10-K 1 d10k.htm FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010 FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

 

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

For the fiscal year ended December 31, 2010

or

 

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

For the transition period from                     to                     

Commission File No. 1-8968

ANADARKO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware   76-0146568
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046

(Address of principal executive offices)

Registrant’s telephone number, including area code (832) 636-1000

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

 

Title of each class   Name of each exchange on which registered
Common Stock, par value $0.10 per share   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.    Yes  x    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  ¨    No  x.

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.    Yes  x    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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x.

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

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer   ¨    Smaller reporting company  ¨.

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

The aggregate market value of the Company’s common stock held by non-affiliates of the registrant on June 30, 2010, was $17.8 billion based on the closing price as reported on the New York Stock Exchange.

The number of shares outstanding of the Company’s common stock at January 31, 2011, is shown below:

 

Title of Class   Number of Shares Outstanding
Common Stock, par value $0.10 per share   496,258,104

 

Part of
Form 10-K
   Documents Incorporated By Reference

Part III

  

Portions of the Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 17, 2011 (to be filed with the Securities and Exchange Commission prior to April 1, 2011).


Table of Contents

TABLE OF CONTENTS

 

         Page  

PART I

    

Items 1 and 2.

 

Business and Properties

     2   
 

General

     2   
 

Oil and Gas Properties and Activities

     3   
 

United States

     4   
 

International

     6   
 

Proved Reserves

     8   
 

Sales Volumes, Prices and Production Costs

     13   
 

Delivery Commitments

     13   
 

Drilling Program

     14   
 

Drilling Statistics

     14   
 

Productive Wells

     15   
 

Properties and Leases

     15   
 

Midstream Properties and Activities

     15   
 

Marketing Activities

     16   
 

Current Market Conditions and Competition

     17   
 

Segment Information

     17   
 

Employees

     17   
 

Regulatory Matters, Environmental and Additional Factors Affecting
Business

     18   
 

Title to Properties

     23   
 

Executive Officers of the Registrant

     23   

Item 1A.

 

Risk Factors

     25   

Item 1B.

 

Unresolved Staff Comments

     40   

Item 3.

 

Legal Proceedings

     40   

PART II

    

Item 5.

 

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

     45   

Item 6.

 

Selected Financial Data

     48   

Item 7.

 

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

     49   

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

     79   

Item 8.

 

Financial Statements and Supplementary Data

     81   

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure

     158   

Item 9A.

 

Controls and Procedures

     158   

Item 9B.

 

Other Information

     158   

PART III

    

Item 10.

 

Directors, Executive Officers and Corporate Governance

     159   

Item 11.

 

Executive Compensation

     159   

Item 12.

 

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

     159   

Item 13.

 

Certain Relationships and Related Transactions, and Director
Independence

     159   

Item 14.

 

Principal Accountant Fees and Services

     159   

PART IV

    

Item 15.

 

Exhibits, Financial Statement Schedules

     160   


Table of Contents

PART I

Items  1 and 2. Business and Properties

GENERAL

Anadarko Petroleum Corporation is among the world’s largest independent oil and natural-gas exploration and production companies, with 2.4 billion barrels of oil equivalent (BOE) of proved reserves at December 31, 2010. Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by exploring for, acquiring and developing oil and natural-gas resources vital to the world’s health and welfare. Anadarko’s portfolio of assets includes positions in onshore resource plays in the Rocky Mountains region, the southern United States and the Appalachian basin. The Company is also among the largest producers in Algeria and in the deepwater Gulf of Mexico, and has significantly expanded its deepwater opportunities worldwide to include positions in high-potential basins located offshore Brazil, East and West Africa, China, Indonesia and New Zealand.

Anadarko is committed to producing energy in a manner that protects the environment and public health, and supports communities. Anadarko’s focus is to deliver resources to the world while upholding the Company’s core values of integrity and trust, servant leadership, commercial focus, people and passion, and open communication in all business activities.

Anadarko’s primary business segments are managed separately due to the nature of the products and services, the unique technology, and distribution and marketing requirements. The Company’s three operating segments are as follows:

Oil and gas exploration and production—This segment explores for and produces natural gas, crude oil, condensate and natural gas liquids (NGLs).

Midstream—This segment provides gathering, processing, treating and transportation services to Anadarko and third-party oil and natural-gas producers. The Company owns and operates natural-gas gathering, processing, treating and transportation systems in the United States.

Marketing—This segment sells much of Anadarko’s production, as well as production purchased from third parties. The Company actively markets oil, natural gas and NGLs in the United States, and actively markets oil from Algeria, China and Ghana.

The Company owns interests in several coal, trona (natural soda ash) and industrial mineral properties through non-operated joint ventures and royalty arrangements within and adjacent to its land grant acreage position (Land Grant). The Land Grant, the ownership of which is a significant competitive advantage for Anadarko, consists of land granted to the Company by the federal government in the mid-1800s that passes through Colorado and Wyoming and into Utah. Within the Land Grant, the Company has fee ownership of the mineral rights under approximately 8 million acres.

Unless the context otherwise requires, the terms “Anadarko” or “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company’s corporate headquarters is located at 1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046, and its telephone number is (832) 636-1000. Additionally, unless noted otherwise, the following information relates to Anadarko’s continuing operations and excludes the discontinued Canadian operations. For additional information, see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Available Information    The Company files or furnishes Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, registration statements and other items with the Securities and Exchange Commission (SEC). Anadarko provides access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing, on its Internet site located at www.anadarko.com/Investor/Pages/SECFilings.aspx. The Company will also make available to any stockholder, without charge, copies of its Annual Report on Form 10-K as filed with the SEC. For copies of this report, or any other filing, please contact Anadarko Petroleum Corporation, Investor Relations Department, P.O. Box 1330, Houston, Texas 77251-1330 or call (832) 636-1216.

 

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In addition, the public may read and copy any materials Anadarko files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers, like Anadarko, that file electronically with the SEC.

OIL AND GAS PROPERTIES AND ACTIVITIES

The map below illustrates the locations of Anadarko’s oil and natural-gas exploration and production operations. The Company plans to allocate approximately 85% of its 2011 capital budget to the oil and gas exploration and production segment.

LOGO

 

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United States

Overview    Anadarko’s operations in the United States include oil and natural-gas exploration and production onshore in the Lower 48 states and Alaska, and the deepwater Gulf of Mexico. The Company’s operations in the United States accounted for 89% of both Anadarko’s total sales volumes during 2010 and total proved reserves at year-end 2010. During 2010, the Company participated in the drilling of 1,570 natural-gas wells, 236 oil wells and 10 dry holes in the United States. The Company plans to allocate approximately 75% of its 2011 oil and gas exploration and production segment capital budget to United States properties.

Onshore    The Company plans to allocate approximately 60% of its 2011 oil and gas exploration and production segment capital budget to onshore properties.

Rocky Mountains Region    Anadarko’s Rocky Mountains Region (Rockies) properties are located in Colorado, Utah and Wyoming and are a mix of oil and natural-gas plays. Although the current mix is more heavily weighted toward natural gas, the Company has redirected its capital investment plans to target development in areas that offer higher liquids yields (liquids-rich areas). Anadarko operates approximately 13,500 wells and has an interest in approximately 10,100 non-operated wells in the Rockies. Anadarko operates tight gas and coalbed methane (CBM) natural-gas assets, as well as enhanced oil recovery (EOR) projects within the region. The Company also earns royalty revenue from many non-operated wells located within the Land Grant. Activities in the Rockies focus on expanding the potential of existing fields to increase production and adding proved reserves through infill drilling and down-spacing operations, re-completions and re-fracture stimulations of existing wells. In 2010, the Company drilled 1,121 wells in the Rockies and plans to maintain an active drilling program in the region in 2011, with a continued emphasis on liquids-rich areas.

The Company’s tight-gas assets are located in the Greater Natural Buttes area in eastern Utah, the Wattenberg field in northeast Colorado, and the Greater Green River area in Wyoming. Anadarko operates 7,500 wells and has an interest in 4,700 non-operated wells in these tight gas areas. Anadarko uses fracture-stimulation technology to produce from tight gas formations. The Company also benefits from third-party-operator success in the Wyoming portion of the Land Grant and actively pursues farm-out projects to capture incremental royalty revenue from exploration and development activity in the area.

The Greater Natural Buttes field, where the Company operates over 1,900 wells, is a core asset for the Company. In 2010, production volumes from the field increased by 10% over 2009 volumes. The Company drilled 263 wells during the year, while reducing the cost per foot drilled by 16%. Based on efficiency gains within the drilling program and a slightly higher rig count, Anadarko was able to drill 70% more wells than were drilled in 2009, while decreasing capital spending per well. The Company has identified more than 6,000 potential locations in the Greater Natural Buttes field for future development. Many of these locations are infill drilling opportunities focused on down-spacing from 40-acre well density to 10-acre well density. Another core area for the Company is the Wattenberg field, where Anadarko operates over 4,800 wells. During 2010, the Company drilled 363 wells in the Wattenberg field and increased sales volumes 11% compared to 2009. Liquids sales volumes in the field increased 20% during the year as the Company focused its efforts on liquids-rich areas. During 2010, 1,777 fracture stimulation treatments were performed compared to 1,010 in 2009. In 2011, Anadarko plans to maintain an active drilling program in these tight gas areas with a focus on liquids-rich areas.

Anadarko also operates multiple CBM properties in the Rockies. CBM is natural gas that is generated and stored within coal seams. To produce CBM, water is extracted from the coal seam, resulting in reduced pressure and the release of natural gas which flows to the wellhead. Anadarko’s primary CBM properties are located in the Powder River basin and Atlantic Rim areas in Wyoming and the Helper and Clawson fields in Utah. Anadarko operates approximately 4,600 low-cost CBM wells and has an interest in approximately 5,200 non-operated CBM wells in the Rockies. In 2011, Anadarko expects to reduce activity levels in its CBM development program as the Company continues to allocate its capital spending toward its liquids-rich opportunities.

The Company’s EOR operations increase the amount of oil that can be produced from mature reservoirs after primary recovery methods have been completed. During 2010, the Company continued to pursue development of its Rockies EOR assets at the Monell and Salt Creek fields in Wyoming. Monell field development is now largely complete with only minor infrastructure investments planned for 2011 to enhance carbon dioxide flood operations. Throughout 2011, the Company plans to progress the long-term tertiary recovery operations at Salt Creek which the Company has been continuously implementing since 2003.

 

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Southern and Appalachia Region    Anadarko’s Southern and Appalachia Region properties are primarily located in Texas and Pennsylvania. Operations in these areas are focused on finding and developing both natural gas and liquids from shales, tight sands and fractured-reservoir plays.

Anadarko holds interest in approximately 840,000 net fairway acres in shale and other emerging-growth plays throughout the Southern and Appalachia Region. These plays include the Eagleford/Pearsall plays in southwest Texas, the Marcellus shale in north-central Pennsylvania, the Bone Spring and Avalon plays in West Texas and the Haynesville shale in East Texas and western Louisiana. Anadarko also has tight gas and/or fractured-reservoir operations in the Bossier, Haley, Carthage, Chalk, South Texas and Ozona areas in Texas, and the Hugoton area in southern Kansas.

The Company drilled 479 wells and completed 359 wells in the Southern and Appalachia Region during 2010. Year-over-year drilling practices have changed significantly within the region with approximately 93% of the rig fleet drilling horizontally in 2010. Drilling efficiency improved in every area with respect to cycle times, while also drilling longer lateral lengths. As natural-gas prices declined during the year, the Company redirected drilling rig activity from gas-prone areas to liquids-rich areas, such as the Eagleford shale in the Maverick basin and the Bone Spring formation in the Delaware basin.

In the first quarter of 2010, Anadarko purchased additional acreage in the Maverick basin, where the liquids-rich Eagleford shale play is being developed. Anadarko currently holds approximately 405,000 gross and 288,000 net acres with an average working interest of approximately 71% in this area. During 2010, rig activity increased from two rigs at the beginning of the year to seven rigs at year end, which helped to increase net production from 2,400 barrels of oil equivalent per day (BOE/d) to over 14,000 BOE/d. Anadarko realized drilling efficiencies in the Eagleford shale play this year, where spud-to-release times were reduced to less than 12 days at the end of 2010, compared to more than 22 days in mid-2009. In 2010, 104 wells were spud and 71 wells were completed. With infrastructure and service agreements in place, about 94% of all completed wells are flowing to sales. Exploration in the area is focused on appraising and delineating the Pearsall shale formation. During the year, three Pearsall wells were spud and four wells were completed. Additional delineation of the Pearsall shale formation is planned for 2011.

In the Appalachian basin, where the Marcellus shale play is being actively developed, the Company entered into a joint-venture agreement that permits a third party to participate with the Company as a 32.5% partner in the Company’s Marcellus shale assets. The third party may earn 100,000 net acres in exchange for funding 100% of the Company’s share of 2010 development costs and 90% of these costs thereafter, up to approximately $1.4 billion, with an estimated funding-completion date in late 2012. During 2010, 53 operated horizontal wells were spud and 22 wells were completed. Anadarko also participated in 158 new horizontal wells and 110 completions as a non-operating partner in the area. Gross production increased from 40 million cubic feet per day (MMcf/d) in January 2010 to a year-end exit rate of approximately 330 MMcf/d. During 2010, gross delivery capacity increased to 1.2 billion cubic feet per day (Bcf/d). The Company plans to increase operated activity in this area in 2011.

The Bone Spring formation in the Delaware basin is an emerging liquids-rich reservoir. Anadarko currently holds 145,000 net acres in a joint-venture with an average working interest of approximately 44%. In 2010, 41 wells were spud and 29 wells were completed in Bone Spring. Drilling and well performance continue to improve in this area with recent well tests in excess of 1,500 BOE/d. Exploration in the Delaware basin is also focused on appraising the liquids-rich Avalon shale formation. At December 31, 2010, five operated rigs and three non-operated rigs were active in the Delaware basin and the Company plans to increase activity in 2011.

Alaska    Anadarko’s oil and natural-gas production and development activity in Alaska is concentrated primarily on the North Slope. Development activity continued at the Colville River Unit through 2010 with 11 wells drilled. In 2011, the Company anticipates participating in approximately 14 development wells and sanctioning of the Alpine West satellite development.

Gulf of Mexico    In the Gulf of Mexico, Anadarko owns an average 63% working interest in 505 blocks. The Company operates seven active floating platforms, holds interests in 26 producing fields and is in the process of delineating and developing five additional fields in the area. Anadarko plans to allocate approximately 15% of its 2011 oil and gas exploration and production segment capital budget to the deepwater Gulf of Mexico with the understanding that the regulatory environment continues to progress.

 

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In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating leasehold interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. The Macondo well was permanently plugged on September 19, 2010, when BP Exploration & Production Inc. (BP), the operator and 65% owner of the Macondo lease, completed a “bottom kill” cementing operation in connection with the successful interception of the well by a relief well. Investigations by the federal government and other parties into the cause of the well blowout, explosion, and resulting oil spill, as well as other matters arising from or relating to these events, are ongoing. For additional information see Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, Risk Factors under Item 1A of this Form 10-K and Legal Proceedings under Item 3 of this Form 10-K.

In May and July 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), previously known as the Minerals Management Service, an agency of the Department of the Interior (DOI), issued directives requiring lessees and operators of federal oil and gas leases in the Outer Continental Shelf regions of the Gulf of Mexico and Pacific Ocean to cease drilling all new deepwater wells, including wellbore sidetracks and bypasses, through November 30, 2010. These deepwater drilling moratoria (collectively, the Moratorium) prohibited drilling and/or spudding any new wells, and required operators that were in the process of drilling wells to proceed to the next safe opportunity to secure such wells, and to take all necessary steps to cease operations and temporarily abandon the impacted wells. Anadarko ceased all drilling operations in the Gulf of Mexico in accordance with the Moratorium, which resulted in the suspension of operations of two operated deepwater wells (Lucius and Nansen) and one non-operated deepwater well (Vito). The Moratorium was lifted October 12, 2010, but the BOEMRE has not approved new drilling permits. The new safety and environmental laws and regulations required by the DOI, delays in the processing and approval of drilling permits and any additional actions could adversely affect and further delay new drilling and ongoing development efforts in the Gulf of Mexico. For additional information see Risk Factors under Item 1A of this Form 10-K.

The Company is ready to resume drilling in the Gulf of Mexico in 2011, as soon as permits are approved. Anadarko’s Gulf of Mexico exploration program is expected to focus on the deep waters of the extensive middle-to-lower Miocene play in the central Gulf of Mexico, the Lower Tertiary play in the western Gulf of Mexico and the developing Pliocene play in the central Gulf of Mexico. During 2010, Anadarko participated in four successful deepwater wells (two Lucius appraisal wells and two Vito appraisal wells) and encountered mechanical problems on the Heidelberg appraisal well, which was being prepared to re-spud when the Moratorium was imposed.

Anadarko utilizes a hub-and-spoke infrastructure in the Gulf of Mexico in order to develop resources more quickly and at a substantial cost savings. In 2010, Anadarko drilled five development wells in the Gulf of Mexico before the Moratorium, and continued to make progress on the Caesar Tonga development project. The Company received permits to initiate well completions and is currently completing the first two Caesar Tonga wells; however, a recent mechanical issue involving the production riser system will delay first production, which was expected in mid-2011. As operator of the Caesar Tonga development project, the Company directed that the production riser undergo an extensive qualification program prior to installation. Additionally, in its role as operator, the Company pursued hydro-testing of the riser, the recent results of which have led Anadarko to delay startup in the interest of safety and the environment. Completion activities will continue as Anadarko works with the co-owners to secure a reliable alternative for the production riser. This field is a sub-sea tieback to the Anadarko-operated and owned Constitution spar, where required topside construction, modification and installation began on the Constitution spar in 2009.

International

Overview    The Company’s international oil and natural-gas production and development operations are located primarily in Algeria, China and Ghana. The Company also has exploration acreage in Ghana, Brazil, Indonesia, Mozambique, Sierra Leone, Cote d’Ivoire, Liberia, New Zealand, Kenya and other countries. These international locations accounted for 11% of both Anadarko’s total sales volumes during 2010 and total proved reserves at year-end 2010. Anadarko drilled 45 wells in international areas in 2010 and achieved first oil at the Jubilee field offshore Ghana in 3.5 years from discovery. In 2011, the Company expects to drill approximately 42 development and 20 exploration wells at various international locations. Anadarko plans to allocate approximately 25% of its 2011 oil and gas exploration and production segment capital budget to international areas.

 

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Algeria    Anadarko is engaged in development and production activities in Algeria’s Sahara Desert in Blocks 404 and 208. Currently, all production is from fields located in Block 404, which produce through the Hassi Berkine South and Ourhoud Central Production Facilities (CPF). Construction of the El Merk CPF and associated infrastructure for the development in Block 208 is progressing and the overall project was approximately 65% complete at December 31, 2010. Initial production is expected to occur around the beginning of 2012 and will be increased gradually until provisional acceptance (or alternatively until commission) of the full facility, which is expected to occur in late 2012. During 2010, nine development wells were drilled in Blocks 404 and 208. The Company expects 2011 development drilling activity to be similar to 2010 levels, with a focus on El Merk drilling.

Contracts and Partners    Since October 1989, the Company’s operations in Algeria have been governed by a Production Sharing Agreement (PSA) between Anadarko, two third parties, and Sonatrach, the national oil and gas company of Algeria. Anadarko’s interest in the PSA for Blocks 404 and 208 is 50% before participation at the exploitation stage by Sonatrach. The Company has two partners, each with a 25% interest, also prior to participation by Sonatrach. Under the terms of the PSA, oil reserves that are discovered, developed and produced are shared by Sonatrach, Anadarko and the remaining two partners. Sonatrach is responsible for 51% of the development and production costs, Anadarko is responsible for 24.5% and its two partners are responsible for 12.25% each. Anadarko and its partners have completed the exploration program on Blocks 404 and 208 and now participate only in development activity on these blocks. Anadarko and its joint-venture partners funded Sonatrach’s share of exploration costs and are entitled to recover these exploration costs from production during the development phase.

In March 2006, Anadarko received a letter from Sonatrach purporting to give notice under the PSA that the enactment of a 2005 law (2005 Law), relating to hydrocarbons, triggered Sonatrach’s right under the PSA to renegotiate the PSA in order to re-establish equilibrium of Anadarko’s and Sonatrach’s interests. Anadarko and Sonatrach reached an impasse over whether Sonatrach had a right to renegotiate the PSA based on the 2005 Law and entered into a formal non-binding conciliation process under the terms of the PSA in an attempt to resolve this dispute. The conciliation on the 2005 Law dispute was concluded in 2007 without a definitive resolution. There have been no further developments on the 2005 Law dispute since 2007. Anadarko currently is unable to reasonably estimate the economic impact under the PSA, if Sonatrach were to succeed in modifying the PSA.

Exceptional Profits Tax    In July 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production. In December 2006, implementing regulations regarding this legislation were issued. These regulations provide for an exceptional profits tax imposed on gross production at rates of taxation ranging from 5% to 50% based on average daily production volumes for each calendar month in which the price of Brent crude averages over $30 per barrel. Exceptional profits tax applies to the full value of production rather than to the amount in excess of $30 per barrel.

In response to the Algerian government’s imposition of the exceptional profits tax, the Company notified Sonatrach of its disagreement with the collection of the exceptional profits tax. The Company believes that the PSA provides fiscal stability through several provisions that require Sonatrach to pay all taxes and royalties. To facilitate discussions between the parties in an effort to resolve the dispute, in October 2007, the Company initiated a conciliation proceeding on the exceptional profits tax as provided in the PSA. Any recommendation issued by a conciliation board (Conciliation Board) arising out of the conciliation proceeding is non-binding on the parties. The Conciliation Board issued its non-binding recommendation in November 2008. In February 2009, the Company initiated arbitration against Sonatrach with regard to the exceptional profits tax. In conformance with the terms of the PSA, a notice of arbitration was submitted to Sonatrach. The arbitration hearing on the merits of the claims presented by Anadarko is scheduled for June 2011.

