporated by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K filed on December 12, 2008; File No. 001-32395).
 
   
4.1
  Rights agreement, dated as of June 30, 2002, between ConocoPhillips and Mellon Investor Services LLC, as rights agent, which includes as Exhibit A the form of Certificate of Designations of Series A Junior Participating Preferred Stock, as Exhibit B the form of Rights Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock (incorporated by reference to Exhibit 4.1 to the Current Report of ConocoPhillips on Form 8-K filed on August 30, 2002; File No. 000-49987).
 
   
 
  ConocoPhillips and its subsidiaries are parties to several debt instruments under which the total amount of securities authorized does not exceed 10 percent of the total assets of ConocoPhillips and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to the SEC upon request.
 
   
10.1
  1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
 
   
10.2
  1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
 
   
10.3
  Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
 
   
10.4
  Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended December 31, 1999; File No. 1-720).
 
   
10.5
  ConocoPhillips Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.7 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).

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Exhibit    
Number   Description
 
   
 
   
10.6
  Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.18 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
 
   
10.7
  Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
 
   
10.8
  Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).
 
   
10.9
  Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
 
   
10.10.1
  ConocoPhillips Key Employee Supplemental Retirement Plan (incorporated by reference to Exhibit 10.11 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
 
   
10.10.2
  First Amendment to the ConocoPhillips Key Employee Supplemental Retirement Plan.
 
   
10.11.1
  Defined Contribution Make-Up Plan of ConocoPhillips—Title I (incorporated by reference to Exhibit 10.13.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).
 
   
10.11.2
  Defined Contribution Make-Up Plan of ConocoPhillips—Title II (incorporated by reference to Exhibit 10.12.2 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
 
   
10.12
  2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
 
   
10.13
  1998 Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
 
   
10.14
  1998 Key Employee Stock Performance Plan of ConocoPhillips (incorporated by reference to Exhibit 10.28 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
 
   
10.15
  Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).
 
   
10.16
  ConocoPhillips Form Indemnity Agreement with Directors (incorporated by reference to Exhibit 10.34 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).

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Table of Contents

     
Exhibit    
Number   Description
 
   
10.17.1
  Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of the Annual Report of ConocoPhillips Holding Company on Form 10-K for the year ended December 31, 1999; File No. 001-14521).
 
   
10.17.2
  Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
 
   
10.18.1
  ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10.40 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003; File No. 000-49987).
 
   
10.18.2
  First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2008; File No. 001-32395).
 
   
10.19
  ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003; File No. 000-49987).
 
   
10.20.1
  Key Employee Deferred Compensation Plan of ConocoPhillips—Title I (incorporated by reference to Exhibit 10.23.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).
 
   
10.20.2
  Key Employee Deferred Compensation Plan of ConocoPhillips—Title II (incorporated by reference to Exhibit 10.21.2 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
 
   
10.20.3
  First Amendment to the Key Employee Deferred Compensation Plan of ConocoPhillips—Title II.
 
   
10.20.4
  Second Amendment to the Key Employee Deferred Compensation Plan of ConocoPhillips—Title II.
 
   
10.21
  ConocoPhillips Key Employee Change in Control Severance Plan (incorporated by reference to Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
 
   
10.22
  ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.23 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
 
   
10.23
  2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Appendix C of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2004 Annual Meeting of Shareholders; File No. 000-49987).
 
   
10.24
  Aircraft Time Sharing Agreement by and between James J. Mulva and ConocoPhillips (incorporated by reference to Exhibit 10 of the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2007; File No. 001-32395).
 
   
10.25
  Form of Stock Option Award Agreement under the ConocoPhillips Stock Option and Stock Appreciation Rights Program (incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).

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Table of Contents

     
Exhibit    
Number   Description
 
   
10.26
  Form of Restricted Stock Unit Award Agreement under the ConocoPhillips Performance Share Program (incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
 
   
10.27
  Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted December 7, 2007 (incorporated by reference to Exhibit 10.30 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2007; File No. 001-32395).
 
   
10.28
  Annex to Nonqualified Deferred Compensation Arrangements of ConocoPhillips (incorporated by reference to Exhibit 10.30 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
 
   
10.29
  2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2009 Annual Meeting of Shareholders; File No. 001-32395).
 
