FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011
Table of Contents
Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x

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

For the fiscal year ended December 31, 2011

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, 2011 was $38.1 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, 2012, is shown below:

 

Title of Class   Number of Shares Outstanding
Common Stock, par value $0.10 per share   498,427,854

 

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 15, 2012 (to be filed with the Securities and Exchange Commission prior to April 5, 2012).


Table of Contents
Index to Financial Statements

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

     7   
  

Proved Reserves

     11   
  

Sales Volumes, Prices, and Production Costs

     15   
  

Delivery Commitments

     16   
  

Drilling Program

     16   
  

Drilling Statistics

     16   
  

Productive Wells

     17   
  

Properties and Leases

     18   
  

Midstream Properties and Activities

     18   
  

Marketing Activities

     19   
  

Competition

     20   
  

Segment Information

     20   
  

Employees

     20   
  

Regulatory Matters, Environmental, and Additional Factors
Affecting Business

     21   
  

Title to Properties

     27   
  

Executive Officers of the Registrant

     27   

Item 1A.

  

Risk Factors

     29   

Item 1B.

  

Unresolved Staff Comments

     43   

Item 3.

  

Legal Proceedings

     43   

Item 4.

  

Mine Safety Disclosures

     43   

PART II

     

Item 5.

  

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

     44   

Item 6.

  

Selected Financial Data

     47   

Item 7.

  

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

     48   

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

     80   

Item 8.

  

Financial Statements and Supplementary Data

     82   

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure

     157   

Item 9A.

  

Controls and Procedures

     157   

Item 9B.

  

Other Information

     157   

PART III

     

Item 10.

  

Directors, Executive Officers, and Corporate Governance

     158   

Item 11.

  

Executive Compensation

     158   

Item 12.

  

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

     158   

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

     158   

Item 14.

  

Principal Accountant Fees and Services

     158   

PART IV

     

Item 15.

  

Exhibits, Financial Statement Schedules

     159   


Table of Contents
Index to Financial Statements

PART I

Items 1 and 2.  Business and Properties

GENERAL

Anadarko Petroleum Corporation is among the world’s largest independent exploration and production companies, with over 2.5 billion barrels of oil equivalent (BOE) of proved reserves at December 31, 2011. 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 asset portfolio is aimed at delivering long-term value to stakeholders by combining a large inventory of development opportunities in the United States onshore with high-potential worldwide offshore exploration and development activities.

Anadarko’s asset portfolio 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 independent producers in the deepwater Gulf of Mexico, and has production and exploration activities worldwide including positions in high-potential basins located in East and West Africa, Algeria, China, Alaska, and New Zealand.

Anadarko is committed to producing energy in a manner that protects the environment and public health. 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 distinct operational differences and unique technology, and distribution and marketing requirements. The Company’s three reporting 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 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.

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.

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 website 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.

 

LOGO

 

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Index to Financial Statements

United States

Overview  Anadarko’s operations in the United States include oil and natural-gas exploration and production onshore in the Lower 48 states, onshore Alaska, and the deepwater Gulf of Mexico. The Company’s operations in the United States accounted for 87% of total sales volumes during 2011 and 90% of total proved reserves at year-end 2011.

Onshore  In 2011, the Company’s shale plays delivered a year-over-year sales-volume increase of almost 200%. Shale volumes now account for slightly more than 10% of the Company total sales volumes, which is up from less than one percent two years ago. Shales also represent about five percent of Anadarko’s total proved reserves.

Rocky Mountains Region  Anadarko’s Rocky Mountains Region (Rockies) properties are located in Colorado, Utah, and Wyoming and are a combination of oil and natural-gas plays, with significant growth and capital investment in areas that offer higher liquids yields (liquids-rich areas). Anadarko operates approximately 14,300 wells and has an interest in approximately 9,500 non-operated wells in the Rockies. Anadarko operates fractured carbonate/shale reservoirs, tight gas assets, and coalbed methane (CBM) natural-gas assets, as well as enhanced oil recovery (EOR) projects within the region. The Company also has fee ownership of mineral rights under approximately 8 million acres that passes through Colorado and Wyoming and into Utah (Land Grant). Management considers the Land Grant a significant competitive advantage to Anadarko because it offers liquids-rich drilling opportunities for the Company, and allows the Company to capture incremental royalty revenue from third-party activity in the area. Activities in the Rockies continue to focus on expanding the 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. During 2011, total sales volumes in the Rockies increased 10% over 2010, with an 18% increase in liquids volumes. In 2011, the Company drilled 1,029 wells in the Rockies and plans to accelerate its drilling program in the region in 2012.

In 2011, the Company was dedicated to the development of new horizontal opportunities in the Niobrara and other formations in the Denver-Julesburg basin, which includes the Wattenberg field. The Niobrara is a naturally fractured carbonate formation that holds liquids and natural gas. During 2011, the Company drilled 33 horizontal wells in the Wattenberg field, focusing on liquids-rich areas in the Niobrara and Codell formations. The Company also drilled 17 horizontal wells in the Denver-Julesburg basin (outside the Wattenberg field) and the Powder River basin as part of the horizontal program.

The Wattenberg field is a liquids-rich area where Anadarko operates over 5,300 wells. During 2011, the Company drilled 433 vertical/directional wells in the Wattenberg field and increased sales volumes 19% compared to 2010, with a year-over-year 32% increase in liquids volumes. Horizontal drilling results in the Wattenberg field have shown strong initial production rates with average liquids yields of approximately 70%. The Company has also identified 1,200 to 2,700 future potential drilling locations in the Niobrara and Codell sandstone that provide substantial opportunity for expanding Anadarko’s activity in these formations. The competitive advantage provided by mineral ownership in the Land Grant, the liquids-rich reservoirs, strong well performance, low development costs, and expandable midstream infrastructure each provide tangible benefits to the Company and position it to accelerate its horizontal drilling program in the Wattenberg field. The Company plans to increase its activity by deploying seven horizontal rigs and drilling approximately 160 horizontal wells in 2012.

 

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The Greater Natural Buttes area in eastern Utah is one of the Company’s major tight gas assets, where the Company is focusing on liquids-rich areas. The Company utilizes refrigeration and cryogenic processing facilities to extract natural-gas liquids from the gas stream. The Company operates over 2,200 wells in the Greater Natural Buttes area, drilled 288 wells in 2011, and increased year-over-year sales volumes from the area by 23%. The Company has identified more than 6,000 potential locations in the Greater Natural Buttes area for future development in the Mesaverde formation. Many of these locations are infill drilling opportunities focused on down-spacing from 40-acre well density to 10-acre well density. Anadarko drilled and completed the lower Mesaverde Blackhawk interval in 56 new development wells during 2011. This is a capital-efficient program with incremental development costs of approximately $0.50 per-Mcf equivalent. The Company’s other tight-gas assets in the Rockies are located in the Greater Green River area in Wyoming. Anadarko is expanding the cryogenic facilities at its Chipeta plant to increase contracted cryogenic processing capacity to 500 MMcf/d by the third quarter of 2012. This expansion is expected to result in an incremental gross recovery of over 15,000 barrels of NGLs per day.

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 4,000 low-cost CBM wells and has an interest in approximately 4,500 non-operated CBM wells in the Rockies. In 2011, Anadarko reduced development activity in its CBM program as the Company continued to allocate its capital spending toward its liquids-rich opportunities. A reduction in CBM development activity is expected to continue in 2012 as a result of low natural-gas prices.

The Company’s EOR operations increase the amount of oil that can be produced from mature reservoirs after primary and water-flood recovery methods have been completed. During 2011, the Company continued to pursue development of its Rockies EOR assets at the Monell and Salt Creek fields in Wyoming. Monell field development is near completion with a small drilling program scheduled to finish edge-pattern development, and some minor infrastructure investments planned for 2012 to enhance carbon dioxide flooding operations. Throughout 2012, the Company plans to progress the tertiary recovery operations at Salt Creek, which the Company has been continuously implementing since 2003.

Southern and Appalachia Region  Anadarko’s Southern and Appalachia Region properties are primarily located in Texas, Pennsylvania, Louisiana, Kansas, and Ohio. 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 an interest in approximately 705,000 net acres in shale and other emerging-growth plays throughout the Southern and Appalachia Region. These plays include the Eagleford/Pearsall shales in southwest Texas, the Marcellus shale in north-central Pennsylvania, the Bone Spring formation and Avalon shale in the Delaware basin of West Texas, the Haynesville shale in East Texas and Louisiana, and the Utica shale in eastern Ohio. 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.

In 2011, the Company drilled 442 wells and completed 364 wells in the Southern and Appalachia Region. Over 97% of the operated wells were drilled horizontally. By utilizing modernized drilling rigs and experienced crews, the region continued to experience improved drilling efficiencies in every area with respect to cycle times, while also drilling longer lateral lengths. Due to lower natural-gas prices, the Company is focusing its drilling activity in liquids-rich areas, such as the Eagleford shale and the Bone Spring and Avalon formations.

 

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The Eagleford shale continues to be one of the Company’s most economic plays, capable of generating returns in excess of 100%. In the first quarter of 2011, Anadarko entered into a joint-venture agreement that conveyed 33.3% of the Company’s Eagleford and Pearsall shale assets to a third party. The third party acquired 96,000 net acres (80,000 acres within the Eagleford shale and the underlying Pearsall shale rights, and an additional 16,000 acres limited to Pearsall shale rights only) in exchange for funding $1.6 billion of Anadarko’s future drilling costs. The funding began in the second quarter of 2011 and covered $500 million of the Company’s 2011 development costs. The funding covers 90% of Anadarko’s development costs in subsequent years up to a $650 million annual limit. Based on expected activity, the third-party funding is expected to be fully utilized in the second half of 2013. Anadarko currently holds approximately 405,500 gross and 193,000 net acres with an average working interest of approximately 49% in this area. During 2011, the Company operated an average of nine rigs, which spud 228 horizontal wells and completed 197 wells. The Company began the year producing 14,300 net (27,000 gross) barrels of oil equivalent per day (BOE/d) and ended the year at over 27,400 net (77,000 gross) BOE/d, after completing over 3,200 fracturing stages during the year.

In the Appalachian basin, where the Marcellus shale is being developed, 134 operated horizontal wells were spud and 73 wells were completed utilizing a fleet that averaged seven rigs for the year. Anadarko also participated in 148 new horizontal wells and 135 completions as a non-operating partner in the area. Anadarko has 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 in exchange for funding $1.4 billion of Anadarko’s drilling costs. The third party funded 100% of the Company’s 2010 development costs and 90% of these costs in 2011. The third party will continue to fund 90% of the development costs until the funding commitment is exhausted, which is anticipated to occur in 2012. Anadarko’s production in the area increased from a net 2010 year-end exit rate of 84 million cubic feet per day (MMcf/d) of natural gas to a net year-end exit rate of 230 MMcf/d.

During 2011, the Company accumulated over 370,000 gross acres in the prospective liquids-rich area of the eastern Ohio Utica shale in the Appalachian basin. Two Utica horizontal pilot wells reached total depth in the fourth quarter of 2011 and Anadarko plans to accelerate the pilot and testing program in 2012.

Anadarko owns 330,000 net acres in the Delaware basin, which has seen significant drilling activity, primarily targeting the liquids-rich Bone Spring formation and Avalon shale. In 2011, Anadarko spud 50 operated wells, participated in 27 non-operated wells, and completed 54 operated wells and 27 non-operated wells in the area. Drilling and well performance continue to improve with well tests producing in excess of 2,000 BOE/d. The Company had four rigs drilling in the Bone Spring formation and one rig drilling in the Avalon shale at year-end 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 2011 with eight wells drilled. In 2012, the Company anticipates participating in approximately 12 development wells and the sanctioning of the Alpine West satellite development.

Gulf of Mexico  In the Gulf of Mexico, Anadarko owns an average 64% working interest in 487 blocks. The Company operates seven active floating platforms, holds interests in 34 producing fields, and is in the process of delineating and developing six additional fields in the area.

Following a period of significantly reduced activity as a result of the drilling moratorium in 2010, during 2011, the Company resumed an active deepwater exploration and appraisal program in the Gulf of Mexico and is continuing to take advantage of existing infrastructure to accelerate resource development at reduced costs. Anadarko made its first post-moratorium deepwater discovery at the Cheyenne East prospect, which is being developed as a tieback to the Independence Hub (IHUB) and is expected to produce 60 MMcf/d of natural gas. First production from this well is expected by March 2012. The Company also completed a workover at the Spiderman IHUB well, resulting in natural-gas production at a rate in excess of 90 MMcf/d. In 4.5 years since first production, aggregate IHUB production surpassed one trillion cubic feet (Tcf) in early 2012. In Green Canyon Block 903, the Heidelberg appraisal well (44% operated working interest) began drilling in October 2011, and was declared successful in February 2012. The Company plans to sidetrack the well to evaluate the down-dip extent of the field.

