10-K 1 d267896d10k.htm FORM 10-K Form 10-K
Table of Contents
Index to Financial Statements

2011

 

 

 

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, 2011
For the fiscal year ended  

            December 31, 2011

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

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

600 North Dairy Ashford

Houston, TX 77079

(Address of principal executive offices) (Zip Code)

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

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

 

Title of each class

      

Name of each exchange

on which registered

Common Stock, $.01 Par Value

     New York Stock Exchange

Preferred Share Purchase Rights Expiring June 30, 2012

     New York Stock Exchange

6.65% Debentures due July 15, 2018

     New York Stock Exchange

7% Debentures due 2029

     New York Stock Exchange

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.  [  ]

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, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $75.19, was $103.2 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 854,854 and 36,219,102 shares, respectively, in determining the aggregate market value.

The registrant had 1,279,692,596 shares of common stock outstanding at January 31, 2012.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 9, 2012 (Part III)

 

 

 


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

Item

       Page  
 

PART I

  

1 and 2.

 

Business and Properties

     1   
 

Corporate Structure

     1   
 

Segment and Geographic Information

     2   
 

Exploration and Production (E&P)

     2   
 

Midstream

     19   
 

Refining and Marketing (R&M)

     21   
 

LUKOIL Investment

     27   
 

Chemicals

     27   
 

Emerging Businesses

     28   
 

Competition

     29   
 

General

     30   

1A.

 

Risk Factors

     31   

1B.

 

Unresolved Staff Comments

     33   

3.

 

Legal Proceedings

     33   

4.

 

Mine Safety Disclosures

     34   
 

Executive Officers of the Registrant

     35   
 

PART II

  

5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     37   

6.

 

Selected Financial Data

     38   

7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     39   

7A.

 

Quantitative and Qualitative Disclosures About Market Risk

     74   

8.

 

Financial Statements and Supplementary Data

     77   

9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     173   

9A.

 

Controls and Procedures

     173   

9B.

 

Other Information

     173   
 

PART III

  

10.

 

Directors, Executive Officers and Corporate Governance

     174   

11.

 

Executive Compensation

     174   

12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     174   

13.

 

Certain Relationships and Related Transactions, and Director Independence

     174   

14.

 

Principal Accounting Fees and Services

     174   
 

PART IV

  

15.

 

Exhibits, Financial Statement Schedules

     175   
 

Signatures

     181   


Table of Contents
Index to Financial Statements

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 73.

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 past investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We completed the divestiture of our entire interest in LUKOIL in the first quarter of 2011.

   

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, 2011, ConocoPhillips employed approximately 29,800 people.

Planned Separation of Downstream Businesses

On July 14, 2011, we announced approval by our Board of Directors to pursue the separation of our refining, marketing and transportation businesses into a stand-alone, publicly traded corporation via a tax-free distribution. The new downstream company, named Phillips 66, will be headquartered in Houston, Texas. In addition to the refining, marketing and transportation businesses, we expect Phillips 66 will also include most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment, to create an integrated downstream company.

 

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Index to Financial Statements

The separation would be accomplished by the pro rata distribution of one share of Phillips 66 stock for every two shares of ConocoPhillips stock held by ConocoPhillips’ shareholders on the record date for such distribution.

In October 2011, we requested a private letter ruling from the U.S. Internal Revenue Service, which is expected to confirm the distribution will qualify as a tax-free reorganization for U.S. federal income tax purposes. In addition, we filed the initial Phillips 66 Form 10 registration statement with the U.S. Securities and Exchange Commission (SEC) on November 14, 2011, and an amendment on January 3, 2012.

The separation is subject to market conditions, customary regulatory approvals, the receipt of an affirmative Internal Revenue Service private letter ruling and final Board approval, and is expected to be completed in the second quarter of 2012.

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, 2011, our E&P segment represented 67 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, transport and market the resulting LNG are also included in the E&P segment. At December 31, 2011, 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 prior 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 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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Index to Financial Statements

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 80 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    2011      2010      2009  
  

 

 

 

Crude oil and natural gas liquids

        

Consolidated operations

     3,287         3,161         3,194   

Equity affiliates

     175         231         1,710   

 

 

Total Crude Oil and Natural Gas Liquids

     3,462         3,392         4,904   

 

 

Natural gas

        

Consolidated operations

     2,933         3,039         3,161   

Equity affiliates

     553         580         880   

 

 

Total Natural Gas

     3,486         3,619         4,041   

 

 

Bitumen

        

Consolidated operations

     530         455         417   

Equity affiliates

     909         844         716   

 

 

Total Bitumen

     1,439         1,299         1,133   

 

 

Synthetic oil

        

Consolidated operations

     -         -         248   

Equity affiliates

     -         -         -   

 

 

Total Synthetic Oil

     -         -         248   

 

 

Total consolidated operations

     6,750         6,655         7,020   

Total equity affiliates

     1,637         1,655         3,306   

 

 

Total company

     8,387         8,310         10,326   

 

 
Includes amounts related to LUKOIL investment:      -         -         1,967   

In 2011, E&P’s worldwide production, including its share of equity affiliates, averaged 1,619,000 barrels of oil equivalent per day (BOED), compared with 1,752,000 BOED in 2010. During 2011, 653,000 BOED were produced in the United States, a 5 percent decrease from 686,000 BOED in 2010. Production from our international E&P operations averaged 966,000 BOED in 2011, a 9 percent decrease from 1,066,000 BOED in 2010. Worldwide production decreased primarily due to suspended operations in Libya and Bohai Bay, China, asset dispositions and unplanned downtime. Normal field decline was largely offset by new production.

E&P’s worldwide annual average crude oil and natural gas liquids sales price increased 34 percent, from $72.77 per barrel in 2010 to $97.22 per barrel in 2011. Worldwide bitumen prices increased 18 percent, from $53.06 per barrel in 2010 to $62.56 per barrel in 2011. E&P’s average annual worldwide natural gas sales price increased 7 percent, from $4.98 per thousand cubic feet in 2010 to $5.34 per thousand cubic feet in 2011.

E&P—UNITED STATES

In 2011, U.S. E&P operations contributed 45 percent of E&P’s worldwide liquids production and 36 percent of natural gas production.

 

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Index to Financial Statements

Alaska

 

       2011  
     Interest     Operator     

      Liquids

MBD(1)

    

Natural Gas

MMCFD(2)

    

Total

MBOED(3)

 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Greater Prudhoe Area

     36.1     BP         106         6         107   

Greater Kuparuk Area

     52.2-55.4        COP         58         -         58   

Western North Slope

     78.0        COP         51         1         51   

Cook Inlet Area

     33.3-100        COP         -         54         9   

 

 

Total Alaska

          215         61         225   

 

 

(1)Thousands of barrels per day.

(2)Millions of cubic feet per day.

(3)Thousands of barrels of oil equivalent per day.

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 which processes natural gas for reinjection 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.

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. Field installations include three central production facilities that separate oil, natural gas and water, as well as a separate seawater treatment plant. The natural gas is either used for fuel or compressed for reinjection.

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. In December 2011, the U.S. Army Corps of Engineers granted us a permit required to build a gravel road, bridge and pipeline crossing over the Nigliq channel of the Colville River for development of a satellite field west of Alpine in the National Petroleum Reserve—Alaska (NPRA), the Alpine West CD5 Project. We plan to incorporate the terms of the permit into our project plan as we progress project sanctioning of CD5 in 2012. Initial production is anticipated toward the end of 2015.

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. Our share of production is used to supply feedstock and fuel to the Kenai LNG Plant and is also sold to local utilities.

In October 2011, we acquired an additional 30 percent interest in the Kenai LNG Plant, bringing our ownership interest to 100 percent. The Kenai LNG Plant had historically supplied LNG to utility companies in Japan. Due to market conditions, the Kenai Plant was scheduled to be mothballed in the second quarter of 2011; however, we delayed the shutdown in order to ship additional cargoes to Asia, due to energy shortages caused by the earthquake and tsunami in Japan. In November 2011, we idled the plant for future use. We subsequently secured additional third-party gas supplies, and as a result, expect to resume limited LNG exports in the second half of 2012.

 

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Exploration

In the February 2008 Outer Continental Shelf (OCS) Lease Sale 193, we successfully bid and were awarded 10-year-primary-term leases on 98 blocks in the Chukchi Sea. We plan to drill an exploration well on our Chukchi Sea leasehold in 2014, subject to the outcome of pending litigation challenging Lease Sale 193 and the receipt of required regulatory permits.

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. In late 2010, we entered into an agreement to farm-down an additional 10 percent of our working interest in the same Chukchi Sea leases, and that agreement received regulatory approval in July 2011.

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 was intended to move natural gas from Alaska’s North Slope to North American markets. In May 2011, the project was canceled as a result of insufficient customer transportation commitments to the project.

U.S. Lower 48

 

       2011  
           Interest           Operator     

      Liquids

MBD

    

Natural

Gas

MMCFD

    

Total

MBOED

 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Eagle Ford

     Various     Various         22         39         29   

Williston

     Various        Various         15         12         17   

Fort Worth

     Various        Various         6         47         13   

Permian

     Various        Various         29         111         48   

San Juan

     Various        Various         49         773         179   

Lobo

     Various        COP         5         138         28   

Panhandles

     Various        Various         2         76         15   

Wind River

     Various        Various         -         88         15   

Bossier

     Various        Various         -         67         11   

Anadarko

     Various        Various         3         59         12   

Other onshore

     Various        Various         21         129         42   

Gulf of Mexico

     Various        Various         16         17         19   

 

 

Total U.S. Lower 48

          168         1,556         428   

 

 

Onshore

Our 2011 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, Eagle Ford, Williston Basin, panhandles of Texas and Oklahoma, Fort Worth Basin, Anadarko Basin and Bossier Trend. We also have operations in the Wind River Basin, East Texas, Rockies and northern and southern Louisiana. Onshore activities in 2011 were centered mostly on continued optimization and development of existing assets, with particular focus on areas with higher liquids production.

 

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Shale Plays

Exploration and development continues in our shale positions in Eagle Ford, Bakken and Barnett. In the Eagle Ford, we drilled approximately 160 exploration and development wells in 2011 and plan to drill approximately 200 wells in 2012. With subsequent investments, we expect to achieve peak production in 2017 and long-term average production of 140,000 BOED. During 2011, we acquired approximately 240,000 additional acres in various resource plays across the Lower 48, which included the Avalon, Wolfcamp and Niobrara areas, further expanding our significant acreage position in Lower 48 shale plays.

 

   

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. We continue to pursue development opportunities in three conventional formations in the San Juan Basin.

Gulf of Mexico

At year-end 2011, our portfolio of producing properties in the Gulf of Mexico consisted of one operated field and three fields operated by co-venturers, including:

 

   

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

   

16 percent nonoperator interest in the unitized Ursa Field located in the Mississippi Canyon Area.

   

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

   

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

Exploration

In the Gulf of Mexico, we have a 45 percent interest in the Coronado well, which was spud in October 2011. A decision to cease drilling the well was made prior to reaching the targeted depth, and the well was expensed as a dry hole. We are in the planning process to appraise the results of Tiber and Shenandoah, which were discovered in 2009. Additionally, we were the successful bidder on 75 blocks in the Paleogene play in OCS Lease Sale 218 in December 2011. We expect these blocks will be awarded in 2012.

Offshore south Louisiana, we drilled the Shalimar exploration well. The well did not reach its target depth due to technical drilling issues and was expensed as a dry hole.

Onshore, we actively pursued the appraisal of our existing unconventional resource plays, including the 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 2012.

Transportation

We have a 25 percent interest in the Rockies Express Pipeline (REX). The REX natural gas pipeline runs 1,679 miles from Cheyenne, Colorado, to Clarington, Ohio, and has a natural gas transmission capacity of 1.8 billion cubic feet per day. Numerous compression facilities support the pipeline system. The REX pipeline is designed to enable natural gas producers in the Rocky Mountains region to deliver natural gas supplies to the Midwest and eastern regions of the United States. Upon the completion of the separation of the downstream businesses, we expect REX will be included in the new downstream company, Phillips 66.

E&P—EUROPE

In 2011, E&P operations in Europe contributed 20 percent of E&P’s worldwide liquids production and 14 percent of natural gas production. Our European assets are principally located in the Norwegian and U.K. sectors of the North Sea.

 

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Norway

 

       2011  
           Interest           Operator     

      Liquids

MBD

    

Natural Gas

MMCFD

    

Total

MBOED

 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Greater Ekofisk Area

     35.1     COP         73         66         84   

Alvheim

     20.0        Marathon         14         11         16   

Heidrun

     24.1        Statoil         10         11         12   

Statfjord Area

     6.0-12.1        Statoil         7         13         9   

Other

     Various        Various         16         62         26   

 

 

Total Norway

          120         163         147   

 

 

The Greater Ekofisk Area, located approximately 200 miles offshore Stavanger, Norway in the North Sea, is comprised of four producing fields: Ekofisk, Eldfisk, Embla and Tor. Ekofisk crude oil is exported to Teesside, England, and the natural gas is exported to Emden, Germany. Our Ekofisk South and Eldfisk II projects continue to progress, with production from both of these projects expected in 2013 and 2014, respectively.

The Alvheim development consists of a floating production, storage and offloading (FPSO) vessel and subsea installations. Produced crude oil is exported via shuttle tankers, and natural gas is transported to the United Kingdom via a pipeline to the Beryl-Sage system.

The Heidrun Field is located in the Norwegian Sea. Produced crude oil is transported to Mongstad in Norway and Tetney in the United Kingdom by double-hulled shuttle tankers. Part of the natural gas is transported and sold to buyers in Europe, while the remainder is used as feedstock in a methanol plant in Norway, in which we own an 18.3 percent interest.