   
12
  Computation of Ratio of Earnings to Fixed Charges.
 
   
21
  List of Subsidiaries of ConocoPhillips.
 
   
23.1
  Consent of Ernst & Young LLP.
 
   
23.2
  Consent of DeGolyer and MacNaughton.
 
   
31.1
  Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
 
   
31.2
  Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
 
   
32
  Certifications pursuant to 18 U.S.C. Section 1350.
 
   
99
  Report of DeGolyer and MacNaughton.
 
   
101.INS
  XBRL Instance Document.
 
   
101.SCH
  XBRL Schema Document.
 
   
101.CAL
  XBRL Calculation Linkbase Document.
 
   
101.DEF
  XBRL Definition Linkbase Document.
 
   
101.LAB
  XBRL Labels Linkbase Document.
 
   
101.PRE
  XBRL Presentation Linkbase Document.

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Table of Contents

SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
     
 
  CONOCOPHILLIPS
 
   
 
   
 
   
February 23, 2011
  /s/ James J. Mulva
 
   
 
  James J. Mulva
 
  Chairman of the Board of Directors
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 23, 2011, on behalf of the registrant by the following officers in the capacity indicated and by a majority of directors.
     
Signature   Title
 
   
 
   
 
   
/s/ James J. Mulva
 
James J. Mulva
  Chairman of the Board of Directors
 and Chief Executive Officer
(Principal executive officer)
 
   
 
   
/s/ Jeff W. Sheets
 
Jeff W. Sheets
  Senior Vice President, Finance
 and Chief Financial Officer
(Principal financial officer)
 
   
 
   
/s/ Glenda M. Schwarz
 
Glenda M. Schwarz
  Vice President and Controller
 (Principal accounting officer)

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Table of Contents

     
 
   
 
   
/s/ Richard L. Armitage
 
Richard L. Armitage
  Director 
 
   
 
   
/s/ Richard H. Auchinleck
 
Richard H. Auchinleck
  Director 
 
   
 
   
/s/ James E. Copeland, Jr.
 
James E. Copeland, Jr.
  Director 
 
   
 
   
/s/ Kenneth M. Duberstein
 
Kenneth M. Duberstein
  Director 
 
   
 
   
/s/ Ruth R. Harkin
 
Ruth R. Harkin
  Director 
 
   
 
   
/s/ Harold W. McGraw III
 
Harold W. McGraw III
  Director 
 
   
 
   
/s/ Robert A. Niblock
 
Robert A. Niblock
  Director 
 
   
 
   
/s/ Harald J. Norvik
 
Harald J. Norvik
  Director 
 
   
 
   
/s/ William K. Reilly
 
William K. Reilly
  Director 
 
   
 
   
/s/ Bobby S. Shackouls
 
Bobby S. Shackouls
  Director 
 
   
 
   
/s/ Victoria J. Tschinkel
 
Victoria J. Tschinkel
  Director 
 
   
 
   
/s/ Kathryn C. Turner
 
Kathryn C. Turner
  Director 
 
   
 
   
/s/ William E. Wade, Jr.
 
William E. Wade, Jr.
  Director 

180

Exhibit 10.10.2
FIRST AMENDMENT TO
CONOCOPHILLIPS
KEY EMPLOYEE SUPPLEMENTAL RETIREMENT PLAN
          Effective December 19, 2008, ConocoPhillips Company (the “Company”) amended and restated the Key Employee Supplemental Retirement Plan (“KESRP”) for the benefit of certain employees of the Company and its affiliates.
          The Company desires to amend the KESRP by adding an Appendix for Select New Hires effective October 6, 2010.
          Pursuant to the foregoing, the KESRP is hereby amended by appending to the end thereof the following Appendix for Select New Hires:
“APPENDIX FOR SELECT NEW HIRES
TO
CONOCO PHILLIPS KEY EMPLOYEE SUPPLEMENTAL RETIREMENT
PLAN
For Select New Hires, as set forth in resolutions adopted from time to time by the Human Resources and Compensation Committee of the Board of Directors of ConocoPhillips, or its successor, the following provisions apply:
  1.   The Select New Hire will, effective on the first day of employment with the Controlled Group, become a Participant in the ConocoPhillips Key Employee Supplemental Retirement Plan. In addition to the benefits provided under the Plan, the Select New Hire will be eligible for a further benefit (the “Further Benefit”), calculated in accordance with the provisions of this Appendix.
 