 

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During 2011, Anadarko continued to advance the Lucius field development. The unitization agreement for the Anadarko-operated Lucius field was signed during the second quarter of 2011, and the Lucius project was sanctioned during the fourth quarter of 2011 with first production expected in 2014. A production-handling agreement to process natural gas from the Hadrian South field at the Lucius facility was executed with the Hadrian South co-venturers, and will add additional value to the Lucius development. The Company completed a successful well test at Lucius, which showed that the well is capable of flowing in excess of 15,000 barrels per day (Bbls/d) of oil and that the main pay intervals are well connected. Lucius will be developed with a truss spar floating production facility with the capacity to produce in excess of 80,000 Bbls/d of oil and 450 MMcf/d of natural gas. The spar is currently under construction and will be the largest of Anadarko’s operated spars. The Company plans to have an active drilling program in the area beginning in 2012, with plans to drill its Spartacus prospect during the year.

Anadarko continued advancing its development project at Caesar/Tonga. The Company completed and tested three wells that each demonstrated facility-constrained flow rates of approximately 15,000 Bbls/d of oil. First production is expected by mid-2012.

During 2011, Anadarko participated in the drilling of the Coronado #1 exploration well (15% working interest), located in Walker Ridge Block 143. The well spud in October 2011 and was plugged and abandoned as a result of unanticipated geopressure in the shallow section. At year-end 2011, seismic was being reviewed to determine a new well location. In June 2011, the Kakuna #1 subsalt exploration well spud. Anadarko has an option to acquire a 6.25% interest or an overriding royalty interest in the well, which is located in Green Canyon Block 505, north of the Company’s Caesar/Tonga development. In addition, the Vito NE appraisal well (20% non-operated working interest), located in Mississippi Canyon Block 940, spud in early 2012 and will test the northeast flank of the Vito discovery.

Due to the drilling moratorium, Anadarko redeployed its deepwater rigs to other parts of the world but retained the Ensco 8500 under a long-term contract for operations in the Gulf of Mexico. The Gulf of Mexico has regained momentum and the Bureau of Safety and Environmental Enforcement (BSEE) is approving drilling permits, which has prompted Anadarko to execute contracts for the Ensco 8505 rig, with delivery scheduled for the second quarter of 2012 and the Ensco 8506 rig, with delivery in the fourth quarter of 2012. Both the Ensco 8500 and the Ensco 8505 are shared rig contracts between Anadarko and other Gulf of Mexico operators. Also, the Transocean Spirit rig, currently working in West Africa, will be mobilized to the Gulf of Mexico in the latter part of 2012 to service the Company’s oil development projects and exploration activities in the Gulf of Mexico. Anadarko expects exploration and appraisal activities to return to pre-moratorium levels in 2012. In addition, Anadarko signed long-term lease agreements for two new-build state-of-the-art drillships. The Ocean BlackHawk is expected to be delivered in late 2013 and the Ocean BlackHornet is expected to be delivered in early 2014. These rigs are dual-activity and dual blowout-prevention rigs, reflecting Anadarko’s focus on continuing to enhance operational efficiency.

International

Overview  The Company’s international oil and natural-gas production and development operations are located primarily in Algeria, Ghana, and China. The Company also has exploration acreage in Ghana, Mozambique, Brazil, Liberia, Sierra Leone, Kenya, Cote d’Ivoire, New Zealand, Indonesia, and other countries. International locations accounted for 13% of Anadarko’s total sales volumes and 27% of sales revenues during 2011, as well as 10% of total proved reserves at year-end 2011. Anadarko drilled 33 wells in international areas in 2011, which included natural-gas discoveries in Mozambique and oil discoveries in Ghana. In 2012, the Company expects to drill approximately 25 development and 25 exploration wells at various international locations.

 

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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). The El Merk project progressed to approximately 88% overall completion at December 31, 2011, and remains on target for initial production in 2012 with significant gross volumes expected at the facility near the end of 2012. The percentage of overall completion captures the progress of ongoing construction work at the El Merk CPF and associated infrastructure such as offsite facilities, export pipelines, and power transmission lines. During 2011, 16 development wells were drilled in Blocks 404 and 208. The Company expects 2012 development drilling activity to be similar to 2011 levels, with continued 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 development and production costs, Anadarko is responsible for 24.5%, and its two partners are each responsible for 12.25%. 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.

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, 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. 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 by submitting a notice of arbitration to Sonatrach. The arbitration hearing on the merits of the claims presented by Anadarko took place in June 2011 and the Company anticipates the issuance of the arbitration panel’s decision in the near term. Any decision issued by the arbitration panel is binding on the parties.

Ghana  Anadarko’s exploration and development activities in Ghana are located offshore in the West Cape Three Points Block and the Deepwater Tano Block. In December 2010, 3.5 years following discovery, the Company and its partners achieved first oil from the Jubilee field. The Company and its partners completed execution of the Phase 1 development program and tied back 17 wells to the floating production, storage, and offloading vessel (FPSO) at the Jubilee field. The gross oil production level was approximately 70,000 Bbls/d at year-end 2011 from eight producing wells. Completion issues required a side-track of one of the original nine Phase 1 production wells in the fourth quarter of 2011 and two or three other producing wells have been identified as possible side-track operations in 2012. Once the completion issues have been resolved, production is expected to increase toward facility capacity of 120,000 Bbls/d. Work is also underway to execute the next phase of development which will tie back another eight wells to the Jubilee FPSO during 2012 and 2013.

 

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During 2011, the Company participated in 10 exploration and appraisal wells outside the Jubilee field, including the Akasa #1 discovery well in the West Cape Three Points Block (32% non-operated interest), two Teak discovery wells, and one Teak appraisal well to the Teak #1 discovery. The successful Teak appraisal well confirmed a northern extension of the discovery. The Company also participated in two successful Enyenra appraisal wells in the Deepwater Tano Block (18% non-operated working interest) and an additional appraisal of the Tweneboa discovery. A drillstem test (DST) conducted on the Tweneboa #2 well in the bottom oil leg of the reservoir and the DST performed at the Tweneboa #4 well confirmed the connectivity of the two wells. The Ntomme #2 was spud in late 2011 and reached total depth in 2012. This successful appraisal well tested the same targets discovered in the Tweneboa #3ST well and encountered oil pay in excellent-quality sandstone reservoirs. In 2012, the Company plans to participate in up to four exploration and appraisal wells in Ghana.

The Company and its partners anticipate declaration of commerciality for the Tweneboa/Enyenra/Ntomme field complex located in the Deepwater Tano Block during the second half of 2012 following completion of the appraisal program. In the West Cape Three Points Block, stand-alone FPSO and Jubilee tie-back development options are being evaluated to maximize the resource value from the Teak and Akasa discoveries.

Mozambique  Anadarko operates two blocks (one onshore and one offshore) in Mozambique totaling approximately six million gross acres. In 2011, the Company drilled two natural-gas discoveries (Tubarão and Camarão) and two successful appraisal wells (Barquentine #2 and Barquentine #3) in the Offshore Area 1 of the Rovuma basin where Anadarko holds a 36.5% working interest. In 2012, the Lagosta #2 and Lagosta #3 appraisal wells successfully appraised discoveries at Lagosta and Camarão. To date, the Company has eight successful wells in the complex, including the Windjammer, Lagosta, Barquentine and Camarão discoveries. As a result, the Company and its partners are continuing to advance a liquefied natural gas (LNG) development, which is being designed to consist of an initial two 5-million-tonne-per-annum trains. Anadarko plans to construct a flexible offshore production system to collect gas from the wells located approximately 35 miles (56 kilometers) offshore, which will deliver gas to the liquefaction plant onshore. Pre-FEED (front-end engineering and design) activities are complete and the Company expects to begin FEED work around the middle of 2012. The Company expects to reach a final investment decision at approximately year-end 2013, with first cargo sales targeted for late 2018.

Also during 2011, Anadarko acquired two new 3D seismic datasets which have led to a growing number of high-potential prospects in other areas of the Offshore Area 1. Early in 2012, Anadarko mobilized a second deepwater drillship to Mozambique to accelerate the planned exploration and appraisal activities, which include an extensive reservoir testing program and up to seven exploration and appraisal wells in 2012.

China  Anadarko’s development and production activities in China are located offshore in Bohai Bay. Development drilling was ongoing throughout 2011, and Anadarko drilled 19 wells during the year including eight side-tracks of low oil-rate/high water-cut producers. The majority of the wells were drilled from the platform expansion decks, which were installed as part of an initiative to sustain continued plateau production. An exploration well in the South China Sea is expected to spud in mid-2012. Consistent with the terms of the Petroleum Contract, the Company is preparing to transfer operatorship of the Bohai Bay development to China National Offshore Oil Corporation at the end of 2012.

Brazil  Anadarko holds exploration interests in approximately 750,000 gross acres in six blocks located offshore Brazil in the Campos and Espírito Santo basins. In these areas, Anadarko drilled two appraisal wells in 2011. In Block BM-C-32 (33% non-operated working interest) in the Campos basin, the successful Itaipu #2 pre-salt appraisal well established a fluid contact and appears to have successfully extended the accumulation 394 feet downdip from the Itaipu discovery well, which is located four miles to the northwest. The appraisal well significantly increases the areal extent of the Itaipu field. In Block BM-C-29 (50% working interest), the Ituana appraisal well was plugged and abandoned in 2012. The Company is reviewing the results of the well as part of the evaluation of the Ituana post-salt discovery. Anadarko expects to drill up to four exploration and appraisal wells in Brazil during 2012, including the Wahoo #4 appraisal well in Block BM-C-30 (30% operated working interest).

 

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Index to Financial Statements

During 2011, the Company began marketing its Brazilian properties and a sale is possible in 2012 subject to receiving acceptable pricing and terms and obtaining regulatory approval.

Liberia  The Company currently operates four blocks in offshore Liberia totaling approximately 3.3 million exploration acres in the Liberian basin. Multiple Cretaceous stratigraphic leads, similar to the Jubilee Mahogany fan, have been identified on these blocks. The Montserrado well was drilled in 2011 on Block LB-15 and encountered good-quality, water-bearing sands in the main objective and 27 net feet of pay in a secondary objective. The well was plugged and abandoned and the results are being incorporated into the Company’s geologic data for future exploration in the Liberian basin. Plans for 2012 include the incorporation of the drilling results into the 3D seismic on Blocks 15, 16, and 17, as well as the evaluation of the newly acquired 3D seismic in the LB-10 Block.

Sierra Leone  Anadarko operates and has a 55% participating interest in Block SL-07B-11 in offshore Sierra Leone encompassing approximately 1.2 million gross acres. Multiple Upper Cretaceous fan-type prospects have been identified in the lightly explored Liberian basin. The Jupiter #1 well, spud in the fourth quarter of 2011, targeted a large Cretaceous fan channel complex similar to the Enyenra and Tweneboa discoveries in Ghana. In 2012, the Jupiter #1 discovery well encountered hydrocarbon pay and has been preserved for possible re-entry, as the area will likely require additional evaluation. The Mercury #2 well, which will be drilled subsequent to Jupiter #1, will appraise the Mercury #1 discovery well that was announced as a discovery in 2010.

Kenya  Anadarko operates and has a 50% participating interest in five deepwater blocks offshore Kenya encompassing approximately 7.5 million gross acres. The Company has completed 2D and 3D seismic programs and evaluation is currently taking place with potential drilling possible in late 2012 or early 2013.

Côte d’Ivoire  During 2011, Anadarko and its partners began interpreting new 3D seismic data on two deepwater exploration blocks totaling approximately 850,000 gross acres offshore Côte d’Ivoire. Multiple Upper Cretaceous fan-type prospects have been identified on the 2D and 3D seismic. The Kosrou #1 well, spud in January 2012 on Block CI 105 (50% operated interest), has multiple targets within a large Cretaceous fan located south and east of the Company’s 2009 South Grand Lahou-1X well, which encountered thin sands with shows in the target. The Paon prospect located on Block CI 103 (40% non-operated interest) will be drilled following the Kosrou well. The geology on the block appears similar to that of the Jubilee, Enyenra, and Tweneboa discoveries in Ghana. In 2012, Anadarko purchased approximately 500,000 gross acres in Blocks CI 515 and CI 516 (45% operated interest).

New Zealand  Anadarko operates approximately 11.5 million exploration acres in the Taranaki and Canterbury basins in New Zealand. A 3D seismic survey of approximately 1,100 square miles was completed on the Taranaki Block in 2011, and a 2D seismic survey of approximately 2,400 miles was acquired over the Canterbury Blocks. Two exploration wells, one on each block, are planned for late 2012 subject to rig availability.

Indonesia  Anadarko has participating interests in approximately 3.4 million gross exploration acres in Indonesia through a combination of one operated and two non-operated Production Sharing Contracts. In 2012, the Company began marketing its Indonesian properties for sale.

Other  Anadarko also has exploration projects in other overseas, new-venture areas including Morocco, Tunisia, and South Africa.

 

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Index to Financial Statements

Proved Reserves

Estimates of proved reserves volumes owned at year end, net of third-party royalty interests, are presented in billion 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. Shrinkage associated with NGLs has been deducted from the natural-gas reserve volumes.