The Statfjord Field straddles the boundary between the United Kingdom and Norway. In January 2012, we entered into an agreement to sell our interests in the Statfjord Field and associated satellites. The transaction is expected to close in the second quarter of 2012.

We also have varying ownership interests in five other producing fields in the Norwegian sector of the North Sea and in the Norwegian Sea.

Exploration

During 2011, we drilled one exploration well, Peking Duck (7/11-12S), including the Agn sidetrack well (7/11-12A). The wells were non-commercial gas discoveries and were expensed as dry holes. In addition, we participated in two partner-operated wells, Caterpillar (PL340BS) in the Alvheim Area and Arran (PL309) in the Oseberg Area. The Caterpillar discovery is currently being evaluated. Arran was a dry hole and has been plugged and abandoned.

We were awarded three new licenses in the Norwegian 21st Licensing Round: PL603, a 25 percent working interest in the Norwegian Sea; PL605, a 50 percent operating interest in the Barents Sea; and PL615, a 25 percent working interest in the Barents Sea. We acquired 3D seismic over PL605.

Transportation

We own a 35.1 percent interest in the Norpipe Oil Pipeline System, a 220-mile pipeline which carries crude oil from Ekofisk to a terminal and natural gas processing facility in Teesside, England. In addition, we own a 1.9 percent interest in Norwegian Continental Shelf Gas Transportation (Gassled), which owns most of the Norwegian gas transportation infrastructure.

 

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United Kingdom

 

       2011  
             Interest     Operator     

      Liquids

MBD

     Natural Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Britannia

     58.7    
 
Britannia
    Operator Ltd.
  
  
     5         136         28   

Britannia Satellites

     75.0-83.5        COP         20         57         30   

J-Block

     32.5-36.5        COP         11         74         23   

Southern North Sea

     Various        Various         -         127         21   

East Irish Sea

     100        HRL         -         62         10   

Other

     Various        Various         19         7         20   

 

 

Total United Kingdom

          55         463         132   

 

 

In addition to our interest in the Britannia natural gas and condensate field, we own 50 percent of Britannia Operator Limited, the operator of the field. Condensate is delivered through the Forties Pipeline to an oil stabilization and processing plant near the Grangemouth Refinery in Scotland, while natural gas is transported through Britannia’s line to St. Fergus, Scotland. The Britannia satellite fields, Callanish and Brodgar, produce via subsea manifolds and pipelines linked to the Britannia platform.

J-Block is comprised of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. central North Sea. In 2010, we received government approval for the development of the Jasmine Field, which is expected to achieve average net peak production of 34,000 BOED by 2013.

We have various ownership interests in 18 producing gas fields in the Rotliegendes and Carboniferous areas of the Southern North Sea. Our interests in the East Irish Sea include the Millom, Dalton and Calder fields, which are operated on our behalf by a third party.

We own a 24 percent interest in the Clair Field, located in the Atlantic Margin. The Clair Ridge Project received government approval in October 2011, and we anticipate initial production in 2016.

In December 2011, we entered into an agreement to sell our interests in the MacCulloch, Alba and Nicol fields. The sales of these interests are expected to close in the first half of 2012.

Exploration

During 2011, we participated in two partner-operated exploration wells. Well 206/12a-3 in the Clair South West Area, West of Shetlands, was an oil discovery and has been suspended in order to evaluate development options for the area. The Cameron well (44/19a-7a) in the Southern North Sea was a small gas discovery and is currently being evaluated for commerciality.

Transportation

We have a 10 percent interest in the Interconnector Pipeline, which links the United Kingdom and Belgium and facilitates the marketing throughout Europe of natural gas produced in the United Kingdom. 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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Index to Financial Statements

Poland

Exploration

We are participating in a shale gas venture in Poland, which provides us with the option to earn a 70 percent operating interest in six exploration licenses in the Baltic Basin. We participated in two wells in 2011.

E&P—CANADA

In 2011, E&P operations in Canada contributed 12 percent of E&P’s worldwide liquids production and 21 percent of E&P’s worldwide natural gas production.

 

       2011  
         Interest         Operator            Liquids
MBD
     Natural
Gas
MMCFD
     Bitumen
MBD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

                

Western Canada

           Various           Various         38         928         -         193   

Surmont

     50.0        COP         -         -         10         10   

Foster Creek

     50.0        Cenovus         -         -         46         46   

Christina Lake

     50.0        Cenovus         -         -         11         11   

 

 

Total Canada

          38         928         67         260   

 

 

Western Canada

Our operations in western Canada are primarily comprised of three core development areas: Deep Basin, Kaybob and O’Chiese, which extend from central Alberta to northeastern British Columbia. We operate or have ownership interests in approximately 80 natural gas processing plants in the region, and, as of December 31, 2011, held leasehold rights in 6 million net acres in western Canada.

Oil Sands

We hold approximately 1 million net acres of land in the Athabasca Region of northeastern Alberta. Our bitumen resources in Canada are produced via an enhanced thermal oil recovery method called steam-assisted gravity drainage (SAGD), whereby steam is injected into the reservoir, effectively liquefying the heavy bitumen, which is recovered and pumped to the surface for further processing.

 

   

Surmont

The Surmont oil sands lease is located approximately 35 miles south of Fort McMurray, Alberta. Surmont Phase II construction began in 2010, with production startup targeted for 2015. Surmont’s net production is expected to increase to 50,000 barrels per day by 2016.

 

   

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, Christina Lake and Narrows Lake SAGD bitumen projects.

Construction continued in 2011 on Foster Creek Phase F, the first of three additional approved expansion phases. Upon completion of Foster Creek Phases F, G and H, net peak production is anticipated to increase by 42,500 barrels per day beginning in 2014. At Christina Lake, first production for Phase C occurred in the third quarter of 2011. Construction of Christina Lake Phase D continued through 2011, with initial production expected in late 2012. Once phases C and D are both fully operational, net peak production at Christina Lake is estimated to be 47,000 barrels per day. Christina Lake Phases E, F and G received regulatory approval in the second quarter of 2011, and construction on Phase E commenced in the third quarter of 2011.

 

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Index to Financial Statements

Narrows Lake is an emerging opportunity within the FCCL Partnership. A regulatory application for the development of Narrows Lake was submitted in June 2010, and we anticipate receiving a response in the second quarter of 2012. Initial production is anticipated in 2017.

For information on WRB, see the “Refining and Marketing (R&M)” section.

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 natural gas field, one of the primary fields in the Mackenzie Delta, which would anchor the pipeline development. In March 2011, the project received regulatory approval from the National Energy Board of Canada. However, due to a continued decline in market conditions and lack of resolution with the Canadian government on fiscal terms, we are currently evaluating multiple options regarding the scope and timing of this project. Should the project not proceed, we would need to assess for impairment the carrying value of the undeveloped leasehold and capitalized project development costs, which totaled $662 million at December 31, 2011, including capitalized interest.

Amauligak

We have a 53.8 percent operating interest in Amauligak, which lies approximately 31 miles offshore in shallow water in the Beaufort Sea. A range of development options are being evaluated.

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 2011, we conducted pilot drilling programs in the Muskwa (Horn River Basin) and Duvernay (West Shale Basin) unconventional resource plays, and we acquired approximately 260,000 acres of exploration leasehold in the Canol Shale, Duvernay Shale and other plays.

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 before an ICSID tribunal during the summer of 2010, and we are currently awaiting an interim decision on key legal and factual issues. A separate arbitration hearing was held in January 2012 before the International Chamber of Commerce on ConocoPhillips’ separate claims against PDVSA for certain breaches of their Association Agreements prior to the expropriation.

Ecuador

In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, 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. An arbitration hearing on case merits occurred in March 2011. On September 30, 2011, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe will not be material. The arbitration process is ongoing.

 

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Index to Financial Statements

Peru

Exploration

We own a 45 percent operating interest in Blocks 123 and 129, covering nearly 1.6 million net acres. During 2011, we completed an initial 2-D seismic program on Blocks 123 and 129 and began to further delineate the play with an infill 2-D seismic program. In April 2011, we entered into an agreement to sell our entire 35 percent interest in Block 39, subject to government approval. Block 124 was relinquished in May 2011.

E&P—ASIA PACIFIC/MIDDLE EAST

In 2011, E&P operations in the Asia Pacific/Middle East Region contributed 15 percent of E&P’s worldwide liquids production and 26 percent of natural gas production.

Australia and Timor Sea

 

       2011  
             Interest     Operator     

    Liquids

MBD

    

Natural

Gas

MMCFD

    

Total

MBOED

 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Australia Pacific LNG

     42.5             Origin Energy         -         122         20   

Bayu-Undan

     56.9        COP         30         199         63   

Athena/Perseus

     50.0        ExxonMobil         -         35         6   

 

 

Total Australia and Timor Sea

          30         356         89   

 

 

Australia Pacific LNG

Australia Pacific LNG (APLNG), our joint venture with Origin Energy and China Petrochemical Corporation (Sinopec), is focused on producing CBM from the Bowen and Surat basins in Queensland, Australia. Origin operates APLNG’s production and pipeline system, and we will operate the LNG facility. Natural 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 supplying Asia Pacific markets. Two initial 4.5-million-tonnes-per-year LNG trains are anticipated, with over 10,000 net 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.

The project received environmental approval from the Australian federal government in February 2011, and a final investment decision on the initial LNG train and common facilities was approved in July 2011. The project’s first LNG exports are expected to begin in 2015.

In April 2011, APLNG and Sinopec signed definitive agreements for APLNG to supply up to 4.3 million tonnes of LNG per year for 20 years. The agreements also specified terms under which Sinopec subscribed for a 15 percent equity interest in APLNG, with both our ownership interest and Origin Energy’s ownership interest diluting from 50 percent to 42.5 percent. The Subscription Agreement was completed in August 2011.

In November 2011, APLNG signed a binding Heads of Agreement with Japan-based Kansai Electric Power Co. Inc., for the sale of approximately 1 million tonnes of LNG per year for 20 years. Under the terms of the agreement, Kansai Electric will be supplied LNG beginning in mid-2016. The agreement is subject to a final investment decision on the second LNG train, which is expected in the first half of 2012.

 

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Index to Financial Statements

In January 2012, APLNG and Sinopec signed an amendment to their existing LNG sales agreement for the sale and purchase of an additional 3.3 million tonnes of LNG per year through 2035, subject to a final investment decision on the second LNG train. This agreement, in combination with the Kansai Electric agreement, finalizes the marketing of the second train. In conjunction with the LNG sale, the parties have also agreed for Sinopec to subscribe for additional shares in APLNG, which would raise its equity interest from 15 percent to 25 percent. As a result, both our ownership interest and Origin Energy’s ownership interest would dilute from 42.5 percent to 37.5 percent. These agreements are subject to customary government approvals.

For additional information, see Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements.

Bayu-Undan

The Bayu-Undan gas condensate field is located in the Timor Sea joint petroleum development area between Timor-Leste and Australia. We also operate and own a 56.9 percent interest in the associated Darwin LNG facility, located at Wickham Point, Darwin. Produced natural gas is used to supply the Darwin LNG Plant. In 2011, we sold 153 billion gross cubic feet of LNG to utility customers in Japan.

Athena/Perseus

The Athena production license (WA-17-L) is located offshore Western Australia and contains part of the Perseus Field which straddles the boundary with WA-1-L, an adjoining license area. Natural gas is produced from these licenses.

Greater Sunrise

We have a 30 percent interest in the Greater Sunrise gas and condensate field located in the Timor Sea. Although the governments of Australia and Timor-Leste have reached an agreement 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.

Exploration

We operate three permits located in the Browse Basin, offshore northwest Australia. We own a 60 percent interest in two of the permits, WA-315-P and WA-398-P. In February 2012, we received regulatory approval to reduce our interest in the third permit, WA-314-P, from 60 percent to 10 percent. The first phase of drilling in 2009/2010 resulted in discoveries in WA-315-P and WA-398-P. In 2011, we completed the analysis of the 3-D seismic survey acquired during the 2009/2010 drilling campaign. The Phase II drilling campaign will commence in the first quarter of 2012 and will comprise a five- to eight-well program.

During 2011, we executed an option agreement to earn up to a 75 percent working interest in the Goldwyer Shale Project located in the Canning Basin of Western Australia. Drilling is expected to commence in 2012. Upon completion of the initial drilling program, we will have the right to assume operatorship of the Goldwyer Shale Project. The agreement is awaiting regulatory approvals.

In the Bonaparte Basin, offshore northern Australia, we operate and own a 60 percent interest in two permits, NT/P69 and NT/P61. During 2011, we reprocessed the seismic data over the Caldita structure in NT/P61, which will allow us to fully evaluate the remaining exploration potential of the permit.

 

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Index to Financial Statements

Indonesia

 

       2011  
                 Interest         Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

South Natuna Sea Block B

     40.0     COP         8         117         28   

South Sumatra

     45.0-54.0        COP         3         333         58   

 

 

Total Indonesia

          11         450         86   

 

 

We operate six production sharing contracts (PSCs) in Indonesia. Three of the blocks are located offshore: South Natuna Sea Block B, Kuma and Arafura Sea. The three onshore PSCs consist of the Corridor Block, South Jambi “B”, both in South Sumatra, and Warim in Papua. Our producing assets are primarily concentrated in two core areas: South Natuna Sea and onshore South Sumatra.

South Natuna Sea Block B

The offshore South Natuna Sea Block B PSC 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

The Corridor PSC consists of 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 was finalized in 2011, and as a result, 10 percent of the field’s proved reserves are now attributable to an adjacent PSC. The South Jambi “B” PSC includes three gas fields which are in various stages of development.