  2.   Further Benefit shall mean the difference between the Putative Title I Benefit and the Offsetting Benefits, both as described below. In determining the Further Benefit, paragraphs (f) and (g) of the Plan shall apply.
 
  3.   The Putative Title I Benefit shall mean the sum of (i), (ii), and (iii) below:
  (i)   The difference between the Select New Hire’s total accrued benefit under Title I and his actual accrued benefit under Title I. For this purpose, a Select New Hire’s “total accrued benefit under Title I” is the accrued benefit he would have if his accrued benefit under Title I were determined under the terms of Title I but with the following modifications:
  (aa)   Include in Annual Earnings an award under the Incentive Compensation Plan which the Select New Hire deferred under the terms of KEDCP. Include such award in the calendar year in which the award would have been paid to the Select New Hire if it had not been deferred.
 
  (bb)   Include in Annual Earnings salary that would have been paid to the Select New Hire but for the fact that he voluntarily elected to defer

1


 

      receipt of that salary under the terms of KEDCP. Include the deferred salary in Annual Earnings in the calendar year in which the salary would have been paid had it not been deferred.
 
  (cc)   Include in Annual Earnings the initial value of a restricted stock or restricted stock unit award under the Incentive Compensation Plan. Include that value in Annual Earnings in the calendar year in which the award was granted.
 
  (dd)   Include in Annual Earnings the value of any special award specified by the Committee under the terms of the special award to be included for Annual Earnings purposes under Title I in the year in which any applicable restrictions on the award lapse or, if deferred, in the year in which any applicable restrictions would have lapsed absent an election to defer.
 
  (ee)   Disregard the limitations on compensation related to Code section 401(a)(17).
 
  (ff)   Disregard the limitation on benefits related to Code section 415.
 
  (gg)   If the Select New Hire is eligible to receive benefits under the ConocoPhillips Executive Severance Plan or under the ConocoPhillips Key Employee Change in Control Severance Plan, include in Annual Earnings an amount determined by dividing the Select New Hire’s Salary by 4.3333 times the number of weeks or partial weeks from the date the Select New Hire’s employment ends with the Employer to the end of that calendar year. Provided, however, this subsection (gg) shall be disregarded to the extent the benefit created solely by operation of this subsection (gg) is provided under the terms of Title I.
 
  (hh)   Determine service credited for purposes of benefit accrual as if the Select New Hire had originally been employed by the Controlled Group on the date that the Select New Hire began employment with the company with which the Select New Hire was employed immediately prior to becoming employed by the Controlled Group.
 
  (ii)   In the case of a Select New Hire who terminated employment on or after February 8, 1993, the Title I-related accrued benefit shall include an additional supplemental accrued benefit calculated under the terms of Title I, but disregarding the limitation on compensation that is taken into account, using as final average earnings the difference, if any, between the Total Final Average Earnings and the Final Average Earnings used in Title I.
 
  (iii)   The Title I-related accrued benefit shall also include any benefit provided under Section IV of this Plan.
  4.   The Offsetting Benefits shall mean any benefit, other than the Further Benefit, provided to the Select New Hire under a defined benefit plan of ConocoPhillips, including but not limited to the ConocoPhillips Retirement Plan (and any successor plan) and the ConocoPhillips Key Employee Supplemental Retirement Plan (and any successor plan), together with any benefit provided to the Select New Hire under a “defined benefit plan” (as defined in section 3(35) of the Employee Retirement Income Security Act of 1974, as amended (ERISA)),

2


 

      including any such plan regardless of whether it might also be considered an “excess benefit plan” as defined in section 3(36) of ERISA, of the company by which the Select New Hire was employed immediately prior to becoming an employee of the Controlled Group. In determining the value of a benefit provided by an employer which is not a member of the Controlled Group, the Plan Administrator may make any reasonable assumptions necessary and use such information as may be publicly available, provided by such employer, or provided by the Select New Hire, although it is within the discretion of the Plan Administrator to determine which such information and assumptions to use and to disregard any information which the Plan Administrator considers invalid, incomplete, or otherwise suspect.
 