China    Anadarko’s development and production activities in China are located offshore in Bohai Bay. Development drilling and recompletion activity was ongoing throughout 2010, and Anadarko drilled 24 wells during the year. In addition, during 2010, a facility expansion was approved and an infill drilling program was implemented in order to sustain current-level production. Development drilling activity is expected to decrease in 2011, as the Company plans to participate in drilling one deepwater exploration well in the South China Sea during 2011.

 

 

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Ghana    Anadarko’s exploration and development activities in Ghana are located offshore in the West Cape Three Points block and the Deepwater Tano block. During 2010, the Company and its partners took delivery and completed installation and commissioning of a floating production, storage and offloading vessel (FPSO) at the Jubilee field. In December 2010, the Company and its partners achieved first oil from the Jubilee field, on budget and in 3.5 years following discovery. Additional development phases tied back to the FPSO may be executed based on performance data from wells already drilled. Immediately following first oil, well capacity was approximately 45,000 BOE/d and is expected to increase to 120,000 BOE/d over a three- to six-month period as additional wells are brought on-line. The Company and its partners have drilled 16 wells in the Jubilee field as of December 31, 2010, with most of the 2010 work focused on completing previously drilled wells. One additional Phase 1 well remains to be drilled during 2011. The Company and its partners filed a declaration of commerciality on the Mahogany East field during 2010 and anticipate sanctioning of the plan of development by year-end 2011. During 2010, the Company also participated in six exploration and appraisal wells outside the Jubilee field, including the successful Mahogany #5 appraisal well, the initial Enyenra (formerly Owo) discovery and subsequent sidetrack, and two appraisal wells at Tweneboa. The Tweneboa #3 appraisal well and the Teak exploration well were drilling at December 31, 2010. In early 2011, the Tweneboa #3 appraisal well and the Teak exploration well were completed and determined to be successful. In 2011, the Company plans to participate in seven to nine exploration and appraisal wells in Ghana.

Brazil    Anadarko holds exploration interests in seven blocks located offshore Brazil in the Campos and Espírito Santo basins. In these areas, Anadarko drilled two exploration wells in 2010, including the Itauna discovery in late 2010 on block BM-C-29. Also during 2010, Anadarko completed a successful pre-salt drill stem test on the Wahoo #1 well on block BM-C-30 in the deepwater Campos basin. In 2011, Anadarko expects to participate in two to three exploration and appraisal wells.

Indonesia    Anadarko has participating interests in approximately 4.5 million exploration acres in Indonesia through a combination of several operated and non-operated Production Sharing Contracts (PSC). The Company participated in three exploration wells in 2010, including the successful Badik #1 well in the Tarakan basin under the Nunukan PSC. The Company may participate in one exploration or appraisal well in 2011.

Mozambique    The Company has participating interests in two blocks (one onshore and one offshore) totaling approximately 6.4 million acres. In 2010, Anadarko primarily focused on deepwater opportunities in the Offshore Area 1 of the Rovuma basin where the Company holds a 36.5% working interest. During the year, Anadarko announced three natural-gas discoveries at the Windjammer, Barquentine and Lagosta prospects. Based on the results of these discoveries, Anadarko and its partners began designing an appraisal program and analyzing various development and commercialization options for the area. In addition, the Tubarão offshore exploration well that was drilling at December 31, 2010, was completed and determined to be successful in February 2011. The Company plans to keep at least one rig operating in the basin to continue its exploration and appraisal program in 2011.

Other    Anadarko also has active exploration projects in Sierra Leone, New Zealand and Kenya, as well as activities in other overseas new-venture areas. The Company also has a $70 million after-tax net investment in Venezuelan assets. Anadarko’s exploration activities in Sierra Leone are located in blocks 6 and 7 in the Liberian basin. In late 2010, Anadarko had a deepwater oil discovery at the Mercury prospect in Sierra Leone. In 2011, the Company plans to drill two to three exploration and appraisal wells in the Liberian basin area. In Cote d’Ivoire, Anadarko holds interests in two blocks located in the Ivorian basin.

Proved Reserves

Reserve and related information for 2010 and 2009 is presented consistent with the requirements of the Modernization of Oil and Gas Reporting rules released by the SEC on December 31, 2008. These revised rules require disclosing oil and gas proved reserves by significant geographic area when such reserves represent more than 15% of total proved reserves, using the 12-month average beginning-of-month commodity prices for the year unless contractual arrangements designate commodity prices, and expand the use of reliable technologies to establish reasonable certainty of the producibility of oil and gas reserves. These rules do not allow for the restatement of prior-year reserve information. All information related to periods prior to 2009 is presented in conformance with prior SEC rules using year-end commodity prices for the estimation of proved reserves; however, prior-year proved reserve data has been reclassified to conform to the current-year presentation of significant geographic areas.

 

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Estimates of proved reserve volumes, net of third-party royalty interests, of natural gas, oil, condensate and NGLs owned at year end are presented in billions of cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch for natural gas and in millions of barrels (MMBbls) for oil, condensate and NGLs. Total volumes are presented in millions of barrels of oil equivalent (MMBOE). For this computation, one barrel is the equivalent of 6,000 cubic feet of natural gas. NGLs are separately identified and any associated shrinkage has been deducted from the natural-gas reserve volumes.

Disclosures by geographic area are provided for the United States and International geographic areas. The International geographic area consists of aggregate proved reserves located in Algeria, China and Ghana, each representing less than 15% of the Company’s total proved reserves.

Summary of Proved Reserves

 

     Natural Gas
(Bcf)
     Oil and
Condensate
(MMBbls)
     NGLs
(MMBbls)
     Total
(MMBOE)
 

As of December 31, 2010

           

Proved

           

Developed

           

United States

     5,982        303        222        1,523  

International

             150                150  

Undeveloped

           

United States

     2,135        195        85        635  

International

             101        13        114  
                                   

Total proved

     8,117        749        320        2,422  
                                   

As of December 31, 2009

           

Proved

           

Developed

           

United States

     5,884        300        199        1,480  

International

             144                144  

Undeveloped

           

United States

     1,880        200        61        574  

International

             89        17        106  
                                   

Total proved

     7,764        733        277        2,304  
                                   

The Company’s estimates of proved reserves, proved developed reserves (PDPs) and proved undeveloped reserves (PUDs) at December 31, 2010, 2009 and 2008, and changes in proved reserves during the last three years are presented in the Supplemental Information on Oil and Gas Exploration and Production Activities (Supplemental Information) under Item 8 of this Form 10-K.

The Company has not filed any information with any other federal authority or agency with respect to its estimated total proved reserves at December 31, 2010. Annually, Anadarko reports gross proved reserves of operated properties in the United States to the U.S. Department of Energy; these reserves are derived from the same data from which its proved reserves of such properties are estimated in this Form 10-K.

Also presented in the Supplemental Information are the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. See Operating Results and Critical Accounting Estimates under Item 7 of this Form 10-K for additional information on the Company’s proved reserves.

Proved Reserves    The Company had proved reserves consisting of 8.1 trillion cubic feet (Tcf) of natural gas, 749 MMBbls of oil and condensate and 320 MMBbls of NGLs, totaling 2,422 MMBOE at December 31, 2010, compared to 2,304 MMBOE at December 31, 2009. This results in a year-end 2010 product mix of 56% natural gas, 31% oil and condensate and 13% NGLs, as compared to a year-end 2009 product mix of 56% natural gas, 32% oil and condensate and 12% NGLs, and a year-end 2008 product mix of 59% natural gas, 31% oil and condensate and 10% NGLs. The combined liquids portion of the Company’s product mix has increased from 41% at the end of 2008 to 44% at the end of 2010, which is consistent with the Company’s efforts to focus on its liquids-rich opportunities.

 

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Proved Undeveloped Reserves    The Company had PUDs consisting of 2.1 Tcf of natural gas, 296 MMBbls of oil and condensate, and 98 MMBbls of NGLs, totaling 749 MMBOE at December 31, 2010, compared to 680 MMBOE of PUDs at December 31, 2009.

Changes in PUDs    Significant changes to PUDs occurring during 2010 are summarized in the table below. Revisions of prior estimates reflect the addition of new PUDs associated with current development plans, revisions to prior PUDs, revisions to infill drilling development plans, as well as the transfer of PUDs to unproved reserve categories due to changes in development plans during 2010. These PUD changes reflect the ongoing evaluation of Anadarko’s asset portfolio and alignment with current-year changes to development plans. The Company’s year-end development plans are consistent with SEC guidelines for PUD development within five years unless specific circumstances warrant a longer development time horizon.

 

MMBOE

  

PUDs at December 31, 2009

     680  

Revisions of prior estimates

     142  

Extensions, discoveries and other additions

     30  

Conversion to Developed

     (103
        

PUDs at December 31, 2010

     749  
        

PUD Conversion    In 2010, the Company converted 103 MMBOE, or 15% of the total year-end 2009 PUDs to developed status. Approximately 65% of PUD conversions occurred in onshore United States assets, approximately 24% in international assets and the remaining 11% in Gulf of Mexico assets. Anadarko spent approximately $1.5 billion associated with the development of PUDs in 2010. Approximately 58% of total 2010 PUD capital related to two major development projects, El Merk in Algeria and Jubilee in Ghana, and approximately 29% related to domestic development programs in the Rockies and the Southern and Appalachia Regions. The remaining 13% of 2010 PUD development spending was associated with Gulf of Mexico, Alaska and other international development projects.

Development Plans    The Company annually reviews all PUDs to ensure an appropriate plan for development exists. Typically, onshore United States PUDs are converted to PDPs within five years. Projects such as EOR, arctic development, deepwater development and international programs may take longer than five years. At December 31, 2010, all of the Company’s onshore United States PUDs were scheduled to be developed within five years, with the exception of the Salt Creek EOR project. Approximately 8% of the Company’s year-end 2010 PUDs were associated with Algeria, Salt Creek EOR and Gulf of Mexico projects with estimated development time periods in excess of five years.

At December 31, 2010, the Company had 134 MMBOE of pre-2006 PUDs that remain undeveloped five years or more after disclosure as PUDs. Approximately 71% of these PUDs are located in Algeria and are being developed according to an Algerian government-approved plan. Nearly all of the Algerian PUDs are associated with the El Merk development project located in Block 208 in the Berkine basin. The initial El Merk development plan prepared in 1998 and 1999 was approved by the Algerian government in April 2003. Further evaluation, including an analysis of the results from a continuing drilling program, resulted in a revised El Merk exploitation license submission in 2005, which was subsequently approved by the Algerian regulatory authority in 2007. Site preparation was initiated in 2008 and construction of the El Merk CPF is continuing. As of year-end 2010, 73 wells have been drilled in the El Merk fields and drilling is continuing in 2011. The Reservoir Development Plan currently includes a total of 141 wells for full development. The overall El Merk project was approximately 65% complete at December 31, 2010. First oil production from the El Merk fields is expected to occur around the beginning of 2012.

Another 22% of the Company’s pre-2006 PUDs are associated with the Salt Creek EOR single-development project located in the Rockies. Since 2003, Anadarko has invested an average of $60 million per year to develop various phases of the Salt Creek integrated EOR project and has plans to continue significant spending levels in the future. Nearly all of the remaining pre-2006 PUDs are associated with Gulf of Mexico sidetrack opportunities where seasonal restrictions limit development activities. The Company expects to take advantage of these opportunities over the next two years, when permitted to resume drilling in the Gulf of Mexico.

 

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Technologies Used in Proved Reserve Estimation    In establishing reserves, the SEC allows the use of techniques that have been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In general, the Company uses numerous data elements and analysis techniques in the estimation of proved reserves. These data elements and techniques include, but are not limited to, production tests, well performance data, decline curve analysis, wireline logs, core data, pressure transient analysis, seismic data and interpretation, computational simulation and material balance calculations.

The Company estimates it has 75 MMBOE of proved reserves, or 3% of the Company’s total proved reserves, that are supported by the use of reliable technologies. Reserve growth associated with the use of reliable technology can be attributed primarily to recording reserves more than one location away from production, increasing recovery factor estimates or extending down-dip reservoir limits.

Reliable technologies have been used in a limited number of onshore United States producing fields to prove formation continuity more than one location away from production, accounting for less than 2% of the Company’s total proved reserves. These reserves are primarily associated with the Greater Natural Buttes area where a selected 10-acre infill drilling program is ongoing on sections previously drilled on 40-acre spacing. An illustration of the application of this program in the Greater Natural Buttes area is included below. The reliable technology associated with this application includes geological mapping and cross-sections based on well log data, decline curve projections from existing producing wells, volumetric calculations, whole and sidewall core analysis, computational simulation, reservoir pressure estimates and analog data. In other onshore United States areas of the Company, similar reliable technology has been used to prove reservoir continuity more than one location away from production, accounting for insignificant reserves volumes.

LOGO

Reliable technology such as pressure gradient data was employed to extend the down-dip limits of a reservoir. In addition, technology such as drill stem tests, interference testing and water injectivity testing was used to support analog data for recovery factor estimating in a newly developed field. These combined account for approximately 1% of total Company proved reserves.

 

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Internal Controls over Reserve Estimation    Anadarko’s estimates of proved reserves and associated future net cash flows at December 31, 2010, were made solely by the Company’s engineers and are the responsibility of management. The Company requires that reserve estimates be made by qualified reserves estimators (QREs), as defined by the Society of Petroleum Engineers’ standards. The QREs are assigned to specific assets within the Company’s regions. The QREs interact with engineering, land and geoscience personnel to obtain the necessary data for projecting future production, costs, net revenues and ultimate recoverable reserves. Management within each region approves the QREs’ reserve estimates each quarter and annually. All QREs receive ongoing education on the fundamentals of SEC reserves reporting through the Company’s reserves manual and internal training programs administered by the Corporate Reserve Group (CRG).

The CRG ensures confidence in the Company’s reserve estimates by maintaining internal policies for estimating and recording reserves in compliance with applicable SEC definitions and guidance. Compliance with the SEC reserve guidelines is the primary responsibility of Anadarko’s CRG.

The CRG is managed through the Company’s finance department, which is separate from its operating regions, and is responsible for overseeing internal reserve reviews and approving the Company’s reserve estimates. The Director–Reserve Administration and the Corporate Reserve Manager manage the CRG and report to the Vice President–Corporate Planning. The Vice President–Corporate Planning reports to the Company’s Senior Vice President, Finance and Chief Financial Officer, who in turn reports to the Chief Executive Officer. The Audit Committee of the Company’s Board of Directors meets with management, members of the CRG, and independent petroleum consultants Miller and Lents, Ltd. (M&L), to discuss matters and policies related to reserves.

The Company’s principal engineer, who is primarily responsible for overseeing the preparation of proved reserve estimates, has over 24 years of experience in the oil and gas industry, including over 10 years as either a reserve evaluator or manager. Further professional qualifications include a degree in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, the principal engineer is an active participant in industry reserve seminars, professional industry groups and has been a member of the Society of Petroleum Engineers for over 24 years.

Third-Party Procedures and Methods Review    The procedures and methods used by Anadarko’s staff in preparing its internal estimates of proved reserves and future net cash flows at December 31, 2010, were reviewed by M&L. The purpose of the review was to determine that the procedures and methods used by Anadarko to estimate its proved reserves are effective and in accordance with the definitions contained in SEC regulations. The procedures and methods review by M&L was a limited review of Anadarko’s procedures and methods and does not constitute a complete review, audit, independent estimate, or confirmation of the reasonableness of Anadarko’s estimates of proved reserves and future net cash flows.

The review consisted of 17 fields which included major assets in the United States and Africa, and encompassed approximately 83% of the Company’s estimates of proved reserves and future net cash flows at December 31, 2010. In each review, Anadarko’s technical staff presented M&L with an overview of the data, methods and assumptions used in estimating its reserves. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures and relevant economic criteria.

Management’s intent in retaining M&L to review its procedures and methods is to provide objective third-party input on the Company’s procedures and methods and to gather industry information applicable to its reserve estimation and reporting process.

 

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Sales Volumes, Prices and Production Costs

The following table provides the Company’s annual sales volumes, average sales prices and average production costs per BOE from continuing operations for each of the last three years. The Company’s sales volumes for 2010, 2009 and 2008 were 235 MMBOE, 220 MMBOE and 206 MMBOE, respectively. Production costs are costs to operate and maintain the Company’s wells and related equipment and include the cost of labor, well service and repair, location maintenance, power and fuel, transportation, other taxes and production-related general and administrative costs. Additional information on volumes, prices and production costs is contained in Financial Results under Item 7 of this Form 10-K. Additional detail regarding production costs is contained in the Supplemental Information under Item 8 of this Form 10-K.

 

    Sales Volumes     Average Sales Prices (1)     Average
Production
Costs (2)
(Per BOE)
 
    Natural
Gas
(Bcf)
    Oil and
Condensate
(MMBbls)
    NGLs
(MMBbls)
    Barrels of
Oil Equivalent
(MMBOE)
    Natural
Gas
(Per Mcf)
    Oil and
Condensate
(Per Bbl)
    NGLs
(Per Bbl)
   

2010

               

United States

               

Greater Natural Buttes

    107       1       4       23       $  3.92       $  66.50       $  39.08        $  9.65   

Other United States

    722       47       19       186       4.15       75.08       43.84        8.56   
                                       

Total United States

    829       48       23       209       4.12       74.96       43.07        8.68   
                                       

International

           26              26              78.52              7.56   
                                       

Total

    829       74       23       235       4.12       76.22       43.07        8.56   
                                       

2009

               

United States

               

Greater Natural Buttes

    100       1       3       21       $  3.13       $  48.84       $  33.68        $  9.43   

Other United States

    709       43       14       175       3.68       58.75       31.00        8.50   
                                       

Total United States

    809       44       17       196       3.61       58.56       31.42        8.59   
                                       

International

           24              24              59.01              6.01   
                                       

Total

    809       68       17       220       3.61       58.72       31.42        8.30   
                                       

2008

               

United States

               

Greater Natural Buttes

    91       1       1       17       $  6.49       $  78.11       $  64.67        $  10.71   

Other United States

    659       39       13       162       7.86       96.54       55.65        9.91   
                                       

Total United States

    750       40       14       179       7.69       96.20       56.11        9.99   
                                       

International

           27              27              95.83              9.02   
                                       

Total

    750       67       14       206       7.69       96.05         56.11        9.86   
                                       

 

Bcf—billion cubic feet

Mcf—thousand cubic feet

Bbl—barrel

(1)

Excludes the impact of commodity derivatives.

(2)

Excludes ad valorem and severance taxes.

Delivery Commitments

The Company sells crude oil and natural gas under a variety of contractual agreements, some of which specify the delivery of fixed and determinable quantities. At December 31, 2010, Anadarko was contractually committed to deliver approximately 750 Bcf of natural gas to various customers in the United States through 2021. These contracts have various expiration dates with approximately 45% of the Company’s current commitment to be delivered in 2011, and 90% by 2015. The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves.

 

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Drilling Program

The Company’s 2010 drilling program focused on proven and emerging oil and natural-gas basins in the United States (onshore and deepwater Gulf of Mexico) and various international locations. As a result of the Moratorium, the Company redirected 7% of total budgeted 2010 capital from the Gulf of Mexico to onshore United States, with particular emphasis on liquids-rich areas. In accordance with the Moratorium, the Company ceased all drilling in the Gulf of Mexico, which resulted in the suspension of two operated wells (Lucius and Nansen) and one non-operated deepwater well (Vito). The Moratorium was lifted October 12, 2010, but the BOEMRE has not approved new drilling permits. Exploration activity in 2010 consisted of 205 gross completed wells, which included 192 onshore U.S. wells, four offshore Gulf of Mexico wells, and nine international wells. Development activity in 2010 consisted of 1,656 gross completed wells, which included 1,618 onshore wells, two offshore Gulf of Mexico wells, and 36 international wells.

Drilling Statistics

The following table shows the number of oil and gas wells that completed drilling in each of the last three years.

 

     Net Exploratory      Net Development         
     Productive      Dry Holes      Total      Productive      Dry Holes      Total      Total  

2010

                    

United States

     84.3        1.2        85.5        1,027.9        3.6        1,031.5        1,117.0  

International

             3.6        3.6        11.2                11.2        14.8  
                                                              

Total

     84.3        4.8            89.1        1,039.1        3.6            1,042.7            1,131.8  
                                                              

2009

                    

United States

     30.6        5.0        35.6        587.2        7.3        594.5        630.1  

International

             3.3        3.3        10.7                10.7        14.0  
                                                              

Total

     30.6        8.3        38.9        597.9        7.3        605.2        644.1  
                                                              

2008

                    

United States

     12.1        4.6        16.7        1,566.1        8.0        1,574.1        1,590.8  

International

             1.6        1.6        4.9        0.4        5.3        6.9  
                                                              

Total

     12.1        6.2        18.3        1,571.0        8.4        1,579.4        1,597.7  
                                                              

The following table shows the number of wells in the process of drilling or in active completion stages and the number of wells suspended or waiting on completion at December 31, 2010.

 

     Wells in the process
of drilling or

in active completion
     Wells suspended or
waiting on completion
 
     Exploration      Development      Exploration      Development  

United States

           

Gross

     46        311        120        287  

Net

     16.3        175.7        44.0        202.6  

International

           

Gross

     6        3        23        12  

Net

     2.3        0.8        8.1        3.0  

Total

           

Gross

     52        314        143        299  

Net

     18.6        176.5        52.1        205.6  

 

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Productive Wells

At December 31, 2010, the Company had an ownership interest in productive wells as follows:

 

     Oil Wells*     Gas Wells*  

United States

    

Gross

     4,219        27,890   

Net

     3,249.5        17,308.8   

International

    

Gross

     315          

Net

     78.7          

Total

    

Gross

     4,534        27,890   

Net

     3,328.2        17,308.8   

 

*

Includes wells containing multiple completions as follows:

 

Gross

     361        1,977  

Net

     335.1        1,557.0  

Properties and Leases

The following schedule shows the developed lease, undeveloped lease and fee mineral acres in which Anadarko held interests at December 31, 2010.