Exploration

We operate two offshore exploration PSCs, Kuma and Arafura Sea, with ownership interests of 60 percent and 51 percent, respectively. During 2011, we drilled the Kaluku well in the Kuma PSC and the Mutiara Putih well in the Arafura Sea PSC. Both were expensed as dry holes. A third PSC, Amborip VI, was relinquished in 2011. We also own and operate 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

 

       2011  
                 Interest         Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Peng Lai

     49.0     COP         42         -         42   

Panyu

     24.5        CNOOC         10         -         10   

 

 

Total China

          52         -         52   

 

 

The Peng Lai 19-3, 19-9 and 25-6 fields are located in Bohai Bay Block 11/05. Production from the Phase I development of the PL 19-3 Field began in 2002. The Phase II development includes six drilling and production platforms and an FPSO vessel used to accommodate production from all the fields.

 

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Index to Financial Statements

On July 13, 2011, the State Oceanic Administration (SOA) in the People’s Republic of China instructed us to suspend production from the Peng Lai 19-3 Field Platforms B and C, as a result of two separate seepage incidents which occurred near the platforms. On September 2, 2011, the SOA ordered us to halt operations at the Peng Lai 19-3 Field, pending additional cleanup efforts and reservoir depressurization activities to ensure any residual seepage had stopped. The incidents resulted in a total release of approximately 700 barrels of oil into Bohai Bay and approximately 2,600 barrels of mineral oil-based drilling mud onto the seafloor. The mineral oil-based drilling mud was recovered and cleaned up from the seafloor. The sources of the seeps have been sealed and containment devices deployed as a preventative measure to capture any residue.

The SOA also required implementation of preventative measures to avoid recurrence, in addition to the filing of an updated environmental impact assessment and development plan for approval. A revised development plan was submitted to China’s National Development and Reform Commission in November 2011 and is currently under review. A revised environmental impact assessment was submitted to the SOA in February 2012.

The approved depressurization plan, combined with limited development and field optimization, reduced 2011 average daily net production from the field by 14,000 barrels of oil per day, compared to 2010 production levels. Future impacts on our business are not known at this time.

In January 2012, we and the China National Offshore Oil Corp. (CNOOC) announced an agreement with China’s Ministry of Agriculture to resolve fishery-related issues in connection with the seepage incidents. Under this agreement, approximately $160 million will be paid as compensation to settle private claims of potentially affected fishermen in relevant Bohai Bay communities, and public claims for alleged fishery damage. We hold a 49 percent ownership interest in the Peng Lai fields. The agreement fulfills the objectives of the compensation fund we announced in September 2011. As part of this agreement, we have also designated approximately $16 million of our previously announced environmental fund to be used to improve fishery resources and for related projects.

The Panyu development, also located in the South China Sea, is comprised of three oil fields: Panyu 4-2, Panyu 5-1 and Panyu 11-6. An expansion of the scope and capacity of the existing Panyu 4-2 and Panyu 5-1 fields is being undertaken, with the addition of two production platforms targeted for completion in 2013.

Vietnam

 

       2011  
             Interest       Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Su Tu Den and Su Tu Vang

     23.3    

 

Cuu Long Joint

    Operating Company

  

  

     13         5         14   

Rang Dong

     36.0       

 

Japan Vietnam

Petroleum Co.

  

  

     5         6         6   

 

 

Total Vietnam

          18         11         20   

 

 

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.

Our activities in Block 15-1 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. Su Tu Den crude oil is processed and stored in a 1-million-barrel FPSO vessel.

The Rang Dong Field is located in Block 15-2. Rang Dong crude oil is stored in a floating storage and offloading vessel.

 

14


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Index to Financial Statements

In February 2012, we entered into an agreement to sell our entire Vietnam business. The transaction is expected to close in the first half of 2012.

Transportation

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

Exploration

An appraisal well, SD-9Pst, was drilled and completed as a producer in the Su Tu Den Field. Early production data is currently being evaluated.

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 from Gumusut is anticipated in 2012, with estimated net peak production of 32,000 barrels of liquids per day occurring in 2014. The development of the Kebabangan Gas Field (KBB) started in 2011, with first production anticipated in late 2014. Estimated net annual peak production from KBB is 29,000 BOED occurring in 2015.

Bangladesh

Exploration

In 2009, we were formally awarded two deepwater blocks in the Bay of Bengal, offshore Bangladesh. We received government approval of the PSC terms in June 2011 and hold 100 percent interests in Blocks 10 and 11. Seismic acquisition activities are expected to commence in early 2012.

Brunei

Exploration

In 2011, we acquired a 6.25 percent working interest in Block CA-2. We drilled two exploration wells in 2011, which were expensed as dry holes. Exploration activities will continue in 2012.

Qatar

 

       2011  
             Interest       Operator     

    Liquids

MBD

    

Natural

Gas

MMCFD

    

Total

MBOED

 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Qatargas 3

     30.0    
 
Qatargas
Operating Co.
  
  
     23         370         85   

 

 

Total Qatar

          23         370         85   

 

 

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-tonnes-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, and we achieved peak production during 2011.

QG3 executed the development of the onshore and offshore assets as a single integrated project with Qatargas 4 (QG4), a joint venture between Qatar Petroleum and Royal Dutch Shell plc. This included the joint development of offshore facilities situated in a common offshore block in the North Field, as well as the construction of two identical LNG process trains and associated gas treating facilities for both the QG3 and QG4 joint ventures. Production from the LNG trains and associated facilities are combined and shared.

 

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Index to Financial Statements

We have a 12.4 percent ownership interest in the Golden Pass LNG Terminal and affiliated Golden Pass Pipeline. It is located adjacent to the Sabine-Neches Industrial Ship Channel northwest of Sabine Pass, Texas. The terminal became commercially operational in May 2011. We hold 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. Market conditions currently favor the flow of LNG to European and Asian markets; therefore, our near-to-mid-term utilization of the terminal is expected to be limited.

E&P—AFRICA

During 2011, E&P operations in Africa contributed 5 percent of E&P’s worldwide liquids production and 3 percent of natural gas production.

Nigeria

 

       2011  
             Interest                 Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

OMLs 60, 61, 62, 63

     20.0     Eni         19         157         45   

 

 

Total Nigeria

          19         157         45   

 

 

We have an interest in four onshore Oil Mining Leases (OMLs). 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 2011, the plant consumed 12 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

The Uge North exploration well in OPL 214 was spud in December 2011 as a step-out to the 2005 Uge Field discovery. It is the first of two remaining commitment wells.

Libya

 

       2011  
             Interest                 Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Waha Concession

     16.3     Waha Oil Co.         8         1         8   

 

 

Total Libya

          8         1         8   

 

 

The Waha Concession is made up of multiple concessions and encompasses nearly 13 million gross acres in the Sirte Basin. Our production operations in Libya and related oil exports were temporarily suspended in 2011 during Libya’s period of civil unrest. Production restarted in late November 2011, and by year-end 2011, net production was approximately 15,000 BOED.

 

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Index to Financial Statements

Algeria

 

       2011  
       Interest       Operator     

    Liquids

MBD

    

Natural

Gas

MMCFD

    

Total

MBOED

 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Menzel Lejmat North

     65.0     COP         9         -         9   

Ourhoud

     3.7       
 
L’Organization
Ourhoud
  
  
     4         -         4   

 

 

Total Algeria

          13         -         13   

 

 

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. Crude oil production from MLN and Ourhoud is transported to northern Algerian ports where it is lifted to tankers and marketed primarily to refineries in North America and Europe. The El Merk Project was sanctioned in 2009 to develop the EMK Field, in which we own a 16.9 percent interest. Engineering, procurement and construction is ongoing.

Angola

Exploration

In December 2011, we signed two PSCs with Angola’s national oil company for a 42.86 percent operating interest in two ultra deepwater blocks, Blocks 36 and 37, in Angola’s subsalt play trend. These agreements became effective in January 2012, and we anticipate commencing acquisition of seismic data in early 2012.

E&P—RUSSIA

During 2011, E&P operations in Russia contributed 3 percent of E&P’s worldwide liquids production.

 

       2011  
             Interest       Operator     

    Liquids

MBD

    

Natural

Gas

MMCFD

    

Total

MBOED

 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Naryanmarneftegaz (NMNG)

     30.0     OOO NMNG         23         -         23   

Polar Lights

     50.0        Polar Lights Co.         6         -         6   

 

 

Total Russia

          29         -         29   

 

 

NMNG

NMNG is a joint venture we entered into with LUKOIL to develop oil and natural gas resources in the northern part of Russia’s Timan-Pechora Province. Yuzhno Khylchuyu (YK), NMNG’s anchor field, achieved first production in June 2008. The joint venture currently holds seven licenses and is producing from five fields. Production 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

Polar Lights Company is an entity which was established to develop the Ardalin Field in the Timan-Pechora Basin in northern Russia.

 

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Index to Financial Statements

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 (NCSPSA), which includes the Kashagan Field. The first phase of field development currently being executed includes construction of artificial drilling islands, processing facilities, living quarters and pipelines to carry production onshore. In addition to the Kashagan Field, the NCSPSA includes the satellite fields of Aktote, Kairan and Kalamkas. The initial production phase of the contract lasts until 2041. First production is expected in 2013.

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. Further exploration drilling is planned to determine development potential of a second area of interest within the block. The Nursultan well is expected to spud in the first quarter of 2012. 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 Block 7011/11, Qamut, in December 2010 for oil and gas exploration in Baffin Bay, offshore Greenland. We own a 61.3 percent operating interest in the Qamut license. The work program, including 2-D seismic acquisitions, commenced in 2011.

Spill Containment

Marine Well Containment Company

In 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 Gulf of Mexico. Since its formation, several companies have joined the Marine Well Containment Company (MWCC).

In February 2011, MWCC launched an interim containment system, which provides rapid containment response capabilities in the event of an underwater well control incident in the deepwater Gulf of Mexico. MWCC is advancing this capability and is currently developing an expanded containment system with significantly increased capacity. The expanded containment system is expected to be available in 2012.

Subsea Well Response Project

During 2011, we, along with eight leading oil and gas companies, launched the Subsea Well Response Project (SWRP), an initiative designed to enhance the industry’s capability to respond to international subsea well control incidents. SWRP is a non-profit organization based in Stavanger, Norway. This project complements the work being undertaken in the United States by MWCC and also in the United Kingdom by the Oil Spill Prevention and Response Advisory Group (OSPRAG). We are also a participant in OSPRAG.

Freeport 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.

 

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LNG Technology

Our Optimized Cascade® LNG liquefaction technology business continues to grow with the demand for new LNG plants. The technology has been applied in nine LNG trains around the world, and eight more are under construction.

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, 2011. No difference exists between our estimated total proved reserves for year-end 2010 and year-end 2009, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2011.

DELIVERY COMMITMENTS

We sell crude oil and natural gas from our E&P producing operations under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Our Commercial organization also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the spot market or a combination of our reserves and the spot market. Worldwide, we are contractually committed to deliver approximately 5 trillion cubic feet of natural gas, including approximately 700 billion cubic feet related to the noncontrolling interests of consolidated subsidiaries, and 180 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, 2011, 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 refinery blendstock. Total natural gas liquids extracted in 2011, including our share of DCP Midstream, averaged 200,000 barrels per day.

DCP Midstream is headquartered in Denver, Colorado. At December 31, 2011, DCP Midstream owned or operated 61 natural gas processing facilities, with a gross inlet capacity of 7.2 billion cubic feet per day of natural gas. Its natural gas pipeline systems included gathering services for these facilities, as well as natural gas transmission, and totaled approximately 62,000 miles of pipeline. At December 31, 2011, DCP Midstream also owned or operated 12 natural gas liquids fractionation plants, along with propane terminal facilities and natural gas liquids pipeline assets.

In 2011, DCP Midstream’s raw natural gas throughput averaged 6.1 billion cubic feet per day, and natural gas liquids extraction averaged 383,000 barrels per day. 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.

 

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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 constructing a natural gas processing plant in the Eagle Ford shale area of Texas. The plant, named the Eagle Plant, is expected to have a capacity of 200 million cubic feet per day and be accompanied by related natural gas liquids infrastructure. The Eagle Plant would increase DCP Midstream’s total natural gas processing capacity in the area to 1 billion cubic feet per day and is expected to be online in the third quarter of 2012.

DCP Midstream is building a major natural gas liquids pipeline in Texas. The Sand Hills Pipeline is designed to provide new natural gas liquids transportation capacity from the Permian Basin and Eagle Ford shale area to markets in the Gulf Coast. The pipeline’s initial capacity is expected to be 200,000 barrels per day, with expansion to 350,000 barrels per day possible. The pipeline will be phased into service, with completion of the first phase expected by the third quarter of 2012 to accommodate DCP Midstream’s growing Eagle Ford liquids volumes. Service from the Permian Basin could be available as soon as the third quarter of 2013.

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, which would bring our net capacity to approximately 32,600 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. In 2011, our share of natural gas liquids extracted averaged 8,000 barrels per day, and our share of fractionated liquids averaged 16,000 barrels per day.

Upon completion of the separation of the downstream businesses, we expect all of our investments in Midstream will be included in Phillips 66, with the exception of the Gallup, New Mexico natural gas liquids fractionation plant and our equity interest in Phoenix Park.

 

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REFINING AND MARKETING (R&M)

At December 31, 2011, 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 prior investment in LUKOIL, which are reported in our LUKOIL Investment segment.

Upon completion of the separation of the downstream businesses, we expect all of the assets within the R&M segment will be included in Phillips 66.