  5.   Nothing in this Appendix is intended to affect the other operations or provisions of the Plan. If the Select New Hire is, under the provisions of the Plan, otherwise eligible to participate in the Plan, the Select New Hire will do so in accordance with those provisions.”
Executed October 11, 2010
For ConocoPhillips Company
         
   
/s/ Carin S. Knickel    
Carin S. Knickel   
Vice President, Human Resources   
 

3

Exhibit 10.20.3
FIRST AMENDMENT TO
TITLE II OF THE
KEY EMPLOYEE DEFERRED COMPENSATION PLAN
OF CONOCOPHILLIPS COMPANY
     Effective December 19, 2008, ConocoPhillips Company (the “Company”) amended and restated the Key Employee Deferred Compensation Plan (“KEDCP”) for the benefit of certain employees of the Company and its affiliates.
     The Company desires to amend the KEDCP by adding an Appendix for Select New Hires effective October 6, 2010.
     Pursuant to the foregoing, the KEDCP is hereby amended by appending to the end thereof the following Appendix for Select New Hires:
“APPENDIX FOR SELECT NEW HIRES
TO TITLE II OF THE
KEY EMPLOYEE DEFERRED COMPENSATION PLAN OF
CONOCOPHILLIPS
     For Select New Hires, as set forth in resolutions adopted from time to time by the Human Resources and Compensation Committee of the Board of Directors of ConocoPhillips, or its successor, the following provisions apply:
  1.   The Select New Hire will, effective on the first day of employment with the Controlled Group, become a Participant in Title II of the Key Employee Deferred Compensation Plan of ConocoPhillips. A Deferred Compensation Account will be created for the Select New Hire in the Plan. The amount set forth in the applicable resolution will be credited to the Deferred Compensation Account for the Select New Hire not less than 30 days after the first day of employment of the Select New Hire. Section 5(a) of the Plan shall be disregarded with respect to the Deferred Compensation Account, and in lieu thereof the Select New Hire shall be asked to complete and return to the Plan Administrator election forms to set the time and form of distribution with regard to the Deferred Compensation Account either before the first day of employment or no later than 30 days after the first day of employment. Other than with regard to the timing of the initial distribution election (as set forth in the preceding sentence), other provisions of Section 5 of the Plan shall apply to the Deferred Compensation Account, including default provisions in the event that a properly completed initial distribution election form is not received within the time set forth in the preceding sentence. For purposes of Section 5(b)(ii) of the Plan, the amount set forth in the table below shall be considered to be a deferred portion of an Incentive Compensation Plan award.
  2.   The resolution granting participation to the Select New Hire will also set the vesting schedule for the Deferred Compensation Account provided pursuant to

1


 

      paragraph 1 of this Appendix.
  3.   All other provisions of the Plan will apply to the Deferred Compensation Account and the Select New Hire as a Participant in the Plan.
  4.   Nothing in this Appendix is intended to affect the other operations of the Plan, such as Salary reductions and deferrals or Incentive Compensation Plan deferrals. If the Select New Hire is, under the provisions of the Plan, otherwise eligible to participate in the Plan, the Select New Hire may do so in accordance with those provisions.”
Executed October 6, 2010
For ConocoPhillips Company
         