 

     Developed
Lease
     Undeveloped
Lease
     Fee Minerals      Total  
thousands of acres    Gross      Net      Gross      Net      Gross      Net      Gross      Net  

United States

                       

Onshore

     5,074        2,993        6,480        2,915        10,226        8,379        21,780        14,287  

Offshore

     338        169        2,611        1,741                        2,949        1,910  
                                                                       

Total United States

     5,412        3,162        9,091        4,656        10,226        8,379        24,729        16,197  
                                                                       

International

     370        97        45,343        22,105                        45,713        22,202  
                                                                       

Total

     5,782        3,259        54,434        26,761        10,226        8,379        70,442        38,399  
                                                                       

MIDSTREAM PROPERTIES AND ACTIVITIES

Anadarko invests in midstream (gathering, processing, treating and transporting) systems to complement its oil and gas operations in regions where the Company has natural-gas production. Through ownership and operation of these facilities, the Company is able to better manage costs associated with bringing on new production and enhance the value received for gathering, processing, treating and transporting the Company’s production. In addition, Anadarko’s midstream business also provides midstream services to third-party customers, including major and independent producers. Anadarko generates revenues from its midstream activities through a variety of agreements including fixed-fee, percent-of-proceeds and keep-whole agreements. For 2011, Anadarko plans to allocate approximately 15% of the Company’s capital budget to the midstream segment.

At the end of 2010, Anadarko had 29 gathering systems located throughout major onshore producing basins in Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma, Pennsylvania and Texas. The Marcellus and Eagleford shale areas were significant new focus areas for midstream activity in 2010. Anadarko’s midstream business added gas gathering capacity in excess of 180 MMcf/d in the Marcellus shale play and 100 MMcf/d, expandable to 225 MMcf/d, in the Eagleford shale area. In addition, an oil gathering system that can be expanded to handle 60,000 barrels per day (Bbls/d) or more was brought online in the Eagleford shale area in 2010. In 2011, the Company’s midstream investment will continue to be focused in the Company’s liquids-rich growth plays in the Maverick basin, Delaware basin, Wattenberg and Greater Natural Buttes areas as well as the Marcellus shale area.

 

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Western Gas Partners, LP (WES), a consolidated subsidiary of Anadarko, is a publicly traded limited partnership formed by Anadarko to own, operate, acquire and develop midstream assets. In addition to the assets transferred to WES in connection with its 2008 initial public offering, Anadarko has transferred additional midstream assets to WES, including the 2010 transfers of the Wattenberg and Granger systems, in exchange for additional WES common units, general partner units and cash. In January 2011, WES entered into a purchase and sale agreement with a third party to acquire a processing plant and related gathering systems located in the Rocky Mountains area. This acquisition is expected to close in the first quarter of 2011 subject to regulatory approval and other customary closing conditions. At December 31, 2010, Anadarko held a 46.5% limited partner interest in WES, as well as a 2% general partner interest and incentive distribution rights.

The following table provides information regarding Company-owned midstream assets by geographic regions at December 31, 2010.

 

Area

  

Asset Type

   Miles of
Gathering
Pipelines
     Total
Horsepower
     2010
Average
Throughput
(MMcf/d)
 

Rocky Mountains

   Gathering, Processing and Treating      9,470        1,089,000        3,010  

Mid-Continent and other

   Gathering      2,470        104,000        150  

Texas

   Gathering and Treating      1,670        117,000        710  
                             

Total

        13,610        1,310,000        3,870  
                             

MARKETING ACTIVITIES

The Company’s marketing segment actively manages Anadarko’s natural-gas, crude-oil, condensate and NGLs sales. In marketing its production, the Company attempts to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. The Company’s sales of natural gas, crude oil, condensate and NGLs are generally made at market prices for those products at the time of sale. The Company also purchases natural gas, crude oil, condensate and NGLs from third parties, primarily near Anadarko’s production areas, to aggregate volumes, which in turn, better positions the Company to fully utilize transportation capacity, attract creditworthy customers, facilitate efforts to maximize prices received and minimize balancing issues with customers and pipelines during operational disruptions.

The Company sells natural gas under a variety of contracts including indexed, fixed-price and cost-escalation based agreements. The Company also engages in limited trading activities for the purpose of generating profits from exposure to changes in market prices of natural gas, crude oil, condensate and NGLs. The Company does not engage in market-making practices and limits its marketing activities to natural-gas, crude-oil and NGLs commodity contracts. The Company’s marketing risk position is typically a net short position (reflecting agreements to sell natural gas, crude oil and NGLs in the future for specific prices) that is offset by the Company’s natural long position as a producer (reflecting ownership of underlying natural-gas and crude-oil reserves). See Energy Price Risk under Item 7A of this Form 10-K.

Natural Gas    Natural gas continues to fulfill a significant portion of North America’s energy needs and the Company believes the importance of natural gas will continue. Anadarko markets its natural-gas production to maximize its value and to reduce the inherent risks of physical-commodity markets. Anadarko’s marketing segment offers supply-assurance and limited risk-management services at competitive prices, as well as other services that are tailored to its customers’ needs. The Company may also receive a service fee related to the level of reliability and service required by the customer.

The Company controls natural-gas firm transportation capacity that ensures access to downstream markets, which enables the Company to maximize its natural-gas production. This transportation capacity also provides the opportunity to capture incremental value when price differentials between physical locations exist. The Company also stores natural gas in contracted storage facilities to minimize operational disruptions to its ongoing operations and to take advantage of seasonal price differentials. Normally, the Company will have forward contracts in place (physical-delivery or financial derivative instruments) to sell stored natural gas at a fixed price.

 

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Crude Oil, Condensate and NGLs    Anadarko’s crude-oil, condensate and NGLs revenues are derived from production in the United States, Algeria, China and Ghana. Most of the Company’s United States crude-oil and NGLs production is sold under contracts with prices based on market indices, adjusted for location, quality and transportation. Oil from Algeria is sold by tanker as Saharan Blend to customers primarily in the Mediterranean area. Saharan Blend is high-quality crude that provides refiners large quantities of premium products such as gasoline, jet and diesel fuel. Oil from China is sold by tanker as Cao Fei Dian (CFD) Blend to customers primarily in the Far East markets. CFD Blend is a heavy sour crude oil which is sold into both the prime fuels refining market and the heavy fuel oil blend stock market. Oil from Ghana is sold by tanker as Jubilee Crude Oil to customers around the world. Jubilee Crude Oil is high-quality crude that provides refiners large quantities of premium products such as gasoline, jet and diesel fuel. The Company also purchases and sells third-party-produced crude oil, condensate and NGLs in the Company’s domestic and international market areas, as well as utilizes contracted NGLs storage facilities to capture market opportunities and to help minimize fractionation and downstream infrastructure disruptions.

CURRENT MARKET CONDITIONS AND COMPETITION

In 2008, most segments in the global economy experienced a sharp downturn. Markets improved in 2009 and 2010; however, significant economic uncertainty continues. This economic uncertainty, along with recent commodity price volatility, has made the creditworthiness, liquidity and financial position of the Company’s counterparties difficult to evaluate. For this reason, the Company has emphasized its monitoring of counterparty risk. Although Anadarko has not experienced any material financial losses associated with third-party credit deterioration, in certain situations the Company has declined to transact with some counterparties and has changed its sales terms to require some counterparties to pay in advance or post letters of credit for purchases.

The oil and gas business is highly competitive in the exploration for and acquisition of reserves and in the gathering and marketing of oil and gas production. The Company’s competitors include national oil companies, major oil and gas companies, independent oil and gas companies, individual producers, gas marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers.

SEGMENT INFORMATION

For additional information on operations by segment location, see Note 19—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

For additional information on risk associated with foreign operations, see Risk Factors under Item 1A of this Form 10-K.

EMPLOYEES

At December 31, 2010, the Company had approximately 4,400 employees. Anadarko considers its relations with its employees to be satisfactory. The Company’s employees are not represented by any union. The Company has had no work stoppages or strikes associated with its employees.

 

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REGULATORY MATTERS, ENVIRONMENTAL AND ADDITIONAL FACTORS AFFECTING BUSINESS

Environmental, Health and Safety Regulations

Anadarko’s business operations are subject to numerous international, federal, state and local environmental, health and safety laws and regulations pertaining to the release, emission or discharge of materials into the environment; the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes); the occupational health and safety of employees; or otherwise relating to the prevention, mitigation or remediation of pollution, or the preservation or protection of natural resources, wildlife or the environment. The more significant of these existing environmental, health and safety laws and regulations include the following United States laws and regulations, as amended from time to time:

 

   

The U.S. Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring and reporting requirements.

 

   

The U.S. Federal Water Pollution Control Act, also known as the federal Clean Water Act (CWA), which regulates discharges of pollutants from facilities to state and federal waters.

 

   

The U.S. Oil Pollution Act of 1990 (OPA), which subjects owners and operators of vessels, onshore facilities and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to strict liability for removal costs and damages arising from an oil spill in waters of the United States.

 

   

U.S. Department of the Interior regulations, which relate to offshore oil and natural-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.

 

   

The Comprehensive Environmental Response, Compensation and Liability Act of 1980, a remedial statute that imposes strict liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.

 

   

The U.S. Resource Conservation and Recovery Act, which governs the treatment, storage and disposal of solid wastes, including hazardous wastes.

 

   

The U.S. Federal Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources.

 

   

The U.S. Emergency Planning and Community Right-to-Know Act, which requires facilities to disseminate information on chemical inventories to employees as well as local emergency planning committees and response departments.

 

   

The U.S. Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances and appropriate control measures.

 

   

The National Environmental Policy Act, which requires federal agencies, including the DOI, to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment.

 

   

The Endangered Species Act, which restricts activities that may affect federally-identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas.

 

   

The Marine Mammal Protection Act, which ensures the protection of marine mammals through the prohibition, with certain exceptions, of the taking of marine mammals in U.S. waters and by U.S. citizens on the high seas and which may require the implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas.

 

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The Migratory Bird Treaty Act, which implements various treaties and conventions between the U.S. and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas.

These laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, the occurrence of delays in the development of projects, and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. Compliance with these laws and regulations also, in most cases, requires new or amended permits that may contain new or more stringent technological standards or limits on emissions, discharges, disposals or other releases in association with new or modified operations. Application for 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 public notice and comment periods required prior to the issuance or amendment of a permit as well as the agency’s processing of an application. Many of the delays associated with the permitting process are beyond the control of the Company.

Many states and foreign countries where the Company operates also have, or are developing, similar environmental laws, regulations or analogous controls governing many of these same types of activities. While the legal requirements may be similar in form, in some cases the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly alter or delay the development of a project or substantially increase the cost of doing business.

Anadarko is also subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations.

Federal and state occupational safety and health laws require the Company to organize information about materials, some of which may be hazardous or toxic, that are used, released or produced in Anadarko’s operations. Certain portions of this information must be provided to employees, state and local governmental authorities and responders, and local citizens. The Company is also subject to the safety hazard communication requirements and reporting obligations set forth in federal workplace standards.

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 and water quality standards, 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 the Company’s operations in the United States and in other countries in which Anadarko operates. Notable areas of potential impacts include air emission monitoring and compliance and mitigation and remediation obligations in the United States.

As a result of the Deepwater Horizon events, the Company has reviewed its potential responsibilities under both OPA and CWA. OPA imposes joint and several liability on the responsible parties for all cleanup and response costs, natural resource damages, and other damages such as lost revenues, damages to real or personal property, damages to subsistence users of natural resources, and lost profits and earning capacity. While OPA requires that a responsible party pay for all cleanup and response costs, it currently limits liability for damages to $75 million, exclusive of response and remediation expenses (for which there is no cap), except in cases of gross negligence, willful misconduct, or the violation of an applicable federal safety, construction, or operating regulation. The federal government may take legislative or other action to increase or eliminate, perhaps even retroactively, the liability cap. As for damages to natural resources, the government may recover damages for injury to, loss of, destruction of, or loss of use of natural resources which may include the costs to repair, replace or restore those or like resources. The CWA governs discharges into waters of the United States and provides for penalties in the event of unauthorized discharges into those waters. Under the CWA, these include, among other penalties, civil penalties that may be assessed in an amount up to $1,100 per barrel of oil discharged. In cases of gross negligence or willful misconduct, such civil penalties that may be sought by the United States Environmental Protection Agency are increased to not more than $4,300 per barrel of oil discharged.

 

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As of the date of filing this Form 10-K with the SEC, no penalties or fines have been assessed by the federal government against the Company under OPA, CWA, and other similar local, state and federal environmental legislation related to the Deepwater Horizon events. However, in December 2010 the Department of Justice (DOJ), on behalf of the federal agencies involved in the spill response, filed a civil lawsuit in the United States District Court for the Eastern District of Louisiana against several parties, including the Company, seeking (i) an assessment of civil penalties under the CWA in an amount to be determined by the court, and (ii) a declaratory judgment that such parties are jointly and severally liable without limitation under OPA for all removal costs and damages resulting from the Deepwater Horizon events. For additional information, see Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

The Company has made and will continue to make operating and capital expenditures, some of which may be material, to comply with environmental, health and safety laws and regulations. These are necessary business costs in the Company’s operations and in the oil and natural-gas industry. Although the Company is not fully insured against all environmental, health and safety risks, and the Company’s insurance does not cover any penalties or fines that may be issued by a governmental authority, it maintains insurance coverage that it believes is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental, health and safety laws and regulations, as well as claims for damages to property or persons, resulting from the Company’s operations, could result in substantial costs and liabilities, including administrative, civil and criminal penalties, to Anadarko. The Company believes that it is in material compliance with existing environmental, health and safety regulations. Further, the Company believes that the cost of maintaining compliance with these existing laws and regulations will not have a material adverse effect on its business, financial position or results of operations or cash flows, but new or more stringently applied or enforced existing laws and regulations could increase the cost of doing business, and such increases could be material.

Oil Spill-Response Plan

Domestically, the Company is required to comply with BOEMRE regulations, which currently require every owner or operator of a U.S. offshore lease to prepare and submit for approval an oil spill-response plan, prior to conducting any offshore operations. The submitted plan is required to provide a detailed description of actions to be taken in the event of a spill, identify contracted spill-response equipment, materials and trained personnel, and stipulate the time necessary to deploy identified resources in the event of a spill. The Company has filed the required information that describes the Company’s ability to deploy surface and subsea containment resources to adequately and promptly respond to a blowout or other loss of well control. BOEMRE regulations may be amended, resulting in changes to the amount and type of spill-response resources to which an owner or operator must maintain ready access. Accordingly, resources available to the Company may change in order to satisfy any new regulatory requirements, or to adapt to changes in the Company’s operations.

Currently, Anadarko has in place and maintains both Regional (Central and Western Gulf of Mexico) and Sub-Regional (Eastern Gulf of Mexico) Oil Spill-Response Plans (Plans) for the Company’s Gulf of Mexico operations, which detail procedures for rapid and effective response to spill events that may occur as a result of Anadarko’s operations. The Plans are reviewed at least annually and updated as necessary. Drills are conducted at least annually to test the effectiveness of the Plans and include the participation of spill-response contractors, representatives of Clean Gulf Associates (CGA, a not-for-profit association of production and pipeline companies operating in the Gulf of Mexico), and representatives of relevant governmental agencies. The Plans must be approved by the BOEMRE.

As part of the Company’s oil spill-response preparedness, and included in the Plans, Anadarko maintains membership in CGA, and has an employee representative on the executive committee of CGA. CGA was created to provide a means of effectively staging response equipment and to provide effective spill-response capability for its member companies operating in the Gulf of Mexico.

At December 31, 2010, CGA equipment includes one High Volume Open Sea Skimmer System (HOSS) barge, four 46-foot skimming vessels, three Marco skimmers, and two Egmopol skimmers. In addition, CGA equipment also consists of:

 

   

Nine Fast Response Units;

 

   

One rope mop;

 

   

Two Foilex skim packages;

 

   

Two 4-drum skimmers (Magnum 100);

 

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Two 2-drum skimmers (TDS 118);

 

   

Eleven sets of Koseq skimming arms;

 

   

Two Aqua Guard Triton RBS;

 

   

Four oil storage barges (249 barrels);

 

   

Nine tanks (100 barrels, primary); and

 

   

Eight tanks (100 barrels, secondary).

Auto boom, beach boom, and fire boom is currently available through CGA. CGA also has a stockpile of Corexit 9500 dispersant spray system through Airborne Support Inc. (ASI), a wildlife rehabilitation trailer, and bird scare guns. CGA currently has one X-band radar on order, and is expected to have a 56-foot skimming vessel available in the near future.

CGA coordinates bareboat charters with Marine Spill Response Corporation (MSRC). MSRC is responsible for inspecting, maintaining, storing and calling out CGA equipment. MSRC has positioned CGA’s equipment and materials in a ready state at various staging areas around the Gulf of Mexico. In the event of a spill, MSRC stands ready to mobilize all of its equipment and materials, including those from CGA. MSRC has a fleet of 15 dedicated Responder Class Oil Spill-Response Vessels (OSRVs), designed and built specifically to recover spilled oil. Each OSRV is approximately 210-feet long, has temporary storage for recovered oil, and has the ability to separate oil and water aboard the vessels using two oil-water separation systems. To enable the OSRV to sustain cleanup operations, recovered oil is transferred into other vessels or barges.

MSRC has equipment housed for the Atlantic Region, the Gulf of Mexico Region, the California Region, and the Pacific/Northwest Region. The Gulf of Mexico Region has a total of 42 skimmers with an Effective Daily Recovery Capacity (EDRC) of 221,051 barrels. At December 31, 2010, the following equipment is available through the various regions:

 

   

Fifteen Responder Class OSRVs;

 

   

Twenty-nine smaller OSRVs;

 

   

Five Fast Response Vessels;

 

   

Nineteen offshore barges;

 

   

Fifty-one shallow water barges (non self-propelled);

 

   

Seventeen shallow water barges (self-propelled);

 

   

Fifty-one shallow water push boats;

 

   

Seventy-one towable storage bladders;

 

   

Three towable storage barges (non self-propelled);

 

   

Twenty-one work boats;

 

   

Twenty-three fastanks (900 barrels);

 

   

Six mini towable storage bladders;

 

   

Twelve tanks/seabags;

 

   

Seven small skimming vessels;

 

   

Nine small barges;

 

   

Thirteen small boats;

 

   

One small Oil Spill-Response Barge;

 

   

Fifteen storage tanks/bladders;

 

   

199,975 feet of ocean boom;

 

   

103,159 gallons of Corexit 9500 dispersant; and

 

   

1,500 gallons of Corexit 9527 dispersant.

 

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MSRC has seven Mobile Communications Suites comprising telephone and computer connections, and UHF and VHF marine, aviation and business band radios. One C-130 dispersant aircraft and one King Air dispersant/spotter aircraft are also available for MSRC member use.

MSRC also handles the maintenance and mobilization of CGA non-marine equipment. MSRC has service contracts in place with domestic environmental contractors as well as with other companies that provide support services during the execution of spill-response activities. In the event of a spill, MSRC will activate these contracts as necessary to provide additional resources or support services requested by CGA. In addition, CGA maintains a service contract with ASI, which provides aircraft and dispersant capabilities for CGA member companies.

The Company also has in place a contract with the National Response Corporation (NRC), a service provider for emergency and crisis management response capabilities (including oil spills). NRC is included as a provider in the Company’s federally approved oil spill-response plans. NRC consists of a headquarters-based International Operations Center (IOC) in Great River, New York, with a team of operation, planning, logistics, finance, safety and administration support specialists. Equipment locations are staged in the Northeast, Southeast, South, Pacific Northwest, West, Caribbean and the Virgin Islands. In addition, NRC has an independent contractor’s network to further supplement NRC’s equipment and personnel.

NRC has an EDRC of 747,569 barrels and temporary storage of 18,444 barrels and an agreement with ASI to utilize ASI’s DC-3 dispersant spray aircraft. NRC is currently in the process of increasing the dispersant stockpile with Corexit 9500. At December 31, 2010, the following equipment is listed for the various locations:

 

   

107,200 feet of 18” and 42” Boom;

 

   

Sixty-six portable storage tanks with 8,334 barrels of storage;

 

   

Forty-six skimmers with an EDRC of 295,896 barrels and 24 barrels of storage; and

 

   

Eight vacuum systems with an EDRC of 48,342 barrels and 180 barrels of storage.

Internationally, Anadarko has in place emergency and oil spill-response plans for each of its exploration and operational activities around the globe. Each plan satisfies the requirements of the relevant local or national authority, describes the actions the Company will take in the event of an incident, is subject to drills at least annually and includes reference to external resources that may become necessary in the event of an incident. Included in these external resources is the Company’s contract with Oil Spill Response Limited (OSR), a global emergency and oil spill-response organization headquartered in London. OSR maintains specialized equipment in a ready state for deployment in the event such equipment is needed by one of its members. OSR is mainly available for response internationally, but their equipment is registered with the United States Coast Guard for domestic use if needed.

Two Hercules aircraft are available for dispersant application or equipment transport, located in the United Kingdom and Singapore. The aircraft have a three-hour callback time. The Hercules can transport two to three pre-packaged equipment loads, or one Aerial Dispersant Delivery System (ADDS) Pack. OSR has 3 ADDS Packs–one in the United Kingdom, one in Bahrain, and one in Singapore. If additional aircraft are needed, OSR retains an aircraft broker so that an aircraft can be charted. For international operations, the majority of equipment will be air freighted. Fast response trailers are available, if within the United Kingdom.

OSR has a number of active recovery boom systems, and a range of booms that can be used for offshore, nearshore, or shoreline responses. Offshore boom is stored in reels of 656.167 feet (200 meters) and located in the United Kingdom, Bahrain, and Singapore. Fireboom systems are currently on order. A variety of nearshore boom exists for spill containment.

Additionally OSR can provide a range of communications equipment, safety equipment, transfer pumps, dispersant application systems, temporary storage equipment, power packs and generators, small inflatable vessels, rigid inflatable boats, work boats, and Fast Response Vessels. Oleophilic, weir and mechanical skimmers provide the ability to recover a range of oil types. OSR also has a wide range of oiled wildlife equipment in conjunction with the Sea Alarm Foundation.