R&M—UNITED STATES

Refining

At December 31, 2011, we owned or had an interest in 12 refineries in the United States.

 

           Thousands of Barrels Daily         

Refinery

  

Location

     Interest     Net Crude
Throughput
Capacity
     Clean Product
Capacity***
     Clean Product
Yield
Capability
 
           Gasolines      Distillates     

East Coast Region

                

Bayway

   Linden, NJ      100     238         145         115         90

Trainer*

   Trainer, PA      100        -         -         -         -   

 

 
          238            

 

 

Gulf Coast Region

                

Alliance

   Belle Chasse, LA      100        247         125         120         86   

Lake Charles

   Westlake, LA      100        239         90         115         69   

Sweeny

   Old Ocean, TX      100        247         130         120         87   

 

 
          733            

 

 

Central Region

                

Wood River**

   Roxana, IL      50        153         83         45         80   

Borger**

   Borger, TX      50        73         50         25         89   

Ponca City

   Ponca City, OK      100        187         105         80         91   

Billings

   Billings, MT      100        58         35         25         89   

 

 
          471            

 

 

West Coast Region

                

Ferndale

   Ferndale, WA      100        100         55         30         75   

Los Angeles

  

Carson/

Wilmington, CA

     100        139         80         65         87   

San Francisco

  

Arroyo Grande/

San Francisco, CA

     100        120         55         55         83   

 

 
          359            

 

 
          1,801            

 

 
    * Net throughput capacity of 185,000 barrels per day was idled effective October 1, 2011.
  ** Represents our proportionate share.
*** Clean Product Capacities are maximum rates for each clean product category, independent of each other. They are not additive when calculating the Clean Product Yield Capability for each refinery.

 

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

 

    Characteristics       Sources
    Sweet   Medium
Sour
  Heavy
Sour
  High
TAN*
      United
States
  Canada   South
America
  Europe
& FSU**
  Middle East
& Africa

Bayway

                             

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.

East Coast Region

Bayway Refinery

The Bayway Refinery is located on the New York Harbor in Linden, New Jersey. Bayway refining units include one of the world’s largest fluid catalytic cracking units, two hydrodesulfurization units, a reformer, alkylation unit and other processing equipment. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel, as well as petrochemical feedstocks, residual fuel oil and home heating oil. Refined products are distributed to East Coast customers by pipeline, barge, railcar and truck. The complex also includes a 775-million-pound-per-year polypropylene plant.

Trainer Refinery

The Trainer Refinery is located on the Delaware River in Trainer, Pennsylvania. Refinery facilities include fluid catalytic cracking units, hydrodesulfurization units, a reformer and a hydrocracker. In September 2011, we announced our intention to sell the refinery and associated pipelines and terminals. We idled the facility effective October 1, 2011, and plan to permanently close the plant by the end of the first quarter of 2012 if a sales transaction is unsuccessful.

Gulf Coast Region

Alliance Refinery

The Alliance Refinery is located on the Mississippi River in Belle Chasse, Louisiana. The single-train facility includes fluid catalytic cracking units, hydrodesulfurization units and a reformer and aromatics unit. Alliance produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks, home heating oil and anode petroleum coke. The majority of the refined products are distributed to customers in the southeastern and eastern United States through major common-carrier pipeline systems and by barge.

Lake Charles Refinery

The Lake Charles Refinery is located in Westlake, Louisiana. Its facilities include crude distillation, fluid catalytic cracker, hydrocracker, delayed coker and hydrodesulfurization units. The refinery produces a high percentage of transportation fuels, such as gasoline, off-road diesel and jet fuel, along with home heating oil. The majority of its refined products are distributed by truck, railcar, barge or major common-carrier pipelines to customers in the southeastern and eastern United States. Refined products can also be sold into export markets through the refinery’s marine terminal. Refinery facilities also include a specialty coker and calciner, which produce graphite petroleum coke for the steel industry.

 

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Excel Paralubes

We own a 50 percent interest in Excel Paralubes, a 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.

Sweeny Refinery

The Sweeny Refinery is located in Old Ocean, Texas, approximately 65 miles southwest of Houston. Refinery facilities include fluid catalytic cracking, delayed coking, alkylation, a continuous regeneration reformer and hydrodesulfurization units. The refinery receives crude oil via tankers, primarily through wholly owned and third-party terminals on the Gulf Coast, including a deepwater terminal at Freeport, Texas. It produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks, home heating oil and coke. The refinery operates nearby terminals and storage facilities in Freeport, Jones Creek and on the San Bernard River, along with pipelines that connect these facilities to the refinery. Refined products are distributed throughout the Midwest and southeastern United States by pipeline, barge and railcar.

MSLP

Merey Sweeny, L.P. (MSLP) owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes 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, which we exercised on August 28, 2009. PDVSA has initiated arbitration with the International Chamber of Commerce challenging the exercise of the call right and claiming it was invalid. The arbitral tribunal is scheduled to hold hearings on the merits of the dispute in December 2012. We continue to use the equity method of accounting for our investment in MSLP.

Central Region

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. We are the operator and managing partner of WRB, which consists of the Wood River and Borger refineries. For additional information on FCCL, see the “Exploration and Production (E&P)” section.

WRB’s processing capability of heavy Canadian or similar crudes was 145,000 barrels per day, after startup of the Keystone pipeline and prior to the finalization of the coker and refinery expansion (CORE) project at the Wood River Refinery. We have completed the CORE Project, and operational startup occurred in the fourth quarter of 2011. Test runs of the CORE Project have been successful to date and will continue through the first quarter of 2012. Upon completion of testing, total processing capability of heavy Canadian or similar crudes within WRB will be dependent on the quality of heavy Canadian crudes that are economically available, and is expected to range between 235,000 to 255,000 barrels per day.

 

   

Wood River Refinery

The Wood River Refinery is located in Roxana, Illinois, about 15 miles northeast of St. Louis, Missouri, at the convergence of the Mississippi and Missouri rivers. Operations include three distilling units, two fluid catalytic cracking units, hydrocracking, coking, reforming, hydrotreating and sulfur recovery. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks, asphalt and coke. Finished product leaves Wood River by pipeline, rail, barge and truck. The CORE Project has resulted in an increased clean product yield of 5 percent. Gross heavy crude oil capacity is expected to increase between 90,000 to 110,000 barrels per day, dependent on the quality of available heavy Canadian crudes. The majority of the existing asphalt production at Wood River will be replaced with production of upgraded products.

 

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Borger Refinery

The Borger Refinery is located in Borger, Texas, in the Texas Panhandle, approximately 50 miles north of Amarillo. The refinery facilities are comprised of coking, fluid catalytic cracking, hydrodesulfurization and naphtha reforming, in addition to a 45,000-barrels-per-day natural gas liquids fractionation facility. It produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel, as well as coke, natural gas liquids and solvents. Refined products are transported via pipelines from the refinery to West Texas, New Mexico, Colorado and the Midcontinent region.

Ponca City Refinery

The Ponca City Refinery is located in Ponca City, Oklahoma. It is a high-conversion facility which includes fluid catalytic cracking, delayed coking and hydrodesulfurization units. It produces a full range of products, including gasoline, diesel, jet fuel, liquefied petroleum gas (LPG) and anode-grade petroleum coke. Finished petroleum products are primarily shipped by company-owned and common-carrier pipelines to markets throughout the Midcontinent region.

Billings Refinery

The Billings Refinery is located in Billings, Montana. Its facilities include fluid catalytic cracking and hydrodesulfurization units, in addition to a delayed coker, which converts heavy, high-sulfur residue into higher value light oils. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and aviation fuels, as well as fuel-grade petroleum coke. Finished petroleum products from the refinery are delivered by pipeline, railcar and truck. The pipelines transport most of the refined products to markets in Montana, Wyoming, Utah and Washington.

West Coast Region

Ferndale Refinery

The Ferndale Refinery is located on Puget Sound in Ferndale, Washington, approximately 20 miles south of the U.S.-Canada border. Facilities include a fluid catalytic cracker, an alkylation unit, a diesel hydrotreater and an S-Zorb™ unit. The refinery produces transportation fuels such as gasoline and diesel. Other products include residual fuel oil, which supplies the northwest marine transportation market. Most refined products are distributed by pipeline and barge to major markets in the northwest United States.

Los Angeles Refinery

The Los Angeles Refinery consists of two linked facilities located about five miles apart in Carson and Wilmington, California, approximately 15 miles southeast of Los Angeles International Airport. Carson serves as the front end of the refinery by processing crude oil, and Wilmington serves as the back end by upgrading the intermediate products to finished products. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include fuel-grade petroleum coke. The refinery produces California Air Resources Board (CARB)-grade gasoline by blending ethanol to meet government-mandated oxygenate requirements. Refined products are distributed to customers in California, Nevada and Arizona by pipeline and truck.

San Francisco Refinery

The San Francisco Refinery consists of two facilities linked by a 200-mile pipeline. The Santa Maria facility is located in Arroyo Grande, California, about 200 miles south of San Francisco, while the Rodeo facility is in the San Francisco Bay Area. Semi-refined liquid products from the Santa Maria facility are sent by pipeline to the Rodeo facility for upgrading into finished petroleum products. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petroleum coke. It also produces CARB-grade gasoline by blending ethanol to meet government-mandated oxygenate requirements. The majority of the refined products are distributed by pipeline, railcar and barge to customers in California.

 

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Marketing

In the United States, as of December 31, 2011, we marketed gasoline, diesel and aviation fuel through approximately 8,250 marketer-owned outlets in 49 states. The majority of these sites utilize the Phillips 66, Conoco or 76 brands.

Wholesale

At December 31, 2011, our wholesale operations utilized a network of marketers operating approximately 6,875 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 500 sites. 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, 2011, aviation gasoline and jet fuel were sold through dealers and independent marketers at approximately 875 Phillips 66-branded locations in the United States.

Lubricants

We manufacture and sell automotive, commercial and industrial lubricants which are marketed worldwide under the Phillips 66, Conoco, 76 and Kendall brands, as well as other private label brands. We also manufacture Group II and import Group III base oils and market both under the respective brand names Pure Performance and Ultra-S globally.

Premium Coke & Polypropylene

We 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. We also manufacture and market polypropylene to North America under the COPYLENE brand name. Our ThruPlus Delayed Coker Technology, a proprietary process for upgrading heavy oil into higher value, light hydrocarbon liquids, was sold in June 2011.

Transportation

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

Pipelines and Terminals

At December 31, 2011, R&M managed approximately 17,000 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 42 finished product terminals, 8 liquefied petroleum gas terminals, 5 crude oil terminals and 1 coke exporting facility.

In October 2011, we sold Seaway Products Pipeline Company to DCP Midstream. In December 2011, we sold our 16.55 percent equity interest in Colonial Pipeline Company and our 50 percent equity interest in Seaway Crude Pipeline Company.

Tankers

At December 31, 2011, we had 15 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 five 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 our subsidiary, Polar Tankers, Inc., which are discussed in the E&P section.

Specialty Businesses

We manufacture and sell a variety of specialty products including pipeline flow improvers and anode material for high-power lithium-ion batteries. Our specialty products are marketed under the LiquidPower and CPreme brand names.

 

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R&M—INTERNATIONAL

Refining

At December 31, 2011, we owned or had an interest in four refineries outside the United States.

 

                 Thousands of Barrels Daily         

Refinery

             

Net Crude

  Throughput

     Clean Product
Capacity***
     Clean Product  
  

Location

       Interest     Capacity      Gasolines      Distillates        Yield Capability  

Humber

   N. Lincolnshire,
United Kingdom
     100.00     221         85         115         81

Whitegate

   Cork, Ireland      100.00        71         15         30         65   

MiRO*

   Karlsruhe, Germany      18.75        58         25         25         85   

Melaka**

   Melaka, Malaysia      47.00        76         20         50         80   

 

 
          426            

 

 
* Mineraloelraffinerie Oberrhein GmbH.
** Capacity increased to 80,000 barrels per day effective January 1, 2012.
*** Clean Product Capacities are maximum rates for each clean product category, independent of each other. They are not additive when calculating the Clean Product Yield Capability for each refinery.

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

 

   

Characteristics

      

Sources

    Sweet  

Medium

Sour

 

Heavy

Sour

 

High

TAN*

      

Europe

& FSU**

 

Middle East

& 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.

Humber Refinery

The Humber Refinery is located on the east coast of England in North Lincolnshire, United Kingdom. It is a fully integrated refinery which produces a high percentage of transportation fuels, such as gasoline and diesel. Humber’s facilities encompass fluid catalytic cracking, thermal cracking and coking. The refinery has two coking units with associated calcining plants, which upgrade the heaviest part of the crude barrel and imported feedstocks into light oil products and high-value graphite and anode petroleum cokes. Humber is the only coking refinery in the United Kingdom and is one of the world’s largest producers of specialty graphite cokes and one of Europe’s largest anode coke producers. Approximately 60 percent of the light oils produced in the refinery are marketed in the United Kingdom, while the other products are exported to the rest of Europe and the United States.

Whitegate Refinery

The Whitegate Refinery is located in Cork, Ireland, and is Ireland’s only refinery. The refinery primarily produces transportation fuels, such as gasoline, diesel and fuel oil, which are distributed to the inland market, as well as being exported to Europe and the United States. We also operate a crude oil and products storage complex consisting of 7.5 million barrels of storage capacity and an offshore mooring buoy, located in Bantry Bay, about 80 miles southwest of the refinery in southern Cork County.