     
  /s/ Carin S. Knickel    
  Carin S. Knickel   
  Vice President, Human Resources   
 

2

Exhibit 10.20.4
SECOND AMENDMENT TO
TITLE II OF THE
KEY EMPLOYEE DEFERRED COMPENSATION PLAN
OF CONOCOPHILLIPS
     Effective December 19, 2008, ConocoPhillips Company (the “Company”) amended and restated the Key Employee Deferred Compensation Plan (“KEDCP”) for the benefit of certain employees of the Company and its affiliates. Furthermore, effective October 6, 2010, the Company adopted the First Amendment to Title II of KEDCP.
     The Company desires to amend the KEDCP by the revisions set forth below, effective at the times set forth below:
  1.   Effective January 1, 2008, Section 2(a) is amended to read as follows:
    Incentive Compensation Plan . Each year after 2008, at such times as the Plan Administrator may determine, Employees who are expected to be eligible to receive an Award for the immediately following calendar year under an Incentive Compensation Plan will be notified and given the opportunity to make an election, using the Election Form or in such other manner prescribed by the Plan Administrator, to defer all or part of such Award; provided, however, that in the case of an Award under an Incentive Compensation Plan determined by the Plan Administrator to be “performance-based compensation” under Code section 409A, the Plan Administrator may delay the notification and opportunity to make an election until no later than June 30 of the year for which the Award is to be made.”
  2.   Effective January 1, 2008, Section 3(a) is amended to read as follows:
    Incentive Compensation Plan . If a Potential Participant elects to defer under this Plan all or any part of the Award to which a notice received under Section 2(a) pertains, the Potential Participant must make such election, using the Election Form or in such other manner prescribed by the Plan Administrator, which must be received on or before December 31 of the year in which said Section 2(a) notice was received (or at such earlier time as may be prescribed by the Plan Administrator). The Potential Participant’s election shall become irrevocable on December 31 of the year in which said Section 2(a) notice was received (except in the case of an election for an Award under an Incentive Compensation Plan determined by the Plan Administrator to be “performance-based compensation” under Code section 409A, the election shall become irrevocable on June 30 of the year for which the Award is to be made), subject to the provisions Section 5(d). If an election is not properly made and timely received, the Potential Participant will be deemed to have elected to receive and not to defer any such Incentive Compensation Plan Award.”
  3.   Effective January 1, 2005, Section 15 is amended by adding at the end thereof the following paragraph (d):

 


 

Exhibit 10.20.4
  “(d)    For purposes of this Plan, electronic communications and signatures shall be considered to be in writing if made in conformity with procedures which the Plan Administrator may adopt from time to time.”
Executed December 1, 2010
For ConocoPhillips Company
/s/ Carin S. Knickel
 
Carin S. Knickel
Vice President, Human Resources

 

Exhibit 12
CONOCOPHILLIPS AND CONSOLIDATED SUBSIDIARIES
TOTAL ENTERPRISE

Computation of Ratio of Earnings to Fixed Charges
                                         
    Millions of Dollars  
    Years Ended December 31  
    2010       2009 **     2008 **     2007 **     2006 **
Earnings Available for Fixed Charges
                                       
Income from continuing operations before income taxes and noncontrolling interests that have not incurred fixed charges
  $ 19,696       9,507       (2,902 )     22,871       28,147  
Distributions less than equity in earnings of affiliates
    (1,073 )     (1,254 )     5,127       (1,400 )     (738 )
Fixed charges, excluding capitalized interest*
    1,573       1,700       1,288       1,680       1,410  
   
 
  $ 20,196       9,953       3,513       23,151       28,819  
   
 
                                       
Fixed Charges
                                       
Interest and expense on indebtedness, excluding
capitalized interest
  $ 1,187       1,289       935       1,253       1,087  
Capitalized interest
    471       487       568       565       458  
Interest portion of rental expense
    185       205       207       171       232  
Interest expense relating to guaranteed debt of affiliates
    -       -       3       19       -  
   
 
  $ 1,843       1,981       1,713       2,008       1,777  
   
Ratio of Earnings to Fixed Charges
    11.0       5.0       2.1       11.5       16.2  
   
*
Includes amortization of capitalized interest totaling approximately $201 million in 2010, $206 million in 2009, $143 million in 2008, $237 million in 2007 and $92 million in 2006.
**
Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles in the company’s Annual Report on Form 10-K for the period ended December 31, 2010, for more information.

Exhibit 21
SUBSIDIARY LISTING OF CONOCOPHILLIPS
Listed below are subsidiaries of the registrant at December 31, 2010. Certain subsidiaries are omitted since such companies considered in the aggregate do not constitute a significant subsidiary.
           