Disclosures by geographic area include United States and International. The International geographic area includes proved reserves located in Algeria, Ghana, and China, which by country and in total represents 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, 2011

           

Proved

           

Developed

           

United States

                 6,113                    352                    267                    1,638  

International

             173                173  

Undeveloped

           

United States

     2,252        184        94        653  

International

             62        13        75  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total proved

     8,365        771        374        2,539  
  

 

 

    

 

 

    

 

 

    

 

 

 

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  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Index to Financial Statements

The Company’s year-end 2011 product mix for proved reserves was 55% natural gas, 30% oil and condensate, and 15% NGLs; compared to a year-end 2010 product mix of 56% natural gas, 31% oil and condensate, and 13% NGLs; and a year-end 2009 product mix of 56% natural gas, 32% oil and condensate, and 12% NGLs.

The Company’s estimates of proved developed reserves, proved undeveloped reserves (PUDs), and total proved reserves at December 31, 2011, 2010, and 2009, 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 information with a federal authority or agency with respect to its estimated total proved reserves at December 31, 2011. Annually, Anadarko reports gross proved reserves of operated properties in the United States to the U.S. Department of Energy; these reported reserves are derived from the same data used to estimate and report proved reserves 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.

Changes in PUDs  Significant changes to PUDs occurring during 2011 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 the period. These PUDs 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 PUDs development within five years unless specific circumstances warrant a longer development time horizon.

 

MMBOE

  

PUDs at December 31, 2010

             749  

Revisions of prior estimates

     60  

Extensions, discoveries, and other additions

     112  

Conversion to developed

     (171

Sales

     (22
  

 

 

 

PUDs at December 31, 2011

     728  
  

 

 

 

PUDs Conversion  In 2011, the Company converted 171 MMBOE, or 23% of the total year-end 2010 PUDs, to developed status. Approximately 58% of PUDs conversions occurred in onshore U.S. assets, 26% in international assets, and the remaining 16% in Gulf of Mexico assets.

The majority of PUDs conversions occurred as a result of ongoing development activities in the Rockies and in the liquids-rich areas of the Southern and Appalachia Region. Approximately 96 MMBOE of PUDs were converted to developed reserves in these areas. The conversion of an additional 45 MMBOE of PUDs occurred in the international areas, most of which are associated with completed production wells in the El Merk project of Algeria where the overall project was approximately 88% complete at December 31, 2011. Another 26 MMBOE of PUDs converted to developed reserves were associated with ongoing development in the Caesar/Tonga project in the U.S. Gulf of Mexico where three completed wells are awaiting tie-back to production facilities. The remaining converted PUDs were a result of development activity in Alaska.

Anadarko spent $900 million associated with the development of PUDs in 2011. Approximately 68% of total 2011 PUDs conversion capital related to domestic development programs in the Rockies and the Southern and Appalachia Regions. Approximately 12% related to the development of the Caesar/Tonga and Lucius projects in the Gulf of Mexico, and 10% related to development of the El Merk project in Algeria. The remaining 10% of 2011 PUDs development spending was associated with Alaska and other international development projects.

 

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Index to Financial Statements

In 2010, the Company converted 103 MMBOE, or 15% of the total year-end 2009 PUDs to developed status. Approximately 65% of PUDs conversions occurred in onshore U.S. assets, 24% in international assets, and the remaining 11% in Gulf of Mexico assets. Anadarko spent $1.5 billion associated with the development of PUDs in 2010. Approximately 58% of total 2010 PUDs capital related to two major development projects, El Merk in Algeria and Jubilee in Ghana, and 29% related to domestic development programs in the Rockies and the Southern and Appalachia Regions. The remaining 13% of 2010 PUDs 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 U.S. PUDs are converted to developed reserves within five years of the initial proved reserves booking. Projects such as EOR, arctic development, deepwater development, and international programs may take longer than five years. All of the Company’s onshore U.S. PUDs were scheduled to be developed within five years at December 31, 2011, with the exception of the Salt Creek EOR project, the annual development of which is limited by CO2 supply contract terms and the amount of work that can be physically completed.

The Company had 101 MMBOE of pre-2007 PUDs that remain undeveloped five years or more after initial disclosure as PUDs. Approximately 50% 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. Site preparation was initiated in 2008 and construction of the El Merk CPF is continuing. As of year-end 2011, 85 wells have been drilled in the El Merk fields and drilling is continuing in 2012. The Reservoir Development Plan includes a total of 141 wells for full development. The overall El Merk project, including future drilling commitments, was approximately 88% complete at December 31, 2011. First oil production from the El Merk fields is expected to occur in 2012.

Another 42% of the Company’s pre-2007 PUDs are associated with the Salt Creek EOR single-development project located in the Rockies. Since 2003, Anadarko has invested an average of $65 million per year to develop various phases of the Salt Creek integrated EOR project and will continue significant spending levels in the future to complete the development. All of the remaining pre-2007 PUDs are associated with Gulf of Mexico opportunities where development timing is influenced by seasonal restrictions and the depletion of reserves from existing completions. The Company expects to complete these opportunities over the next three years.

Technologies Used in Proved Reserve Estimation  The Company’s 2011 proved reserves additions were based on estimates generated through the integration of pertinent geological, engineering, and production data, utilizing technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. Data used in these integrated assessments included information obtained directly from the subsurface through wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements such as seismic data. The tools used to interpret the data included proprietary and commercially available seismic processing software and commercially available reservoir modeling and simulation software. Reservoir parameters from analogous reservoirs were used to increase the quality of and confidence in the reserves estimates when available. The method or combination of methods used to estimate the reserves of each reservoir was based on the unique circumstances of each reservoir and the dataset available at the time of the estimate.

 

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Index to Financial Statements

Internal Controls over Reserves Estimation  Anadarko’s estimates of proved reserves and associated future net cash flows were made solely by the Company’s engineers and are the responsibility of management. The Company requires that reserves 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, net cash flows, and ultimate recoverable reserves. Management within each region approves the QREs’ reserve estimates. 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 Reserves Group (CRG).

The CRG ensures confidence in the Company’s reserves estimates by maintaining internal policies for estimating and recording reserves in compliance with applicable SEC definitions and guidance. Compliance with the SEC reserves 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 reserves reviews and approving the Company’s reserve estimates. The Director–Reserves Administration and the Corporate Reserves Manager manage the CRG and report to the Director–Corporate Planning. The Director–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 the Company’s 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 reserves estimates, has over 25 years of experience in the oil and gas industry, including over 11 years as either a reserves evaluator or manager. Further professional qualifications include a degree in petroleum engineering, extensive internal and external reserves training, and asset evaluation and management. In addition, the principal engineer is an active participant in industry reserves seminars, professional industry groups, and has been a member of the Society of Petroleum Engineers for over 25 years.

Third-Party Procedures and Methods Review  M&L reviewed 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, 2011. 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 85% of the Company’s estimates of proved reserves and associated future net cash flows at December 31, 2011. 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 reserves estimation and reporting processes.

 

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Index to Financial Statements

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 for each of the last three years. The Company’s sales volumes for 2011, 2010, and 2009 were 248 MMBOE, 235 MMBOE, and 220 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)        
    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)
    Average
Production
Costs(2)
(Per BOE)
 

2011

               

United States

               

Greater Natural Buttes

            135                       1                       4                       27       $  3.58       $  84.29       $  52.04        $  9.54   

Other United States

    717       47       23       190       3.93       97.93       54.28        9.48   
 

 

 

   

 

 

   

 

 

   

 

 

         

Total United States

    852       48       27       217       3.87       97.70       53.95        9.50   
 

 

 

   

 

 

   

 

 

   

 

 

         

International

           31              31              109.20              9.98   
 

 

 

   

 

 

   

 

 

   

 

 

         

Total

    852       79       27       248       3.87       102.24       53.95        9.55   
 

 

 

   

 

 

   

 

 

   

 

 

         

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   
 

 

 

   

 

 

   

 

 

   

 

 

         

 

Bcf—billion cubic feet

Mcf—thousand cubic feet

Bbl—barrel

 

(1) 

Excludes the impact of commodity derivatives.

 

(2) 

Excludes ad valorem and severance taxes.

 

15


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Index to Financial Statements

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, 2011, Anadarko was contractually committed to deliver approximately 775 Bcf of natural gas to various customers in the United States through 2021. These contracts have various expiration dates with approximately 50% of the Company’s current commitment to be delivered in 2012, and 85% by 2016. At December 31, 2011, Anadarko was also contractually committed to deliver approximately 8 MMBbls of crude oil to ports in Algeria and Ghana through 2012. The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves.

Drilling Program

The Company’s 2011 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. Exploration activity in 2011 consisted of 224 gross completed wells, which included 216 onshore U.S. wells, three offshore Gulf of Mexico wells, and five international wells. Development activity in 2011 consisted of 1,843 gross completed wells, which included 1,813 onshore U.S. wells, two offshore Gulf of Mexico wells, and 28 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.

 

000000 000000 000000 000000 000000 000000 000000
    Net Exploratory     Net Development        
    Productive     Dry Holes     Total     Productive     Dry Holes     Total     Total  

2011

             

United States

    79.0       2.2       81.2       1,169.6       6.3       1,175.9       1,257.1  

International

    0.5       1.2       1.7       6.8       0.2       7.0       8.7  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    79.5       3.4       82.9       1,176.4       6.5       1,182.9       1,265.8  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

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, 2011.

 

     Wells in the process
of drilling or
in active completion
   Wells suspended or
waiting on completion
     Exploration    Development    Exploration    Development

United States

                   

Gross

       39            286            172            346    

Net

       14.0            204.7            65.5            206.4    

International

                   

Gross

       5            2            34            —    

Net

       1.6            0.3            11.3            —    

Total

                   

Gross

       44            288            206            346    

Net

       15.6            205.0            76.8            206.4    

Productive Wells

At December 31, 2011, the Company’s ownership interest in productive wells was as follows:

 

     Oil Wells(1)    Gas Wells(1)

United States

         

Gross

       4,220           28,550    

Net

       3,292.4           17,777.7    

International

         

Gross

       338           —    

Net

       85.7           —    

Total

         

Gross

       4,558           28,550    

Net

       3,378.1           17,777.7    

 

(1) 

Includes wells containing multiple completions as follows:

 

Gross

       380          2,395  

Net

       347.4          1,899.1  

 

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Index to Financial Statements

Properties and Leases

The following schedule shows the developed lease, undeveloped lease, and fee mineral acres in which Anadarko held interests at December 31, 2011.

 

00000 00000 00000 00000 00000 00000 00000 00000
    Developed
Lease
    Undeveloped
Lease
    Fee Minerals     Total  
thousands of acres   Gross     Net     Gross     Net     Gross     Net     Gross     Net  

United States

               

Onshore

    5,041       2,977       6,134       2,776       10,231       8,373       21,406       14,126  

Offshore

    340       167       2,403       1,645                     2,743       1,812  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total United States

    5,381       3,144       8,537       4,421       10,231       8,373       24,149       15,938  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

International

    362       88       38,205       19,160                     38,567       19,248  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    5,743       3,232       46,742       23,581       10,231       8,373       62,716       35,186  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

At December 31, 2011, the Company had approximately 13 million net undeveloped lease acres scheduled to expire by December 31, 2012, if the Company does not establish production or take any other action to extend the terms. The Company plans to continue the terms of many of these licenses and concession areas through operational or administrative actions and does not expect a significant portion of the Company’s net acreage position to expire before such actions occur.

MIDSTREAM PROPERTIES AND ACTIVITIES

Anadarko invests in midstream (gathering, processing, treating, and transportation) assets to complement its operations in regions where the Company has oil and natural-gas production. Through ownership and operation of these facilities, the Company is better able to manage costs, control the timing of 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 provides 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.

At the end of 2011, Anadarko had 31 gathering systems and 25 processing and treating plants located throughout major onshore producing basins in Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma, Pennsylvania, and Texas. In 2011, the focus of the midstream activity was the Company’s liquids-rich growth areas such as Greater Natural Buttes, Wattenberg, Delaware basin, and the Eagleford shale, as well as growth in the Marcellus shale dry-gas play. In 2012, the Company plans to continue to focus its midstream investments in these areas, as well as the prospective liquids-rich Utica shale play in Ohio.

In Greater Natural Buttes, gathering and compression capacity of 70 MMcf/d was added in 2011 and the Company is constructing a second cryogenic processing train with a capacity of 300 MMcf/d at the Chipeta processing complex. The new train is expected to commence operations by the third quarter of 2012.

In the Wattenberg area, the Company acquired an additional 93% interest in a 195 MMcf/d processing facility from a third party in May 2011 that positions the Company to realize the additional economics associated with the NGL uplift from its natural-gas production that was previously shared with the facility owner. The Company operates and owns a 100% interest in the Wattenberg Plant. The Company plans to expand cryogenic processing capacity with the addition of the 300 MMcf/d Lancaster plant in Wattenberg, which will significantly increase ethane recoveries in the basin. Permitting and engineering for the Lancaster Plant are underway with start-up operations planned for early 2014.