The Company has also entered into contractual commitments to access subsea intervention, containment, capture and shut-in capacity (Containment) for deepwater exploration wells. CGA has contracted with Helix Energy Solutions Group, on behalf of its membership, for the provision of these Containment assets, which will initially provide processing capacity of 45,000 Bbls/d of oil, 60,000 Bbls/d of liquids, and flaring of 80 MMcf/d of natural gas from the vessel HP-1, and burning 10,000 Bbls/d of oil from the vessel Q4000. The system, known as the Helix Fast Response System, currently operates at up to 8,000-feet of sea water depth, and is rated at a 10,000 psi shut-in capability. Member operators are considering various capacity expansion options.

 

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In addition to Anadarko’s membership in CGA, NRC and OSR, and in light of the Deepwater Horizon events in the Gulf of Mexico, the Company is participating in industry-wide task forces, which are currently studying improvements in both gaining access to and controlling blowouts in subsea environments. Two such task forces are the Subsea Well Control and Containment Task Force and the Oil Spill Task Force.

TITLE TO PROPERTIES

As is customary in the oil and gas industry, only a preliminary title review is conducted at the time properties believed to be suitable for drilling operations are acquired by the Company. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted and curative work is performed with respect to significant defects, if any, before proceeding with operations. Anadarko believes the title to its leasehold properties is good and defensible and is customary with practices in the oil and gas industry, subject to such exceptions that, in the opinion of legal counsel for the Company, are not so material as to detract substantially from the use of such properties.

The leasehold properties owned by the Company are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties may be subject to burdens such as liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions. Anadarko does not believe any of these burdens will materially interfere with its use of these properties.

EXECUTIVE OFFICERS OF THE REGISTRANT

 

Name

     

Age at End
of 2011

     

Position

James T. Hackett

    57     Chairman of the Board and Chief Executive Officer

R. A. Walker

    54     President and Chief Operating Officer

Robert P. Daniels

    52     Senior Vice President, Worldwide Exploration

Robert G. Gwin

    48     Senior Vice President, Finance and Chief Financial Officer

Charles A. Meloy

    51     Senior Vice President, Worldwide Operations

Robert K. Reeves

    54     Senior Vice President, General Counsel and Chief Administrative Officer

M. Cathy Douglas

    55     Vice President and Chief Accounting Officer

Mr. Hackett was named Chief Executive Officer in December 2003 and assumed the additional role of Chairman of the Board in January 2006. He also served as President from December 2003 to February 2010. Prior to joining Anadarko, he served as President and Chief Operating Officer of Devon Energy Corporation following its merger with Ocean Energy, Inc. in April 2003. Mr. Hackett served as President and Chief Executive Officer of Ocean Energy, Inc. from March 1999 to April 2003 and as Chairman of the Board from January 2000 to April 2003. He currently serves as a director of Fluor Corporation, Halliburton Company and The Welch Foundation.

Mr. Walker was named Chief Operating Officer in March 2009 and assumed the additional role of President in February 2010. He previously served as Senior Vice President, Finance and Chief Financial Officer from September 2005 until his appointment as Chief Operating Officer. Prior to joining Anadarko, he served as Managing Director for the Global Energy Group of UBS Investment Bank from 2003 to 2005. He has served as a director of Temple-Inland, Inc. since November 2008 and as a director of CenterPoint Energy, Inc. since April 2010. Since August 2007, he has also served as director of Western Gas Holdings, LLC, the general partner of WES, and served as the general partner’s Chairman of the Board from August 2007 to September 2009.

Mr. Daniels was named Senior Vice President, Worldwide Exploration in December 2006. Prior to this position, he served as Senior Vice President, Exploration and Production since May 2004 and prior to that position, he served as Vice President, Canada since July 2001. Mr. Daniels also served in various managerial roles in the Exploration Department for Anadarko Algeria Company, LLC. He has worked for the Company since 1985.

 

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Mr. Gwin was named Senior Vice President, Finance and Chief Financial Officer in March 2009 and had previously served as Senior Vice President since March 2008. He also has served as Chairman of the Board of Western Gas Holdings, LLC since October 2009 and as a director since August 2007. Mr. Gwin also served as President of Western Gas Holdings, LLC from August 2007 to September 2009 and as Chief Executive Officer of Western Gas Holdings, LLC from August 2007 to January 2010. He joined Anadarko in January 2006 as Vice President, Finance and Treasurer. Prior to joining Anadarko, he served as President and CEO of Prosoft Learning Corporation from November 2002 to November 2004 and as Chairman from November 2002 to February 2006, and prior to that served as its Chief Financial Officer from August 2000 to November 2002. Previously, Mr. Gwin spent 10 years at Prudential Capital Group in merchant banking roles of increasing responsibility, including serving as Managing Director with responsibility for the firm’s energy investments worldwide.

Mr. Meloy was named Senior Vice President, Worldwide Operations in December 2006 and had served as Senior Vice President, Gulf of Mexico and International Operations since the acquisition of Kerr-McGee in August 2006. Prior to joining Anadarko, he served Kerr-McGee as Vice President of Exploration and Production from 2005 to 2006, Vice President of Gulf of Mexico Exploration, Production and Development from 2004 to 2005, Vice President and Managing Director of Kerr-McGee North Sea (U.K.) Limited from 2002 to 2004 and Vice President of Gulf of Mexico Deep Water from 2000 to 2002. Mr. Meloy has also served as a director of Western Gas Holdings, LLC since February 2009.

Mr. Reeves was named Senior Vice President, General Counsel and Chief Administrative Officer in February 2007 and served as Corporate Secretary from February 2007 to August 2008. He had previously served as Senior Vice President, Corporate Affairs & Law and Chief Governance Officer since 2004. Prior to joining Anadarko, he served as Executive Vice President, Administration and General Counsel of North Sea New Ventures from 2003 to 2004, and as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003. He has also served as a director of Key Energy Services, Inc., a publicly traded oilfield services company, since October 2007, and as a director of Western Gas Holdings, LLC since August 2007.

Ms. Douglas was named Vice President and Chief Accounting Officer in November 2008 and had served as Corporate Controller from September 2007 to March 2009. She served as Assistant Controller from July 2006 to September 2007. Ms. Douglas also served as Director, Accounting, Policy and Coordination from October 2006 to September 2007 and Financial Reporting and Policy Manager from January 2003 to October 2006. She joined Anadarko in 1979.

Officers of Anadarko are elected at an organizational meeting of the Board of Directors following the annual meeting of stockholders, which is expected to occur on May 17, 2011, and hold office until their successors are duly elected and shall have qualified. There are no family relationships between any directors or executive officers of Anadarko.

 

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Item 1A. Risk Factors

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:

 

   

the Company’s assumptions about the energy market;

 

   

production levels;

 

   

reserve levels;

 

   

operating results;

 

   

competitive conditions;

 

   

technology;

 

   

the availability of capital resources, capital expenditures and other contractual obligations;

 

   

the supply and demand for and the price of natural gas, oil, natural gas liquids (NGLs) and other products or services;

 

   

volatility in the commodity-futures market;

 

   

the weather;

 

   

inflation;

 

   

the availability of goods and services;

 

   

drilling risks;

 

   

future processing volumes and pipeline throughput;

 

   

general economic conditions, either internationally or nationally or in the jurisdictions in which the Company or its subsidiaries are doing business;

 

   

legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, deepwater drilling and permitting regulations, derivatives reform, changes in state, federal and foreign income taxes, environmental regulation, environmental risks and liability under federal, state, foreign and local environmental laws and regulations;

 

   

the outcome of events in the Gulf of Mexico related to the Deepwater Horizon events;

 

   

the success of BP Exploration & Production Inc.’s (BP) cleanup efforts related to the Deepwater Horizon events;

 

   

current and potential legal proceedings, and environmental or other obligations arising from the Deepwater Horizon events, the Oil Pollution Act of 1990 (OPA) and other regulatory obligations, and the operating agreement (OA) for the Macondo well;

 

   

the legislative and regulatory changes that may impact the Company’s Gulf of Mexico and international offshore operations resulting from the Deepwater Horizon events;

 

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the Company’s ability to resume drilling operations in the Gulf of Mexico;

 

   

current and potential legal proceedings, environmental or other obligations related to or arising from Tronox Incorporated (Tronox);

 

   

the creditworthiness of the Company’s counterparties, including financial institutions, operating partners and other parties;

 

   

the securities, capital or credit markets;

 

   

the Company’s ability to repay its debt;

 

   

the impact of downgrades to the Company’s credit rating, including the ability of the Company to access capital and remain liquid;

 

   

the outcome of any proceedings related to the Algerian exceptional profits tax; and

 

   

other factors discussed below and elsewhere in this Form 10-K and in the Company’s other public filings, press releases and discussions with Company management.

We may be subject to claims and liability as a result of being a co-lessee of the Mississippi Canyon Block 252 lease and our ownership of a 25% non-operating leasehold interest in the Macondo exploration well in the Gulf of Mexico, which suffered a blowout and drilling rig explosion in April 2010, resulting in loss of life and a significant oil spill.

In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating leasehold interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. Response and cleanup efforts are being conducted by BP, the operator and 65% owner of the Macondo lease, and by other parties, all under the direction of the Unified Command of the United States Coast Guard (the USCG).

On July 15, 2010, after several attempts to contain the oil spill, BP successfully installed a capping stack that shut in the well and prevented the further release of hydrocarbons. Installation of the capping stack was a temporary solution that was followed by a successful “static kill” cementing operation completed on August 5, 2010. The Macondo well was permanently plugged on September 19, 2010, when BP completed a “bottom kill” cementing operation in connection with the successful interception of the well by a relief well. Investigations by the federal government and other parties into the cause of the well blowout, explosion, and resulting oil spill, as well as other matters arising from or relating to these events, are ongoing.

Based on information provided by BP to the Company, BP has incurred costs of approximately $16.5 billion (including costs associated with USCG invoices totaling $606 million) through December 31, 2010, related to spill response and containment, relief-well drilling, grants to certain Gulf Coast states for cleanup costs, local tourism promotion, monetary damage claims and federal costs. In addition, BP has incurred more than $1.4 billion of costs since December 31, 2010.

BP has sought reimbursement from Anadarko for amounts BP has paid or committed to pay for spill-response efforts, grants, damage claims and costs incurred by the federal government through provisions of the OA, which is the contract governing the relationship between BP and the non-operating OA parties to the Mississippi Canyon Block 252 lease in which the Macondo well is located (Lease). Contractual language in the OA, which governs the relationship among the operator and the two non-operating parties, generally provides that BP, as operator, is entitled to reimbursement of certain costs and expenses from the other working interest owners in proportion to their ownership interest in the well. With respect to the operator’s duties and liabilities, the OA provides that BP, as operator, owes duties to the non-operating parties (including Anadarko) to perform the drilling of the well in a good and workmanlike manner and to comply with all applicable laws and regulations. The OA dictates that liability for losses, damages, costs, expenses, or claims involving activities or operations shall be borne by each party in proportion to its participating interest, except that when liability results from the gross negligence or willful misconduct of a party, that party shall be solely responsible for liability resulting from its gross negligence or willful misconduct.

BP has invoiced the Company an aggregate $4.0 billion for what BP considers to be Anadarko’s 25% proportionate share of actual costs through December 31, 2010. In addition, BP has invoiced Anadarko for anticipated near-term future costs related to the Deepwater Horizon events. Anadarko has withheld reimbursement to BP for

Deepwater Horizon event-related invoices pending the completion of various ongoing investigations into the cause of

 

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the well blowout, explosion, and subsequent release of hydrocarbons. Final determination of the root causes of the Deepwater Horizon events could materially impact the Company’s potential obligations under the OA. To the extent that we are ultimately determined to be responsible for our allocable share of the operator’s costs under the OA, we expect our costs to be significantly in excess of the coverage limits under our insurance program.

BP, Anadarko and other parties, including parties that do not own an interest in the Lease, such as the drilling contractor, have received correspondence from the USCG referencing their identification as a “responsible party or guarantor” (RP) under OPA, and the United States Department of Justice (DOJ) has also filed a civil lawsuit against such parties to, among other things, confirm each party’s identified RP status. Under OPA, RPs may be held jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims directly related to the spill and spill cleanup. The USCG has directly invoiced the identified RPs for reimbursement of spill-related response costs incurred by the USCG and other federal and state agencies. The identified RPs each received identical invoices for total costs, without specification or stipulation of any allocation of costs between or among the identified RPs. As a 25% non-operating leasehold interest owner in the Lease, and an identified RP under OPA, we may incur liability under currently existing environmental laws and regulations and we may be asked to contribute to the significant and ongoing response and remediation expenses.

To date, as operator, BP has paid all USCG invoices as well as other costs and has sought reimbursement from Anadarko for a 25% portion of these costs through the OA. To the extent that BP discontinues payment or is otherwise unable to satisfy its obligations under OPA for any reason, we would be exposed to additional liability for spill-response and remediation expenses. We have similar exposure relative to the other identified RPs where the failure on the part of any other such identified RPs to satisfy their OPA obligations would expose us to potential liability.

As more facts become known, it is reasonably possible that the Company may be required to recognize a liability related to the Deepwater Horizon events, and that liability could be material to the Company’s consolidated financial position, results of operations or cash flows. For example, new information arising out of the legal-discovery process could alter the legal assessment as to the likelihood of the Company incurring a liability related to its existing OA contingent obligations. Moreover, if BP discontinues payment or is otherwise unable to satisfy its obligations, the Company could be required to recognize an OPA-related environmental liability. Similarly, if other identified RPs do not satisfy their obligations under OPA, the Company could incur additional liability. In addition, while OPA contains a $75 million cap for certain costs and damages, exclusive of response and remediation expenses (for which there is no cap), the federal government may take legislative or other action to increase or eliminate the cap, perhaps even retroactively.

As part of its pledge to pay all legitimate claims related to the Deepwater Horizon events, BP announced in June 2010 that it had agreed to contribute $20 billion into an escrow fund over a four-year period to support an independent claims facility, the purpose of which is, according to BP, “to satisfy legitimate claims including natural resource damages and state and local response costs” resulting from the Deepwater Horizon events, with fines and penalties to be excluded from the fund and paid separately. As claims are paid out of this escrow fund, we may be asked to contribute to the payment of such claims pursuant to the OA.

As described above, we are continuing to evaluate our contractual rights and obligations under the OA. If the parties are unable to reach an agreement on liability, one of the possible outcomes is to pursue arbitration under the OA. In any arbitration, the weight to be given to evidence would be determined by the arbitrators. The Company cannot guarantee the success of any such arbitration proceeding.

While we will seek any and all protections available to us pursuant to the OA or otherwise as well as our insurance coverage, an adverse resolution of our contractual rights and responsibilities to BP under the OA or the failure of BP and other identified RPs to satisfy their obligations under OPA could subject us to significant monetary damages and other penalties, such as penalties under the Clean Water Act (CWA), which could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

For all of these reasons or if we were to suffer the other effects described in this risk factor and the following risk factors, our actual liabilities relating to the Deepwater Horizon events could exceed our estimates, and we could incur additional liabilities that we are unable to reasonably estimate at this time, and these events could have a material adverse effect on our financial position, results of operations or cash flows, growth and prospects, including, without limitation, our ability to obtain debt, equity or other financing on acceptable terms, or at all. In addition, the new $5.0 billion senior secured revolving credit facility, which we entered into in September 2010, contains covenants limiting our ability to incur additional debt or pledge additional assets, subject to exceptions. These limitations could adversely affect our ability to obtain additional financing for any future liabilities that may arise in connection with the Deepwater Horizon events.

 

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We have been named as a defendant in various litigation matters as a result of the Deepwater Horizon events. The outcome of existing and future claims could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

Numerous civil lawsuits have been filed against BP and other parties, including the Company, by fishing, boating and shrimping industry groups; restaurants; commercial and residential property owners; certain rig workers or their families; the State of Alabama and several of its political subdivisions; the DOJ; environmental non-governmental organizations; the Plaquemines Parish School Board, a political subdivision of the State of Louisiana; and certain Mexican states. Many of the lawsuits filed assert various claims of negligence, gross negligence and violations of several federal and state laws and regulations, including, among others, OPA; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Air Act; the CWA; and the Endangered Species Act; or challenge existing permits for operations in the Gulf of Mexico. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment and/or injunctive relief.

In August 2010, the United States Judicial Panel on Multidistrict Litigation created Multidistrict Litigation No. 2179 (MDL) to administer essentially all litigation filed in federal court involving Deepwater Horizon event-related claims. Federal Judge Carl Barbier presides over this MDL in the United States District Court for the Eastern District of Louisiana in New Orleans, Louisiana. The court issued a number of case management orders that establish a schedule for procedural matters, discovery and trial of the MDL cases. The court set for trial beginning in June 2011, one or more cases brought against BP as an RP under OPA, to serve as test cases for causation and damage issues. The court has not yet selected the specific OPA test cases to be tried. Also, the court scheduled a February 2012 trial to determine the liability issues and allocable liability among the parties involved in the Deepwater Horizon events. The parties to the MDL are actively engaged in discovery.

On December 15, 2010, the DOJ, on behalf of the federal agencies involved in the spill response, filed a civil lawsuit in the United States District Court for the Eastern District of Louisiana against several parties, including the Company, seeking (i) an assessment of civil penalties under the CWA in an amount to be determined by the Court, and (ii) a declaratory judgment that such parties are jointly and severally liable without limitation under OPA for all removal costs and damages resulting from the Deepwater Horizon events. In the lawsuit, the DOJ states that civil penalties under the CWA may be assessed in an amount up to $1,100 per barrel of oil discharged or in cases involving gross negligence or willful misconduct in an amount up to $4,300 per barrel of oil discharged.

Lawsuits seeking to place limitations on the oil and gas industry’s operations in the Gulf of Mexico, including those of the Company, have also been filed outside of the MDL by non-governmental organizations against various governmental agencies. These cases are filed in the United States District Court for the Southern District of Alabama, the Eastern District of Louisiana, and the District of Columbia and in the United States Court of Appeals for the Fifth Circuit.

Two separate class action complaints were filed in June and August 2010 in the United States District Court for the Southern District of New York on behalf of purported purchasers of the Company’s stock between June 12, 2009, and June 9, 2010, against Anadarko and certain of its officers. The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In November 2010, the District Court for the Southern District of New York consolidated the two cases and appointed The Pension Trust Fund for Operating Engineers and Employees’ Retirement System of the Government of the Virgin Islands (the Virgin Islands Group) to act as Lead Plaintiff. In January 2011, the Lead Plaintiff filed its Consolidated Amended Complaint. Prior to filing its Consolidated Amended Complaint, the Lead Plaintiff requested leave from the court to transfer this lawsuit to the United States District Court for the Southern District of Texas. The Company opposes the Lead Plaintiff’s request to transfer the case to the District Court for the Southern District of Texas. The court has ordered the parties to brief the transfer of venue issue.

Also in June 2010, a shareholder derivative petition was filed in the 157th Judicial District Court of Harris County, Texas, by a shareholder of the Company against Anadarko (as a nominal defendant) and certain of its officers and current and certain former directors. The petition alleges breaches of fiduciary duties, unjust enrichment, and waste of corporate assets in connection with the Deepwater Horizon events. The plaintiffs seek certain changes to the Company’s governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs. In November 2010, the court granted Anadarko’s Motion to Dismiss for Lack of Jurisdiction and Special

 

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Exceptions and granted the plaintiffs 120 days to file an Amended Petition. In September 2010, a purported shareholder made a demand on the Company’s Board of Directors (the Board) to investigate allegations of breaches of duty by members of management. The Board duly considered the demand and in January 2011 determined that it would not be in the best interest of the Company to pursue the issues in the demand letter.

Additional proceedings related to the Deepwater Horizon events may be filed against Anadarko. These proceedings may involve civil claims for damages or governmental investigative, regulatory or enforcement actions. The adverse resolution of any proceedings related to the Deepwater Horizon events could subject us to significant monetary damages, fines and other penalties, which could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

The additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration and oil spill-response plans, and other related developments resulting from the recently lifted deepwater drilling moratoria in the Gulf of Mexico may have a material adverse effect on our business, financial condition or results of operations.

In May and July 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), previously known as the Minerals Management Service, an agency of the Department of the Interior (DOI), issued directives requiring lessees and operators of federal oil and gas leases in the Outer Continental Shelf regions of the Gulf of Mexico and Pacific Ocean to cease drilling all new deepwater wells, including wellbore sidetracks and bypasses, through November 30, 2010. These deepwater drilling moratoria (collectively, the Moratorium) prohibited drilling and/or spudding any new wells, and required operators that were in the process of drilling wells to proceed to the next safe opportunity to secure such wells, and to take all necessary steps to cease operations and temporarily abandon the impacted wells. Anadarko ceased all drilling operations in the Gulf of Mexico in accordance with the Moratorium, which resulted in the suspension of operations of two operated deepwater wells (Lucius and Nansen) and one non-operated deepwater well (Vito). The Moratorium was lifted effective October 12, 2010, but the Company is not currently permitted to resume drilling operations in the Gulf of Mexico due to delays in the processing and approval by the BOEMRE of drilling permits and exploration and oil spill-response plans.

The Moratorium did not apply to workovers, completions, plugging and abandonment or production activities; however, in order to continue such activities, the Company is required to comply with additional safety inspection and certification requirements that were set forth in two Notices to Lessees and Operators (NTL) issued by the BOEMRE in June 2010.

On June 8, 2010, the BOEMRE issued an NTL implementing certain safety measures recommended by the Secretary of the Interior in a 30-day safety report to the President of the United States. This NTL requires additional inspections to be conducted and safety measures to be implemented prior to conducting any floating drilling operations with a subsea blowout preventer (BOP) system or surface BOP system, including workovers, completions, and plugging and abandonment operations. On June 18, 2010, the BOEMRE issued another NTL requiring additional information from operators regarding existing and future Exploration Plans, Development and Production Plans and Development and Coordination Documents, all of which may have a significant impact on the timing of and ability to execute exploration and development operations across the Gulf of Mexico.