 
  Company Name     Incorporation
Location
 
 
Ashford Energy Capital S.A.
    Luxembourg  
 
BR (Global) Holdings B.V.
    Netherlands  
 
BROG LP Inc.
    Delaware  
 
Burlington Resources (Irish Sea) Limited
    England  
 
Burlington Resources (Netherlands) B.V.
    Netherlands  
 
Burlington Resources (UK) Holdings Limited
    England  
 
Burlington Resources Algeria Holdings Limited
    Bermuda  
 
Burlington Resources Canada (Hunter) Ltd.
    Alberta  
 
Burlington Resources China Holdings Limited
    Bermuda  
 
Burlington Resources China LLC
    Delaware  
 
Burlington Resources Finance Company
    Nova Scotia  
 
Burlington Resources Inc.
    Delaware  
 
Burlington Resources International Holdings LLC
    Delaware  
 
Burlington Resources International Inc.
    Delaware  
 
Burlington Resources Offshore Inc.
    Delaware  
 
Burlington Resources Oil & Gas Company LP
    Delaware  
 
Burlington Resources Trading Inc.
    Delaware  
 
Canadian Hunter Resources
    Alberta  
 
Clearwater Ltd.
    Bermuda  
 
Conoco AG, Zug
    Switzerland  
 
Conoco Asia Ltd.
    Bermuda  
 
Conoco Funding Company
    Nova Scotia  
 
Conoco Global Power Assets Sabine Inc.
    Delaware  
 
Conoco Orinoco Inc.
    Delaware  
 
Conoco Petroleum Operations LLC
    Delaware  
 
Conoco Venezuela C.A.
    Venezuela  
 
ConocoPhillips (03-12) Pty Ltd
    Victoria  
 
ConocoPhillips (Browse Basin) Pty Ltd
    Western Australia  
 
ConocoPhillips (Grissik) Ltd.
    Bermuda  
 
ConocoPhillips (U.K.) Cuu Long Limited
    England  
 
ConocoPhillips (U.K.) Eta Limited
    England  
 
ConocoPhillips (U.K.) Gama Limited
    England  
 
ConocoPhillips (U.K.) Limited
    England  
 
ConocoPhillips (U.K.) Theta Limited
    England  
 
ConocoPhillips (U.K.) Zeta Limited
    England  
 
ConocoPhillips Alaska, Inc.
    Delaware  
 
ConocoPhillips Alaska Natural Gas Corporation
    Delaware  
 
ConocoPhillips Algeria Ltd.
    Cayman Islands  
 
ConocoPhillips ANS Marketing Company
    Delaware  
 
ConocoPhillips Australia Gas Holdings Pty Ltd
    Western Australia  
 

1


 