In the Delaware basin, the Company expanded its natural-gas-gathering capacity to 65 MMcf/d and placed oil-gathering and pipeline facilities into service. The oil-gathering and pipeline facilities are directly connected to third-party pipelines. This allows Anadarko to realize greater value for its oil production due to reduced trucking costs. Also in the Delaware basin, the Company entered into a joint venture with two third parties to build the 100 MMcf/d Ranch Westex joint-venture cryogenic processing plant that is expected to be operational in early 2013.

 

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In the Eagleford shale, gas-gathering capacity was expanded from 100 MMcf/d in 2010 to 225 MMcf/d in 2011 with plans to further expand system capacity to 500 MMcf/d by the end of 2013. A new Company-operated cryogenic processing plant in the Eagleford shale with capacity of 200 MMcf/d is scheduled to be operational in the first quarter of 2013. The Eagleford oil-gathering system was placed in service in 2011 with an initial capacity of 30,000 Bbls/d. The Company plans to expand the capacity to 100,000 Bbls/d by the end of 2013. In addition, the first phase of a crude-oil pipeline, with an initial capacity of 100,000 Bbls/d, was placed in service. The oil pipeline replaces truck-based sales and provides price uplift on Anadarko’s oil by reducing aggregate transportation costs.

In the Marcellus shale, Anadarko’s gas-gathering capacity increased from 180 MMcf/d in 2010 to 500 MMcf/d in 2011. The Company plans to add an additional 500 MMcf/d of capacity in 2012.

During 2011, Anadarko and its partners agreed to design and construct a new NGL pipeline that will originate from Skellytown, Texas and extend approximately 580 miles to NGL fractionation and storage facilities in Mont Belvieu, Texas. The new Texas Express Pipeline (TEP) will help Anadarko maximize the value of the Company’s production by providing additional takeaway capacity and enhancing access to the Gulf Coast NGL market. Initial capacity on TEP will be approximately 280,000 Bbls/d that can be readily expanded to approximately 400,000 Bbls/d. Subject to regulatory approvals, the pipeline is expected to begin service in the second quarter of 2013.

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 the first quarter of 2011, WES acquired a gas processing facility and related gathering systems in the Wattenberg area from a third party. At December 31, 2011, Anadarko held a 43.3% limited partner interest in WES, as well as the entire 2% general partner interest and incentive distribution rights.

The following table provides information regarding the Company’s midstream assets by geographic regions.

 

0000000 0000000 0000000 0000000

Area

  

Asset Type

   Miles of
Gathering
Pipelines
     Total
Horsepower
     2011
Average
Throughput
(MMcf/d)
 

Rocky Mountains

   Gathering, Processing, and Treating      9,700        1,088,200        3,500  

Mid-Continent and other

   Gathering      2,500        105,100        200  

Texas

   Gathering and Treating      2,200        168,700        700  
     

 

 

    

 

 

    

 

 

 

Total

        14,400        1,362,000        4,400  
     

 

 

    

 

 

    

 

 

 

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 and better position the Company to fully utilize transportation and storage 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.

 

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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 to increase. 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.

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 U.S. 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, and 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 market for the heavy fuel oil blend stock. 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 and 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, and utilizes contracted NGLs storage facilities to capture market opportunities and reduce fractionation and downstream infrastructure disruptions.

COMPETITION

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 consumers.

SEGMENT INFORMATION

For additional information on operations by segment, see Note 20—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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

EMPLOYEES

The Company had approximately 4,800 employees at December 31, 2011.

 

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Index to Financial Statements

REGULATORY MATTERS, ENVIRONMENTAL, AND ADDITIONAL FACTORS AFFECTING BUSINESS

Environmental and Occupational Health and Safety Regulations

Anadarko’s business operations are subject to numerous international, federal, state and local environmental and occupational 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 workplace 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 and occupational health and safety laws and regulations include the following U.S. 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 (DOI) 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.

 

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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.

 

   

The Migratory Bird Treaty Act, which implements various treaties and conventions between the United States 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.

There have been several regulatory and governmental initiatives to restrict the hydraulic-fracturing process, which could have an adverse impact on our completion or production activities. The U.S. Environmental Protection Agency (EPA) has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic-fracturing practices notwithstanding the existence of current oil and gas regulations adopted at the state level. Moreover, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected to be available by 2014. The EPA has also announced plans to propose effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities by 2014. Certain other governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices, including evaluations by the U.S. Department of Energy and the DOI, and coordination of an administration-wide review of these practices by the White House Council on Environmental Quality. Congress is currently considering, and has from time to time in the past considered, bills that would regulate hydraulic fracturing and/or require public disclosure of chemicals used in the hydraulic-fracturing process. A number of states, including states in which we operate, have adopted or are considering legal requirements that could impose more stringent permitting, public disclosure, and well-construction requirements on hydraulic-fracturing activities.

 

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The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor 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 and the threat of adverse impacts to groundwater arising from hydraulic-fracturing activities, 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, compliance, mitigation, and remediation obligations in the United States.

The Company has reviewed its potential responsibilities under both OPA and CWA as they relate to the Deepwater Horizon events. 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 EPA are increased to not more than $4,300 per barrel of oil discharged.

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 U.S. 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 October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify, relating to the Deepwater Horizon events (Settlement Agreement), pursuant to which BP has fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events and related damage claims arising under OPA. Under the Settlement Agreement, BP does not indemnify the Company against penalties or fines that may be assessed against the Company as a result of the Deepwater Horizon events, including for example, under the CWA. 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 and occupational 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 and occupational 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 sufficient based on the Company’s assessment of insurable risks and consistent with insurance coverage held by other similarly situated industry participants. Nevertheless, it is possible that other developments, such as stricter and more comprehensive environmental and occupational 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 and occupational 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, results of operations, or cash flows, but new or more

 

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Index to Financial Statements

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 BSEE regulations, which 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 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. The BSEE 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.

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. These plans detail procedures for a 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 BSEE.

As part of the Company’s oil spill-response preparedness, and as set forth 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.

CGA equipment includes one High Volume Open Sea Skimmer System (HOSS) barge, four 46-foot skimming vessels, one 56-foot skimming vessel, three Marco skimmers, and two Egmopol skimmers. In addition, CGA equipment also consists of:

 

   

Nine Fast Response Units;

 

   

One rope mop;

 

   

Three Foilex skim packages;

 

   

Two 4-drum skimmers (Magnum 100);

 

   

Two 2-drum skimmers (TDS 118);

 

   

Eleven sets of Koseq skimming arms;

 

   

Two Aqua Guard Triton RBS;

 

   

Four oil storage barges (249 barrels);

 

   

Ten tanks (100 barrels, primary); and

 

   

Nine tanks (100 barrels, secondary).

Auto boom, beach boom, and fire boom are 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 installed on the HOSS Barge. CGA has ordered three 95–foot fast response vessels and is scheduled to receive delivery on or about the end of the second quarter of 2012.

 

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The 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.

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.

As of December 2, 2011, Anadarko became a member of the Marine Preservation Association, which provides full access to the MSRC cooperative including the Deep Blue enhanced Gulf of Mexico Response capability. 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 61 skimmers with an Effective Daily Recovery Capacity of 449,108 barrels. The following equipment was available through the various regions at December 31, 2011:

 

   

Fifteen Responder Class OSRVs;

 

   

Twenty-nine smaller OSRVs;

 

   

Five Fast Response Vessels;

 

   

Nineteen offshore barges;

 

   

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

 

   

Fifty-one shallow water push boats;

 

   

Seventeen shallow water barges (self-propelled);

 

   

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;

 

   

275,734 feet of ocean boom;

 

   

103,159 gallons of Corexit 9500 dispersant; and

 

   

1,500 gallons of Corexit 9527 dispersant.

 

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As of December 31, 2011, Anadarko will no longer maintain a retainer-based service contract with National Response Corporation. These services have been superseded by the MSRC contract and are available as a commercial service should the extraordinary case arise.

Anadarko has emergency and oil spill-response plans in place 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 its equipment is registered with the U.S. Coast Guard for domestic use if needed.

OSR has two Hercules aircraft, located in the United Kingdom and Singapore, available for dispersant application or equipment transport. 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 chartered. 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 the United Kingdom, Bahrain, and Singapore. Fireboom systems have been delivered and a team is trained to operate the system. 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 (Helix), 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.

In addition, during 2011, the Company became an investing member in the Marine Well Containment Company (MWCC), which is open to all oil and gas operators in the U.S. Gulf of Mexico and provides members access to oil spill-response equipment and services on a per-well fee basis. Anadarko has an employee representative on the Executive Committee of MWCC and this employee currently serves as its Chair. MWCC members have access to an interim containment system that includes a 15-kpsi capping stack and dispersant capability. The interim containment system is engineered to operate in deepwater depths of up to 10,000 feet, and has the capacity to contain 60 MBbls/d of liquids and flare 120 MMcf/d of natural gas. The DOI has reviewed the functional specifications of the MWCC interim containment system, and DOI input was included in the final specifications.

MWCC members also expect to have access to an expanded containment system that is planned for use in deepwater depths of up to 10,000 feet with containment capacity of 100 MBbls/d of liquids and flare capability for 200 MMcf/d of natural gas. The expanded system is planned to include a 15-kpsi subsea containment assembly with three rams stack, dedicated capture vessels, and a dispersant injection system. The expanded containment system may also be further expanded with additional capture vessels, modified tankers, drill ships, and extended well-test vessels, all of which may process, store, and offload oil to shuttle tankers, which may then take the oil to shore for further processing. This expanded containment system is on schedule for delivery in 2012.

 

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In addition to Anadarko’s membership in or access to CGA, MSRC, OSR, Helix, and MWCC, the Company is also 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, defensible, and customary with practices in the oil and gas industry, subject to such exceptions that, in the opinion of legal counsel for the Company, do not materially detract from the use of such properties.

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, 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 as of
February 21,
2012

  

Position

James T. Hackett

   58    Chairman of the Board and Chief Executive Officer

R. A. Walker

   55    President and Chief Operating Officer

Robert P. Daniels

   53    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

On February 21, 2012, Anadarko announced the transition of Mr. Hackett from Chairman and Chief Executive Officer to Executive Chairman effective May 15, 2012. 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, Mr. Hackett served as President and Chief Operating Officer of Devon Energy Corporation following its merger with Ocean Energy, Inc. in April 2003. He 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, Bunge Limited, and The Welch Foundation.

On February 21, 2012, Anadarko announced the appointment of Mr. Walker as Chief Executive Officer of Anadarko effective May 15, 2012. He will continue as President. 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, Mr. Walker served as Managing Director for the Global Energy Group of UBS Investment Bank from 2003 to 2005. Mr. Walker served as a director of Temple-Inland Inc. from November 2008 to February 2012 and has served 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.

 

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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.

Mr. Gwin was named Senior Vice President, Finance and Chief Financial Officer in March 2009 and previously had served as Senior Vice President since March 2008. He also serves as Chairman of the Board of Western Gas Holdings, LLC, the general partner of WES, 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 and served in that capacity until March 2008. 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. 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. He has served as a director of LyondellBassell Industries N.V. since May 2010.

Mr. Meloy was named Senior Vice President, Worldwide Operations in December 2006 and 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 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 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 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 served as Corporate Controller from September 2007 to March 2009. She served as Assistant Controller from July 2006 to September 2007. She 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. Ms. Douglas 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 15, 2012, 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 management discussions, 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, the price of, and the commercializing and transporting of natural gas, crude 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 ability of BP Exploration & Production Inc. (BP) to meet its indemnification obligations to the Company for, among other things, damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and associated damage-assessment costs, and any claims arising under the Operating Agreement (OA) for the Macondo well, as well as the ability of BP

 

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Corporation North America Inc. (BPCNA) and BP p.l.c. to satisfy their guarantees of such indemnification obligations;

 

   

the impact of remaining claims related to the Deepwater Horizon events, including, but not limited to, fines, penalties, and punitive damages for which the Company is not indemnified by BP;

 

   

the legislative and regulatory changes that may impact the Company’s Gulf of Mexico and international offshore operations;

 

   

the impact of future regulations on the Company’s ability to fully 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);

 

   

civil or political unrest in a region or country;

 

   

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

 

   

volatility in the securities, capital, or credit markets;

 

   

the Company’s ability to successfully monetize select assets, repay its debt, and the impact of changes in the Company’s credit ratings;

 

   

disruptions in international crude oil cargo shipping activities;

 

   

electronic, cyber, and physical security breaches;

 

   

the supply and demand, technological, political, and commercial conditions associated with long-term development and production projects in domestic and international locations;

 

   

the outcome of 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 liabilities relating to the Deepwater Horizon events that are not covered by BP’s indemnification obligations under our Settlement Agreement with BP, or that result in losses to the Company, notwithstanding BP’s indemnification against such losses, as a result of BP’s inability to satisfy its indemnification obligations under the Settlement Agreement and BPCNA’s and BP p.l.c’s inability to satisfy their guarantees of BP’s indemnification obligations.