MiRO Refinery

The Mineraloelraffinerie Oberrhein GmbH (MiRO) Refinery, located on the Rhine River in Karlsruhe in southwest Germany, is a joint venture in which we own an 18.75 percent interest. Facilities include three crude unit trains, fluid catalytic cracking, petroleum coking and calcining, hydrodesulfurization units,

 

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reformers, isomerization and aromatics recovery units, ethyl tert-butyl ether (ETBE) and alkylation units. MiRO produces a high percentage of transportation fuels, such as gasoline and diesel. Other products include petrochemical feedstocks, home heating oil, bitumen, and anode- and fuel-grade petroleum coke. Refined products are delivered to customers in southwest Germany, northern Switzerland and western Austria by truck, railcar and barge.

Melaka Refinery

The Melaka Refinery in Melaka, Malaysia, is a joint venture refinery in which we own a 47 percent interest. Melaka produces a full range of refined petroleum products and capitalizes on coking technology to upgrade low-cost feedstocks into higher-margin products. An expansion project was completed during 2010 to increase crude oil conversion and treating unit capacities. Our share of refined products is transported by tanker and marketed in Malaysia and other Asian markets.

Wilhelmshaven Refinery

The Wilhelmshaven Refinery is located in the northern state of Lower Saxony in Germany, and has a 260,000 barrels-per-day crude oil processing capacity. We sold the refinery, tank farm and marine terminal in August 2011.

Marketing

At December 31, 2011, R&M had marketing operations in five European countries. Our 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, 2011, we had approximately 1,430 marketing outlets in our European operations, of which approximately 900 were company-owned and 330 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 250 additional sites.

LUKOIL INVESTMENT

This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011. See Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for more information.

CHEMICALS

At December 31, 2011, 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. Upon completion of the separation of the downstream businesses, we expect our investment in the Chemicals segment will be included in Phillips 66.

CPChem’s business is structured around two primary operating segments: Olefins & Polyolefins (O&P) and Specialties, Aromatics & Styrenics (SA&S). 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 SA&S segment manufactures and markets aromatics products, such as benzene, styrene, paraxylene and cyclohexane, as well as polystyrene and styrene-butadiene copolymers. SA&S also manufactures and markets a variety of specialty chemical products including organosulfur chemicals, solvents, drilling chemicals, mining chemicals and high-performance engineering plastics and compounds.

 

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CPChem’s manufacturing facilities are located in Belgium, China, Colombia, Qatar, Saudi Arabia, Singapore, South Korea and the United States.

Key Projects

In October 2010, CPChem announced 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. 1-hexene is a critical component used in the manufacture of polyethylene, a plastic resin commonly converted into film, plastic pipe, milk jugs, detergent bottles and food and beverage containers. Project planning has begun, with startup anticipated in 2014.

In November 2011, CPChem completed the acquisition of a polyalphaolefins (PAO) plant located in Beringen, Belgium. The addition of the plant more than doubled CPChem’s PAO production capability. PAOs are used in many synthetic products, such as lubricants, greases and fluids, and have emerged as essential components in many industries and applications.

In December 2011, CPChem announced plans to pursue a project to construct a world-scale ethane cracker and two polyethylene facilities in the U.S. Gulf Coast Region. The project would leverage the development of significant shale gas resources in the United States. CPChem’s Cedar Bayou facility in Baytown, Texas, would be the location of the 1.5-million-metric-tons-per-year ethylene unit. The two polyethylene facilities, each with an annual capacity of 500,000 metric tons, would be located at either the Cedar Bayou facility, or near CPChem’s Sweeny facility in Old Ocean, Texas. Further evaluation will occur during 2012, with a final investment decision expected in 2013.

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), an additional joint venture in Mesaieed. The Q-Chem II facility produces polyethylene and normal alpha olefins (NAO) on a site adjacent to the Q-Chem complex. In connection with this project, an ethane cracker that provides ethylene feedstock via pipeline to the Q-Chem II plants was developed in Ras Laffan Industrial City, Qatar. The ethane cracker and pipeline are owned by Ras Laffan Olefins Company, a joint venture of Q-Chem II and Qatofin Company Limited. Q-Chem II’s interests in the ethane cracker, pipeline and polyethylene and NAO plants are collectively referred to as Q-Chem II. Operational startup of Q-Chem II occurred 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 (JCP), another 50-percent-owned joint venture of CPChem, owns and operates an integrated styrene facility adjacent to the SCP aromatics complex. SCP and JCP are collectively known as S-Chem.

In December 2011, Saudi Polymers Company (SPCo), a 35-percent-owned joint venture company of CPChem, completed the construction of an integrated petrochemicals complex at Jubail Industrial City, Saudi Arabia. SPCo will produce ethylene, propylene, polyethylene, polypropylene, polystyrene and 1-hexene. Commercial production is expected in 2012.

EMERGING BUSINESSES

At December 31, 2011, 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. Upon completion of the separation of the downstream businesses, we expect our power generation assets and certain technology operations will be included in Phillips 66.

 

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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.

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. We also invest in technologies to find more efficient, economical and environmentally sound ways to produce oil and natural gas by focusing on our oil sands position, the rapid growth from unconventional reservoirs and advances in subsurface technologies.

In 2011, we formed Energy Technology Ventures (ETV), a joint venture with General Electric Capital and NRG Energy, Inc., which focuses on the development of next generation energy technology. ETV invests in, and offers 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 operate 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™ Technology) 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, 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 third parties. We have licensed E-Gas™ Technology 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, bitumen, natural gas liquids and natural gas in an efficient, cost-effective manner. Based on publicly available year-end 2010 reserves statistics, we had the seventh-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 5, 2011, issue of the Oil & Gas Journal, we are one of the largest refiners of petroleum products in the United States. Worldwide, our refining capacity ranked in the top ten 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 2011 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 2011, we held a total of 1,229 active patents in 63 countries worldwide, including 525 active U.S. patents. During 2011, we received 52 patents in the United States and 70 foreign patents. Our products and processes generated licensing revenues of $136 million in 2011. 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 $267 million, $230 million and $190 million in 2011, 2010 and 2009, 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 64 through 67 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2011 and those expected for 2012 and 2013.

Web Site Access to SEC Reports

Our Internet Web site address is http://www.conocophillips.com. Information contained on our Internet Web site is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our Web site, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s Web site at http://www.sec.gov.

 

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Item 1A. RISK FACTORS

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

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, bitumen 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 material 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 certain 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 60 percent of our hydrocarbon production was derived from production outside the United States in 2011, and 56 percent of our proved reserves, as of December 31, 2011, was 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, bitumen 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 significant hazards and risks, including operational hazards and risks such as explosions, fires, pipeline interruptions, pipeline ruptures, crude oil or refined products spills, severe weather, geological events, labor disputes, or cyber attacks. Our operations are also subject to the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks. All such hazards could result in loss of human life, significant property and equipment damage, environmental pollution, impairment of operations, substantial losses to us and damage to our reputation.

The proposed separation of our downstream businesses is contingent upon the satisfaction of a number of conditions, which may not be consummated on the terms or timeline currently contemplated or may not achieve the intended results.

We expect the separation will be effective in the second quarter of 2012. Our ability to timely effect the separation is subject to several conditions, including, among others, the receipt of a favorable private letter ruling from the IRS and the SEC declaring effective a registration statement relating to the securities of Phillips 66. We cannot assure we will be able to complete the separation in a timely fashion, if at all. For these and other reasons, the separation may not be completed on the terms or timeline contemplated. Further, if the separation is completed, it may not achieve the intended results. Any such difficulties could adversely affect our business, results of operations or financial condition.

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 2011, as well as matters previously reported in our 2010 Form 10-K and our

first-, second- and third-quarter 2011 Form 10-Qs that were not resolved prior to the fourth quarter of 2011. 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 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.

 

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New Matters

In December 2011, ConocoPhillips was notified by the EPA of alleged violations related to the use of Renewable Identification Numbers (RINs). The EPA intends to present an administrative settlement agreement to resolve the alleged violations under which it would seek a penalty of $250,000. ConocoPhillips is working with the EPA to resolve this matter.

On November 28, 2011, the Borger Refinery received a Notice of Enforcement from the Texas Commission on Environmental Quality (TCEQ) for alleged emissions events that occurred during inclement weather in January and February 2011. The TCEQ is seeking a penalty of $120,000. ConocoPhillips is working with TCEQ to resolve this matter.

In October 2011, ConocoPhillips was notified by the Attorney General of the State of California it was conducting an investigation into possible violations of the regulations relating to the operation of underground storage tanks at gas stations in California. ConocoPhillips is contesting these allegations.

Matters Previously Reported

On April 13, 2011, ConocoPhillips received a Notice of Enforcement and Proposed Agreed Order from the TCEQ seeking a penalty to settle several violations of air pollution control regulations and/or facility permit conditions at the Borger Refinery. These violations were previously disclosed on the ConocoPhillips Borger Refinery Title V deviation report. The TCEQ approved the settlement of this matter on October 18, 2011, with payment of a $70,963 penalty and a $70,962 Supplemental Environmental Project. This matter is now resolved.

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. ConocoPhillips is 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) it had self-identified certain compliance issues related to Benzene Waste Operations National Emission Standard for Hazardous Air Pollutants requirements at its Trainer, Pennsylvania, and Borger, Texas, facilities. On January 6, 2010, the DOJ provided its initial penalty demand for this matter as part of our confidential settlement negotiations. ConocoPhillips has reached an agreement with the EPA and DOJ regarding an appropriate penalty amount, which will be reflected in the third amendment to the consent decree in Civil Action No. H-05-258 (the agreed-upon penalty amount remains confidential until that time).

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

In October 2003, the District Attorney’s Office in Sacramento, California, filed a complaint in California 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. On December 19, 2011, the Court approved a settlement of this lawsuit which includes the payment of $500,000 which will be treated as a civil penalty. This matter is now resolved.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

 

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EXECUTIVE OFFICERS OF THE REGISTRANT

 

Name    Position Held    Age*
Willie C. W. Chiang    Senior Vice President, Refining, Marketing, Transportation and Commercial    51
Greg C. Garland    Senior Vice President, Exploration and Production—Americas    54
Alan J. Hirshberg    Senior Vice President, Planning and Strategy    50
Janet L. Kelly    Senior Vice President, Legal, General Counsel and Corporate Secretary    54
Ryan M. Lance    Senior Vice President, Exploration and Production—International    49
James J. Mulva    Chairman of the Board of Directors, President and Chief Executive Officer    65
Glenda M. Schwarz    Vice President and Controller    46
Jeff W. Sheets    Senior Vice President, Finance and Chief Financial Officer    54

 

*On February 15, 2012.

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 9, 2012. Set forth below is information about the executive officers.

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, President and Chief Executive Officer since May 2011, having previously served as Chairman of the Board of Directors and Chief Executive Officer since October 2008. He previously served as Chairman of the Board of Directors, President and Chief Executive Officer since 2004.

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  
  

 

 

    

 

 

 

2011

        

First

   $             81.80         66.50         .66   

Second

     81.75         70.08         .66   

Third

     80.13         60.40         .66   

Fourth

     73.90         58.65         .66   

 

 

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   

 

 

Closing Stock Price at December 31, 2011

         $ 72.87   

Closing Stock Price at January 31, 2012

         $ 68.21   

Number of Stockholders of Record at January 31, 2012*

           57,800   

 

 

*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  

Period

    

 

Total Number of

Shares Purchased

  

   

 

 

Average

Price Paid

Per Share

  

  

  

    

 

 

 

 

Total Number of

Shares Purchased

as Part of Publicly

Announced Plans

or Programs

  

  

  

  

** 

   

 

 

 

 

Approximate Dollar

Value of Shares

that May Yet Be

Purchased Under the

Plans or Programs

  

  

  

  

  

 

 

October 1-31, 2011

     15,727,577      $ 66.77         15,724,559        $             2,100   

November 1-30, 2011

     15,108,133        70.21         15,108,040        1,039   

December 1-31, 2011

     14,726,654        70.60         14,720,228        10,000   

 

 

Total

     45,562,364      $ 69.15         45,552,827     

 

 
  * 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. Share repurchases under this program were completed in the first quarter of 2011. On February 11, 2011, we announced plans to repurchase up to $10 billion of our common stock over the subsequent two years. Share repurchases under this program were completed in the fourth quarter of 2011. On December 2, 2011, we announced a share repurchase program for a further $10 billion of common stock over the next 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  
     2011         2010         2009         2008        2007   
  

 

 

 

Sales and other operating revenues

   $     244,813         189,441         149,341         240,842        187,437   

Net income (loss)

     12,502         11,417         4,492         (16,279     11,545   

Net income (loss) attributable to ConocoPhillips

     12,436         11,358         4,414         (16,349     11,458   

Per common share

             

Basic

     9.04         7.68         2.96         (10.73     7.06   

Diluted

     8.97         7.62         2.94         (10.73     6.96   

Total assets

     153,230         156,314         152,138         142,865        177,094   

Long-term debt

     21,610         22,656         26,925         27,085        20,289   

Joint venture acquisition obligation—

long-term

     3,582         4,314         5,009         5,669        6,294   

Cash dividends declared per common share

     2.64         2.15         1.91         1.88        1.64   

 

 

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 from 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 21, 2012

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 73.

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 29,800 employees worldwide, and at year-end 2011 had assets of $153 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

Our business is organized into six operating segments:

 

   

Exploration and Production (E&P)—This segment primarily explores for, produces, transports and markets crude oil, 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 past investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We completed the divestiture of our entire interest in LUKOIL in the first quarter of 2011.