Exhibit 21
           
 
  Company Name     Incorporation
Location
 
 
ConocoPhillips Australia Holdings Pty Ltd
    Australia  
 
ConocoPhillips Australia Pacific LNG Pty Ltd
    Western Australia  
 
ConocoPhillips Australia Pty Ltd
    Western Australia  
 
ConocoPhillips Bohai Limited
    Bahamas  
 
ConocoPhillips Canada (BRC) Partnership
    Alberta  
 
ConocoPhillips Canada Energy Partnership
    Alberta  
 
ConocoPhillips Canada (North) Limited
    Canada  
 
ConocoPhillips Canada Marketing & Trading ULC
    Alberta  
 
ConocoPhillips Canada Resources Corp.
    Alberta  
 
ConocoPhillips China Inc.
    Liberia  
 
ConocoPhillips Company
    Delaware  
 
ConocoPhillips Continental Holding GmbH
    Germany  
 
ConocoPhillips Energy Holding GmbH
    Germany  
 
ConocoPhillips Funding Ltd.
    Bermuda  
 
ConocoPhillips Gas Company
    Delaware  
 
ConocoPhillips Germany GmbH
    Germany  
 
ConocoPhillips Gulf of Paria B.V.
    Netherlands  
 
ConocoPhillips Hamaca B.V.
    Netherlands  
 
ConocoPhillips Holdings Limited
    England  
 
ConocoPhillips Indonesia Holding Ltd.
    British Virgin Islands  
 
ConocoPhillips Indonesia Inc. Ltd.
    Bermuda  
 
ConocoPhillips International Inc.
    Delaware  
 
ConocoPhillips International Trading Pte. Ltd.
    Singapore  
 
ConocoPhillips International Ventures Ltd.
    Bahamas  
 
ConocoPhillips Libya Waha Ltd.
    Cayman Islands  
 
ConocoPhillips Limited
    England  
 
ConocoPhillips Mineraloel Grosshandels GmbH
    Germany  
 
ConocoPhillips NGL Marketing (Canada) ULC
    Alberta  
 
ConocoPhillips Norge
    Delaware  
 
ConocoPhillips North Caspian Ltd.
    Liberia  
 
ConocoPhillips Petroleum Company U.K. Limited
    England  
 
ConocoPhillips Petroleum Holdings B.V.
    Netherlands  
 
ConocoPhillips Pipe Line Company
    Delaware  
 
ConocoPhillips Pipeline Australia Pty Ltd
    Western Australia  
 
ConocoPhillips Qatar Funding Ltd.
    Cayman Islands  
 
ConocoPhillips Qatar Ltd.
    Cayman Islands  
 
ConocoPhillips Russia Inc.
    Delaware  
 
ConocoPhillips Sabah Ltd.
    Bermuda  
 
ConocoPhillips Skandinavia AS
    Norway  
 
ConocoPhillips Surmont Partnership
    Alberta  
 
ConocoPhillips Transportation Alaska, Inc.
    Delaware  
 
ConocoPhillips Treasury Limited
    England  
 
ConocoPhillips WA-248 Pty Ltd
    Western Australia  
 
ConocoPhillips Western Canada Partnership
    Alberta  
 
ConocoPhillips Whitegate Refinery Limited
    Ireland  
 
Continental Oil Company (Nederland) B.V.
    Netherlands  
 

2


 

Exhibit 21
           
 
  Company Name     Incorporation
Location
 
 
COP Holdings Limited
    England  
 
COPREX LLC
    Delaware  
 
Danube Limited
    Bermuda  
 
Darwin LNG Pty Ltd
    Western Australia  
 
Douglas Oil Company of California
    California  
 
Dubai Petroleum Company
    Delaware  
 
Immingham CHP LLP
    England  
 
Inexco Oil Company
    Delaware  
 
International Petroleum Holdings LLC
    Delaware  
 
Kayo Oil Company
    Delaware  
 
Phillips Coal Company
    Nevada  
 
Phillips Gas Company Stockholder, Inc.
    Delaware  
 
Phillips International Investments, Inc.
    Delaware  
 
Phillips Investment Company
    Nevada  
 
Phillips Oil Company Nigeria Ltd.
    Nigeria  
 
Phillips Petroleum International Corporation
    Delaware  
 
Phillips Petroleum International Investment Company
    Delaware  
 
Phillips-San Juan Partners, L.P.
    Delaware  
 
Polar Tankers, Inc.
    Delaware  
 
Sooner Insurance Company
    Vermont  
 
Springtime Holdings Limited
    Cayman Islands  
 
The Louisiana Land and Exploration Company
    Maryland  
 
Wilhelmshavener Raffineriegesellschaft mbH
    Germany  
 

3

Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference of our reports dated February 23, 2011, with respect to the consolidated financial statements, condensed consolidating financial information, and financial statement schedule of ConocoPhillips, and the effectiveness of internal control over financial reporting of ConocoPhillips, included in this Annual Report (Form 10-K) for the year ended December 31, 2010, in the following registration statements and related prospectuses.
         
ConocoPhillips
  Form S-3   File No. 333-157547
 
       
ConocoPhillips
  Form S-4   File No. 333-130967
 
       
ConocoPhillips
  Form S-8   File No. 333-98681
 
       
ConocoPhillips
  Form S-8   File No. 333-116216
 
       
ConocoPhillips
  Form S-8   File No. 333-133101
 
       
ConocoPhillips
  Form S-8   File No. 333-159318
 
       
ConocoPhillips
  Form S-8   File No. 333-171047
/s/ Ernst & Young LLP
Houston, Texas
February 23, 2011

Exhibit 23.2
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
February 23, 2011
ConocoPhillips
600 North Dairy Ashford
Houston, Texas 77079
Ladies and Gentlemen:
We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton as an independent petroleum engineering consulting firm, under “Part II” under the heading “8. Financial Statements and Supplemental Data,” under the subheading “Reserves Governance” and under “Part IV” under the heading “15. Exhibits, Financial Statement Schedules” under the subheading “Index to Exhibits” in ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2010, and to the inclusion of our process review letter report dated February 23, 2011, (our “Report”) as an exhibit to ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2010. We also consent to the incorporation by reference of our Report in the Registration Statements filed by ConocoPhillips on Form S-3 (No. 333-157547), Form S-4 (No. 333-130967) and Form S-8 (No. 333-98681, No. 333-116216, No. 333-133101, No. 333-159318 and No. 333-171047).
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716