In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify, relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company paid $4.0 billion and transferred its interest in the Macondo well and the Lease to BP, and BP accepted this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued through the settlement date as well as for potential reimbursements of subsequent costs incurred by BP related to the Deepwater Horizon events, including costs under the OA.

Under the Settlement Agreement, BP fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims arising under OPA, NRD claims and associated damage-assessment costs, and any claims arising under the OA. This indemnification is guaranteed by BPCNA and, in the event that the net worth of BPCNA declines below an agreed-upon amount, BP p.l.c. has agreed to become the sole guarantor.

Any failure or inability on the part of BP to satisfy its indemnification obligations under the Settlement Agreement, or on the part of BPCNA or BP p.l.c. to satisfy their respective guarantee obligations, could subject us to significant monetary liability beyond the terms of the Settlement Agreement, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Furthermore, in certain instances we may be required to recognize a liability for amounts for which we are indemnified in advance of or in connection with recognizing a receivable from BP for the related indemnity

 

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payment. Any such liability recognition without collection of the offsetting receivable could adversely impact our results of operations, our financial condition, and our ability to make borrowings.

Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder, derivative, or security laws claims, or certain other claims. The adverse resolution of any current or future proceeding related to the Deepwater Horizon events for which we are not indemnified by BP could subject us to significant monetary liability, 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 arising after the deepwater drilling moratorium 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 (OCS) regions of the Gulf of Mexico and Pacific Ocean to cease drilling all new deepwater wells, including wellbore sidetracks and bypasses, but excluding workovers, completions, plugging and abandonment, or production, through November 30, 2010 (Moratorium). 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.

Between mid-May 2010 and mid-October 2010, part of which time the Moratorium was in place, the BOEMRE issued a series of rules and Notices to Lessees and Operators (NTLs) imposing new regulatory safety and performance requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. The new regulatory requirements include the following:

 

   

Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements.

 

   

Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers.

 

   

Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and enhances oversight requirements relating to blowout preventers and related components, including shear and pipe rams.

 

   

Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system (SEMS) in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills. The BOEMRE subsequently issued a proposed rulemaking in 2011 that would amend the Workplace Safety Rule by requiring the imposition of certain added safety procedures to a company’s SEMS not covered by the original rule (including, by way of example, procedures to authorize any and all employees on an offshore facility authority to stop work when witnessing any activity that poses a threat of danger to an individual, property, or the environment) and revising existing obligations that a company’s SEMS be audited by requiring the use of an independent third-party auditor who is pre-approved by the agency to perform the auditing task.

In addition, the BOEMRE issued an NTL effective October 15, 2010, that established a more stringent regiment for the timely decommissioning of what is known as “idle iron”—wells, platforms, and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease—in the Gulf of Mexico. This NTL establishes more stringent standards for the deadlines by which idle iron must be decommissioned, the result of which is that Anadarko anticipates incurring costs to plug, abandon, or decommission wells and facilities on a more expedited basis than it might otherwise, absent this NTL.

 

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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, development, and oil spill-response plans, as a result of the new laws and regulations, the split of the BOEMRE into two new federal bureaus, and possible additional regulatory initiatives 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 on our drilling operations in the Gulf of Mexico.

In addition to the drilling restrictions and new safety and permitting measures already issued and the possibility of new safety and environmental laws and regulations in the future, there have been discussions by government and private constituencies to amend existing laws such that exploration and production operators in the Gulf of Mexico would have to demonstrate or otherwise have available greater financial resources in order to conduct operations. For example, legislation has been discussed that could require companies operating in the Gulf of Mexico to establish and maintain a higher level of financial responsibility under its Certificate of Financial Responsibility, a certificate required by the OPA which evidences a company’s financial ability to pay for cleanup and damages caused by oil spills. There have also been discussions regarding the establishment of a new industry mutual insurance fund in which companies would be required to participate and which would be available to pay for consequential damages arising from an oil spill.

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 U.S. 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, insurance costs may 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, the deepwater Gulf of Mexico (as well as international deepwater locations) lacks the degree of physical and oilfield service infrastructure present in shallower waters. Therefore, 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.

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.

In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code (the Bankruptcy) in the U.S. Bankruptcy Court for the Southern District of New York (Bankruptcy 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 (Adversary Proceeding). Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee and seeks, among other things, to recover damages, including interest, in excess of $14.5 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. 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.

 

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For additional information regarding the nature and status of these and other material legal proceedings, see Note 16—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Oil, natural-gas, and NGLs prices are volatile. A substantial or extended decline in the price of these commodities 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, market prices for natural gas in the United States have declined substantially from 2008 price levels, 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, but are not limited to, the following:

 

   

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 and environmental protection 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, Congress, from time to time, has considered adopting legislation that could adversely affect our business, financial condition, results of operations, or cash flows related to the following:

 

   

Climate Change.  Congress has considered climate-change legislation that would seek to reduce emissions of green-house gases (GHGs) through establishment of a “cap-and-trade” plan. It is not possible at this time to predict whether or when Congress may re-introduce or act on climate-change legislation. The U.S. Environmental Protection Agency (EPA) has made findings that emissions of GHGs present a danger to public health and the environment and, based on these findings, has adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain sources, including, among others, onshore and offshore oil and natural-gas production facilities, which includes certain of our operations, on an annual basis. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

 

   

Taxes.  The U.S. President’s Fiscal Year 2013 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.

Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities could result in increased costs, additional operating restrictions or delays, and adversely affect our production.

Hydraulic fracturing is an essential and common practice used to stimulate production of natural gas and/or oil from dense subsurface rock formations such as shales that generally exist between 4,000 and 14,000 feet below ground. We routinely apply hydraulic-fracturing techniques in many of our U.S. onshore oil and natural-gas drilling and completion programs. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The process is typically regulated by state oil and natural-gas commissions; however, the EPA, recently asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In February 2012, the DOI released draft regulations governing hydraulic fracturing on federal and Indian oil and gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval for well-stimulation activities, mechanical integrity testing of casing, and monitoring of well-stimulation operations. In addition, Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure

 

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Index to Financial Statements

of the chemicals used in the hydraulic-fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic-fracturing process are adopted in areas where we currently or in the future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

Certain states in which we operate, including Colorado, Pennsylvania, Louisiana, Texas, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, and additional well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general and/or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, in the event state or local restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic-fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities and plans to propose these standards by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Also, the DOI is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. These ongoing or proposed studies, depending on any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

The 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 Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), signed into law in 2010, establishes, among other provisions, 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 required the Commodities Futures Trading Commission (CFTC) and the Securities and Exchange Commission (SEC) to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In July 2011, the CFTC granted temporary exemptive relief from certain swap regulation provisions of the legislation until December 21, 2011, or until the agency finalized the corresponding rules. In December 2011, the CFTC extended the potential latest expiration date of the exemptive relief to July 16, 2012. In its rulemaking under the new legislation, the CFTC has issued a final rule on 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 are exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize other regulations, including critical rulemaking on the definition of “swap”, “swap dealer” and “major swap participant.” Depending on the Company’s classification, the financial reform legislation may require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities. 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

 

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Index to Financial Statements

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 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.

Our total debt was $15.2 billion at December 31, 2011. We also have various commitments for leases, drilling contracts, derivative contracts, firm 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/or fewer financial commitments.

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

 

   

incur additional indebtedness;

 

   

sell assets; and

 

   

incur liens.

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.

As of December 31, 2011, our debt was rated “BBB-” with a stable outlook by Standard and Poor’s (S&P), “BBB-” with a negative outlook by Fitch Ratings (Fitch), and “Ba1” and under review for upgrade by Moody’s Investors Service (Moody’s). Although we are not aware of any current plans of S&P, Fitch, or Moody’s to lower their respective ratings on our debt, our credit ratings may be subject to future downgrades. A downgrade in our credit ratings could negatively impact our cost of capital or our ability to effectively execute aspects of our strategy. If we were to be downgraded, it could be difficult for us to raise debt in the public debt markets and the cost of that new debt could be much higher than our outstanding debt. In addition, a downgrade could affect the Company’s requirements to provide financial assurance of its performance under

 

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certain contractual arrangements and derivative agreements. See Note 10—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 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 depend on 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 and court rulings;

 

   

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 fair value of the estimated oil, natural-gas, and NGLs reserves attributable to our properties. For the December 31, 2011, 2010, and 2009 reserves, in accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are based on 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 future discounted 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 U.S. mortgage market, uncertainties with regard to European sovereign debt, and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on global financial markets and commodity prices. If the economic recovery in the United States or abroad remains 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

 

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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 goodwill impairments.

As a result of mergers and acquisitions, we have approximately $5.6 billion of goodwill on our Consolidated Balance Sheet. Goodwill must be tested at least annually for impairment, and more frequently when circumstances indicate likely impairment. 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 natural-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 or for any contamination resulting from our operations. Future environmental laws and regulations, such as the designation of previously unprotected species as threatened or endangered in areas where we operate, 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 or could result in limitations on our exploration and production activities, which could have an adverse impact on our ability to develop and produce our reserves. For a description of certain environmental proceedings in which we are involved, see Note 16—Contingencies and Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 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, New Zealand, and other countries. Our operations and financial results could be significantly impacted by conditions in some of these areas because we are vulnerable to certain unique 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;

 

 

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Index to Financial Statements
   

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.

In addition, we conduct some of our exploration in deep waters (greater than 1,000 feet) 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 significant 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, Sierra Leone, and New Zealand. 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, the U.K. Bribery Act, and other anti-corruption compliance issues;

 

   

increases in taxes and governmental royalties;

 

   

unilateral renegotiation of contracts by governmental entities;

 

   

redefinition of international boundaries or boundary disputes;

 

   

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 to 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. The arbitration hearing related to Anadarko’s dispute regarding the imposition of the Algerian exceptional profits tax was held in June 2011. Any decision issued by the arbitration panel is binding on the parties. For additional information, see Note 17—Other Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

In addition, Ghana and Cote d’Ivoire are currently engaged in a dispute regarding the international maritime and land boundaries between the two countries. As a result, Cote d’Ivoire claims to be entitled to the maritime area which covers a portion of the Deepwater Tano Block where we are currently conducting

 

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Index to Financial Statements

exploration and appraisal activities. In the event Cote d’Ivoire is successful in its maritime border claims, our operations in the block could be materially impacted.

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 events in Tunisia, Egypt, and Libya, these outbreaks have 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. 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.

Our commodity-price risk-management and trading activities may prevent us from fully benefiting 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 by our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill 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, production facilities, and other property, as well as injury to persons. For protection against financial loss resulting from these operating hazards, we maintain insurance coverage, including insurance coverage for certain physical damage, blowout/control of a well, comprehensive general liability, aviation liability, and worker’s compensation 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,

 

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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 and could have a material adverse effect on our results of operations.

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 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 to us 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.

 

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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.

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 on the availability, proximity, and capacity of pipeline facilities and tanker transportation. If any pipelines or tankers become unavailable, we would, to the extent possible, 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 nomination and removal of directors; the prohibition of stockholder action by written consent and regulation of stockholders’ ability 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.

 

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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 on actions taken by our Board of Directors, as well as, our financial condition, results of operations, cash flows, levels of capital and exploration expenditures, 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 could have an adverse effect on our business. 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, 2011.

Item 3.  Legal Proceedings

GENERAL  The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims, title disputes, royalty claims, contract claims, oil-field contamination claims, and environmental claims, including claims involving assets owned by predecessors of acquired companies. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

See Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, which is incorporated herein by reference, for a discussion of legal proceedings related to the Deepwater Horizon events.

See Note 16—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, which is incorporated herein by reference, for a discussion of other material legal proceedings to which the Company is a party.

Item 4.  Mine Safety Disclosures

Not applicable.

 

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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, 2012, there were approximately 13,700 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 2011 and 2010.

 

0000 0000 0000 0000
     First
Quarter
     Second
Quarter
     Third
Quarter
     Fourth
Quarter
 

2011

           

Market Price

           

High

   $     84.00      $     85.50      $     85.25      $     84.42  

Low

   $ 73.02      $ 68.67      $ 63.03      $ 57.11  

Dividends

   $ 0.09      $ 0.09      $ 0.09      $ 0.09  

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  

The amount of future common stock dividends will depend on earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with its financial covenants, 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 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, 2011.

 

15,474,224 15,474,224 15,474,224

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

                       9,868,589      $ 55.27                            15,474,224  

Equity compensation plans not approved by security holders

                                     —           
  

 

 

    

 

 

    

 

 

 

Total

     9,868,589      $ 55.27        15,474,224  
  

 

 

    

 

 

    

 

 

 

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS

The following sets forth information with respect to repurchases made by the Company of its shares of common stock during the fourth quarter of 2011.