In particular, on October 14, 2010, the DOI published in the Federal Register an interim final drilling safety rule, effective immediately, enacting into law the June 8, 2010 NTL. The 60-day public comment period closed on December 13, 2010. The rule will become final, either in its current form, or as may be modified by the DOI based on comments received. On October 15, 2010, the DOI published in the Federal Register a final rule requiring operators to develop and implement Safety and Environmental Management Systems (SEMS) for all Gulf of Mexico operations. Effective November 8, 2010, the BOEMRE issued an NTL requiring that every application for a well permit to conduct operations using a subsea blowout preventer (BOP) or surface BOP on a floating facility must be accompanied by information sufficient to demonstrate access to subsea containment resources together with a statement of compliance by an authorized company official covering numerous regulations. Currently, the BOEMRE is evaluating the application of categorical exclusions under the National Environmental Policy Act taking into consideration comments requested in October 2010. In the meantime, the BOEMRE has announced a policy that will require site-specific environmental assessments, as opposed to the categorical exclusion reviews, which could result in further delays in the processing and approval of drilling permits and exploration plans.

On January 11, 2011, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, established by the President of the United States, released its Final Report, entitled “Deep Water: The Gulf Oil Disaster

 

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and the Future of Offshore Drilling,” detailing its findings with respect to the investigation of the Deepwater Horizon events and setting forth recommendations for changes in safety and environmental regulations and laws governing operations in the Gulf of Mexico. As a result, the federal government may issue further safety and environmental laws and regulations regarding operations in the Gulf of Mexico. These additional rules and regulations, delays in the processing and approval of drilling permits and exploration and oil spill-response plans, and possible additional actions could adversely affect and further delay new drilling and ongoing development efforts in the Gulf of Mexico. Among other adverse impacts, these additional measures could delay or disrupt our operations, result in increased costs and limit activities in certain areas of the Gulf of Mexico. We cannot predict with any certainty the full impact of any new laws or regulations, or when we would be able to resume any drilling operations in the Gulf of Mexico.

As a result of the Moratorium and additional inspection and safety requirements issued by the BOEMRE, in May and June 2010, the Company provided notification of force majeure to drilling contractors of four of the Company’s contracted deepwater rigs in the Gulf of Mexico. Some of the contracts have provisions that authorize contract termination by either party if force majeure conditions continue for a specified number of consecutive days.

In June 2010, the Company gave written notice of termination to the drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit in the United States District Court for the Southern District of Houston against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on June 19, 2010. The drilling contractor filed an Original Answer in July 2010 denying the Moratorium constituted a force majeure event and asserted that Anadarko had breached the drilling contract. If the Company does not prevail in its claim, it could be obligated to pay the rig contract rate from the contract-termination date through March 2011, the end of the original contract term. The disputed rentals for that period could result in approximately $90 million of cost.

In September 2010, the Company gave written notice of termination to another drilling contractor of a rig that had been placed in force majeure, and the Company filed a lawsuit in the United States District Court for the Southern District of Houston against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on September 18, 2010. The drilling contractor filed a Motion to Dismiss and an Original Answer in October 2010. The court, acting on its discretion, converted the Motion to Dismiss into a Motion for Summary Judgment and entered a scheduling order for submission of briefs during February and March 2011. If the Company does not succeed in its claim, it could be obligated to pay the rig contract rate from the contract-termination date through March 2013, the end of the original contract term. The disputed rentals for that period could result in approximately $377 million of cost.

In September 2010, the BOEMRE issued an NTL that requires lessees to plug all wells that have been idle for the past five years and decommission related equipment. Lessees were required to submit a company-wide plan for decommissioning facilities and wells. Anadarko completed this plan and does not believe the costs to implement the plan will have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Other governments may also adopt safety, environmental or other laws and regulations that would adversely impact our offshore developments in other areas of the world, including offshore Brazil, New Zealand, West Africa, Mozambique and Southeast Asia. Additional United States or foreign government laws or regulations would likely increase the costs associated with the offshore operations of our drilling contractors. As a result, our drilling contractors may seek to pass increased operating costs to us through higher day-rate charges or through cost escalation provisions in existing contracts.

In addition to increased governmental regulation, we currently expect that insurance costs will increase across the energy industry and certain insurance coverage may be subject to reduced availability or not available on economically reasonable terms, if at all. In particular, the events in the Gulf of Mexico relating to the Macondo well may make it increasingly difficult to obtain offshore property damage, well control and similar insurance coverage. The potential increased costs and risks associated with offshore development may also result in certain current participants allocating resources away from offshore development and discourage potential new participants from undertaking offshore development activities. Accordingly, we may encounter increased difficulty identifying suitable partners willing to participate in our offshore drilling projects and prospects.

Further, as the deepwater Gulf of Mexico (as well as international deepwater locations) lacks the extent of physical and oilfield service infrastructure present in shallower waters, it may be difficult for us to quickly or effectively execute any contingency plans related to future events similar to the Macondo well oil spill.

The matters described above, individually or in the aggregate, could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

 

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We are, and in the future may become, involved in legal proceedings related to Tronox and, as a result, may incur substantial costs in connection with those proceedings.

Prior to its acquisition by Anadarko, Kerr-McGee Corporation (Kerr-McGee), through an initial public offering and spin-off transaction, disposed of its chemical business. A new publicly traded corporation, Tronox, resulted from this transaction. After the Tronox initial public offering and spin-off, Kerr-McGee was acquired by a wholly owned subsidiary of Anadarko and, as a result, became a wholly owned subsidiary of Anadarko. Under the terms of the Master Separation Agreement (together with all annexes, related agreements, and ancillary agreements to it, the MSA), which was entered into in connection with the Tronox initial public offering, Kerr-McGee agreed to reimburse Tronox for certain qualifying environmental-remediation costs associated with those businesses, subject to certain limitations and conditions. The reimbursement obligation under the MSA was limited to a maximum aggregate reimbursement amount of $100 million. As described below, Tronox has rejected the MSA in its Chapter 11 cases and therefore Kerr-McGee is no longer obligated to reimburse to Tronox under the terms of the agreement. In addition, Tronox and certain third parties have claimed that Kerr-McGee and Anadarko have liability for costs allegedly attributable to the facilities and operations owned by Tronox and for Kerr-McGee’s activities prior to the date a subsidiary of Anadarko acquired Kerr-McGee.

In January 2009, Tronox and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (the Court). Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance (the Adversary Proceeding). Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee. Tronox seeks, among other things, to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko as well as the litigation fees and costs. In addition, Tronox seeks to equitably subordinate and/or disallow all claims asserted by Anadarko and Kerr-McGee in the bankruptcy cases.

The United States filed a motion to intervene in the Adversary Proceeding, asserting that it has an independent cause of action against Anadarko, Kerr-McGee and Tronox under the Federal Debt Collection Procedures Act relating primarily to environmental cleanup obligations allegedly owed to the United States by Tronox. That motion to intervene has been granted, and the United States is now a co-plaintiff against Anadarko and Kerr-McGee in the Adversary Proceeding. Anadarko and Kerr-McGee have moved to dismiss the United States’ complaint-in-intervention, but that motion currently has been stayed by order of the Court.

In addition, a consolidated class action complaint has been filed in the United States District Court for the Southern District of New York (the District Court) on behalf of purported purchasers of Tronox’s equity and debt securities between November 21, 2005, and January 12, 2009 (the Class Period), against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors and Ernst & Young LLP. The complaint alleges causes of action arising under the Securities Exchange Act of 1934 (the Exchange Act) for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort claim liabilities. The plaintiffs allege, among other things, that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including filings made in connection with Tronox’s initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. Anadarko, Kerr-McGee and other defendants moved to dismiss the class action complaint and in June 2010, the District Court issued an opinion and order dismissing the plaintiffs’ complaint against Anadarko, but granted the plaintiffs leave to replead their allegations related to the claim that Anadarko was liable as a successor-in-interest to Kerr-McGee. The District Court further granted in part and denied in part the motions to dismiss by Kerr-McGee and certain of its former officers and directors, but permitted the plaintiffs leave to replead certain of the dismissed claims. The plaintiffs’ filed an amended consolidated class action complaint in July 2010. In August 2010, Anadarko moved to dismiss the plaintiffs’ amended complaint in whole and Kerr-McGee moved to dismiss the plaintiffs’ allegations against it in part. In January 2011, the District Court issued an opinion and order granting Anadarko’s motion in part and denying Kerr-McGee’s motion in its entirety. The discovery process is ongoing.

In June 2010, Anadarko and Kerr-McGee filed a motion in Tronox’s Chapter 11 cases to compel Tronox to assume or reject the MSA. In response to this motion Tronox announced to the Court that it would reject the MSA effective July 22, 2010. In August 2010, the Court entered a Stipulation and Agreed Order among Tronox, Anadarko, and Kerr-McGee authorizing the rejection of the MSA. Following Tronox’s rejection of the MSA, Anadarko and Kerr-McGee filed amended proofs of claim (the Proofs of Claim), which include claims for damages arising from such rejection of the MSA. Tronox and several of its creditors objected to the Proofs of Claim. At the end of January 2011, the Court

 

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entered a Stipulation and Agreed Order regarding a settlement of the claims by Anadarko and Kerr-McGee against Tronox resulting from its rejection of the MSA. In February 2011, the Company received its agreed-upon claim, in the form of Tronox equity, valued at $29 million.

An adverse resolution of any proceedings related to Tronox could subject us to significant monetary damages and other penalties, which could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

For additional information regarding the nature and status of these and other material legal proceedings, see Legal Proceedings under Item 3 of this Form 10-K.

Oil, natural-gas and NGLs prices are volatile. A substantial or extended decline in prices could adversely affect our financial condition and results of operations.

Prices for oil, natural gas and NGLs can fluctuate widely. Our revenues, operating results and future growth rates are highly dependent on the prices we receive for our oil, natural gas and NGLs. Historically, the markets for oil, natural gas and NGLs have been volatile and may continue to be volatile in the future. For example, in recent years market prices for natural gas in the United States have declined substantially from the highs achieved in 2008 and the rapid development of shale plays throughout North America has contributed significantly to this trend. Factors influencing the prices of oil, natural gas and NGLs are beyond our control. These factors include, among others:

 

   

domestic and worldwide supply of, and demand for, oil, natural gas and NGLs;

 

   

volatile trading patterns in the commodity-futures markets;

 

   

the cost of exploring for, developing, producing, transporting and marketing oil, natural gas and NGLs;

 

   

weather conditions;

 

   

the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other producing nations to agree to and maintain production levels;

 

   

the worldwide military and political environment, civil and political unrest in Africa and the Middle East, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities or further acts of terrorism in the United States, or elsewhere;

 

   

the effect of worldwide energy conservation efforts;

 

   

the price and availability of alternative and competing fuels;

 

   

the price and level of foreign imports of oil, natural gas and NGLs;

 

   

domestic and foreign governmental regulations and taxes;

 

   

the proximity to, and capacity of, natural-gas pipelines and other transportation facilities; and

 

   

general economic conditions worldwide.

The long-term effect of these and other factors on the prices of oil, natural gas and NGLs are uncertain. Prolonged or substantial declines in these commodity prices may have the following effects on our business:

 

   

adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;

 

   

reducing the amount of oil, natural gas and NGLs that we can produce economically;

 

   

causing us to delay or postpone some of our capital projects;

 

   

reducing our revenues, operating income or cash flows;

 

   

reducing the amounts of our estimated proved oil and natural-gas reserves;

 

   

reducing the carrying value of our oil and natural-gas properties;

 

   

reducing the standardized measure of discounted future net cash flows relating to oil and natural-gas reserves; and

 

   

limiting our access to sources of capital, such as equity and long-term debt.

 

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Our domestic operations are subject to governmental risks that may impact our operations.

Our domestic operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, regional, state, tribal, local and other laws and regulations such as restrictions on production, permitting, changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies, price or gathering-rate controls, hydraulic fracturing and environmental protection regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, regional, state, tribal and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including environmental and tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, federal legislation, proposed in the recently concluded session of Congress and that could be introduced in the current session of Congress, could adversely affect our business, financial condition, results of operations or cash flows, if such legislation were introduced and adopted, which legislation includes the following:

 

   

Climate Change.    In the recently concluded session of Congress, climate-change legislation establishing a “cap-and-trade” plan for green-house gases (GHGs) was approved by the U.S. House of Representatives. It is not possible at this time to predict whether or when the current session of Congress may act on climate-change legislation. The U.S. Environmental Protection Agency (EPA) has also taken recent action related to GHGs. Based on recent developments, the EPA now purports to have a basis to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act, effective January 2, 2011.

 

   

Taxes.    The U.S. President’s Fiscal Year 2012 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural-gas exploration and development, and (iii) implementing certain international tax reforms.

 

   

Hydraulic Fracturing.    In the recently concluded session of Congress, legislation amending the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural-gas industry in the hydraulic-fracturing process was considered. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. It is not possible at this time to predict whether or when the current session of Congress may act on hydraulic-fracturing legislation. Such legislation, if adopted, could establish an additional level of regulation and permitting at the federal level.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.

The U.S. Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission (the CFTC) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the new legislation, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to the Company is uncertain at this time. The financial reform legislation may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to

 

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less creditworthy counterparties. If the Company reduces its use of derivatives as a result of the legislation and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Company’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Our debt and other financial commitments may limit our financial and operating flexibility.

At December 31, 2010, our total debt was $13.0 billion. We also have various commitments for leases, drilling contracts and transportation and purchase obligations for services and products. Our financial commitments could have important consequences to our business including, but not limited to:

 

   

increasing our vulnerability to general adverse economic and industry conditions;

 

   

limiting our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flows from operations to payments on our debt or to comply with any restrictive terms of our debt;

 

   

limiting our flexibility in planning for, or reacting to, changes in the industry in which we operate; and

 

   

placing us at a competitive disadvantage compared to our competitors that have less debt and fewer financial commitments.

Additionally, the credit agreement governing our senior secured revolving credit facility (the $5.0 billion Facility) contains a number of covenants that impose greater operating and financial constraints on the Company than those that existed under the previous borrowing arrangements, including restrictions on our ability to:

 

   

incur additional indebtedness;

 

   

sell assets; and

 

   

incur liens.

Our cost of capital under the terms of the $5.0 billion Facility is greater than our cost of capital under the $1.3 billion revolving credit agreement previously in effect due to the increased size and term of the $5.0 billion Facility and then-current market conditions. Provisions of the $5.0 billion Facility also require us to maintain specified financial covenants as further described in Liquidity and Capital Resources under Item 7 of this Form 10-K. Our ability to meet such covenants may be affected by events beyond our control.

A downgrade in our credit rating could negatively impact our cost of and ability to access capital.

In June 2010, Moody’s Investors Service (Moody’s) lowered the Company’s senior unsecured credit rating from “Baa3” to “Ba1” and placed the Company’s long-term ratings under review for further possible downgrade (the Credit Rating Downgrade), while Standard & Poor’s (S&P) and Fitch Ratings (Fitch) each affirmed their “BBB-” rating with a negative outlook. In September 2010, Moody’s announced that it concluded its review and confirmed Anadarko’s “Ba1” credit rating and changed the rating outlook to stable. As of the date of filing this Form 10-K, no changes in the Company’s credit rating have occurred and we are not aware of any current plans of S&P, Fitch or Moody’s to revise their respective ratings on our long-term debt. However, we cannot provide assurance that our credit ratings will not be further lowered. Any further downgrade to our credit ratings could negatively impact both our cost of, and our ability to access capital.

As a result of the Credit Rating Downgrade, Anadarko also is more likely to be required to post collateral as financial assurance of its performance under other contractual arrangements, such as pipeline transportation contracts, oil and gas sales contracts, and work commitments. At December 31, 2010, $461 million of letters of credit were provided as assurance of the Company’s performance under these types of arrangements, $377 million of which were issued under the $5.0 billion Facility. Further downgrades by the rating agencies may prompt requests by some of Anadarko’s business partners for the posting of additional collateral in the form of letters of credit or cash.

 

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In addition, as a result of the Credit Rating Downgrade, the Company’s credit thresholds with its derivative counterparties were reduced and in many cases eliminated. There have been no requests for termination or full settlement of derivative liability positions by counterparties, most of which maintain secured positions with respect to these balances as lenders under the $5.0 billion Facility. The aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed on December 31, 2010, was $9 million, net of collateral. Cash collateral held by derivative counterparties from Anadarko was $15 million at December 31, 2010. For additional information, see Liquidity and Capital Resources under Item 7 of this Form 10-K.

Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or assumptions underlying our reserve estimates could cause the quantities and net present value of our reserves to be overstated or understated.

There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated or understated. The reserve information included or incorporated by reference in this report represents estimates prepared by our internal engineers. The procedures and methods for estimating the reserves by our internal engineers were reviewed by independent petroleum consultants; however, no reserve audit was conducted by these consultants. Estimation of reserves is not an exact science. Estimates of economically recoverable oil and natural-gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, any of which may cause actual results to vary considerably from these estimates, such as:

 

   

historical production from an area compared with production from similar producing areas;

 

   

assumed effects of regulation by governmental agencies;

 

   

assumptions concerning future oil and natural-gas prices, future operating costs and capital expenditures; and

 

   

estimates of future severance and excise taxes, workover and remedial costs.

Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The discounted cash flows included in this report should not be construed as the current market value of the estimated oil, natural-gas and NGLs reserves attributable to our properties. For the December 31, 2009 and 2010 reserves, in accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are based upon average 12-month sales prices using the average beginning-of-month price, while reserves for all periods prior to December 31, 2009, are based on year-end sales prices. Actual future prices and costs may differ materially from the SEC regulation-compliant prices used for purposes of estimating discounted future net cash flows from proved reserves.

Failure to replace reserves may negatively affect our business.

Our future success depends upon our ability to find, develop or acquire additional oil and natural-gas reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We may be unable to find, develop or acquire additional reserves on an economic basis. Furthermore, if oil and natural-gas prices increase, our costs for finding or acquiring additional reserves could also increase.

Poor general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

During the last few years, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy.

These factors, combined with volatile oil, natural-gas and NGLs prices, declining business and consumer confidence, and increased unemployment, contributed to the recession in the United States during 2008 and 2009. Concerns about global economic conditions have had a significant adverse impact on global financial markets and

 

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commodity prices. If an economic recovery in the United States or abroad is slow or prolonged, demand for petroleum products could diminish or stagnate, which could impact the price at which we can sell our oil, natural gas and NGLs, affect our vendors’, suppliers’ and customers’ ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition.

Our results of operations could be adversely affected by asset impairments.

As a result of mergers and acquisitions, at December 31, 2010, we had approximately $5.3 billion of goodwill on our Consolidated Balance Sheet. Goodwill is not amortized, and must be tested at least annually for impairment, and more frequently when circumstances indicate likely impairment, by applying a fair-value-based test. Goodwill is considered impaired to the extent that its carrying amount exceeds its implied fair value. Various factors could lead to an impairment of goodwill, such as the Company’s inability to replace the value of its depleting asset base, or other adverse events, such as lower sustained oil and gas prices, which could reduce the fair value of the associated reporting unit. An impairment of goodwill could have a substantial negative effect on our profitability.

We are subject to complex laws and regulations relating to environmental protection that can adversely affect the cost, manner and feasibility of doing business.

Our operations and properties are subject to numerous federal, regional, state, tribal, local and foreign laws and regulations relating to environmental protection from the time projects commence until abandonment. These laws and regulations govern, among other things:

 

   

the amounts and types of substances and materials that may be released;

 

   

the issuance of permits in connection with exploration, drilling, production and midstream activities;

 

   

the protection of endangered species;

 

   

the release of emissions;

 

   

the discharge and disposition of generated waste materials;

 

   

offshore oil and gas operations;

 

   

the reclamation and abandonment of wells and facility sites; and

 

   

the remediation of contaminated sites.

In addition, these laws and regulations may impose substantial liabilities for our failure to comply with them or for any contamination resulting from our operations. Future environmental laws and regulations, such as proposed legislation regulating climate change or hydraulic fracturing, may negatively impact our industry. The cost of satisfying these requirements may have an adverse effect on our financial condition, results of operations or cash flows. For a description of certain environmental proceedings in which we are involved, see Legal Proceedings under Item 3 of this Form 10-K.

We are vulnerable to risks associated with our offshore operations that could negatively impact our operations and financial results.

We conduct offshore operations in the Gulf of Mexico, Ghana, Mozambique, Brazil, China and other countries. Our operations and financial results could be significantly impacted by conditions in some of these areas, such as the Gulf of Mexico, because we explore and produce extensively in those areas. As a result of this activity, we are vulnerable to the risks associated with operating offshore, including those relating to:

 

   

hurricanes and other adverse weather conditions;

 

   

oil field service costs and availability;

 

   

compliance with environmental and other laws and regulations;

 

   

terrorist attacks, such as piracy;

 

   

remediation and other costs and regulatory changes resulting from oil spills or releases of hazardous materials; and

 

   

failure of equipment or facilities.

 

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In addition, we expect to conduct some of our exploration in the deep waters (greater than 1,000 feet) of the Gulf of Mexico, where operations are more difficult and costly than in shallower waters. The deep waters in the Gulf of Mexico, as well as international deepwater locations, lack the physical and oilfield service infrastructure present in its shallower waters. As a result, deepwater operations may require a significant amount of time between a discovery and the time that we can market our production, thereby increasing the risk involved with these operations.

Further, production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than from reservoirs in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years of production and, as a result, our reserve replacement needs from new prospects may be greater there than for our operations elsewhere. Also, our revenues and return on capital will depend significantly on prices prevailing during these relatively short production periods.

We operate in other countries and are subject to political, economic and other uncertainties.

Our operations outside the United States are based primarily in Algeria, Brazil, China, Cote d’Ivoire, Ghana, Indonesia, Liberia, Mozambique and Sierra Leone. As a result, we face political and economic risks and other uncertainties with respect to our international operations. These risks may include, among other things:

 

   

loss of revenue, property and equipment as a result of hazards such as expropriation, war, piracy, acts of terrorism, insurrection, civil unrest and other political risks;

 

   

transparency issues in general and, more specifically, the U.S. Foreign Corrupt Practices Act and other anti-corruption compliance issues;

 

   

increases in taxes and governmental royalties;

 

   

unilateral renegotiation of contracts by governmental entities;

 

   

difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;

 

   

changes in laws and policies governing operations of foreign-based companies;

 

   

foreign-exchange restrictions; and

 

   

international monetary fluctuations and changes in the relative value of the U.S. dollar as compared with the currencies of other countries in which we conduct business.