   

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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Our earnings depend largely on the profitability of our E&P and R&M segments. Crude oil and natural gas prices, along with refining margins, are the most significant factors affecting our profitability. In recent years, the business environment for the energy industry has experienced extreme volatility. As a result, in late 2009, we announced several strategic initiatives designed to improve our financial position and increase returns on capital. We have made significant progress on our three-year strategic plan through portfolio optimization, debt reduction and increased shareholder distributions. During 2011, we announced plans to sell an additional $5–$10 billion of noncore assets over the next two years, bringing the total asset divestiture program target to $15–$20 billion for the years 2010 through 2012. As of year-end 2011, we have generated approximately $10.7 billion from asset dispositions, the proceeds of which were primarily targeted toward share repurchases and debt reduction.

We also completed the sale of our entire interest in LUKOIL in the first quarter of 2011, which generated total proceeds of $9.5 billion in 2010 and 2011. These proceeds were largely used to fund share repurchases. In December 2011, our Board authorized the additional purchase of up to $10 billion of our common stock over the next two years. This increased the share repurchase program from $15 billion to $25 billion. Since the inception of the share repurchase programs, we have repurchased 15 percent of our shares outstanding for a total of $15 billion. During 2011, we also increased the amount of our quarterly dividend rate by 20 percent, paid dividends on our common stock of $3.6 billion for the full year and reduced our debt by 4 percent.

Our total capital program in 2012 is expected to be $15.5 billion, a $1.5 billion increase from $14.0 billion in 2011. We also expect 2012 production to be approximately 1.6 million barrels of oil equivalent per day (BOED), excluding the impact of any additional asset sales.

Consistent with our strategy to focus on value creation for our shareholders, in July 2011, our Board approved pursuing the separation of our refining, marketing and transportation businesses into a stand-alone, publicly traded corporation via a tax-free distribution. The new downstream company, named Phillips 66, will also include most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment. We believe the separation will enable each company to pursue a more focused strategy, which will enable the management of each company to concentrate their resources on its particular market segments, customers and core businesses. The separation is subject to market conditions, customary regulatory approvals, the receipt of an affirmative Internal Revenue Service private letter ruling and final Board approval, and is expected to be completed in the second quarter of 2012.

Upon completion of the separation, ConocoPhillips will be a large and geographically diverse pure-play exploration and production company. Our strategy of enhancing returns on capital through developing new resources, growing reserves and production per share, continuing the asset sale program and increasing shareholder distributions will not change.

Phillips 66 will be an integrated downstream company, with operations encompassing natural gas gathering and processing, crude oil refining, petroleum products marketing, transportation, power generation and petrochemicals manufacturing and marketing.

We believe the execution of our strategic plan will position the two companies to be successful and competitive in the long term. Other important factors that we must continue to manage well in order to sustain our long-term competitive position include:

 

   

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 2011, our worldwide refining capacity utilization rate was 92 percent, compared with 81 percent in 2010. The increase in 2011 primarily resulted from the removal of the Wilhelmshaven Refinery (WRG) from our refining capacities effective January 1, 2011, and lower turnaround activity, partially offset by higher planned maintenance.

 

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There has been heightened public focus on the safety of the oil and gas industry as a result of the 2010 Deepwater Horizon incident in the Gulf of Mexico. Safety and environmental stewardship, including the operating integrity of our assets, remain our highest priorities. 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 and improve industry spill response in the U.S. Gulf of Mexico. To complement this work internationally, in 2011, we and several leading oil and gas companies established the Subsea Well Response Project in Norway, and we participated in the Oil Spill Prevention and Response Advisory Group in the United Kingdom.

 

   

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, 2011, our reserve replacement was 102 percent, excluding LUKOIL and the impact of acquisitions, dispositions and expropriations.

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 1 percent in 2011, compared with 2010.

 

   

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.

The capital expenditures and investments portion of our capital program totaled $13.3 billion in 2011, and we anticipate capital expenditures and investments to be approximately $14.8 billion in 2012. The increase reflects our strategic emphasis on delivering value by investing in the most profitable opportunities. We expect competitive returns from increased investments in unconventional resource projects, such as our oil sands business in Canada, liquids-rich shale plays in the U.S. Lower 48 and the Australia Pacific LNG (APLNG) joint venture. As our production profile adjusts over time to reflect our increased levels of investment in liquids plays and lower levels in North American conventional natural gas, we expect higher returns in E&P, absent changes in market factors.

 

   

Managing our asset portfolio. We continually evaluate our assets to determine whether they fit our strategic plans or should be sold or otherwise disposed. As part of our $15–$20 billion asset divestiture program for 2010–2012, during 2010, we sold our 9.03 percent interest in the Syncrude oil

 

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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. In 2011, we continued to divest low-return, noncore assets in the Lower 48 and western Canada. We also sold WRG, Seaway Products Pipeline Company, and our equity interests in Colonial Pipeline Company and Seaway Crude Pipeline Company. Additionally, we completed the divestiture of our entire interest in LUKOIL in the first quarter of 2011.

East Coast refining has been under severe market pressure for several years. As a result, in September 2011, we announced our intention to sell the Trainer Refinery located in Trainer, Pennsylvania. The refinery has been idled and will permanently close by the end of the first quarter of 2012 if a sales transaction is unsuccessful. In addition, in E&P we recently entered into agreements to sell our Vietnam business, as well as certain North Sea assets. These sales are expected to close in the first half of 2012.

 

   

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.

Other significant factors that can affect our profitability include:

 

   

Commodity prices. In 2011, the global economic rate of growth slowed, leading to lower oil demand growth. Oil prices, however, increased in 2011, as supply concerns, including concerns over the loss of Libyan production, outweighed the economic uncertainty in the United States and Europe. U.S. natural gas prices remained under pressure during 2011, as increased production from shale plays outpaced demand growth. As a result, storage inventory levels reached record highs by the end of 2011. We expect these factors will continue to moderate natural gas prices, resulting in limited U.S. LNG imports in the near- to mid-term.

In recent years, the use of hydraulic fracturing in shale natural gas formations has led to increased industry actual and forecasted natural gas production in the United States. Although providing short- and long-term significant growth opportunities for our company, the increased abundance of natural gas due to development of shale plays could also have adverse financial implications to us, including: an extended period of low natural gas prices; production curtailments on properties that produce primarily natural gas; cancelation or delay of plans to develop Alaska North Slope and Canadian Arctic natural gas fields; and underutilization of LNG regasification facilities and certain natural gas pipelines. Should one or more of these events occur, our revenues would be reduced and additional impairments might be possible.

 

   

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 2011 totaled $1.3 billion and primarily resulted from the impairments of the Trainer Refinery, our equity investment in Naraynmarneftegaz (NMNG) and certain Canadian natural gas properties. Before-tax impairments in 2010 totaled $2.4 billion and primarily related to the $1.5 billion property impairment of WRG and the $0.6 billion impairment of our equity investment in NMNG.

 

   

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

 

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Fiscal and regulatory environment. 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. Civil unrest or strained relationships with governments may impact our operations or investments. These changing environments have generally negatively impacted our results of operations, and further changes to government fiscal take could have a negative impact on future operations. Our production operations in Libya and related oil exports were temporarily suspended in 2011 during Libya’s period of civil unrest. 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.

Segment Analysis

Earnings for the E&P segment are generally closely aligned with industry price levels for crude oil and natural gas. 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 2011, compared with 2010, averaging $95.05 per barrel in 2011, an increase of 20 percent. Industry natural gas prices at Henry Hub decreased 8 percent during 2011 to an average price of $4.04 per million British thermal units.

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 23 percent in 2011.

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 significantly improved during 2011, compared with 2010. The U.S. 3:2:1 crack spread, which is primarily WTI-based, increased 126 percent in 2011, while the N.W. Europe benchmark increased 20 percent. The improvement in domestic refining margins primarily resulted from increased production from shale plays and high inventory levels in the Midcontinent area, causing WTI to trade at a deeper discount relative to waterborne crudes for most of 2011. This discount, however, began to narrow toward the end of 2011. During the periods of large WTI-Brent spreads, refineries capable of processing WTI and crude oils that are WTI-based benefitted from the lower regional feedstock prices. In contrast, East Coast refining, which relies primarily on Brent-based crudes, has been under severe market pressure. Product imports, weakness in motor fuel demand, and costly regulatory requirements are key challenges in this difficult environment.

The LUKOIL Investment segment consisted of our prior investment in the ordinary shares of LUKOIL. 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.

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.

 

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RESULTS OF OPERATIONS

Consolidated Results

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

 

     Millions of Dollars  
Years Ended December 31    2011     2010     2009  
  

 

 

 

E&P

   $ 8,242        9,198        3,604   

Midstream

     458        306        313   

R&M

     3,751        192        37   

LUKOIL Investment

     239        2,503        1,219   

Chemicals

     745        498        248   

Emerging Businesses

     (26     (59     3   

Corporate and Other

     (973     (1,280     (1,010

 

 

Net income attributable to ConocoPhillips

   $ 12,436        11,358        4,414   

 

 

2011 vs. 2010

Earnings for ConocoPhillips increased 9 percent in 2011. The improvement was mainly due to:

 

   

Higher commodity prices in our E&P segment. Commodity price benefits were somewhat offset by increased production taxes.

   

Improved results from our R&M operations, reflecting significantly higher U.S. refining margins.

   

Lower impairments. In 2011, impairments totaled $1,004 million after-tax, compared with 2010 impairments of $1,928 million after-tax.

These items were partially offset by:

 

   

Lower gains from asset sales. In 2011, gains from asset dispositions and LUKOIL share sales were $1,637 million after-tax, compared with 2010 gains of $4,583 million after-tax.

   

The absence of equity earnings from LUKOIL due to the divestiture of our interest.

   

Lower production volumes from our E&P segment.

2010 vs. 2009

The improved results in 2010 were primarily the result of:

 

   

Higher prices for crude oil, natural gas, natural gas liquids (NGL) and 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.

 

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Income Statement Analysis

2011 vs. 2010

Sales and other operating revenues increased 29 percent in 2011, while purchased crude oil, natural gas and products increased 37 percent. The increases were mainly due to significantly higher prices for petroleum products, crude oil and NGLs.

Equity in earnings of affiliates increased 30 percent in 2011. The increase primarily resulted from:

 

   

Earnings from Qatar Liquefied Gas Company Limited (3) (QG3), primarily due to sales of LNG following production startup, which occurred in October 2010.

   

Improved earnings from WRB Refining LP, primarily due to higher refining margins.

   

Improved earnings from CPChem, mainly due to higher margins in the olefins and polyolefins business line.

   

Lower impairments from NMNG. In 2011, equity earnings included a $395 million impairment of our equity investment, and 2010 equity earnings included a $645 million impairment.

   

Improved earnings from FCCL Partnership, mostly due to higher commodity prices and volumes.

   

Improved earnings from DCP Midstream, LLC, mainly as a result of higher NGL prices.

These increases were partially offset by the absence of equity earnings from LUKOIL due to the divestiture of our interest.

Gain on dispositions decreased 65 percent in 2011. Gains in 2011 primarily resulted from the disposition of Seaway Products Pipeline Company, our interests in Seaway Crude Pipeline Company and Colonial Pipeline Company, certain E&P assets located in the Lower 48 and Canada, and the remaining divestiture of our LUKOIL shares. These gains were partially offset by the loss on dilution of our equity interest in APLNG from 50 percent to 42.5 percent and the loss on disposition of WRG. Gains in 2010 primarily reflected the $2,878 million gain realized from the sale of our interest in Syncrude, 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 or Sold and Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements.

Depreciation, depletion and amortization (DD&A) decreased 12 percent in 2011. The decrease was mostly associated with our E&P segment, reflecting lower production volumes and lower unit-of-production rates related to reserve bookings in 2011.

Impairments decreased 56 percent in 2011, primarily due to the $1,514 million impairment of WRG in 2010. This decrease was partially offset by the impairment of the Trainer Refinery and various North American E&P natural gas properties in 2011. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes increased 9 percent in 2011, 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 18 percent in 2011, primarily due to lower debt levels.

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

 

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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 was primarily due to the $2,878 million gain realized from the Syncrude sale, 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.

Impairments increased $1,245 million in 2010, primarily as a result of the 2010 WRG impairment.

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 provision for income taxes and effective tax rate.