 

124,306 124,306 124,306 124,306

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

     175      $       63.05                                   —      

November 1-30

     83,614      $ 78.47             

December 1-31

     40,517      $ 80.38             
  

 

 

      

 

 

    

 

 

 

Fourth Quarter 2011

     124,306      $ 79.07              $   
  

 

 

      

 

 

    

 

 

 

 

(1) 

During the fourth quarter of 2011, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee stock plan share issuances.

For additional information, see Note 14—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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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 peer group of 11 companies. The companies included in the 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.

Comparison of 5-Year Cumulative Total Return Among

Anadarko Petroleum Corporation, the S&P 500 Index

and a Peer Group

 

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, 2006, and its relative performance is tracked through December 31, 2011.

 

0000000 0000000 0000000 0000000 0000000 0000000
Fiscal Year Ended December 31    2006      2007      2008      2009      2010      2011  

Anadarko Petroleum Corporation

   $ 100.00      $ 152.04      $   89.83      $ 146.59      $ 179.98      $ 181.24  

S&P 500

     100.00        105.49        66.46        84.05        96.71        98.75  

Peer Group

     100.00        137.07        95.49        112.00        138.00        147.01  

 

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Index to Financial Statements

Item 6. Selected Financial Data

 

     Summary Financial Information(1)  
millions except per-share amounts    2011     2010      2009     2008     2007  

Sales Revenues

   $ 13,882     $ 10,842      $ 8,210     $ 14,079     $ 11,656   

Gains (Losses) on Divestitures and Other, net

     85       142        133       1,083       4,760   

Reversal of Accrual for DWRRA Dispute

                    657                
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Total Revenues and Other

     13,967       10,984        9,000       15,162       16,416   

Deepwater Horizon settlement and related costs

     3,930       15                        

Operating Income (Loss)

     (1,870     1,769        377       5,601       7,871   

Income (Loss) from Continuing Operations

     (2,568     821        (103     3,220       3,767   

Income from Discontinued Operations, net of taxes

                           63       11   

Net Income (Loss) Attributable to Common Stockholders

     (2,649     761        (135     3,260       3,778   

Per Common Share (amounts attributable to common stockholders):

           

Income (Loss) from Continuing Operations—Basic

   $ (5.32   $ 1.53      $ (0.28   $ 6.79     $ 8.01   

Income (Loss) from Continuing Operations—Diluted

   $ (5.32   $ 1.52      $ (0.28   $ 6.78     $ 7.99   

Income from Discontinued Operations—Basic

   $      $       $      $ 0.13     $ 0.02   

Income from Discontinued Operations—Diluted

   $      $       $      $ 0.13     $ 0.02   

Net Income (Loss)—Basic

   $ (5.32   $ 1.53      $ (0.28   $ 6.92     $ 8.03   

Net Income (Loss)—Diluted

   $ (5.32   $ 1.52      $ (0.28   $ 6.91     $ 8.01   

Dividends

   $ 0.36     $ 0.36      $ 0.36     $ 0.36     $ 0.36   

Average Number of Common Shares Outstanding—Basic

     498       495        480       465       465   

Average Number of Common Shares Outstanding—Diluted

     498       497        480       466       467   

Cash Provided by Operating Activities—Continuing Operations

   $ 2,505     $ 5,247      $ 3,926     $ 6,447     $ 2,766   

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

                           (5     134   

Net Cash Provided by Operating Activities

     2,505       5,247        3,926       6,442       2,900   

Capital Expenditures

   $ 6,553     $ 5,169      $ 4,558     $ 4,881     $ 3,990   

Current Debt

   $ 170     $ 291      $      $ 1,472     $ 1,396   

Long-term Debt

     15,060       12,722        11,149       9,128       11,151   

Midstream Subsidiary Note Payable to a Related Party

                    1,599       1,739       2,200   

Total Debt

   $     15,230     $     13,013      $     12,748     $     12,339     $     14,747   

Total Stockholders’ Equity

     18,105       20,684        19,928       18,795       16,364   

Total Assets

   $ 51,779     $ 51,559      $ 50,123     $ 48,923     $ 48,451   

Annual Sales Volumes:

           

Natural Gas (Bcf)

     852       829        809       750       698   

Oil and Condensate (MMBbls)

     79       74        68       67       79   

Natural Gas Liquids (MMBbls)

     27       23        17       14       16   

Total (MMBOE)(2)

     248       235        220       206       211   

Average Daily Sales Volumes:

           

Natural Gas (MMcf/d)

     2,334       2,272        2,217       2,049       1,912   

Oil and Condensate (MBbls/d)

     217       201        187       182       215   

Natural Gas Liquids (MBbls/d)

     74       63        47       39       43   

Total (MBOE/d)

     680       643        604       563       577   

Proved Reserves:

           

Natural-Gas Reserves (Tcf)

     8.4       8.1        7.8       8.1       8.5   

Oil and Condensate Reserves (MMBbls)

     771       749        733       709       843   

Natural-Gas Liquids Reserves (MMBbls)

     374       320        277       217       171   

Total Proved Reserves (MMBOE)

     2,539       2,422        2,304       2,277       2,431   

Number of Employees

     4,800       4,400        4,300       4,300       4,000   
(1) 

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

(2) 

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 2011 by increasing sales volumes by approximately 6% year-over-year and adding 392 million barrels of oil equivalent (BOE) of proved reserves. Additionally, the Company continued its offshore exploration and appraisal drilling success with an approximate 80% success rate for wells completed in 2011. Anadarko ended 2011 with $2.7 billion cash on hand and $2.1 billion available under its five-year $5.0 billion senior secured revolving credit facility ($5.0 billion Facility), as well as additional access to credit and capital markets as needed. Management believes that the Company is positioned to satisfy its operational objectives and capital commitments with cash on hand, available borrowing capacity, and cash flows from operations.

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 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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Deepwater Horizon Settlement and Indemnity

In October 2011, the Company and BP Exploration & Production Inc. (BP) entered into a settlement agreement, mutual releases, and agreement to indemnify, relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company paid $4.0 billion and transferred its interest in the Macondo well and the Mississippi Canyon Block 252 lease (Lease) to BP, and BP accepted this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued through the settlement date as well as for potential reimbursements of subsequent costs incurred by BP related to the Deepwater Horizon events, including costs under the Operating Agreement (OA). In addition, BP fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and associated damage-assessment costs, and any claims arising under the OA. This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-upon amount, BP p.l.c. has agreed to become the sole guarantor. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder, derivative, or security laws claims, or certain other claims. The Company believes that costs associated with any non-indemnified items, individually or in the aggregate, will not materially impact the Company’s consolidated financial position, results of operations, or cash flows. 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.

Operating Highlights

Significant 2011 operating highlights include the following:

Overall

 

   

Anadarko’s total-year sales volumes were 248 MMBOE, representing a 6% increase over 2010.

 

   

Anadarko achieved liquids sales volumes of 106 MMBOE, representing a 10% increase over 2010.

 

   

The Company achieved an approximate 80% success rate from offshore exploration and appraisal drilling completed in 2011.

United States Onshore

 

   

The Company’s Rocky Mountains Region (Rockies) achieved total-year sales volumes of 303 thousand barrels of oil equivalent per day (MBOE/d), representing a 10% increase over 2010.

 

   

The Company’s Southern and Appalachia Region achieved total-year sales volumes of 146 MBOE/d, representing a 17% increase over 2010, primarily due to increased drilling in the Eagleford and Marcellus shales.

 

   

The Company entered into a joint-venture agreement that requires a third-party joint-venture partner to fund up to $1.6 billion of Anadarko’s future capital costs in exchange for a one-third interest in Anadarko’s Eagleford shale assets.

 

   

The Company increased its ownership interest in a natural-gas processing plant (Wattenberg Plant), located in northeast Colorado, by acquiring an additional 93% interest for $576 million. The Company operates and owns a 100% interest in the Wattenberg Plant.

 

   

Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, acquired a natural-gas processing plant and related gathering systems (Platte Valley), located in northeast Colorado, for $302 million.

 

   

Anadarko has accumulated over 370,000 gross acres in the prospective liquids-rich area of the eastern Ohio Utica shale.

 

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Gulf of Mexico

 

   

The Company’s Gulf of Mexico total-year sales volumes were 131 MBOE/d, representing a 15% decrease from 2010.

 

   

Anadarko and its partners finalized a unitization agreement to develop the Lucius field, which was sanctioned in December 2011. Anadarko will operate the unit and has a 35% working interest in the field.

 

   

The Company received drilling permits for one development well and two exploration appraisal wells, including the Cheyenne East well, Anadarko’s first deepwater discovery since the deepwater drilling moratorium.

International

 

   

The Company’s International total-year sales volumes were 85 MBOE/d, representing a 20% increase from 2010.

 

   

The Company completed drilling five successful exploration wells; three in Ghana and two in Mozambique.

 

   

The Company completed drilling seven successful appraisal wells; four in Ghana, two in Mozambique, and one in Brazil.

Financial Highlights

Significant 2011 financial highlights include the following:

 

   

Anadarko’s net loss attributable to common stockholders for 2011, including the effect of the $4.0 billion payment made as a result of the Settlement Agreement, totaled $2.6 billion compared to net income of $761 million in 2010.

 

   

The Company generated $2.5 billion of cash flows from operations, including the effect of the $4.0 billion payment required by the Settlement Agreement, compared to $5.2 billion in 2010 and ended the year with $2.7 billion of cash on hand.

 

   

The Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit (LOC Facility) which lowered the Company’s cost to issue letters of credit.

 

   

The Company amended its $5.0 billion Facility to reduce maintenance costs and to lower interest rates under the facility by 125 basis points on borrowings and 30 basis points on undrawn amounts.

 

   

Anadarko modified and extended swap maturity dates from October 2011 to June 2014 for certain of its interest-rate swaps with an aggregate notional principal of $1.85 billion to better align the swap portfolio with the anticipated timing of future debt issuances.

 

   

The Company impaired $1.2 billion of oil and gas reporting segment properties and $458 million of midstream reporting segment properties.

 

   

The Company restructured 500,000 MMBtu/d of natural-gas three-way collar positions into fixed-price commodity swap positions for one million MMBtu/d with an average price of $4.69 per MMBtu.

 

   

The Company received $419 million in contingent consideration related to its 2008 divestiture of its interest in the Peregrino field offshore Brazil.

Gulf of Mexico Deepwater Drilling Update

In July and August 2011, the Bureau of Ocean Energy Management, Regulation and Enforcement, an agency of the Department of the Interior (DOI), issued drilling permits to Anadarko for the Heidelberg appraisal well, the Cheyenne East exploration well near the Independence Hub facility, and a development well in the Nansen field. Anadarko received a drilling permit for the Spartacus prospect in 2012 and is awaiting additional DOI approvals for other exploration plans and drilling permits. See Note 16—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.

 

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The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the year ended December 31, 2011” refer to the comparison of the year ended December 31, 2011, to the year ended December 31, 2010. Similarly, 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. The primary factors that affect the Company’s results of operations include 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 OPERATIONS

Selected Data

 

millions except per-share amounts and percentages    2011     2010      2009  

Financial Results

       

Oil and condensate, natural-gas, and NGLs sales

   $ 12,834     $ 10,009      $ 7,482  

Gathering, processing, and marketing sales

     1,048       833        728  

Gains (losses) on divestitures and other, net

     85       142        133  

Reversal of accrual for DWRRA dispute

                    657  
  

 

 

   

 

 

    

 

 

 

Total revenues and other

     13,967       10,984        9,000  

Costs and expenses(1)

     15,837       9,215        8,623  

Other (income) expense

     254       128        485  

Income tax expense (benefit)

     (856     820        (5

Net income (loss) attributable to common stockholders

   $ (2,649   $ 761      $ (135

Net income (loss) per common share attributable to common stockholders—diluted

   $ (5.32   $ 1.52      $ (0.28

Average number of common shares outstanding—diluted

     498       497        480  
       

Operating Results

       

Adjusted EBITDAX(2)

   $ 8,560     $ 7,241      $ 6,033  

Total proved reserves (MMBOE)

     2,539       2,422        2,304  

Annual sales volumes (MMBOE)

     248       235        220  
       

Capital Resources and Liquidity

       

Cash provided by operating activities

   $ 2,505     $ 5,247      $ 3,926  

Capital expenditures

     6,553       5,169        4,558  

Total debt

     15,230       13,013        12,748  

Stockholders’ equity

   $ 18,105     $ 20,684      $ 19,928  

Debt to total capitalization ratio

     45.7%        38.6%         39.0%   

 

MMBOE—millions of barrels of oil equivalent

(1) 

Includes Deepwater Horizon settlement and related costs of $3.9 billion and $15 million in 2011 and 2010, respectively.

(2) 

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 for a reconciliation of Adjusted EBITDAX to income (loss) before income taxes, which is presented in accordance with GAAP.