For example, in 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production and issued regulations implementing this legislation. In response to the Algerian government’s imposition of the exceptional profits tax, we notified Sonatrach of our disagreement with the collection of the exceptional profits tax. In February 2009, we initiated arbitration against Sonatrach with regard to the exceptional profits tax. For additional information, see Note 16—Other Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Recently, outbreaks of civil and political unrest have occurred in several countries in Africa and the Middle East, including countries where we conduct operations, such as Algeria and Cote d’Ivoire. As exhibited by the recent events in Tunisia and Egypt, these outbreaks have in certain instances resulted in the established governing body being overthrown. Continued or escalated civil and political unrest in the countries in which we operate could result in our curtailing operations. For instance, a dispute over a recent election in Cote d’Ivoire has resulted in the establishment of two rival governments. Due to the uncertainty surrounding the civil and political unrest resulting from this disputed election, in February 2011, we suspended our operations in Cote d’Ivoire by declaring force majeure. We are unable to predict when or how the disputed election will be resolved, and when or if we would be able to resume operations in Cote d’Ivoire. In the event that countries in which we operate experience political or civil unrest, especially in events where such unrest leads to an unseating of the established government, our operations in such country could be materially impaired.

Our international operations may also be adversely affected by laws and policies of the United States affecting foreign trade and taxation.

Realization of any of the factors listed above could materially and adversely affect our financial position, results of operations or cash flows.

 

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Our commodity-price-risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to other risks.

To the extent that we engage in commodity-price-risk management activities to protect our cash flows from commodity price declines, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our commodity-price-risk management and trading activities may expose us to the risk of financial loss in certain circumstances, including instances in which:

 

   

our production is less than the hedged volumes;

 

   

there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

 

   

the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements; or

 

   

a sudden unexpected event materially impacts oil and natural-gas prices.

The credit risk of financial institutions could adversely affect us.

We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, investment funds and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions through our derivative transactions. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.

We are not insured against all of the operating risks to which our business is exposed.

Our business is subject to all of the operating risks normally associated with the exploration for and production, gathering, processing and transportation of oil and gas, including blowouts, cratering and fire, any of which could result in damage to, or destruction of, oil and natural-gas wells or formations or production facilities and other property and injury to persons. As protection against financial loss resulting from these operating hazards, we maintain insurance coverage, including certain physical damage, blowout/control of well, comprehensive general liability and worker’s compensation insurance and employer’s liability. However, our insurance coverage may not be sufficient to cover us against 100% of potential losses arising as a result of the foregoing, and for certain risks, such as political risk, business interruption, war, terrorism and piracy, for which we have limited or no coverage. In addition, we are not insured against all risks in all aspects of our business, such as hurricanes. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Material differences between the estimated and actual timing of critical events may affect the completion of and commencement of production from development projects.

We are involved in several large development projects. Key factors that may affect the timing and outcome of such projects include:

 

   

project approvals by joint-venture partners;

 

   

timely issuance of permits and licenses by governmental agencies;

 

   

weather conditions;

 

   

availability of personnel;

 

   

manufacturing and delivery schedules of critical equipment; and

 

   

commercial arrangements for pipelines and related equipment to transport and market hydrocarbons.

Delays and differences between estimated and actual timing of critical events may affect the forward-looking statements related to large development projects.

 

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The oil and gas exploration and production industry is very competitive, and some of our exploration and production competitors have greater financial and other resources than we do.

The oil and gas business is highly competitive in the search for and acquisition of reserves and in the gathering and marketing of oil and gas production. Our competitors include national oil companies, major oil and gas companies, independent oil and gas companies, individual producers, gas marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. Some of our competitors may have greater and more diverse resources upon which to draw than we do. If we are not successful in our competition for oil and gas reserves or in our marketing of production, our financial condition and results of operations may be adversely affected.

The high cost or unavailability of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition or results of operations.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment, supplies and personnel are substantially greater and their availability may be limited. Additionally, these services may not be available on commercially reasonable terms. The high cost or unavailability of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition or results of operations.

Our drilling activities may not be productive.

Drilling for oil and natural gas involves numerous risks, including the risk that we will not encounter commercially productive oil or natural-gas reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

   

unexpected drilling conditions;

 

   

pressure or irregularities in formations;

 

   

equipment failures or accidents;

 

   

fires, explosions, blowouts and surface cratering;

 

   

marine risks such as capsizing, collisions and hurricanes;

 

   

title problems;

 

   

other adverse weather conditions; and

 

   

shortages or delays in the delivery of equipment.

Certain of our future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. Because of the percentage of our capital budget devoted to high-risk exploratory projects, it is likely that we will continue to experience significant exploration and dry hole expenses.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital and lead to unexpected future costs.

 

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Our ability to sell our gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation.

The marketability of our production depends in part upon the availability, proximity and capacity of pipeline facilities and tanker transportation. If any of the pipelines or tankers become unavailable, we would be required to find a suitable alternative to transport the natural gas and oil, which could increase our costs and/or reduce the revenues we might obtain from the sale of the gas and oil.

Provisions in our corporate documents and Delaware law could delay or prevent a change of control of Anadarko, even if that change would be beneficial to our stockholders.

Our restated certificate of incorporation and by-laws contain provisions that may make a change of control of Anadarko difficult, even if it may be beneficial to our stockholders, including provisions governing the classification, nomination and removal of directors, prohibiting stockholder action by written consent and regulating the ability of our stockholders to bring matters for action before annual stockholder meetings, and the authorization given to our Board of Directors to issue and set the terms of preferred stock.

In addition, Section 203 of the Delaware General Corporation Law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.

We may reduce or cease to pay dividends on our common stock.

We can provide no assurance that we will continue to pay dividends at the current rate or at all. The amount of cash dividends, if any, to be paid in the future will depend upon their declaration by our Board of Directors and upon our financial condition, results of operations, cash flows, the levels of our capital and exploration expenditures, our future business prospects, expected liquidity needs and other related matters that our Board of Directors deems relevant.

The loss of key members of our management team, or difficulty attracting and retaining experienced technical personnel, could reduce our competitiveness and prospects for future success.

The successful implementation of our strategies and handling of other issues integral to our future success will depend, in part, on our experienced management team. The loss of key members of our management team, including James T. Hackett, our Chairman and Chief Executive Officer, could have an adverse effect on our business. We entered into an employment agreement with Mr. Hackett to secure his employment with us. We do not carry key man insurance. Our exploratory drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers and other professionals. Competition for such professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

Item 1B. Unresolved Staff Comments

The Company has no unresolved SEC staff comments that have been outstanding greater than 180 days from December 31, 2010.

Item 3. Legal Proceedings

GENERAL    The Company is a defendant in a number of lawsuits and is involved in governmental proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. The Company has also been named as a defendant in various personal injury claims, including claims by employees of third-party contractors alleging exposure to asbestos, silica and benzene while working at refineries (previously owned by predecessors of acquired companies) located in Texas, California and Oklahoma. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company.

 

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DEEPWATER HORIZON EVENTSRELATED PROCEEDINGS    In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating leasehold interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. Response and cleanup efforts are being conducted by BP, the operator and 65% owner of the Macondo lease, and by other parties, all under the direction of the Unified Command of the USCG.

On July 15, 2010, after several attempts to contain the oil spill, BP successfully installed a capping stack that shut in the well and prevented the further release of hydrocarbons. Installation of the capping stack was a temporary solution that was followed by a successful “static kill” cementing operation completed on August 5, 2010. The Macondo well was permanently plugged on September 19, 2010, when BP completed a “bottom kill” cementing operation in connection with the successful interception of the well by a relief well. Investigations by the federal government and other parties into the cause of the well blowout, explosion, and resulting oil spill, as well as other matters arising from or relating to these events, are ongoing.

BP, Anadarko and other parties, including parties that do not own an interest in the Lease, such as the drilling contractor, have received correspondence from the USCG referencing their identification as an RP under OPA, and the DOJ has also filed a civil lawsuit against such parties seeking to, among other things, confirm each party’s identified RP status. Under OPA, RPs may be held jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims directly related to the spill and spill cleanup. The USCG has directly invoiced the identified RPs for reimbursement of spill-related response costs incurred by the USCG and other federal and state agencies. The identified RPs each received identical invoices for total costs, without specification or stipulation of any allocation of costs between or among the identified RPs. To date, as operator, BP has paid all USCG invoices, thereby satisfying the joint and several obligation of the identified RPs to the USCG for these costs. BP has also made repeated public statements regarding its intention to continue to pay 100% of costs associated with cleanup efforts, claims and reimbursements related to the Deepwater Horizon events.

As a result of the Deepwater Horizon events, numerous civil lawsuits have been filed against BP and other parties, including the Company, by fishing, boating and shrimping industry groups; restaurants; commercial and residential property owners; certain rig workers or their families; the State of Alabama and several of its political subdivisions; the DOJ; environmental non-governmental organizations; the Plaquemines Parish School Board, a political subdivision of the State of Louisiana; and certain Mexican states. Many of the lawsuits filed assert various claims of negligence, gross negligence and violations of several federal and state laws and regulations, including, among others, OPA; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Air Act; the CWA; and the Endangered Species Act; or challenge existing permits for operations in the Gulf of Mexico. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment and/or injunctive relief.

In August 2010, the United States Judicial Panel on Multidistrict Litigation created MDL No. 2179 to administer essentially all litigation filed in federal court involving Deepwater Horizon event-related claims. Federal Judge Carl Barbier presides over this MDL in the United States District Court for the Eastern District of Louisiana in New Orleans, Louisiana. The court issued a number of case management orders that establish a schedule for procedural matters, discovery and trial of the MDL cases. The court set for trial beginning in June 2011, one or more cases brought against BP as an RP under OPA, to serve as test cases for causation and damage issues. The court has not yet selected the specific OPA test cases to be tried. Also, the court scheduled a February 2012 trial to determine the liability issues and allocable liability among the parties involved in the Deepwater Horizon events. The parties to the MDL are actively engaged in discovery.

On December 15, 2010, the DOJ, on behalf of the federal agencies involved in the spill response, filed a civil lawsuit in the United States District Court for the Eastern District of Louisiana against several parties, including the Company, seeking (i) an assessment of civil penalties under the CWA in an amount to be determined by the Court, and (ii) a declaratory judgment that such parties are jointly and severally liable without limitation under OPA for all removal costs and damages resulting from the Deepwater Horizon events. In the lawsuit, the DOJ states that civil penalties under the CWA may be assessed in an amount up to $1,100 per barrel of oil discharged or in cases involving gross negligence or willful misconduct in an amount up to $4,300 per barrel of oil discharged.

Lawsuits seeking to place limitations on the oil and gas industry’s operations in the Gulf of Mexico, including those of the Company, have also been filed outside of the MDL by non-governmental organizations against various governmental agencies. These cases are filed in the United States District Court for the Southern District of Alabama, the Eastern District of Louisiana, and the District of Columbia and in the United States Court of Appeals for the Fifth Circuit.

 

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Two separate class action complaints were filed in June and August 2010 in the United States District Court for the Southern District of New York on behalf of purported purchasers of the Company’s stock between June 12, 2009, and June 9, 2010, against Anadarko and certain of its officers. The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In November 2010, the District Court for the Southern District of New York consolidated the two cases, and appointed the Virgin Islands Group to act as Lead Plaintiff. In January 2011, the Lead Plaintiff filed its Consolidated Amended Complaint. Prior to filing its Consolidated Amended Complaint, the Lead Plaintiff requested leave from the court to transfer this lawsuit to the United States District Court for the Southern District of Texas. The Company opposes the Lead Plaintiff’s request to transfer the case to the District Court for the Southern District of Texas. The court has ordered the parties to brief the transfer of venue issue.

Also in June 2010, a shareholder derivative petition was filed in the 157th Judicial District Court of Harris County, Texas, by a shareholder of the Company against Anadarko (as a nominal defendant) and certain of its officers and current and certain former directors. The petition alleges breaches of fiduciary duties, unjust enrichment, and waste of corporate assets in connection with the Deepwater Horizon events. The plaintiffs seek certain changes to the Company’s governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs. In November 2010, the court granted Anadarko’s Motion to Dismiss for Lack of Jurisdiction and Special Exceptions and granted the plaintiffs 120 days to file an Amended Petition. In September 2010, a purported shareholder made a demand on the Board to investigate allegations of breaches of duty by members of management. The Board duly considered the demand and in January 2011 determined that it would not be in the best interest of the Company to pursue the issues in the demand letter.

These proceedings are at a very early stage; accordingly, the Company currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the proceedings described above. The Company intends to vigorously defend itself, its officers and its directors in these proceedings.

TRONOX PROCEEDINGS    In January 2009, Tronox, a former wholly owned subsidiary of Kerr-McGee, and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the Court. Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance (the Adversary Proceeding). Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee. Tronox seeks, among other things, to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko as well as the litigation fees and costs. In addition, Tronox seeks to equitably subordinate and/or disallow all claims asserted by Anadarko and Kerr-McGee in the bankruptcy cases. Anadarko and Kerr-McGee moved to dismiss the complaint in its entirety. In March 2010, the Court issued an opinion granting in part and denying in part Anadarko’s and Kerr-McGee’s motion to dismiss the complaint. Notably, the Court dismissed, with prejudice, Tronox’s request for punitive damages relating to the fraudulent conveyance claims. The Court granted Tronox leave to replead certain of its common law claims, and Tronox filed an amended complaint in April 2010. Anadarko and Kerr-McGee have moved to dismiss three breach of fiduciary duty-related claims in the amended complaint. That motion has been briefed and is awaiting a ruling by the Court. The Adversary Proceeding is set for trial in March 2012.

 

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The United States filed a motion to intervene in the Adversary Proceeding, asserting that it has an independent cause of action against Anadarko, Kerr-McGee and Tronox under the Federal Debt Collection Procedures Act relating primarily to environmental cleanup obligations allegedly owed to the United States by Tronox. That motion to intervene has been granted, and the United States is now a co-plaintiff against Anadarko and Kerr-McGee in the Adversary Proceeding. Anadarko and Kerr-McGee have moved to dismiss the United States’ complaint-in-intervention, but that motion currently has been stayed by order of the Court.

In June 2010, Anadarko and Kerr-McGee filed a motion in Tronox’s Chapter 11 cases to compel Tronox to assume or reject the MSA. In response to this motion, Tronox announced to the Court that it would reject the MSA effective July 22, 2010. In August 2010, the Court entered a Stipulation and Agreed Order among Tronox, Anadarko, and Kerr-McGee authorizing the rejection of the MSA. Anadarko and Kerr-McGee filed the Proofs of Claim, which include claims for damages arising from such rejection of the MSA. Tronox and several of its creditors have objected to the Proofs of Claim. At the end of January 2011, the Court entered a Stipulation and Agreed Order regarding a settlement of the claims by Anadarko and Kerr-McGee against Tronox resulting from its rejection of the MSA. In February 2011, the Company received its agreed-upon claim, in the form of Tronox equity, valued at $29 million. The Company will continue to monitor events subsequent to the MSA rejection and will assess the impact of future events on the Company’s consolidated financial position, results of operations or cash flows.

In August 2010, Tronox filed a motion seeking, among other things, (i) authority to enter into a certain plan support agreement and equity-commitment agreement (together, the Plan Support Agreements) and (ii) approval of procedures for a rights offering. Anadarko and Kerr-McGee filed an objection to the motion. In the objection, Anadarko and Kerr-McGee requested that the Court order mediation of the Adversary Proceeding. Tronox and the United States opposed mediation, citing, in support of their position, a lack of sufficient discovery. The Court declined to order mediation at that time. In September 2010, the Court entered an order authorizing Tronox to enter into the Plan Support Agreements and approved the rights offering procedures. Anadarko and Kerr-McGee are not subject to the rights offering procedures. However, Anadarko and Kerr-McGee reached an agreement with Tronox that will entitle them to receive the economic benefit on account of their claims against Tronox as if they had participated in the rights offering if certain conditions are satisfied.

In September 2010, Tronox filed a Proposed First Amended Joint Plan of Reorganization pursuant to Chapter 11 of the Bankruptcy Code (the Plan) and a related disclosure statement (the Disclosure Statement), which modify and supersede the terms of its plan and disclosure statement filed in July 2010. Tronox subsequently filed further amendments to the Plan and Disclosure Statement. The Plan contemplates, among other things, that (a) the claims of the United States (as well as other federal, state, local or tribal governmental entities having regulatory authority or responsibilities with respect to environmental laws) related to Tronox’s environmental liabilities at legacy sites, will be settled through the creation of certain environmental response trusts and a litigation trust, to which Tronox will contribute the following consideration: (i) $270 million in cash, (ii) 88% of the proceeds from the Adversary Proceeding, (iii) certain Nevada assets, including the real property located in Henderson, Nevada, (iv) certain other real property and related assets, and (v) certain insurance and financial assurance assets worth at least $50 million; (b) certain creditors who have asserted tort claims against Tronox arising from, among other things, environmental contamination or chemical or asbestos exposure will receive the following consideration from a trust to be created under the Plan: (i) $13 million in cash, (ii) 12% of the proceeds from the Adversary Proceeding, and (iii) certain insurance assets, including the net proceeds of certain insurance settlements; and (c) certain creditors who have asserted general unsecured claims against Tronox will receive the following consideration: (i) their pro rata share of 50.9% of the common equity of reorganized Tronox and (ii) the right to purchase up to 45.5% of the common equity of reorganized Tronox. Objections to the Plan and Disclosure Statement were filed by various interested parties, including Anadarko and Kerr-McGee.

 

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In September 2010, the Court approved the Disclosure Statement and authorized Tronox to begin soliciting votes to accept or reject the Plan. In October 2010, the Court entered a stipulation between Anadarko and Tronox which provides for allowance of Anadarko’s claims for voting purposes only.

In October and November 2010, Tronox filed certain documents central to the Plan as part of the Plan Supplement including, among other things, the Environmental Claims Settlement Agreement and the Tort Claims Trust Agreement. The Plan contemplates that additional documents, including the Anadarko Litigation Trust Agreement, will be filed as part of the Plan Supplement and parties in interest will have an opportunity to object to those documents before they become effective pursuant to the Plan. Also in November 2010, the Court confirmed the Plan, subject to certain modifications and settlements, and entered the order confirming the Plan. Anadarko’s objections to the Plan were resolved prior to confirmation. In February 2011, Tronox emerged from bankruptcy. It is unclear what, if any, effect the Plan might have on the Adversary Proceeding or its outcome.

In addition, a consolidated class action complaint has been filed in the United States District Court for the Southern District of New York (the District Court) on behalf of purported purchasers of Tronox’s equity and debt securities between November 21, 2005, and January 12, 2009 (the Class Period), against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors and Ernst & Young LLP. The complaint alleges causes of action arising under the Exchange Act for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort claim liabilities. The plaintiffs allege, among other things, that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including filings made in connection with Tronox’s initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. Anadarko, Kerr-McGee and other defendants moved to dismiss the class action complaint and in June 2010, the District Court issued an opinion and order dismissing the plaintiffs’ complaint against Anadarko, but granted the plaintiffs leave to replead their allegations related to the claim that Anadarko was liable as a successor-in-interest to Kerr-McGee. The District Court further granted in part and denied in part the motions to dismiss by Kerr-McGee and certain of its former officers and directors, but permitted the plaintiffs leave to replead certain of the dismissed claims. The plaintiffs filed an amended consolidated class action complaint in July 2010. In August 2010, Anadarko, Kerr-McGee, and several of Kerr-McGee’s former officers and directors filed respective motions to dismiss. In January 2011, the District Court issued an opinion and order denying the motions of Kerr-McGee and several former Kerr-McGee officers and directors. The District Court also denied Anadarko’s motion to dismiss the remaining Section 20(a) claim under the Exchange Act covering the period beginning on August 10, 2006, through the end of the alleged Class Period. However, the District Court dismissed this claim against Anadarko to the extent it was based on a successor-in-interest theory of liability. The discovery process is ongoing.

These proceedings are at a very early stage; accordingly, the Company currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the proceedings described above. The Company intends to vigorously defend itself, its officers and its directors in these proceedings.

See Note 2—Deepwater Horizon Events, Note 14—Commitments and Note 15—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

OTHER MATTERS    The Company is subject to other legal proceedings, claims and liabilities which arise in the ordinary course of its business. In the opinion of Anadarko, the liability with respect to these actions will not have a material effect on the consolidated financial position, results of operations or cash flows of the Company.

 

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PART II

 

Item 5.

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

  

 Securities

MARKET INFORMATION, HOLDERS AND DIVIDENDS

As of January 31, 2011, there were approximately 14,560 record holders of Anadarko common stock. The common stock of Anadarko is traded on the New York Stock Exchange. The following shows information regarding the market price of and dividends declared and paid on the Company’s common stock by quarter for 2010 and 2009.

 

     First
Quarter
     Second
Quarter
     Third
Quarter
     Fourth
Quarter
 

2010

           

Market Price

           

High

   $ 73.89      $ 75.07      $ 58.42      $ 78.98  

Low

   $ 60.75      $ 34.54      $ 36.06      $ 55.65  

Dividends

   $ 0.09      $ 0.09      $ 0.09      $ 0.09  

2009

           

Market Price

           

High

   $ 44.00      $ 52.38      $ 66.21      $ 69.37  

Low

   $ 30.88      $ 37.80      $ 40.28      $ 55.87  

Dividends

   $ 0.09      $ 0.09      $ 0.09      $ 0.09  

The amount of future common stock dividends will depend on earnings, financial condition, capital requirements and other factors, and will be determined by the Board of Directors on a quarterly basis. For additional information, see Liquidity and Capital Resources—Uses of Cash—Dividends under Item 7 and Note 13—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following table sets forth information with respect to the equity compensation plans available to directors, officers and employees of the Company at December 31, 2010.