 

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Segment Results

E&P

 

     2011      2010      2009  
  

 

 

 
     Millions of Dollars  

Net Income (Loss) Attributable to ConocoPhillips

        

Alaska

   $ 1,983         1,735         1,540   

Lower 48

     1,271         1,033         (37

 

 

United States

     3,254         2,768         1,503   

International

     4,988         6,430         2,101   

 

 
   $ 8,242         9,198         3,604   

 

 
     Dollars Per Unit  

Average Sales Prices

        

Crude oil and natural gas liquids (per barrel)

        

United States

   $ 91.77         69.73         53.21   

International

     102.68         74.95         57.40   

Total consolidated operations

     97.12         72.63         55.47   

Equity affiliates

     98.60         74.81         58.23   

Total E&P

     97.22         72.77         55.63   

Bitumen (per barrel)

        

International

     55.16         51.10         39.67   

Equity affiliates

     63.93         53.43         45.69   

Total E&P

     62.56         53.06         44.84   

Natural gas (per thousand cubic feet)

        

United States

     4.01         4.27         3.50   

International

     6.73         5.60         5.06   

Total consolidated operations

     5.64         5.07         4.40   

Equity affiliates

     2.89         2.79         2.35   

Total E&P

     5.34         4.98         4.37   

 

 

Average Production Costs Per Barrel of Oil Equivalent

        

United States

   $ 9.70         8.30         7.73   

International

     9.70         7.96         7.72   

Total consolidated operations

     9.70         8.10         7.73   

Equity affiliates

     7.85         8.11         7.68   

Total E&P

     9.48         8.10         7.72   

 

 
     Millions of Dollars  

Worldwide Exploration Expenses

        

General and administrative; geological and geophysical; and lease rentals

   $ 596         678         576   

Leasehold impairment

     161         241         247   

Dry holes

     309         236         359   

 

 
   $ 1,066         1,155         1,182   

 

 

 

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     2011      2010      2009  
  

 

 

 
     Thousands of Barrels Daily  

Operating Statistics

        

Crude oil and natural gas liquids produced

        

Alaska

     215         230         252   

Lower 48

     168         160         166   

 

 

United States

     383         390         418   

Canada

     38         38         40   

Europe

     175         211         241   

Asia Pacific/Middle East

     111         140         132   

Africa

     40         79         78   

Other areas

     -         -         4   

 

 

Total consolidated operations

     747         858         913   

Equity affiliates

        

Russia

     29         52         55   

Asia Pacific/Middle East

     23         3         -   

 

 
     799         913         968   

 

 

Synthetic oil produced

        

Consolidated operations—Canada

     -         12         23   

 

 

Bitumen produced

        

Consolidated operations—Canada

     10         10         7   

Equity affiliates—Canada

     57         49         43   

 

 
     67         59         50   

 

 
     Millions of Cubic Feet Daily  

Natural gas produced*

        

Alaska

     61         82         94   

Lower 48

     1,556         1,695         1,927   

 

 

United States

     1,617         1,777         2,021   

Canada

     928         984         1,062   

Europe

     626         815         876   

Asia Pacific/Middle East

     695         712         713   

Africa

     158         149         121   

 

 

Total consolidated operations

     4,024         4,437         4,793   

Equity affiliates

        

Asia Pacific/Middle East

     492         169         84   

 

 
     4,516         4,606         4,877   

 

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

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, 2011, 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 averaged 1,619,000 BOED in 2011, compared with 1,752,000 BOED in 2010.

 

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2011 vs. 2010

Earnings from our E&P segment were $8,242 million in 2011, a 10 percent decrease compared with earnings of $9,198 million in 2010. 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 were $3,254 million in 2011, an 18 percent increase compared with earnings of $2,768 million in 2010. The increase primarily resulted from higher crude oil and NGL prices, and, to a lesser extent, lower DD&A. These increases were partially offset by higher production taxes, mainly in Alaska, lower sales volumes, higher operating expenses and lower gains from asset sales in the Lower 48.

U.S. E&P production averaged 653,000 BOED in 2011, a decrease of 5 percent from 686,000 BOED in 2010. The decrease was primarily due to field decline and asset dispositions, which was partially offset by new production, mostly from the Lower 48.

International E&P

International E&P earnings were $4,988 million in 2011, a 22 percent decrease compared with earnings of $6,430 million in 2010. Earnings in 2011 included $316 million in additional income tax expense, as a result of legislation enacted in the United Kingdom in July 2011. This additional tax expense consisted of $106 million for the revaluation of deferred tax liabilities and $210 million to reflect the higher tax rates from the effective date of the legislation, March 24, 2011, through December 31, 2011. In 2011, earnings also included impairments of our investment in NMNG and various natural gas properties located in Canada, in addition to a $279 million loss on the dilution of our equity interest in APLNG from 50 percent to 42.5 percent. Earnings in 2010 included gains from the sale of Syncrude and certain Canadian properties and an impairment of NMNG. Excluding the impact from these items, earnings increased in 2011, primarily due to higher prices, a full year of LNG sales from QG3 and lower DD&A. These increases to earnings were partially offset by lower volumes and higher taxes.

International E&P production averaged 966,000 BOED in 2011, a decrease of 9 percent from 1,066,000 BOED in 2010. The decrease primarily resulted from suspended operations in Libya and in Bohai Bay, China, asset dispositions and unplanned downtime. Normal field decline was largely offset by new production.

2010 vs. 2009

Earnings from our E&P segment were $9,198 million in 2010, compared with earnings of $3,604 million in 2009.

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 NGLs. Earnings also benefitted from higher gains from asset sales in our Lower 48 portfolio and lower DD&A. 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 BOED in 2010, a decrease of 9 percent from 755,000 BOED in 2009. The decrease was primarily due to field decline and unplanned downtime, which was somewhat offset by new production.

 

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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 BOED in 2010, a decrease of 3 percent from 1,099,000 BOED 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.

Midstream

 

     2011      2010      2009  
  

 

 

 
     Millions of Dollars  

Net Income Attributable to ConocoPhillips*

   $ 458         306         313   

 

 

*Includes DCP Midstream-related earnings:

   $ 274         191         183   
     Dollars Per Barrel  

Average Sales Prices

        

U.S. natural gas liquids*

        

Consolidated

   $ 57.79         45.42         33.63   

Equity affiliates

     50.64         41.28         29.80   

 

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

Operating Statistics

        

Natural gas liquids extracted*

     200         193         187   

Natural gas liquids fractionated**

     144         152         166   

 

 

  *Includes our share of equity affiliates.

**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 NGLs from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the NGLs are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel or refinery 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 NGL fractionation, trading and marketing businesses, primarily in the United States and Trinidad.

2011 vs. 2010

Earnings from the Midstream segment increased 50 percent in 2011, reflecting higher equity earnings from DCP Midstream and improved results from our other Midstream operations. Both DCP Midstream and our equity affiliate in Trinidad benefited from significantly higher NGL prices, which generally tracked the improved crude oil price environment in 2011. Also benefiting 2011 earnings were higher fees received for NGL fractionation services, reflecting favorably renegotiated contracts. These items were partially offset by higher costs at DCP Midstream, primarily due to higher maintenance and repair costs and increased DD&A.

 

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2010 vs. 2009

Midstream earnings decreased 2 percent in 2010. Higher NGL prices and, to a lesser extent, improved volumes from our equity affiliate in Trinidad, 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 contributed to the decrease in earnings.

R&M

 

$00,000 $00,000 $00,000
     2011     2010     2009  
  

 

 

 
     Millions of Dollars   
  

 

 

 

Net Income (Loss) Attributable to ConocoPhillips

      

United States

   $ 3,595        1,022        (192

International

     156        (830     229   

 

 
  

$

3,751

  

    192        37   

 

 
     Dollars Per Gallon   
  

 

 

 

U.S. Average Wholesale Prices*

      

Gasoline

   $ 2.94        2.24        1.84   

Distillates

     3.12        2.30        1.76   

 

 
*Excludes excise taxes.   
     Thousands of Barrels Daily  

Operating Statistics

      

Refining operations*

      

United States

      

Crude oil capacity**

     1,939        1,986        1,986   

Crude oil processed

     1,757        1,782        1,731   

Capacity utilization (percent)

     91     90        87   

Refinery production

     1,932        1,958        1,891   

International

      

Crude oil capacity**

     426        671        671   

Crude oil processed

     409        374        495   

Capacity utilization (percent)

     96     56        74   

Refinery production

     419        383        504   

Worldwide

      

Crude oil capacity**

     2,365        2,657        2,657   

Crude oil processed

     2,166        2,156        2,226   

Capacity utilization (percent)

     92     81        84   

Refinery production

     2,351        2,341        2,395   

 

 

Petroleum products sales volumes

      

United States

      

Gasoline

     1,129        1,120        1,130   

Distillates

     884        873        858   

Other products

     401        400        367   

 

 
     2,414        2,393        2,355   

International

     714        647        619   

 

 
     3,128        3,040        2,974   

 

 

  *Includes our share of equity affiliates.

**Weighted-average crude oil capacity for the periods.

 

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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.

2011 vs. 2010

R&M reported earnings of $3,751 million in 2011, compared with earnings of $192 million in 2010. 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 $3,595 million in 2011, compared with earnings of $1,022 million in 2010. The increase in earnings primarily resulted from significantly higher refining margins and gains from asset sales. In 2011, gains from asset sales of $1,577 million after-tax mainly resulted from the sales of Seaway Products Pipeline Company and our equity investments in Seaway Crude Pipeline Company and Colonial Pipeline Company, while 2010 included the $113 million after-tax gain on sale of our 50 percent interest in CFJ Properties. These increases were partially offset by the $303 million after-tax impairment and warehouse inventory write-down associated with our Trainer Refinery in 2011.

Our U.S. refining crude oil capacity utilization rate was 91 percent in 2011, compared with 90 percent in 2010. The increase mainly resulted from lower turnaround activity, partially offset by higher planned and unplanned downtime.

International R&M

International R&M reported earnings of $156 million in 2011, compared with a loss of $830 million in 2010. The increase in earnings was mostly due to the absence of the 2010 WRG impairment, in addition to higher refining volumes and foreign currency gains in 2011. These increases were partially offset by lower refining margins and the $86 million after-tax loss on sale of WRG and related warehouse inventory write-downs in 2011.

Our international refining crude oil capacity utilization rate was 96 percent in 2011, compared with 56 percent in 2010. The increase primarily resulted from the removal of WRG from our refining capacities effective January 1, 2011, and lower turnaround activity.

2010 vs. 2009

R&M reported earnings of $192 million in 2010, compared with earnings of $37 million in 2009.

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 largely 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 mainly 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 reflected run reductions at WRG in response to market conditions.

 

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LUKOIL Investment

 

$00,0000 $00,0000 $00,0000
     Millions of Dollars  
     2011      2010      2009  
  

 

 

 

Net Income Attributable to ConocoPhillips

   $ 239         2,503         1,219   

 

 

Operating Statistics

        

Crude oil production (thousands of barrels daily)

     -         284         388   

Natural gas production (millions of cubic feet daily)

     -         254         295   

Refinery crude oil processed (thousands of barrels daily)

     -         189         240   

 

 

This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011.

2011 vs. 2010

Earnings in 2011 primarily represented the realized gain on remaining share sales. Earnings in 2010 primarily reflected earnings from the equity investment in LUKOIL we held at the time, in addition to gains on the partial sale of our LUKOIL investment.

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.

Chemicals

 

$00,0000 $00,0000 $00,0000
     Millions of Dollars  
     2011      2010      2009  
  

 

 

 

Net Income Attributable to ConocoPhillips

   $ 745         498         248   

 

 

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.

2011 vs. 2010

Earnings from the Chemicals segment increased 50 percent in 2011, primarily due to higher margins, volumes and equity earnings in the olefins and polyolefins business line. The specialties, aromatics and styrenics business line also contributed to the increase in earnings due to higher margins.

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.

 

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Emerging Businesses

 

$00,0000 $00,0000 $00,0000
     Millions of Dollars  
     2011     2010     2009  
  

 

 

 

Net Income (Loss) Attributable to ConocoPhillips

      

Power

   $ 115        49        105   

Other

    
(141

    (108     (102

 

 
   $ (26     (59     3   

 

 

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.

2011 vs. 2010

The Emerging Businesses segment reported a loss of $26 million in 2011, compared with a loss of $59 million in 2010. The increase in “Power” earnings was primarily due to the absence of 2010 impairment charges related to a U.S. cogeneration plant, which was sold in December 2010, combined with higher international power generation results. Higher technology development expenses contributed to the increase in “Other” losses in 2011.

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 in “Power” earnings was mainly due to higher operating costs and lower margins in international power generation, in addition to the impairment charges and loss on sale of the U.S. cogeneration plant. Higher technology development expenses contributed to the increase in “Other” losses in 2010.

Corporate and Other

 

$00,0000 $00,0000 $00,0000
     Millions of Dollars  
     2011     2010     2009  
  

 

 

 

Net Loss Attributable to ConocoPhillips

      

Net interest

   $ (667     (965     (851

Corporate general and administrative expenses

     (199     (209     (108

Separation costs

     (25     -        -   

Other

     (82     (106     (51

 

 
   $ (973     (1,280     (1,010

 

 

2011 vs. 2010

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 decreased 31 percent in 2011, mostly due to lower interest expense, which resulted from lower debt levels; the absence of a $114 million after-tax premium on early debt retirement, which occurred in 2010; and slightly higher interest income.

Separation costs consist of expenses incurred for the planned separation of our downstream businesses into a stand-alone, publicly traded company, Phillips 66. Expenses incurred in 2011 primarily included legal, accounting and information systems costs.

 

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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 resulted from foreign currency transaction gains and lower environmental costs, partially offset by a $20 million after-tax property impairment.

2010 vs. 2009

Net interest increased 13 percent in 2010, mostly due to the $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.

Changes in the “Other” category primarily reflected foreign currency transaction losses.

 

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

 

     Millions of Dollars
Except as Indicated
 
     2011     2010      2009  
  

 

 

 

Net cash provided by operating activities

   $ 19,646        17,045         12,479   

Short-term debt

     1,013        936         1,728   

Total debt

     22,623        23,592         28,653   

Total equity

     65,734        69,109         62,613   

Percent of total debt to capital*

     26     25         31   

Percent of floating-rate debt to total debt**

     10     10         9   

 

 

  *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 2011, we received $4,820 million in proceeds from asset sales. During 2011, the primary uses of our available cash were $13,266 million to support our ongoing capital expenditures and investments program; $11,123 million to repurchase common stock; $3,632 million to pay dividends on our common stock; and $961 million to repay debt. During 2011, cash and cash equivalents decreased by $3,674 million to $5,780 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 2011, cash of $19,646 million was provided by operating activities, a 15 percent increase from cash from operations of $17,045 million in 2010. The increase was primarily due to higher commodity prices in our E&P segment and higher U.S. refining margins in our R&M segment.

During 2010, cash flow from operations increased $4,566 million, compared with 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.