Exhibit 31.1
CERTIFICATION
I, James J. Mulva, certify that:
1.   I have reviewed this annual report on Form 10-K of ConocoPhillips;
 
2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
  (a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  (b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
  (c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  (d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
  (a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
  (b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
February 23, 2011
     
    /s/ James J. Mulva
     
    James J. Mulva
Chairman and
Chief Executive Officer

Exhibit 31.2
CERTIFICATION
I, Jeff W. Sheets, certify that:
1.   I have reviewed this annual report on Form 10-K of ConocoPhillips;
 
2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
  (a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  (b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
  (c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  (d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
  (a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
  (b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
February 23, 2011
     
    /s/ Jeff W. Sheets
     
    Jeff W. Sheets
    Senior Vice President, Finance and
    Chief Financial Officer

Exhibit 32
CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350
In connection with the Annual Report of ConocoPhillips (the Company) on Form 10-K for the period ended December 31, 2010, as filed with the U.S. Securities and Exchange Commission on the date hereof (the Report), each of the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to their knowledge:
  (1)   The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and
 
  (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
February 23, 2011
     
    /s/ James J. Mulva
     
    James J. Mulva
    Chairman and
    Chief Executive Officer
     
     
    /s/ Jeff W. Sheets
     
    Jeff W. Sheets
    Senior Vice President, Finance and
    Chief Financial Officer

Exhibit 99
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
February 23, 2011
ConocoPhillips
600 North Dairy Ashford
Houston, Texas 77079
Re: SEC Process Review
Ladies and Gentlemen:
               Pursuant to your request, DeGolyer and MacNaughton has performed a process review of the processes and controls used within ConocoPhillips in preparing its internal estimates of proved reserves, as of December 31, 2010. The process review, which is contemplated by Item 1202 (a) (8) of Regulation S-K of the Securities and Exchange Commission (SEC), has been performed specifically to address the adequacy and effectiveness of ConocoPhillips’ internal processes and controls relative to its estimation of proved reserves in compliance with Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC.
               DeGolyer and MacNaughton has participated as an independent member of the internal ConocoPhillips Reserves Compliance Assessment Team in reviews and discussions with each of the relevant ConocoPhillips business units relative to SEC proved reserves estimation. DeGolyer and MacNaughton participated in the review of all major fields in all countries where ConocoPhillips has proved reserves worldwide, which ConocoPhillips has indicated represents over 90 percent of its estimated total proved reserves as of December 31, 2010.
               The reviews with ConocoPhillips’ technical staff involved presentations and discussions of a) basic reservoir data including seismic, well log, pressure and production tests, core analysis, PVT data and production history, b) technical methods employed in SEC proved reserves estimation including performance analysis, geology, mapping and volumetric estimates, c) economic analysis, and d) commercial assessment, including the legal basis for the


 

 2
DeGolyer and MacNaughton
interest in the reserves, primarily related to lease agreements and other petroleum license agreements, such as concession and production sharing agreements.
               A field examination of the properties was not considered necessary for the purposes of this review of ConocoPhillips’ processes and controls.
               It is our opinion that ConocoPhillips’ estimates of proved reserves for the properties reviewed were prepared by the use of recognized geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by ConocoPhillips’ experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. It is our opinion that the general processes and controls employed by ConocoPhillips in estimating its December 31, 2010, proved reserves for the properties reviewed are in accordance with the SEC reserves definitions.
               This process review of ConocoPhillips’ procedures and methods does not constitute a review, study, or independent audit of ConocoPhillips’ estimated proved reserves and corresponding future net revenues. This report is not intended to indicate that DeGolyer and MacNaughton is offering any opinion as to the reasonableness of reserves estimates reported by ConocoPhillips.
               DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in ConocoPhillips. Our fees were not contingent on the results of our evaluation.
Submitted,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
/s/ R. M. Shuck, P.E.
R. M. Shuck, P.E.
Senior Vice President
DeGolyer and MacNaughton