 

Plan Category

   (a)
Number of  securities
to be issued upon
exercise of
outstanding options,
warrants and rights
     (b)
Weighted-average
exercise price of
outstanding
options, warrants
and rights
     (c)
Number of  securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column(a))
 

Equity compensation plans approved by security holders

     9,545,056      $ 49.15        19,812,498  

Equity compensation plans not approved by security holders

                    
                          

Total

     9,545,056      $ 49.15        19,812,498  
                          

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS

In August 2008, the Company announced a share-repurchase program (the Program) to purchase up to $5 billion in shares of common stock. The Program replaces a prior share-repurchase program and is authorized to extend through August 2011; however, the Program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. The following table sets forth information with respect to repurchases made by the Company of its shares of common stock during the fourth quarter of 2010.

 

Period

   Total
number of
shares
purchased (1)
     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

     345        $ 57.06                                     —      

November 1-30

     33,688        $ 66.15             

December 1-31

             64,128        $ 67.96             
                       

Fourth Quarter 2010

     98,161        $ 67.30              $ 4,400,000,000   
                             

 

(1)

During the fourth quarter of 2010, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee stock plan share issuances, which are not within the scope of the Program.

 

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PERFORMANCE GRAPH

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

The following graph compares the cumulative five-year total return to stockholders on Anadarko’s common stock relative to the cumulative total returns of the S&P 500 index and a customized peer group of 11 companies. The companies included in the customized peer group are: Apache Corporation; Chevron Corporation; ConocoPhillips; Devon Energy Corporation; EOG Resources, Inc.; Hess Corporation; Marathon Oil Corporation; Noble Energy, Inc.; Occidental Petroleum Corporation; Pioneer Natural Resources Company; and Plains Exploration and Production Company.

LOGO

An investment of $100 (with reinvestment of all dividends) is assumed to have been made in the Company’s common stock, in the index and in the peer group on December 31, 2005, and its relative performance is tracked through December 31, 2010.

 

Fiscal Year Ended December 31

     2005        2006        2007        2008        2009        2010  

Anadarko Petroleum Corporation

   $ 100.00      $ 92.56      $ 140.73      $ 83.15      $ 135.68      $ 166.59  

S&P 500

     100.00        115.80        122.16        76.96        97.33        111.99  

Peer Group

     100.00        124.08        170.07        118.48        138.97        171.23  

 

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Item 6. Selected Financial Data

 

        Summary Financial Information*  
millions except per-share amounts      2010        2009      2008      2007        2006   

Sales Revenues

     $ 10,842        $ 8,210      $ 14,079      $ 11,656        $   10,116   

Gains (Losses) on Divestitures and Other, net

       142          133        1,083        4,760          114   

Reversal of Accrual for DWRRA Dispute

                 657                            
                                                  

Total Revenues and Other

       10,984          9,000        15,162        16,416          10,230   

Operating Income (Loss)

       1,769          377        5,601        7,871          4,381   

Income (Loss) from Continuing Operations

       821          (103      3,220        3,767          2,471   

Income from Discontinued Operations, net of taxes

                         63        11          2,275   

Net Income (Loss) Attributable to Common Stockholders

       761          (135      3,260        3,778          4,746   

Per Common Share (amounts attributable to common stockholders):

                    

Income (Loss) from Continuing Operations—Basic

     $ 1.53        $ (0.28    $ 6.79      $ 8.01        $ 5.33   

Income (Loss) from Continuing Operations—Diluted

     $ 1.52        $ (0.28    $ 6.78      $ 7.99        $ 5.31   

Income from Discontinued Operations—Basic

     $         $       $ 0.13      $ 0.02        $ 4.91   

Income from Discontinued Operations—Diluted

     $         $       $ 0.13      $ 0.02        $ 4.88   

Net Income (Loss)—Basic

     $ 1.53        $ (0.28    $ 6.92      $ 8.03        $ 10.24   

Net Income (Loss)—Diluted

     $ 1.52        $ (0.28    $ 6.91      $ 8.01        $ 10.19   

Dividends

     $ 0.36        $ 0.36      $ 0.36      $ 0.36        $ 0.36   

Average Number of Common Shares Outstanding—Basic

       495          480        465        465          460   

Average Number of Common Shares Outstanding—Diluted

       497          480        466        467          463   

Cash Provided by Operating Activities—Continuing Operations

     $ 5,247        $ 3,926      $ 6,447      $ 2,766        $ 4,671   

Cash Provided by (Used in) Operating Activities—Discontinued Operations

                         (5      134          (178 )  

Net Cash Provided by Operating Activities

       5,247          3,926        6,442        2,900          4,493   

Capital Expenditures

     $ 5,169        $ 4,558      $ 4,881      $ 3,990        $ 4,212   

Current Debt

     $ 291        $       $ 1,472      $ 1,396        $ 11,471   

Long-term Debt

       12,722          11,149        9,128        11,151          11,520   

Midstream Subsidiary Note Payable to a Related Party

                 1,599        1,739        2,200            

Total Debt

     $ 13,013        $ 12,748      $ 12,339      $ 14,747        $ 22,991   

Total Stockholders’ Equity

       20,684          19,928        18,795        16,364          12,403   

Total Assets

     $ 51,559        $ 50,123      $ 48,923      $ 48,451        $ 54,964   

Annual Sales Volumes:

                    

Continuing Operations

                    

Natural Gas (Bcf)

       829          809        750        698          558   

Oil and Condensate (MMBbls)

       74          68        67        79          70   

Natural Gas Liquids (MMBbls)

       23          17        14        16          15   

Total (MMBOE)**

       235          220        206        211          178   

Discontinued Operations (MMBOE)

                                           17   

Total (MMBOE)**

       235          220        206        211          195   

Average Daily Sales Volumes:

                    

Continuing Operations

                    

Natural Gas (MMcf/d)

       2,272          2,217        2,049        1,912          1,529   

Oil and Condensate (MBbls/d)

       201          187        182        215          193   

Natural Gas Liquids (MBbls/d)

       63          47        39        43          42   

Total (MBOE/d)

       643          604        563        577          489   

Discontinued Operations (MBOE/d)

                                           46   

Total (MBOE/d)

       643          604        563        577          535   

Reserves:

                    

Natural-Gas Reserves (Tcf)

       8.1          7.8        8.1        8.5          10.5   

Oil and Condensate Reserves (MMBbls)

       749          733        709        843          1,126   

Natural-Gas Liquids Reserves (MMBbls)

       320          277        217        171          138   

Total Reserves (MMBOE)

       2,422          2,304        2,277        2,431          3,011   

Number of Employees

       4,400          4,300        4,300        4,000          5,200   
*

Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.

**

Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.

 

Table of Measures

  

Bcf—Billion cubic feet

   MBbls/d—Thousand barrels per day

MMBbls—Million barrels

   MBOE/d—Thousand barrels of oil equivalent per day

MMBOE—Million barrels of oil equivalent

   Tcf—Trillion cubic feet

MMcf/d—Million cubic feet per day

  

 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this report in Item 8, and the information set forth in Risk Factors under Item 1A. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

OVERVIEW

Anadarko achieved its key operational objectives in 2010 by increasing sales volumes by approximately 7% year-over-year, reducing oil and gas operating expenses per unit by approximately 9% year-over-year, and adding 359 million barrels of oil equivalent (BOE) of proved reserves. Additionally, the Company continued offshore exploration and appraisal drilling success with an approximate 75% success rate and achieved first oil at the Jubilee field offshore Ghana in 3.5 years following discovery. Anadarko ended 2010 with approximately $3.7 billion cash on hand and retains the availability of its undrawn five-year $5.0 billion senior secured revolving credit facility (the $5.0 billion Facility) less $377 million in outstanding letter of credit supported by the $5.0 billion Facility, as well as additional access to credit and capital markets as needed. Management believes that the Company’s cash on hand, available borrowing capacity and cash flows from operations position the Company to satisfy its operational objectives and capital commitments.

Mission and Strategy

Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by exploring for, acquiring and developing oil and natural-gas resources vital to the world’s health and welfare. Anadarko employs the following strategy to achieve this mission:

 

   

identify and commercialize resources;

 

   

explore in high-potential, proven basins;

 

   

employ a global business development approach; and

 

   

ensure financial discipline and flexibility.

Developing a portfolio of primarily unconventional resources provides the Company a stable base of capital-efficient, predictable and repeatable development opportunities which, in turn, positions the Company for consistent growth at competitive rates.

Exploring in high-potential, proven and emerging basins worldwide provides the Company with growth opportunities. Anadarko’s exploration success, which includes 17 offshore discoveries in the last two years, has created value by expanding its future resource potential, while providing the flexibility to manage risk by monetizing discoveries.

Anadarko’s global business development approach transfers core skills across the globe to assist in the discovery and development of world-class resources that are accretive to the Company’s performance. These resources help form an optimized global portfolio where both surface and subsurface risks are actively managed.

A strong balance sheet is essential for the development of the Company’s assets, and Anadarko is committed to disciplined investments in its businesses to manage through commodity price cycles. Maintaining financial discipline enables the Company to capitalize on the flexibility of its global portfolio, while allowing the Company to pursue new strategic growth opportunities.

 

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Operating Highlights

Significant 2010 operating highlights include the following:

Deepwater Horizon Events

In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating leasehold interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. In September 2010, the Macondo well was permanently plugged. Refer to Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for discussion and analysis of these events.

Deepwater Drilling Moratorium and Other Related Matters

Anadarko ceased all drilling operations in the Gulf of Mexico in accordance with the deepwater drilling moratoria (collectively, the Moratorium), which resulted in the suspension of operations of two operated deepwater wells (Lucius and Nansen) and one non-operated deepwater well (Vito). The Moratorium was lifted October 12, 2010, but the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) has not approved new drilling permits. Anadarko is currently positioned to resume exploration and development drilling operations in the Gulf of Mexico, pending approvals of drilling permits and exploration and oil spill-response plans. See Note 15—Contingencies—Deepwater Drilling Moratorium and Other Related Matters in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information on the Moratorium.

United States Onshore

 

   

The Company reallocated 7% of total 2010 budgeted capital expenditures from the Gulf of Mexico and redirected onshore United States capital expenditures to liquids-rich areas of the portfolio, including Eagleford, Bone Spring, Wattenberg and Greater Natural Buttes.

 

   

The Company’s Rocky Mountains Region (Rockies) achieved total-year sales volumes of 276 thousand barrels of oil equivalent per day (MBOE/d), representing an 11% increase over 2009.

 

   

The Company’s Southern and Appalachia Region achieved total-year sales volumes of 124 MBOE/d, representing a 7% increase over 2009.

 

   

The Company entered into a joint-venture agreement that requires a third-party joint-venture partner to fund up to $1.5 billion of Anadarko’s share of future acquisition, drilling, completion, equipment and other capital expenditures to earn a 32.5% interest in Anadarko’s Marcellus shale assets, primarily located in north-central Pennsylvania.

 

   

The Company acquired more than 80,000 net acres in the Maverick basin of southwest Texas for $93 million and increased its working interest in these properties to 75%.

Gulf of Mexico

 

   

The Company’s Gulf of Mexico total-year sales volumes were 155 MBOE/d, representing a 2% increase from 2009.

 

   

The Company drilled successful sidetrack appraisal wells in the Gulf of Mexico at Lucius (50% working interest) and Vito (20% working interest).

 

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International

 

   

The Company drilled seven successful exploration wells with a 54% discovery rate. These wells included three in Mozambique, and one in each of Ghana, Indonesia, Sierra Leone and Brazil.

 

   

The Company drilled five appraisal wells, four in Ghana and one in Brazil, with a 100% success rate.

 

   

The Company and its partners took delivery and completed installation and commissioning of the floating production, storage and offloading vessel (FPSO) and achieved first oil at the Ghana Jubilee field in late 2010 on budget and 3.5 years following discovery.

Financial Highlights

Significant 2010 financial highlights include the following:

 

   

Anadarko’s income from continuing operations attributable to common stockholders for 2010 totaled $761 million compared to a loss of $135 million in 2009.

 

   

The Company generated $5.2 billion of cash flows from operations compared to $3.9 billion in 2009 and ended the year with $3.7 billion of cash on hand.

 

   

To manage its liquidity and the term structure of its debt, the Company raised $2.7 billion of cash in the public debt markets, and repaid $3.0 billion of aggregate principal amount of debt scheduled to mature in 2011 and 2012, reducing scheduled 2011 and 2012 debt maturities.

 

   

The Company replaced its $1.3 billion revolving credit agreement scheduled to mature in 2013 with the $5.0 billion Facility maturing in 2015, which was undrawn at December 31, 2010.

 

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The following discussion pertains to Anadarko’s financial condition, results of operations and changes in financial condition. Unless noted otherwise, the following information relates to the continuing operations and any increases or decreases “for the year ended December 31, 2010” refer to the comparison of the year ended December 31, 2010, to the year ended December 31, 2009. Similarly, any increases or decreases “for the year ended December 31, 2009” refer to the comparison of the year ended December 31, 2009, to the year ended December 31, 2008. The primary factors that affect the Company’s results of operations include, among other things, commodity prices for natural gas, crude oil and natural gas liquids (NGLs), sales volumes, the Company’s ability to discover additional oil and natural-gas reserves, the cost of finding such reserves, and operating costs.

RESULTS OF CONTINUING OPERATIONS

Selected Data

millions except per-share amounts and percentages

                   
   2010      2009     2008  

Financial Results

       

Oil and condensate, natural-gas and NGLs sales

   $ 10,009      $ 7,482     $ 12,997  

Gathering, processing and marketing sales

     833        728       1,082  

Gains on divestitures and other, net

     142        133       1,083  

Reversal of accrual for DWRRA dispute

             657         
                         

Total revenues and other

     10,984        9,000       15,162  

Costs and expenses

     9,215        8,623       9,561  

Other (income) expense

     128        485       233  

Income tax expense (benefit)

     820        (5     2,148  

Income (loss) from continuing operations attributable to common stockholders

   $ 761      $ (135   $ 3,197  

Income (loss) from continuing operations per common share attributable to common stockholders—diluted

   $ 1.52      $ (0.28   $ 6.78  

Average number of common shares outstanding—diluted

     497        480       466  

Operating Results

       

Adjusted EBITDAX*

   $ 7,226      $ 6,033     $ 9,941  

Total proved reserves (MMBOE)

     2,422        2,304       2,277  

Annual sales volumes (MMBOE)

     235        220       206  

Capital Resources and Liquidity

       

Cash provided by operating activities

   $ 5,247      $ 3,926     $ 6,447  

Capital expenditures

     5,169        4,558       4,881  

Total debt

     13,013        12,748       12,339  

Stockholders’ equity

   $     20,684      $     19,928     $     18,795  

Debt to total capitalization ratio

     38.6%         39.0%        39.6%   

 

MMBOE—millions of barrels of oil equivalent

 

*

See Operating Results—Segment Analysis—Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a U.S. Generally Accepted Accounting Principles (GAAP) measure, and a reconciliation of Adjusted EBITDAX to income (loss) from continuing operations before income taxes, which is presented in accordance with GAAP.

FINANCIAL RESULTS

Income (Loss) from Continuing Operations Attributable to Common Stockholders    Anadarko’s income from continuing operations attributable to common stockholders for 2010 totaled $761 million, or $1.52 per share (diluted), compared to a loss from continuing operations attributable to common stockholders for 2009 of $135 million, or $0.28 per share (diluted). Anadarko’s income from continuing operations attributable to common stockholders in 2008 was $3.2 billion, or $6.78 per share (diluted).

 

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Sales Revenues, Volumes and Prices

millions except percentages

                                
   2010      Inc/(Dec)
vs. 2009
    2009      Inc/(Dec)
vs. 2008
    2008  

Natural-gas sales

   $ 3,420        17   $ 2,924        (49 )%    $ 5,770  

Oil and condensate sales

     5,592        39       4,022        (37     6,425  

Natural-gas liquids sales

     997        86       536        (33     802  
                              

Total

   $     10,009        34     $     7,482        (42   $     12,997  
                              

Anadarko’s sales revenues for the year ended December 31, 2010, increased primarily due to higher commodity prices and increased production volumes, while sales revenues for the year ended December 31, 2009, decreased primarily due to lower commodity prices partially offset by higher production volumes, as follows:

millions

                        
   Natural
Gas
    Oil and
Condensate
    NGLs     Total  

2008 sales revenues

   $ 5,770     $ 6,425     $ 802     $ 12,997  

Changes associated with sales volumes

     454       155       154       763  

Changes associated with prices

     (3,300     (2,558     (420     (6,278
                                

2009 sales revenues

   $ 2,924     $ 4,022     $ 536     $ 7,482  

Changes associated with sales volumes

     72       286       192       550  

Changes associated with prices

     424       1,284       269       1,977  
                                

2010 sales revenues

   $     3,420     $ 5,592     $     997     $     10,009  
                                

The following table provides Anadarko’s sales volumes for the years ended December 31, 2010, 2009 and 2008.

 

     2010      Inc/(Dec)
vs. 2009
    2009      Inc/(Dec)
vs. 2008
    2008  

Barrels of Oil Equivalent (MMBOE except percentages)

            

United States

     209        7     196        9     179  

International

     26        7       24        (9     27  
                              

Total

         235        7           220        7           206  
                              

Barrels of Oil Equivalent per Day (MBOE/d except percentages)

            

United States

     572        7     537        9     489  

International

     71        7       67        (9     74  
                              

Total

     643        7       604        7       563  
                              

Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Other (Income) Expense—(Gains) Losses on Commodity Derivatives, net. Production of natural gas, crude oil and NGLs is usually not affected by seasonal swings in demand.

 

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Natural-Gas Sales Volumes, Average Prices and Revenues

 

     2010      Inc/(Dec)
vs. 2009
    2009      Inc/(Dec)
vs. 2008
    2008  

United States

            

Sales volumes—Bcf

     829        2     809        8     750  

                            MMcf/d

     2,272        2       2,217        8       2,049  

Price per Mcf

   $ 4.12        14     $ 3.61        (53   $ 7.69  

Natural-gas sales revenues (millions)

   $     3,420        17     $     2,924        (49   $     5,770  

 

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

The Company’s daily natural-gas sales volumes increased 55 MMcf/d for the year ended December 31, 2010, primarily due to increased production in the Rockies of 61 MMcf/d, resulting from increased drilling in Greater Natural Buttes and the Greater Green River basins, as well as increased production in the Southern and Appalachia Region of 12 MMcf/d, associated with increased drilling in the Maverick basin, Haynesville shale and Marcellus shale. Increased natural-gas sales volumes were partially offset by natural production declines in the Gulf of Mexico of 18 MMcf/d.

The Company’s daily natural-gas sales volumes increased 168 MMcf/d for the year ended December 31, 2009, primarily due to increased production in the Rockies of 138 MMcf/d due to positive results from dewatering coalbed methane wells and higher production uptime due to favorable weather. An increase in production in the Gulf of Mexico of 54 MMcf/d related to favorable weather conditions as compared to hurricane-related downtime experienced during 2008. Also, runtime at Independence Hub increased during 2009 as compared to 2008 when export pipeline repair work resulted in downtime. These increases in natural-gas production were partially offset by a 24 MMcf/d decrease in the Southern and Appalachia Region resulting from natural production declines experienced while drilling programs were shifted from established fields to emerging shale plays.

The average natural-gas price Anadarko received increased for the year ended December 31, 2010, primarily due to an increase in demand. Anadarko’s average natural-gas price decreased substantially for the year ended December 31, 2009, primarily because of higher year-over-year U.S. natural-gas production and storage volumes coupled with lower United States demand for natural gas, triggered by the economic downturn in the United States.

 

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Crude-Oil and Condensate Sales Volumes, Average Prices and Revenues

 

    2010     Inc/(Dec)
vs. 2009
    2009     Inc/(Dec)
vs. 2008
    2008  

United States

         

Sales volumes—MMBbls

    48       7     44       10     40  

                            MBbls/d

    130       7       120       10       108  

Price per barrel

  $ 74.96       28     $ 58.56       (39   $ 96.20  

International

         

Sales volumes—MMBbls

    26       7       24       (9     27  

                            MBbls/d

    71       7       67       (9     74  

Price per barrel

  $ 78.52       33     $ 59.01       (38   $ 95.83  

Total

         

Sales volumes—MMBbls

    74       7       68       2       67  

                            MBbls/d

    201       7       187       2       182  

Total price per barrel

  $ 76.22       30     $ 58.72       (39   $ 96.05  

Oil and condensate sales revenues (millions)

  $     5,592       39     $     4,022       (37   $     6,425  

 

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s daily crude-oil and condensate sales volumes increased 14 MBbls/d for the year ended December 31, 2010. This increase was partially due to higher crude-oil sales volumes of 5 MBbls/d in the Gulf of Mexico as completion of repairs to third-party downstream infrastructure that was damaged during the 2008 hurricane season occurred during the third quarter of 2009. In addition, crude-oil sales volumes increased 4 MBbls/d in the Southern and Appalachia Region due to a shift in focus from drilling in dry-gas areas to drilling in liquids-rich areas and 3 MBbls/d in the Rockies due to a full year of production efficiencies related to an oil pipeline that was placed in service in mid-2009, as well as a shift in focus to liquids-rich areas. Also, Algerian crude-oil sales volumes increased 3 MBbls/d primarily due to the timing of cargo liftings.

Anadarko’s daily crude-oil and condensate sales volumes increased 5 MBbls/d for the year ended December 31, 2009, primarily due to higher crude-oil sales volumes of 8 MBbls/d in the Gulf of Mexico and 3 MBbls/d in the Rockies. The increase in the Gulf of Mexico results from additional production that came online during the fourth quarter of 2008, and favorable weather conditions as compared to 2008, which was impacted by export pipeline repair work and hurricane-related disruptions. The increase in the Rockies relates to production efficiencies from an oil pipeline that was placed into service in mid-2009. These increases were offset by lower Algerian crude-oil sales volumes of 6 MBbls/d due to the timing of cargo liftings and variances in the Organization of Petroleum Exporting Countries (OPEC) quotas.

The average crude-oil price Anadarko received increased for the year ended December 31, 2010, as a result of increased global demand. Anadarko’s average crude-oil price decreased for the year ended December 31, 2009, primarily due to increased spare OPEC production capacity coupled with decreased global demand, particularly in the United States, Europe and Japan as a result of the economic downturn.