While the stability of our cash flows from operating activities benefits from geographic diversity, 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 prices increased in 2009, 2010 and 2011, although natural gas prices remained weak. Global refining margins were under pressure during 2009 and 2010. Domestic refining margins significantly improved during the first three quarters of 2011, followed by a sharp decline in the fourth quarter of 2011. 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.

 

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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, 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 2011 averaged 1.62 million BOED. 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 2012, excluding the impact of any additional dispositions, is expected to be approximately 1.6 million BOED. We continue to evaluate various properties as potential candidates for our disposition program. The makeup and timing of our disposition program will also impact 2012 and future years’ production levels.

To maintain or grow our production volumes, we must continue to add to our proved reserve base. Our total reserve replacement in 2011 was 112 percent, including 117 percent from consolidated operations. Excluding the impact of acquisitions and dispositions, the reserve replacement was 120 percent of 2011 production. Over the five-year period ended December 31, 2011, our reserve replacement was 30 percent (including 64 percent from consolidated operations) reflecting the disposition of our interest in LUKOIL, the expropriation of our assets in Venezuela and the impact of our asset disposition program. Excluding these items and acquisitions, our five-year reserve replacement was 102 percent. The total reserve replacement amount above is 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 2011, 2010 and 2009, revisions increased 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 2011 were $4.8 billion, compared with $15.4 billion in 2010. The 2011 proceeds from asset sales included $2.0 billion from the sale of our ownership interests in Colonial Pipeline Company and Seaway Crude Pipeline Company and $1.2 billion from the sale of our remaining interest in LUKOIL. Other asset sales primarily included mature North American natural gas assets and a products pipeline. We plan to raise an additional $5 billion to $10 billion from asset sales in 2012.

 

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Commercial Paper and Credit Facilities

In August 2011, we increased our revolving credit facilities from $7.85 billion to $8.0 billion by replacing our $7.35 billion revolving credit facility with a $7.5 billion facility expiring in August 2016. The terms of the new revolving credit facility are similar to the terms of the replaced facility. We also have 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 QG3 Project. At December 31, 2011 and 2010, 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, $1,128 million of commercial paper was outstanding at December 31, 2011, compared with $1,182 million at December 31, 2010. Since we had $1,128 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.8 billion in borrowing capacity under our revolving credit facilities at December 31, 2011.

Our senior long-term debt is rated “A1” by Moody’s Investors 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 $7.5 billion and $500 million revolving credit facilities.

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.

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.

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. On December 15, 2011, QG3 achieved financial completion and all project loan facilities became nonrecourse to the project participants. At December 31, 2011, QG3 had approximately $3.9 billion outstanding under all the loan facilities, including $1.2 billion owed to ConocoPhillips.

 

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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, 2011, was $22.6 billion, a decrease of $1.0 billion during 2011, and our debt-to-capital ratio was 26 percent at year-end 2011, versus 25 percent at the end of 2010. The slight increase in the debt-to-capital ratio was due to a decrease in total equity resulting from the share repurchase programs in 2011, partially offset by the debt reduction. Our debt-to-capital ratio target range is 20 to 25 percent.

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 $732 million was short-term and was included in the “Accounts payable—related parties” line on our December 31, 2011, consolidated balance sheet. The principal portion of these payments, which totaled $695 million in 2011, 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.

During 2011, WRB Refining LP repaid $550 million of loan financing to ConocoPhillips that had been provided to assist WRB in meeting its operating and capital spending requirements. No outstanding balance remained at December 31, 2011.

In February 2012, we announced a dividend of 66 cents per share. The dividend is payable March 1, 2012, to stockholders of record at the close of business February 21, 2012.

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 was completed in the first quarter of 2011. On February 11, 2011, the Board authorized the additional purchase of up to $10 billion of our common stock over the subsequent two years. Repurchase of shares under this authorization was completed in the fourth quarter of 2011. Under both programs, repurchases totaled 220 million shares at a cost of $15 billion through December 31, 2011. On December 2, 2011, our Board of Directors authorized the purchase of up to an additional $10 billion of our common stock over the subsequent two years.

 

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Contractual Obligations

The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2011:

 

     Millions of Dollars  
     Payments Due by Period  
     Total      Up to 1
Year
    

Years

2-3

    

Years

4-5

   

After

5 Years

 
  

 

 

 

Debt obligations (a)

   $ 22,592         1,005         2,799         3,933        14,855   

Capital lease obligations

     31         8         3         2        18   

 

 

Total debt

     22,623         1,013         2,802         3,935        14,873   

 

 

Interest on debt and other obligations

     19,798         1,319         2,567         2,227        13,685   

Operating lease obligations

     2,761         767         901         502        591   

Purchase obligations (b)

     145,114         60,105         13,142         8,101        63,766   

Joint venture acquisition obligation (c)

     4,314         732         1,586         1,762        234   

Other long-term liabilities (d)

             

Asset retirement obligations

     8,920         387         668         505        7,360   

Accrued environmental costs

     922         126         147         97        552   

Unrecognized tax benefits (e)

     153         153         (e)         (e     (e

 

 

Total

   $       204,605         64,602         21,813         17,129        101,061   

 

 

 

(a) Includes $449 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 $71,737 million. In addition, $50,741 million are product purchases from CPChem, mostly for natural gas and natural gas liquids over the remaining term of 88 years, and Excel Paralubes, for base oil over the remaining initial term of 14 years.

Purchase obligations of $17,044 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 six-year period to the FCCL upstream joint venture with Cenovus.

 

(d) Does not include: Pensions—for the 2012 through 2016 time period, we expect to contribute an average of $490 million per year to our qualified and nonqualified pension and postretirement benefit plans in the United States and an average of $250 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 $690 million for 2012 and then approximately $445 million per year for the remaining four years. Our required minimum funding in 2012 is expected to be $530 million in the United States and $220 million outside the United States.

 

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(e) Excludes unrecognized tax benefits of $918 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

 

$00,00000 $00,00000 $00,00000 $00,00000
     Millions of Dollars  
     2012
Budget
     2011      2010      2009  
  

 

 

 

Capital Expenditures and Investments

           

E&P

           

United States—Alaska

   $ 900         775         730         810   

United States—Lower 48

     4,800         3,880         1,855         2,664   

International

     7,600         7,350         5,908         5,425   

 

 
     13,300         12,005         8,493         8,899   

 

 

Midstream

     -         17         3         5   

 

 

R&M

           

United States

     1,000         768         790         1,299   

International

     200         226         266         427   

 

 
     1,200         994         1,056         1,726   

 

 

LUKOIL Investment

     -         -         -         -   

Chemicals

     -         -         -         -   

Emerging Businesses

     100         30         27         97   

Corporate and Other

     200         220         182         134   

 

 
   $ 14,800         13,266         9,761         10,861   

 

 

United States

   $ 7,000         5,679         3,576         4,921   

International

     7,800         7,587         6,185         5,940   

 

 
   $ 14,800         13,266         9,761         10,861   

 

 

Our capital expenditures and investments for the three-year period ending December 31, 2011, totaled $33.9 billion, with 87 percent allocated to our E&P segment.

Our capital expenditures and investments budget for 2012 is $14.8 billion. Included in this amount is approximately $0.4 billion in capitalized interest. We plan to direct 90 percent of the capital expenditures and investments budget to E&P and 8 percent to R&M. With the addition of principal contributions related to funding our portion of the FCCL business venture, our total capital program for 2012 is approximately $15.5 billion.

E&P

Capital expenditures and investments for E&P during the three-year period ended December 31, 2011, totaled $29.4 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.

   

Advancement of coalbed methane (CBM) projects associated with the APLNG joint venture in Australia.

   

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.

 

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Development drilling and facilities projects in the Norwegian sector of the North Sea, including the Greater Ekofisk Area, Alvheim and Statfjord, and Heidrun in the Norwegian 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 Jasmine discovery in the J-Block Area, the development of Clair Ridge, development drilling on Clair and in the southern and central North Sea.

   

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, North American shale plays, Canadian oil sands projects, deepwater Gulf of Mexico, Alaska, U.K. and Norwegian sectors of the North Sea, Kazakhstan and Indonesia.

   

The El Merk Project, comprised of wells, gathering lines and a shared central processing facility to develop the EMK Field Unit in Algeria.

2012 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET

E&P’s 2012 capital expenditures and investments budget is $13.3 billion, 11 percent higher than actual expenditures in 2011. Forty-three percent of E&P’s 2012 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 focus capital expenditures and investments on development of liquids-rich areas, such as the Eagle Ford Trend, and the Williston and Permian basins. We also expect to direct capital spending towards exploration and appraisal activities in the Eagle Ford shale formation, as well as recently acquired acreage in the Avalon, Wolfcamp, and Niobrara areas. In addition, we plan to appraise our recent deepwater Gulf of Mexico discoveries.

E&P is directing $7.6 billion of its 2012 capital expenditures and investments budget to international projects. Funds in 2012 are expected to be directed to developing major long-term projects including:

 

   

Liquids opportunities in the western Canada basins and Canadian oil sands projects.

   

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, and offshore Block B and onshore South Sumatra in Indonesia.

   

In the North Sea, the Greater Ekofisk Area, development of the Jasmine discovery in the J-Block Area, development of Clair Ridge and the Britannia Long-Term Compression Project.

   

The Kashagan Field in the Caspian Sea.

   

Onshore developments in Nigeria, Algeria and Libya.

   

Exploration and appraisal activities in Canadian shale plays and oil sands projects, Australia’s offshore Browse Basin and onshore Canning Basin, deepwater Angola, Kazakhstan’s Block N, offshore Indonesia, Nigeria and the North Sea.

For information on proved undeveloped reserves and the associated costs 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, 2011, 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 $3.8 billion, which represented 11 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 emissions from the Fluid Catalytic Crackers at the Alliance and Sweeny refineries.

   

Installation of facilities to reduce nitrous oxide emissions from the crude furnace and installation of a new vacuum furnace at the Bayway Refinery.

   

Completion of gasoline benzene reduction projects at the Alliance and Ponca City refineries.

Major construction activities in progress include:

 

   

Installation, revamp and expansion of equipment at the Bayway Refinery to enable production of low benzene gasoline.

   

U.S. programs aimed at air emission reductions.

2012 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET

R&M’s 2012 capital expenditures and investments budget is $1.2 billion, a 21 percent increase from actual spending in 2011, with about $1.0 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, efficiency and reliability.

Emerging Businesses

Capital spending for Emerging Businesses during the three-year period ended December 31, 2011, was primarily for an expansion and other capital improvements at 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 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

 

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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.

 

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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 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.

Another example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas that is otherwise trapped in lower permeability rock formations. A range of local, state, federal or national laws and regulations currently govern hydraulic fracturing operations. Although hydraulic fracturing has been conducted for many decades, a number of new laws, regulations and permitting requirements are under consideration by the U.S. Environmental Protection Agency (EPA), the U.S. Department of the Interior, and others which could result in increased costs, operating restrictions, operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas investments. We have adopted operating principles that incorporate established industry standards designed to meet or exceed government requirements. Our practices continually evolve as technology improves and regulations change.

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 occasionally 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, 2010, we reported we had been notified of potential liability under CERCLA and comparable state laws at 73 sites around the United States. At December 31, 2011, we had been notified of 8 new sites, settled 5 sites and closed 2 sites, bringing the number to 74 unresolved sites with potential liability.

 

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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 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 $1,039 million in 2011 and are expected to be about $1,100 million per year in 2012 and 2013. Capitalized environmental costs were $573 million in 2011 and are expected to be about $875 million per year in 2012 and 2013.

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, 2011, our balance sheet included total accrued environmental costs of $922 million, compared with $994 million at December 31, 2010. 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.

 

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California’s Global Warming Solutions Act, which requires the California Air Resources Board to develop regulations and market mechanisms that will target reduction of 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.

   

The EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that triggers regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects.

   

Carbon taxes in certain jurisdictions.

   

Cap and trade programs in certain jurisdictions, including the Australian Clean Energy Legislation which is scheduled to take effect July 2012.

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, some additional form of regulation may be forthcoming in the future at the federal and state levels 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 there is a reasonable likelihood 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 2011, 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 $1,880 million and the accumulated impairment reserve was $487 million. The weighted-average judgmental percentage probability of ultimate failure was approximately 47 percent, and the weighted-average amortization period was approximately four years. If that judgmental percentage were to be raised by 5 percent across all calculations, pretax leasehold impairment expense in 2012 would increase by approximately $22 million. The remaining $5,966 million of gross capitalized unproved property costs at year-end 2011 consisted of individually significant leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently drilling, suspended exploratory wells, and capitalized interest. 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 $3.0 billion is concentrated in 10 major development areas. One of these major assets totaling $97 million is expected to move to proved properties in 2012.

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 2011, total suspended well costs were $1,037 million, compared with $1,013 million at year-end 2010. 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 commodity prices; 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 income statement because the proved developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of DD&A of the capitalized costs for that asset. At year-end 2011, the net book value of productive E&P properties, plants and equipment (PP&E) subject to a unit-of-production calculation was approximately $57 billion and the DD&A

 

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recorded on these assets in 2011 was approximately $6.6 billion. The estimated proved developed reserves for our consolidated operations were 5.2 billion BOE at the end of 2010 and 5.1 billion BOE at the end of 2011. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 5 percent across all calculations, pretax DD&A in 2011 would have increased by an estimated $347 million.

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.

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 plugging and abandonment of wells, 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 into PP&E 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, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.

Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases to DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as well as previously sold assets for which we retained the asset removal obligation, an increase in the asset

 

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removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the increased obligation would immediately be subject to impairment, due to the low fair value of these properties.

In addition to asset removal obligations, 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 PP&E 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, 2011, we had $701 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 ind