 

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FINANCIAL RESULTS

Net Income (Loss) Attributable to Common Stockholders  Anadarko’s net loss attributable to common stockholders for 2011 totaled $2.6 billion, or $5.32 per share (diluted), compared to net income attributable to common stockholders for 2010 of $761 million, or $1.52 per share (diluted). Anadarko’s net loss attributable to common stockholders in 2009 was $135 million, or $0.28 per share (diluted). Anadarko’s net loss for 2011 included the effect of the $4.0 billion Settlement Agreement with BP related to the Deepwater Horizon events.

Sales Revenues and Volumes

 

millions except percentages   2011   Inc/(Dec)
vs. 2010
  2010   Inc/(Dec)
vs. 2009
  2009

Sales Revenues

                   

Natural-gas sales

    $ 3,300         (4 )%     $ 3,420         17 %     $ 2,924  

Oil and condensate sales

      8,072         44         5,592         39         4,022  

Natural-gas liquids sales

      1,462         47         997         86         536  
   

 

 

         

 

 

         

 

 

 

Total

    $ 12,834         28       $ 10,009         34       $ 7,482  
   

 

 

         

 

 

         

 

 

 

Anadarko’s total sales revenues for the year ended December 31, 2011, increased primarily due to higher prices for crude oil and NGLs, as well as increased liquids volumes, partially offset by lower average natural-gas prices. Total sales revenues for the year ended December 31, 2010, increased primarily due to higher commodity prices and increased sales volumes.

 

000000 000000 000000 000000
millions   Natural
Gas
    Oil and
Condensate
    NGLs     Total  

2009 sales revenues

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

Changes associated with prices

    424       1,284       269       1,977  

Changes associated with sales volumes

    72       286       192       550  
 

 

 

   

 

 

   

 

 

   

 

 

 

2010 sales revenues

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

Changes associated with prices

    (214     2,055       295       2,136  

Changes associated with sales volumes

    94       425       170       689  
 

 

 

   

 

 

   

 

 

   

 

 

 

2011 sales revenues

  $ 3,300     $ 8,072     $ 1,462     $ 12,834  
 

 

 

   

 

 

   

 

 

   

 

 

 

 

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The following table provides Anadarko’s sales volumes for the years ended December 31, 2011, 2010, and 2009.

 

Sales Volumes   2011   Inc/(Dec)
vs. 2010
  2010   Inc/(Dec)
vs. 2009
  2009

Barrels of Oil Equivalent
(MMBOE except percentages)

                   

United States

              217         4 %               209         7 %                   196  

International

      31         20         26         7         24  
   

 

 

         

 

 

         

 

 

 

Total

      248         6         235         7         220  
   

 

 

         

 

 

         

 

 

 

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

                   

United States

      595         4 %       572         7 %       537  

International

      85         20         71         7         67  
   

 

 

         

 

 

         

 

 

 

Total

      680         6         643         7         604  
   

 

 

         

 

 

         

 

 

 

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 Note 10—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 and 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.

Natural-Gas Sales Volumes, Average Prices, and Revenues

 

    2011   Inc/(Dec)
vs. 2010
  2010   Inc/(Dec)
vs. 2009
  2009

United States

                   

Sales volumes—Bcf

      852         3 %       829         2 %       809  

                              MMcf/d

      2,334         3         2,272         2         2,217  

Price per Mcf

    $ 3.87         (6 )     $ 4.12         14       $ 3.61  

Natural-gas sales revenues (millions)

    $     3,300         (4 )     $     3,420         17       $     2,924  

 

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

The Company’s natural-gas sales volumes increased 62 MMcf/d for the year ended December 31, 2011, primarily due to increased sales volumes in the Rockies of 84 MMcf/d, resulting from increased drilling in the Greater Natural Buttes area and the Wattenberg field, as well as increased sales volumes in the Southern and Appalachia Region of 66 MMcf/d, primarily related to increased drilling in the Marcellus shale. These increases were partially offset by lower sales volumes in the Gulf of Mexico of 86 MMcf/d, primarily due to 2010 price-related royalty relief, which did not apply for 2011, as well as natural production declines.

The Company’s natural-gas sales volumes increased 55 MMcf/d for the year ended December 31, 2010, primarily due to increased sales volumes 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 sales volumes in the Southern and Appalachia Region of 12 MMcf/d, associated with increased drilling in the Eagleford, Haynesville and Marcellus shales. These increases were partially offset by lower sales volumes in the Gulf of Mexico of 18 MMcf/d due to natural production declines.

 

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The average natural-gas price Anadarko received decreased for the year ended December 31, 2011, primarily due the industry’s supply growing at a faster pace than demand in 2011. Anadarko’s average natural-gas price received increased for the year ended December 31, 2010, primarily due to an increase in demand.

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

 

    2011   Inc/(Dec)
vs. 2010
  2010   Inc/(Dec)
vs. 2009
  2009

United States

                   

Sales volumes—MMBbls

                48         1 %                 48         7 %                 44  

                              MBbls/d

      132         1         130         7         120  

Price per barrel

    $ 97.70         30       $ 74.96         28       $ 58.56  

International

                   

Sales volumes—MMBbls

      31         20 %       26         7 %       24  

                              MBbls/d

      85         20         71         7         67  

Price per barrel

    $ 109.20         39       $ 78.52         33       $ 59.01  

Total

                   

Sales volumes—MMBbls

      79         8 %       74         7 %       68  

                              MBbls/d

      217         8         201         7         187  

Total price per barrel

    $ 102.24         34       $ 76.22         30       $ 58.72  

Oil and condensate sales revenues (millions)

    $ 8,072         44       $ 5,592         39       $ 4,022  

 

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s crude-oil and condensate sales volumes increased 16 MBbls/d for the year ended December 31, 2011. This increase primarily resulted from an additional 15 MBbls/d in Ghana, where the Company’s first lifting occurred in the first quarter of 2011. Increased drilling in the Wattenberg field led to a 5 MBbls/d sales-volume improvement in the Rockies. Additionally, increased activity in the Eagleford shale and Bone Spring formation increased sales volumes from those areas by approximately 170%, contributing to an 8 MBbls/d sales-volume increase in the Southern and Appalachian Region. Partially offsetting these increases was a 9 MBbls/d sales-volume decline in the Gulf of Mexico principally caused by downtime for repairs at the Company’s Constitution spar and a third-party oil pipeline in 2011, as well as natural production declines.

Anadarko’s crude-oil and condensate sales volumes increased 14 MBbls/d for the year ended December 31, 2010. This increase was partially due to higher sales volumes of 5 MBbls/d in the Gulf of Mexico as repairs to third-party downstream infrastructure that was damaged in the 2008 hurricane season was completed 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 realizing a full year of operations from 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 due to the timing of cargo liftings.

The average crude-oil price Anadarko received increased for the year ended December 31, 2011, as a result of increased global demand, as well as supply disruptions and unrest in the Middle East and North Africa. The average crude-oil price realized by the Company was enhanced by the widening differential between West Texas Intermediate and Brent crude, as approximately 70% of Anadarko’s 2011 crude-oil sales volumes were based on prices that are either directly indexed to, or highly correlated to, Brent crude. Anadarko’s average crude-oil price increased for the year ended December 31, 2010, primarily due to increased global demand.

 

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Natural-Gas Liquids Sales Volumes, Average Prices, and Revenues

 

    2011   Inc/(Dec)
vs. 2010
  2010   Inc/(Dec)
vs. 2009
  2009

United States

                   

Sales volumes—MMBbls

                27         17 %                 23         36 %                 17  

                            MBbls/d

      74         17         63         36         47  

Price per barrel

    $ 53.95         25       $ 43.07         37       $ 31.42  

Natural-gas liquids sales revenues (millions)

    $ 1,462         47       $ 997         86       $ 536  

NGLs sales represent revenues from the sale of products derived from the processing of Anadarko’s natural-gas production. The Company’s NGLs sales volumes increased by 11 MBbls/d for the year ended December 31, 2011, as a result of the Company’s increased focus on liquids-rich areas, expanded horizontal drilling programs in the Wattenberg field, and increases related to the Wattenberg Plant acquisition.

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

The average NGLs price increased for the years ended December 31, 2011 and 2010, primarily due to higher crude-oil prices and sustained global petrochemical demand.

Gathering, Processing, and Marketing Margin

 

millions except percentages   2011   Inc/(Dec)
vs. 2010
  2010   Inc/(Dec)
vs. 2009
  2009

Gathering, processing, and marketing sales

    $     1,048         26 %     $         833         14 %     $         728  

Gathering, processing, and marketing expenses

                791         29         615                 617  
   

 

 

         

 

 

         

 

 

 

Margin

    $ 257         18       $ 218         96       $ 111  
   

 

 

         

 

 

         

 

 

 

For the year ended December 31, 2011, the gathering, processing, and marketing margin increased $39 million. This increase was primarily due to increased natural-gas processing margins from higher NGLs prices and volumes, lower prices for natural-gas purchases, and favorable impacts attributable to 2011 asset acquisitions. These increases were partially offset by lower margins associated with natural-gas sales from inventory.

For the year ended December 31, 2010, the gathering, processing, and marketing margin increased $107 million. The increase was primarily due to higher margins associated with natural-gas sales from inventory and increased NGLs volumes and prices. These increases were partially offset by the absence of gas-processing margins associated with assets divested in 2009.

Gains (Losses) on Divestitures and Other, net

Gains (losses) on divestitures in 2011 included losses on assets held for sale of $422 million as the Company began marketing certain onshore domestic properties from the oil and gas exploration and production reporting segment and the midstream reporting segment in order to redirect its operating activities and capital investment to other areas. These assets were impaired to fair value. See Note 4—Divestitures and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. Also included is a loss of $76 million related to the effective termination of natural-gas processing contracts between the Company and the previous owner of the Wattenberg Plant that occurred in connection with the Company’s purchase of the plant. The loss represents the aggregate amount by which the Company’s contracts with the previous owner of the Wattenberg Plant were unfavorable as compared to current market transactions for the same or similar services at the date of the Company’s acquisition of the plant. These losses

 

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were partially offset by a gain of $419 million related to the receipt and final settlement of contingent consideration related to the Company’s 2008 divestiture of its interest in the Peregrino field offshore Brazil. Gains on divestitures also include the recognition of a $21 million gain from the acquisition-date fair-value remeasurement of the Company’s pre-acquisition 7% equity interest in the Wattenberg Plant.

Gains on divestitures in 2010 were $29 million and related primarily to the divestiture of onshore U.S. oil and gas properties. Gains on divestitures in 2009 were $44 million, primarily related to the sale of oil and gas properties in Qatar.

Reversal of Accrual for DWRRA Dispute

In January 2006, the DOI issued an order (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 U.S. Supreme Court was denied on October 5, 2009.

In 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 liability for accrued royalties on leases listed in the 2006 Order, 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 interest on these unpaid royalty amounts. Effective October 1, 2009, the Company ceased accruing liabilities for royalties and interest costs for deepwater Gulf of Mexico leases that have royalties suspended under the DWRRA. For more information on the DWRRA dispute, see Note 16—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   2011   Inc/(Dec)
vs. 2010
  2010   Inc/(Dec)
vs. 2009
  2009

Oil and gas operating

    $ 993         20 %     $       830         (3 )%     $ 859  

Oil and gas transportation and other

      891         9         816         23         664  

Exploration

          1,076         10         974         (12 )             1,107  

For the year ended December 31, 2011, oil and gas operating expenses increased by $163 million primarily due to (i) increased workovers and related freight costs of $47 million primarily in the Gulf of Mexico and the Rockies, (ii) $36 million related to increased joint-venture activity primarily in the Rockies, Bone Spring and Marcellus shale in the Southern and Appalachia Region, and in Alaska, (iii) operating costs of $34 million resulting from the start of production in Ghana, and (iv) higher surface maintenance costs of $10 million primarily in the Rockies. 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 associated delays in obtaining drilling permits.

For the year ended December 31, 2011, oil and gas transportation and other expenses increased $75 million due to higher volumes, higher natural-gas processing fees that rise with increases in NGLs prices, and increased costs attributable to growth in U.S. onshore plays. These increases were partially offset by the 2010 expensing of amounts attributable to drilling rig lease payments made for rigs that sat idle during the moratorium, as well as rig termination fees incurred in 2010 related to deepwater drilling rigs in the Gulf of Mexico. 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 drilling rig lease payments and $19 million of rig termination fees as discussed above. 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.

 

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Exploration expense increased $102 million for the year ended December 31, 2011, due to $143 million of higher geological and geophysical expense, primarily associated with increased seismic purchases in the Rockies, Gulf of Mexico, the Marcellus shale, Indonesia, Liberia, and East Africa. These additional expenses were partially offset by $48 million of lower dry hole expense, primarily in the Gulf of Mexico. 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, and lower exit costs of $15 million in various international locations, partially offset by higher dry hole expense of $26 million in various other international locations, including Brazil, Ghana, and Mozambique. Exploration expense for 2010 included a $46 million increase related to the Macondo well in the Gulf of Mexico.