 

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Natural-Gas Liquids Sales Volumes, Average Prices and Revenues

 

     2010      Inc/(Dec)
vs. 2009
    2009      Inc/(Dec)
vs. 2008
    2008  

United States

            

Sales volumes—MMBbls

     23        36     17        20     14  

                            MBbls/d

     63        36       47        20       39  

Price per barrel

   $     43.07        37     $     31.42        (44   $     56.11  

Natural-gas liquids sales revenues (millions)

   $ 997        86     $ 536        (33   $ 802  

NGLs sales represent revenues from the sale of products derived from the processing of Anadarko’s natural-gas production. The Company’s daily NGLs sales volumes increased 16 MBbls/d for the year ended December 31, 2010, primarily related to operations in the Rockies where natural-gas production increased, an additional natural-gas processing train was brought online late in the second quarter of 2009, and improved recoveries due to new processing agreements entered into late in 2009.

Anadarko’s daily NGLs sales volumes increased 8 MBbls/d for the year ended December 31, 2009, primarily because of a new processing train placed in service during the second quarter of 2009 at the Chipeta natural-gas processing plant, increased natural-gas production in the Rockies, and improved recoveries in the Southern and Appalachia Region due to new processing agreements in the Ozona area.

The average NGLs price increased for the year ended December 31, 2010, primarily due to higher crude-oil prices and sustained global petrochemical demand. For the year ended December 31, 2009, average NGLs prices decreased primarily due to decreased global petrochemical demand as a result of the economic downturn.

Gathering, Processing and Marketing Margin

millions except percentages

                                
   2010      Inc/(Dec)
vs. 2009
    2009      Inc/(Dec)
vs. 2008
    2008  

Gathering, processing and marketing sales

   $ 833        14   $ 728        (33 )%    $     1,082  

Gathering, processing and marketing expenses

     615               617        (23     800  
                              

Margin

   $     218        96     $     111        (61   $ 282  
                              

For the year ended December 31, 2010, gathering, processing and marketing margin increased $107 million. The increase was primarily due to higher margins associated with natural-gas sales from inventory, an increase in processed NGLs volumes and higher NGLs prices, both of which increased margins under percent-of-proceeds and keep-whole contracts, partially offset by the absence of gas-processing margins associated with assets divested in 2009.

For the year ended December 31, 2009, gathering, processing and marketing margin decreased $171 million. The decrease was primarily due to lower market prices for natural gas, NGLs and condensate, which led to reduced gas processing margins, lower margins associated with firm transportation contracts due to price differentials between supply and market areas, and unrealized losses on derivatives related to gas-storage activity, which is seasonal in nature, in that the margin realized on the future sale of stored volumes covered by these derivative instruments is expected to more than offset the recorded unrealized losses. These amounts were partially offset by increases in crude- oil and NGLs marketing margins, which were largely attributable to inventory write-downs to market value that occurred in the fourth quarter of 2008.

Gains (Losses) on Divestitures and Other, net

Gains on divestitures in 2010 were $29 million and related primarily to the divestiture of onshore United States oil and gas properties. Proceeds from the sale of these properties were $70 million. Gains on divestitures in 2009 were $44 million, primarily related to the sale of oil and gas properties in Qatar. Proceeds from the sale of oil and gas properties and midstream properties in 2009 were $109 million and $67 million, respectively. Gains on divestitures in 2008 were $1.2 billion, primarily related to the divestiture of certain oil and gas properties in Brazil, onshore United States and the Gulf of Mexico. Proceeds from 2008 divestitures were $2.5 billion and were used to reduce debt.

 

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In 2008, gains (losses) on divestitures and other, net include a net $82 million ($52 million after tax) reduction related to corrections resulting from the analysis of property records after the adoption of the successful efforts method of accounting. This net amount includes a reduction of $163 million related to 2007. Management concluded that this misstatement was not material relative to 2007 interim and annual results, or to the 2008 periods, and corrected the error in the first quarter of 2008.

Reversal of Accrual for DWRRA Dispute

In January 2006, the Department of the Interior (DOI) issued an order (the 2006 Order) to Kerr-McGee Oil and Gas Corporation (KMOG), a subsidiary of Kerr-McGee Corporation (Kerr-McGee), to pay oil and gas royalties and accrued interest on KMOG’s deepwater Gulf of Mexico production associated with eight 1996, 1997 and 2000 leases, for which KMOG considered royalties to be suspended under the Deepwater Royalty Relief Act (DWRRA). KMOG successfully appealed the 2006 Order, and the DOI’s petition for a writ of certiorari with the United States Supreme Court was denied on October 5, 2009.

Based on the U.S. Supreme Court’s denial of the DOI’s petition for review by the court, Anadarko reversed its $657 million accrued liability in the third quarter of 2009 for royalties on leases listed in the 2006 order, as well as on similar orders to pay issued in 2008 and 2009, and other deepwater Gulf of Mexico leases with similar price threshold provisions. In addition, the Company reversed its $78 million accrued liability for unpaid interest on these amounts in the third quarter of 2009. Effective October 1, 2009, royalties and interest are no longer being accrued for deepwater Gulf of Mexico leases that have royalties suspended under the DWRRA. For more information on the DWRRA dispute, see Note 15—Contingencies—Deepwater Royalty Relief Act in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Costs and Expenses

millions except percentages

                                
   2010      Inc/(Dec)
vs. 2009
    2009      Inc/(Dec)
vs. 2008
    2008  

Oil and gas operating

   $     830        (3 )%    $ 859        (17 )%    $     1,036  

Oil and gas transportation and other

     816        23       664        7       621  

Exploration

     974        (12         1,107        (19     1,369  

For the year ended December 31, 2010, oil and gas operating expenses decreased primarily due to decreased workover costs of $28 million in the Gulf of Mexico as a result of the Moratorium and subsequent delays in obtaining permits. For the year ended December 31, 2009, oil and gas operating expenses decreased primarily as a result of cost savings programs initiated in response to the reduction in oil prices in 2008 and 2009. Cost savings were achieved through operating efficiencies, deferral of certain workovers and vendor negotiations. These cost savings were realized primarily through lower workover costs and surface maintenance costs of $48 million and $21 million, respectively. Additional reductions were due to lower production handling costs of $54 million, primarily in the Gulf of Mexico due to repair-related pipeline downtime. In 2011, the Company expects to maintain efforts to manage costs more efficiently through its knowledge transfer initiatives and supply chain management negotiations; however, oil and gas operating expense per BOE could increase. Additionally, the costs of doing business in the Gulf of Mexico could increase due to the permit-timing delays and compliance with heightened BOEMRE regulatory requirements.

For the year ended December 31, 2010, oil and gas transportation and other expenses increased due to higher gas gathering and transportation costs of $77 million and $45 million, primarily attributable to increased production in the Rockies and the Southern and Appalachia Region, respectively, and the expensing of $27 million of idle drilling rig lease payments and $19 million of rig termination fees incurred in 2010 related to deepwater drilling rigs in the Gulf of Mexico. See Note 15—Contingencies—Deepwater Drilling Moratorium and Other Related Matters in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for discussion regarding the Company’s decision to invoke force majeure on certain drilling rigs in the Gulf of Mexico. Partially offsetting this increase in oil and gas transportation and other expenses was $29 million of drilling rig contract termination fees incurred in 2009 as a result of low 2009 commodity prices. For the year ended December 31, 2009, oil and gas transportation and other expenses increased due to incremental transportation fees paid on increasing volumes in the Rockies of $41 million, and $29 million of drilling rig contract termination fees discussed above. These increases were partially offset by a decline in surface owner fees in the Rockies of $21 million due to lower 2009 commodity prices.

 

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Exploration expense decreased $133 million for the year ended December 31, 2010, primarily due to a $128 million decline in dry hole expense in the United States, lower termination costs of $15 million in various international locations, and other items, partially offset by higher dry hole expense of $26 million in various other international locations, including Brazil, Ghana and Mozambique. Exploration expense for 2010 includes $46 million related to the Macondo well. Exploration expense decreased by $262 million for the year ended December 31, 2009, primarily due to lower impairments of unproved properties of $205 million and lower geological and geophysical expense of $87 million. The decrease in impairments of unproved properties related primarily to Gulf of Mexico properties partially offset by an increase in unproved property impairments in China due to the drilling of an unsuccessful well with no additional exploration plans. The decrease in geological and geophysical expense was primarily related to seismic data which was acquired and expensed in 2008 for Mozambique and Indonesia.

millions except percentages

                                
   2010      Inc/(Dec)
vs. 2009
    2009      Inc/(Dec)
vs. 2008
    2008  

General and administrative

   $ 982          $ 983        14   $ 866  

Depreciation, depletion and amortization

         3,714        5           3,532        11           3,194  

Other taxes

     1,068        43       746        (49     1,452  

Impairments

     216        88       115        (48     223  

For the year ended December 31, 2010, general and administrative (G&A) expense decreased due to lower bonus plan expense of $67 million, offset by higher legal and consulting fees of $56 million primarily due to costs associated with the Tronox Incorporated (Tronox) bankruptcy and the Deepwater Horizon events, and higher employee-related costs of $11 million. The Company expects insurance costs to increase in 2011 as a result of higher coverage and related rates resulting from the Deepwater Horizon events that will be in effect for the full year in 2011 versus only part of 2010. In addition, the Company expects employee costs to increase primarily due to increased pension costs associated with changes in discount rates as well as increased headcount. The Company also expects legal expenses to increase in 2011 primarily due to Deepwater Horizon litigation; however, legal expenses related to Tronox are expected to decrease in 2011. See Legal Proceedings under Item 3 of this Form 10-K. For the year ended December 31, 2009, G&A expense increased primarily due to bonus plan expense. The increase was primarily related to a supplemental bonus plan, the payment of which was triggered by the Company’s total-shareholder-return performance relative to a group of peer companies. The performance resulted in significantly increased market value relative to the peer-group-average performance, and all non-officer employees qualified for prescribed payments under the plan.

For the year ended December 31, 2010, depreciation, depletion and amortization (DD&A) increased $182 million primarily due to a $209 million increase attributable to higher production volumes and $89 million associated with depleted fields in the Gulf of Mexico, partially offset by lower DD&A rates attributable to reserve increases in the Marcellus shale and the Maverick basin. For the year ended December 31, 2009, DD&A increased $338 million primarily due to a $237 million increase attributable to higher sales volumes and an $84 million increase attributable to higher DD&A rates that were driven by higher accumulated costs associated with acquiring, finding and developing oil and gas reserves.

For the year ended December 31, 2010, other taxes increased $322 million primarily due to higher commodity prices and volumes resulting in increased Algerian exceptional profits tax of $129 million, increased United States production and severance taxes of $118 million, and increased Chinese windfall profits tax of $44 million. In addition, higher assessed property values increased ad valorem taxes by $30 million. For the year ended December 31, 2009, other taxes decreased $706 million primarily due to lower commodity prices, which resulted in lower United States production and severance taxes of $343 million, lower Algerian exceptional profits tax of $269 million, lower Chinese windfall profits tax of $60 million, and lower ad valorem taxes of $32 million.

 

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Impairments for the year ended December 31, 2010, included $145 million of oil and gas exploration and production operating segment properties located in the United States. The properties in the United States include $114 million related to a production platform that remains idle with no immediate plan for use, and for which a limited market currently exists. The platform was impaired to its estimated fair value of $25 million. Impairments for the year ended December 31, 2010, also included $61 million ($23 million net of tax) related to the Company’s investment in Venezuelan assets that was impaired to its estimated fair value. The Company’s remaining after-tax net investment in these Venezuelan assets is $70 million. Also, for 2010, impairments included $8 million of marketing operating segment impairments related to the impairment of firm transportation contracts and $2 million of midstream operating segment assets. Impairments for the year ended December 31, 2009, related to $86 million of marketing operating segment assets, $22 million of oil and gas exploration and production operating segment properties in the United States and $7 million of midstream operating segment assets. The marketing operating segment impairments related to the impairment of firm transportation contracts, caused by narrowing margins between areas connected by acquired pipelines, and LNG facility-site properties.

Other (Income) Expense

millions except percentages

                              
   2010     Inc/(Dec)
vs. 2009
    2009     Inc/(Dec)
vs. 2008
    2008  

Interest Expense

          

Current debt, long-term debt and other

   $     856       17   $     734       (4 )%    $     762  

Midstream subsidiary note payable to a
related party

     24       (38     39       (64     109  

(Gain) loss on early debt retirements and
commitment termination

     103       NM        (2     88       (16

Capitalized interest

     (128     (86     (69     44       (123
                            

Interest expense

   $ 855       22     $ 702       (4   $ 732  
                            

 

NM—not meaningful

Anadarko’s interest expense increased for the year ended December 31, 2010, primarily due to the reversal of $78 million in 2009 for previously accrued interest expense related to the DWRRA dispute, $17 million of costs expensed in 2010 in connection with the termination of a contemplated but unexecuted term-loan facility, $12 million of amortized debt issuance costs associated with the $5.0 billion Facility, and $9 million of expensed unamortized debt issuance costs, the recognition of which was triggered by the retirement of the Midstream Subsidiary Note Payable to a Related Party due 2012 (Midstream Subsidiary Note). Also, for 2010, interest expense included losses on early retirements of debt of $86 million, resulting from the repurchase of $1.4 billion aggregate principal amount of senior notes during 2010. These increases were partially offset by increases in capitalized interest of $59 million due to higher construction-in-progress balances related to long-term capital projects. Future interest expense is expected to increase due to amortization of issuance costs related to the $5.0 billion Facility and capital lease obligations. Anadarko’s interest expense decreased for the year ended December 31, 2009, primarily due to the reversal of $78 million of previously accrued interest expense related to the DWRRA dispute, lower interest expense of $70 million due to the partial retirement of the Midstream Subsidiary Note and lower interest expense of $60 million due to the retirement of $1.4 billion in aggregate principal amount of Floating-Rate Notes during 2009, partially offset by interest expense of $108 million on $2.0 billion of debt issued in 2009 and $14 million primarily related to 2008 gains on early debt retirements. Also, in 2009, capitalized interest decreased $54 million due to lower capitalized costs that qualified for interest capitalization. For additional information, see Liquidity and Capital Resources—Uses of Cash—Debt Retirements and Repayments and Interest-Rate Risk under Item 7A of this Form 10-K.

 

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millions except percentages

                              
   2010     Inc/(Dec)
vs. 2009
    2009     Inc/(Dec)
vs. 2008
    2008  

(Gains) Losses on Commodity Derivatives, net

          

Realized (gains) losses

          

Natural gas

   $ (513     85   $ (277     166   $ (104

Oil and condensate

     15       (130     (50     111       443  
                            

Total realized (gains) losses

     (498     52       (327     196       339  
                            

Unrealized (gains) losses

          

Natural gas

     (353     180       444       NM        (380

Oil and condensate

     (42     114       291       (156     (520
                            

Total unrealized (gains) losses

     (395     154       735       (182     (900
                            

Total (gains) losses on commodity derivatives, net

   $     (893     NM      $     408       (173   $     (561
                            

The Company utilizes commodity derivative instruments to manage the risk of a decrease in the market prices for its anticipated sales of natural gas and crude oil. The change in (gain) loss on commodity derivatives, net includes the impact of derivatives entered into or settled and price changes related to positions open at December 31 of each year. For additional information on (gains) losses on commodity derivatives, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

millions except percentages

                                
   2010      Inc/(Dec)
vs. 2009
    2009     Inc/(Dec)
vs. 2008
       2008    

(Gains) Losses on Other Derivatives, net

            

Realized (gains) losses—interest-rate
derivatives and other

   $         (100 )%    $ (525     NM       $   

Unrealized (gains) losses—interest-rate
derivatives and other

     285        NM        (57     NM         7  
                              

Total (gains) losses on other derivatives, net

   $     285        (149   $     (582     NM       $     7  
                              

Anadarko enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to interest-rate changes. In December 2008 and January 2009, Anadarko entered into interest-rate swap contracts as a fixed-rate payor to mitigate the cost of potential 2011 and 2012 debt issuances. During periods of declining ten- and thirty-year U.S. Treasury yields, the fair value of this swap portfolio declines, as was the case during the year ended December 31, 2010. Conversely, when ten- and thirty-year U.S. Treasury yields rise, the fair value of this swap portfolio increases, as occurred during the year ended December 31, 2009. In 2009, the Company revised its contract terms which increased the weighted-average interest rate of the Company’s swap portfolio from approximately 3.25% to approximately 4.80%, resulting in a realized gain of $552 million. For additional information, see Interest-Rate Risk under Item 7A of this Form 10-K.

 

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millions except percentages

                              
   2010     Inc/(Dec)
vs. 2009
    2009     Inc/(Dec)
vs. 2008
    2008  

Other (Income) Expense, net

          

Interest income

   $ (13     (32 )%    $ (19     (57 )%    $ (44

Other

     (106     NM        (24     124       99  
                            

Total other (income) expense, net

   $     (119     177      $     (43     178     $     55  
                            

Under the terms of the Master Separation Agreement (together with all annexes, related agreements, and ancillary agreements to it, the MSA) entered into between Kerr-McGee and Tronox, a former wholly owned subsidiary of Kerr-McGee that held Kerr-McGee’s chemical business, Kerr-McGee agreed to reimburse Tronox for 50% of certain qualifying environmental-remediation costs incurred and paid by Tronox and its subsidiaries before November 28, 2012, subject to certain limitations and conditions. The reimbursement obligation under the MSA was limited to a maximum aggregate reimbursement of $100 million. During 2010, the Company reversed its $95 million liability for this reimbursement obligation to other (income) expense, net as a result of the cancellation of the MSA by Tronox that occurred as part of Tronox’s bankruptcy proceedings. See Note 14—Commitments and Note 15—Contingencies in the Notes to Consolidated Financial Statements under Item 8, and Legal Proceedings under Item 3 of this Form 10-K for further discussion of events related to Tronox and this obligation.

In addition, changes in foreign currency exchange rates lowered other income by $54 million (losses of $2 million in 2010 compared to gains of $52 million in 2009) for the year ended December 31, 2010, primarily attributable to cash held in escrow pending final determination of the Company’s Brazilian tax liability attributable to its 2008 divestiture of the Peregrino field offshore Brazil.

For 2009, the increase in total other income was primarily related to changes in foreign currency exchange rates of $70 million due to cash held in escrow pending final determination of the Company’s Brazilian tax liability attributable to its 2008 divestiture of the Peregrino field offshore Brazil.

Income Tax Expense

millions except percentages

                  
   2010     2009     2008  

Income tax expense (benefit)

   $     820     $     (5   $     2,148  

Effective tax rate

     50     5     40

The increase from the 35% statutory rate for the year ended December 31, 2010, is primarily attributable to the following:

 

   

the accrual of the Algerian exceptional profits tax that is non-deductible for Algerian income tax purposes;

 

   

U.S. tax on foreign income inclusions and distributions;

 

   

foreign tax rate differential and valuation allowance; and

 

   

the unfavorable resolution of uncertain tax positions.

These amounts were partially offset by the following:

 

   

U.S. income tax impact from losses and restructuring of foreign operations; and

 

   

the federal manufacturing deduction and other items.

The decrease from the 35% statutory rate for the year ended December 31, 2009, is primarily attributable to the following:

 

   

the accrual of the Algerian exceptional profits tax;

 

   

foreign tax rate differential and valuation allowance; and

 

   

U.S. tax on foreign income inclusions and distributions.

 

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These amounts were partially offset by the following:

 

   

benefits associated with changes in uncertain tax positions;

 

   

state income taxes, including a change in the state income tax rate expected to be in effect at the time the Company’s deferred state income tax liability is expected to be settled or realized; and

 

   

U.S. income tax impact from losses and restructuring of foreign operations and other items.

The increase from the 35% statutory rate for the year ended December 31, 2008, is primarily attributable to the following:

 

   

the accrual of the Algerian exceptional profits tax;

 

   

U.S. tax on foreign income inclusions and distributions; and

 

   

state income taxes and other items.

For additional information on income tax rates, see Note 17—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Net Income Attributable to Noncontrolling Interests

For the years ended December 31, 2010, 2009 and 2008, the Company’s net income attributable to noncontrolling interests of $60 million, $32 million and $23 million, respectively, primarily related to the public ownership interests in Western Gas Partners, LP (WES), a consolidated subsidiary of the Company. Public ownership of WES was 51.5%, 43.2% and 36.7% at year-end 2010, 2009 and 2008, respectively. See Note 7—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

OPERATING RESULTS

Segment Analysis—Adjusted EBITDAX    To assess the operating results of Anadarko’s segments, the chief operating decision maker analyzes income (loss) from continuing operations before income taxes, interest expense, exploration expense, DD&A, impairments, and unrealized (gains) losses on derivative instruments, net, less net income attributable to noncontrolling interests (Adjusted EBITDAX). Anadarko’s definition of Adjusted EBITDAX, which is not a GAAP measure, excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. The Company’s definition of Adjusted EBITDAX also excludes exploration expense, as exploration expense is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. In addition, unrealized (gains) losses on derivative instruments, net are excluded from Adjusted EBITDAX since these unrealized (gains) losses are not considered to be a measure of asset-operating performance. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions to stockholders.

Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies. Therefore, Anadarko’s consolidated Adjusted EBITDAX should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect net income (loss) attributable to common stockholders and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Anadarko’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) from continuing operations before income taxes.

 

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Adjusted EBITDAX

millions except percentages

                              
   2010     Inc/(Dec)
vs. 2009
    2009     Inc/(Dec)
vs. 2008
    2008  

Income (loss) from continuing operations before income taxes

   $ 1,641       NM      $ (108     (102 )%    $ 5,368  

Exploration expense

     974       (12 )%      1,107       (19     1,369  

DD&A

     3,714       5       3,532       11       3,194  

Impairments

     216       88       115       (48     223  

Interest expense

     855       22       702       (4     732  

Unrealized (gains) losses on derivative instruments, net*

     (114     (116     717       178       (922

Less: Net income attributable to noncontrolling
interests

     60       88       32       39       23  
                            

Consolidated Adjusted EBITDAX

   $     7,226       20     $     6,033       (39   $     9,941  
                            

Adjusted EBITDAX by segment

          

Oil and gas exploration and production

   $ 6,689       22     $ 5,463       (47   $ 10,332  

Midstream

     387       19       324       (24     428  

Marketing

     7       106       (110     NM &nbs