 

millions except percentages   2011   Inc/(Dec)
vs. 2010
  2010   Inc/(Dec)
vs. 2009
  2009

General and administrative

    $     1,060         10 %     $ 967         (2 )%     $ 983  

Depreciation, depletion, and amortization

      3,830         3             3,714         5             3,532  

Other taxes

      1,492         40         1,068         43         746  

Impairments

      1,774         NM         216         88         115  

Deepwater Horizon settlement and related costs

      3,930         NM         15         NM          

 

NM—not meaningful

For the year ended December 31, 2011, general and administrative (G&A) expense increased by $93 million primarily due to higher employee-related costs of $67 million primarily from operational expansions and changes in pension discount rates; higher legal, consulting, and other expenses of $51 million related to ongoing litigation and other matters; and increased insurance costs of $9 million related to higher industry-specific rates as a result of the Deepwater Horizon events. These increased costs are partially offset by a gain of $46 million from the financial settlement stemming from Tronox’s rejection of the Master Separation Agreement (MSA) discussed in Note 16—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. For the year ended December 31, 2010, G&A expense decreased due to lower bonus plan expense of $67 million, offset by higher legal and consulting fees of $41 million primarily due to costs associated with the Tronox bankruptcy, and higher employee-related costs.

For the year ended December 31, 2011, depreciation, depletion, and amortization (DD&A) expense increased by $116 million primarily attributable to higher sales volumes, partially offset by a lower average DD&A rate, largely the result of an $89 million DD&A expense that was taken in 2010 associated with depleted fields in the Gulf of Mexico. For the year ended December 31, 2010, DD&A increased $182 million primarily due to higher sales volumes and $89 million associated with the Gulf of Mexico, as discussed above, partially offset by a lower average DD&A rate attributable to reserve increases in the Marcellus shale and the Eagleford shale.

For the year ended December 31, 2011, other taxes increased by $424 million primarily due to higher crude-oil prices and total sales volumes, resulting in increased Algerian exceptional profits tax of $172 million, increased U.S. production and severance taxes of $152 million, and increased Chinese windfall profits tax of $55 million. Additionally, ad valorem taxes increased by $46 million in 2011 due to higher assessed property values. For the year ended December 31, 2010, other taxes increased $322 million primarily due to higher commodity prices and total sales volumes, resulting in increased Algerian exceptional profits tax of $129 million, increased U.S. 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. Refer to Note 17—Other Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information on the Algerian exceptional profits tax.

 

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Impairment expense of $1.8 billion for the year ended December 31, 2011, included $1.2 billion related to oil and gas exploration and production reporting segment properties located in the United States, $458 million for midstream reporting segment properties, and $91 million related to the Company’s investment in Venezuelan assets. Impairment expense of $952 million for U.S. onshore oil and gas properties and $446 million for associated midstream properties was triggered by lower natural-gas prices. Impairment expense also included $162 million related to reserves revisions for certain Gulf of Mexico properties, and $100 million related to onshore properties due to changes in projected cash flows, which resulted from the Company’s intent to divest the properties. All of these assets were impaired to fair value. Further declines in commodity prices could result in additional price-related impairments. See Risk Factors under Item 1A of this Form 10-K for further discussion on the risks associated with oil, natural-gas, and NGLs prices. Impairment expense for the year ended December 31, 2010, included $145 million related to oil and gas exploration and production reporting segment properties located in the United States. The properties in the United States include $114 million related to a production platform included in the oil and gas exploration and production reporting segment that remains idle with no immediate plan for use, and for which a limited market 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 related to the Company’s investment in Venezuelan assets that was impaired to its estimated fair value.

For the year ended December 31, 2011, Deepwater Horizon settlement and related costs included a $4.0 billion expense for the Company’s cash payment made to BP pursuant to the Settlement Agreement, as well as $93 million of legal expenses and other related costs associated with the Deepwater Horizon events. These amounts were partially offset by a $163 million gain recognized in the fourth quarter for insurance recoveries associated with the Deepwater Horizon events. Legal expenses of $15 million related to the Deepwater Horizon events for 2010, previously recorded to general and administrative expense, were reclassified to Deepwater Horizon settlement and related costs. Although Anadarko has been indemnified by BP for certain costs, the Company may be required to recognize a liability for amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c. Additionally, as part of the Settlement Agreement, BP has agreed that, to the extent it receives value in the future from claims that it has asserted or could assert against third parties arising from or relating to the Deepwater Horizon events, it will make cash payments (not to exceed $1.0 billion in the aggregate) to Anadarko, on a current and continuing basis, equal to 12.5% of the aggregate value received by BP in excess of $1.5 billion. Any payments received by the Company pursuant to this arrangement will be accounted for as a reimbursement of the $4.0 billion payment made to BP as part of the Settlement Agreement. Refer to Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information.

 

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Other (Income) Expense

 

millions except percentages   2011   Inc/(Dec)
vs. 2010
  2010   Inc/(Dec)
vs. 2009
  2009

Interest Expense

                   

Current debt, long-term debt, and other

    $ 986         13 %     $ 871         13 %     $ 773  

(Gain) loss on early debt retirements and commitment termination

              (100 )       112         NM         (2 )

Capitalized interest

      (147 )       (15 )       (128 )       (86 )       (69 )
   

 

 

         

 

 

         

 

 

 

Interest expense

    $       839         (2 )     $       855         22       $       702  
   

 

 

         

 

 

         

 

 

 

Anadarko’s interest expense decreased for the year ended December 31, 2011, due to $19 million of increased capitalized interest related to higher construction-in-progress balances for long-term capital projects. Additionally, 2011 interest expense was lower due to items that occurred in 2010 with no similar expense in 2011, including $86 million associated with losses on early debt retirements, $17 million of commitment and structuring costs associated with a contemplated term-loan facility, and $9 million related to unamortized debt issuance costs recognized with the retirement of the Midstream Subsidiary Note Payable to a Related Party. These items were partially offset by $48 million from a higher average outstanding debt balance and weighted-average interest rate on outstanding debt, $29 million related to interest on capital lease obligations incurred in 2011, $24 million attributable to increased amortization of debt-issuance and credit-facility origination costs, and $20 million of higher fees on issued letters of credit and credit-facility commitment fees. 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. In addition, $86 million of losses on early retirements of debt, $17 million of commitment and structuring costs, and $9 million of expensed unamortized debt issuance costs, discussed above, were incurred in 2010. The Company also incurred $12 million of amortized debt issuance costs associated with the $5.0 billion Facility. 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. 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.

 

millions except percentages    2011   Inc/(Dec)
vs. 2010
  2010   Inc/(Dec)
vs. 2009
  2009

(Gains) Losses on Commodity Derivatives, net

                    

Realized (gains) losses

                    

Natural gas

     $ (288 )       (44 )%     $ (513 )       85 %     $ (277 )

Oil and condensate

             61         NM               15         (130 )       (50 )

Natural gas liquids

       1         NM                          
    

 

 

         

 

 

         

 

 

 

Total realized (gains) losses

       (226 )       (55 )       (498 )       52         (327 )
    

 

 

         

 

 

         

 

 

 

Unrealized (gains) losses

                    

Natural gas

       (192 )       (46 )       (353 )       180         444  

Oil and condensate

       (140 )       NM         (42 )       114         291  

Natural gas liquids

       (4 )       NM                          
    

 

 

         

 

 

         

 

 

 

Total unrealized (gains) losses

       (336 )       (15 )       (395 )       154         735  
    

 

 

         

 

 

         

 

 

 

Total (gains) losses on commodity derivatives, net

     $ (562 )       (37 )     $ (893 )       NM       $       408  
    

 

 

         

 

 

         

 

 

 

 

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The Company enters into commodity derivatives to manage the risk of a decrease in the market prices for its anticipated sales of production. The change in (gains) losses 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 10—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

millions except percentages    2011      Inc/(Dec)
vs. 2010
     2010      Inc/(Dec)
vs. 2009
    2009  

(Gains) Losses on Other Derivatives, net

             

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

   $ 59        NM       $         (100 )%    $ (525

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

     964        NM         285        NM        (57
  

 

 

       

 

 

      

 

 

 

Total (gains) losses on other derivatives, net

   $     1,023        NM       $       285        (149   $       (582
  

 

 

       

 

 

      

 

 

 

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 2008 and 2009, Anadarko entered into interest-rate swap contracts as a fixed-rate payor to mitigate interest-rate risk associated with anticipated debt issuances. In 2009, the Company revised the swap contract terms to increase the weighted-average interest rate of the swap portfolio, and realized a $552 million gain. In 2011, the Company extended the swap maturity dates from October 2011 to June 2014 for interest-rate swaps with an aggregate notional principal amount of $1.85 billion. In connection with these extensions, the swap interest rates were also adjusted. In addition, interest-rate swap agreements with an aggregate notional principal amount of $150 million were settled for a loss of $57 million in October 2011. For additional information, see Note 10—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

millions except percentages    2011     Inc/(Dec)
vs. 2010
    2010     Inc/(Dec)
vs. 2009
    2009  

Other (Income) Expense, net

          

Interest income

   $ (21       62   $ (13     (32 )%    $ (19

Other

     275       NM        (106     NM        (24
  

 

 

     

 

 

     

 

 

 

Total other (income) expense, net

   $       254       NM      $       (119     177     $           (43
  

 

 

     

 

 

     

 

 

 

Total other income decreased $373 million for the year ended December 31, 2011, primarily due to a $250 million Tronox-related contingent loss in 2011, the 2010 reversal of the $95 million reimbursement obligation to Tronox described below, and $20 million due to unfavorable exchange-rate changes applicable to foreign currency purchased in anticipation of funding future expenditures on major development projects and foreign currency held in escrow as of December 31, 2011, pending final determination of the Company’s Brazilian tax liability from its 2008 divestiture of the Peregrino field offshore Brazil. The Brazilian tax matter is currently being considered by the Brazilian courts, and the Company expects this litigation to be resolved within the next 18 to 24 months. An unfavorable decision may require the Company to record an additional tax liability in its consolidated financial statements. See Note 16—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information regarding Tronox litigation.

 

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For 2010, total other income increased primarily due to the reversal of the $95 million reimbursement obligation to Tronox as a result of the cancellation of the MSA by Tronox that occurred as part of Tronox’s bankruptcy proceedings. Under the terms of the MSA entered into between Kerr-McGee and Tronox, a former 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. The reversal of this liability in 2010 was partially offset by $54 million of unfavorable changes in foreign-currency exchange rates primarily attributable to cash denominated in Brazilian currency held in escrow.

Income Tax Expense

 

millions except percentages    2011   2010   2009

Income tax expense (benefit)

     $ (856     $ 820       $     (5

Effective tax rate

           25           50       5

The Company reported a loss before income taxes for the year ended December 31, 2011. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% U.S. federal statutory rate for the year ended December 31, 2011, was primarily attributable to the following:

 

   

tax expense associated with the accrual of the Algerian exceptional profits tax, which is non-deductible for Algerian income tax purposes;

 

   

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

 

   

foreign tax rate differential and valuation allowances; and

 

   

items resulting from business acquisitions and other items.

These amounts were partially offset by the following:

 

   

U.S. income tax benefits associated with foreign losses and the restructuring of foreign operations; and

 

   

state income tax benefits.

The increase from the 35% U.S. federal statutory rate for the year ended December 31, 2010, was primarily attributable to the following:

 

   

tax expense associated with the accrual of the Algerian exceptional profits tax;

 

   

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

 

   

foreign tax rate differential and valuation allowances; 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.

 

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The decrease from the 35% U.S. federal statutory rate for the year ended December 31, 2009, was primarily attributable to the following:

 

   

tax expense associated with the accrual of the Algerian exceptional profits tax;

 

   

foreign tax rate differential and valuation allowances; and

 

   

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

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.

For additional information on income tax rates, see Note 18—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, 2011, 2010, and 2009, the Company’s net income attributable to noncontrolling interests of $81 million, $60 million, and $32 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 54.7%, 51.5%, and 43.2% at year-end 2011, 2010, and 2009, respectively. See Note 8—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 performance of Anadarko’s reporting segments, the chief operating decision maker analyzes income (loss) before income taxes, interest expense, exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and unrealized (gains) losses on derivatives, net, less net income attributable to noncontrolling interests (Adjusted EBITDAX). The Company’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. Adjusted EBITDAX also excludes exploration expense, as it 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. Anadarko’s definition of Adjusted EBITDAX excludes Deepwater Horizon settlement and related costs as these costs are outside the normal operations of the Company. See Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. Finally, unrealized (gains) losses on derivatives, net are excluded from Adjusted EBITDAX because unrealized (gains) losses on derivatives 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.

 

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Index to Financial Statements

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 flows 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) before income taxes, and consolidated Adjusted EBITDAX by reporting segment.

Adjusted EBITDAX

 

millions except percentages    2011     Inc/(Dec)
vs. 2010
    2010     Inc/(Dec)
vs. 2009
    2009  

Income (loss) before income taxes

   $ (3,424     NM      $ 1,641       NM      $ (108

Exploration expense

     1,076       10     974       (12 )%      1,107  

DD&A

     3,830       3       3,714       5